EDGAR 10-K Filing

Company CIK: 1064728
Filing Year: 2025
Filename: 1064728_10-K_2025_0001064728-25-000018.json

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ITEM 1. BUSINESS
Item 1. Business.
Overview
Peabody is a leading producer of metallurgical and thermal coal. At December 31, 2024, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia, including a 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount).
On November 21, 2024, Peabody entered into a partnership with RWE, a renewable energy company, to advance renewable energy projects by repurposing reclaimed land previously used for mining, including certain reclaimed mining land held by the Company.
On November 25, 2024, Peabody entered into definitive agreements with Anglo American plc, a United Kingdom public limited company (Anglo), to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia. The acquisition is expected to close in the second quarter of 2025, subject to regulatory approvals, completion of preemptive rights processes and satisfaction of other customary closing conditions.
During 2024, Peabody continued to advance the development of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, as planned. Development coal was produced and sold during the year, and commencement of longwall production is targeted for the first quarter of 2026.
Segment and Geographic Information
As of December 31, 2024, Peabody 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 Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding the Company’s segments. Note 22. “Segment and Geographic Information” to the accompanying consolidated financial statements is incorporated herein by reference and also contains segment and geographic financial information.
Mining Locations
The maps that follow display Peabody’s active and development mine locations as of December 31, 2024. Also shown are the primary ports that the Company uses for its coal exports and the Company’s corporate headquarters in St. Louis, Missouri.
Peabody Energy Corporation 2024 Form 10-K
U.S. Locations
Peabody Energy Corporation 2024 Form 10-K
Australian Locations
Peabody Energy Corporation 2024 Form 10-K
The table below summarizes information regarding the operating characteristics of each of the Company’s mines in the U.S. and Australia. The mines are listed within their respective reporting segment in descending order, as determined by tons produced in 2024.
Production
Segment/Mining Complex Location Mine Type Mining Method Coal Type Primary Transport Method Processing
Plants Year Ended December 31,
2024 2023 2022
Seaborne Thermal (Tons in millions)
Wilpinjong New South Wales S D, T/S T R, EV Yes 12.6 12.0 12.1
Wambo Open-Cut (1)
New South Wales S T/S T, C R, EV Yes 3.3 2.6 2.0
Wambo Underground (2)
New South Wales U LW T, C R, EV Yes 1.4 1.2 1.1
Seaborne Metallurgical
Shoal Creek (3)
Alabama U LW C B, EV Yes 2.1 0.6 0.8
Metropolitan New South Wales U LW C, P, T R, EV Yes 1.8 2.2 1.8
Coppabella (4)
Queensland S DL, D, T/S P R, EV Yes 1.7 2.2 2.4
Moorvale (4)
Queensland S D, T/S C, P, T R, EV Yes 1.5 2.2 1.5
Centurion (5)
Queensland U LW C R, EV Yes 0.2 - -
Middlemount (6)
Queensland S D, T/S C, P R, EV Yes - - -
Powder River Basin
North Antelope Rochelle Wyoming S DL, D, T/S T R No 59.7 62.0 60.4
Caballo Wyoming S D, T/S T R No 10.8 15.3 12.1
Rawhide Wyoming S D, T/S T R No 9.1 9.8 10.3
Other U.S. Thermal
Bear Run Indiana S DL, D, T/S T Tr, R, EV Yes 5.0 5.5 6.7
El Segundo/Lee Ranch New Mexico S DL, D, T/S T R No 2.4 3.4 3.7
Gateway North Illinois U CM T Tr, R, R/B, T/B, EV Yes 2.1 2.5 2.4
Wild Boar Indiana S HW, DL, D, T/S T Tr, R, R/B, T/B Yes 1.8 1.9 2.3
Francisco Underground Indiana U CM T R Yes 1.6 2.0 1.8
Twentymile Colorado U LW T R, Tr, EV Yes 1.0 1.3 1.5
Legend:
S Surface Mine B Barge
U Underground Mine Tr Truck
HW Highwall Miner R/B Rail to Barge
DL Dragline T/B Truck to Barge
D Dozer/Casting T/R Truck to Rail
T/S Truck and Shovel EV Export Vessel
LW Longwall T Thermal/Steam
CM Continuous Miner C Coking
R Rail P Pulverized Coal Injection
(1)Peabody owns a 50% undivided interest in an unincorporated joint venture that owns the Wambo Open-Cut Mine. The tons shown reflect its share. The Company’s 50% joint venture interest is subject to an outside non-controlling ownership interest.
(2)Majority-owned mine in which there is an outside non-controlling ownership interest.
(3)The mine experienced a fire in March 2023 and restarted production in June 2023.
(4)Peabody owns a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. The tons shown reflect its share.
(5)The mine has been undergoing development since 2023. The first development coal was produced in June 2024. Longwall mining is expected to commence in the first quarter of 2026.
(6)Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine. Because Middlemount is accounted for as an unconsolidated equity affiliate, the table above excludes tons produced from that mine, which totaled 1.3 million, 1.2 million and 1.4 million tons, respectively (on a 50% basis).
Refer to the Reserves and Resources tables within Item 2. “Properties,” which is incorporated by reference herein, for additional information regarding coal reserves and resources, and product characteristics associated with each mine.
Peabody Energy Corporation 2024 Form 10-K
Coal Supply Agreements
Customers. Peabody’s coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of the Company’s sales from its mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions). A smaller portion of the Company’s sales from its mining operations are made under contracts with terms of less than one year, including sales made on a spot basis. Sales under long-term coal supply agreements comprised approximately 90%, 92% and 85% of the Company’s worldwide sales from its mining operations (by volume) for the years ended December 31, 2024, 2023 and 2022, respectively.
For the year ended December 31, 2024, Peabody derived 27% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 16 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2024 to 2028. Peabody’s largest customer in 2024 contributed revenue of approximately $340 million, or approximately 8% of Peabody’s total revenue from coal supply agreements, and has contracts expiring in 2025.
Backlog. Peabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 153 million and 221 million tons of coal as of January 1, 2025 and 2024, respectively. Contracts in backlog have remaining terms ranging from one to seven years and represent slightly more than one year of production based on the Company’s 2024 production volume of 118.1 million tons. Approximately 42% of its backlog is expected to be filled beyond 2025.
Seaborne Operations. Revenue from Peabody’s Seaborne Thermal and Seaborne Metallurgical segments represented approximately 55%, 56% and 59% of the Company’s total revenue from coal supply agreements for the years ended December 31, 2024, 2023 and 2022, respectively, during which periods the coal mining activities of those segments contributed approximately 20%, 18% and 18% of the Company’s sales volumes from mining operations, respectively. Production from these segments is primarily sold into the seaborne thermal and metallurgical markets. A majority of the sales in these segments are executed through annual and multi-year international coal supply agreements which primarily contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. Industry commercial practice, and Peabody’s typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a quarterly, spot or index basis. For its seaborne operations, the portion of sales volume under contracts with a duration of less than one year represented 36% in 2024.
U.S. Thermal Operations. Revenue from Peabody’s Powder River Basin and Other U.S. Thermal segments, in aggregate, represented approximately 45%, 44% and 41% of the Company’s revenue from coal supply agreements for the years ended December 31, 2024, 2023 and 2022, respectively, during which periods the coal mining activities of those segments contributed approximately 80%, 82% and 82% of the Company’s sales volumes from mining operations, respectively. The Company expects to continue selling a significant portion of coal production from its U.S. thermal operating segments under existing long-term supply agreements. Certain customers utilize long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements 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. Peabody’s approach is to selectively renew, or enter into new, long-term supply agreements when it can do so at prices and terms and conditions it believes are favorable.
Transportation
Methods of Distribution. Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. Peabody’s U.S. mine sites are typically adjacent to a rail loop; however, in limited circumstances coal may be trucked to a barge site or directly to customers. Title predominately passes to the purchaser at the rail or barge, as applicable. Peabody’s U.S. and Australian export coal is usually sold at the loading port, with purchasers paying ocean freight. In each case, the Company usually pays transportation costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).
The Company believes it has good relationships with U.S. and Australian rail carriers and port and barge companies due, in part, to its modern coal-loading facilities and the experience of its transportation coordinators. During 2024, lock outages along the Black Warrior River in Alabama, U.S.A. negatively impacted Peabody’s sales volume and transportation costs at the Shoal Creek Mine. The lock outages have largely been resolved during the second half of 2024, and Peabody anticipates improved sales volume and lower transportation costs at the Shoal Creek Mine in 2025. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.
Peabody Energy Corporation 2024 Form 10-K
Export Facilities. Peabody has generally secured its ability to transport coal in Australia through rail and port contracts and access to five east coast coal export terminals that are primarily funded through take-or-pay arrangements (refer to the “Liquidity and Capital Resources” section in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on its take-or-pay obligations). In Queensland, seaborne thermal and metallurgical coal from the Company’s mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by its joint venture Middlemount Mine. In New South Wales, the Company’s primary ports for exporting thermal and metallurgical coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group. Peabody has secured its ability to transport coal from its Shoal Creek Mine under barge and port contracts; the primary port is the McDuffie Terminal in Mobile, Alabama, which the Company utilizes without a take-or-pay arrangement.
Peabody’s U.S. thermal operations exported less than 1% of their annual tons sold during the year ended December 31, 2022. No tons were exported during the years ended December 31, 2024 and 2023. The primary port used for U.S. thermal exports is the Kinder Morgan Terminal near Houston, Texas.
Suppliers
Mining Supplies and Equipment. Peabody relies on various goods to support its mining operations, including mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (such as roof control materials), lubricants and electricity. The Company has established strong, strategic relationships with key suppliers and does not consider itself overly dependent on any single supplier.
When Peabody has chosen to concentrate a significant portion of its purchases with one supplier, it has been to leverage cost savings from bulk purchases, secure long-term pricing for parts and ensure a reliable supply chain. This approach also enables fleet standardization for mining equipment, improving asset utilization, streamlining maintenance practices across global operations and optimizing inventory management, which reduces working capital.
In 2024, lead times for parts and components required for surface and underground mining equipment showed notable improvement. Peabody continues to leverage its global purchasing power and comprehensive planning strategies to maintain a reliable supply chain that effectively supports the needs of its active mines.
Services. In addition to goods, Peabody also contracts services for its mine sites, such as maintenance for mining equipment, construction, temporary labor, explosives use and other requirements. The Company does not perceive any undue operational or financial risk from reliance on individual service providers.
In 2024, inflationary pressures stabilized, returning to more normal levels, and supply chain constraints eased. This resulted in improved access to materials and supplies necessary to support mining operations.
Competition
Demand for coal and the prices that the Company will be able to obtain for its coal are highly competitive and influenced by factors beyond the Company’s control, including but not limited to global economic conditions; the demand for electricity and steel; the cost of alternative sources; the impact of weather on heating and cooling demand; the capacity and cost of transportation; geopolitical risks; and taxes and environmental regulations imposed by the U.S. and foreign governments.
Thermal Coal. Demand for Peabody’s thermal coal products is impacted by economic conditions; demand for electricity, which is impacted by energy efficient products; and the cost of electricity generation from coal and alternative forms of generation. Regulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption. The Company’s products compete with producers of other forms of electricity generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use. The use and price of thermal coal is heavily influenced by the availability and relative cost of alternative fuel sources and the generation of electricity utilizing alternative fuels, with customers focused on securing the lowest cost fuel supply in order to coordinate the most efficient utilization of generating resources in the economic dispatch of the power grid at the most competitive price.
Peabody Energy Corporation 2024 Form 10-K
In the U.S., natural gas is highly competitive (along with other alternative fuel sources) with thermal coal for electricity generation. The competitiveness of natural gas has been strengthened by continued growth in domestic natural gas production and new natural gas combined cycle generation capacity. The Henry Hub Natural Gas Prompt Price averaged $2.41 per mmBtu in 2024, versus $2.66 and $6.54 per mmBtu in 2023 and 2022, respectively. In addition, the competitiveness of other alternative fuel sources for electricity generation has been strengthened by the growth of renewable energy generation. These pressures, coupled with regulatory burdens, contributed to a significant number of coal plant retirements. During 2024, approximately 6 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by approximately forty-two percent. Conversely, emerging technologies, including data centers, artificial intelligence and cryptocurrency, are expected to drive U.S. electricity demand in coming years. As a result, U.S. coal consumption is expected to increase in 2025 which has led to deferrals of planned coal plant retirements.
Internationally, thermal coal also competes with alternative forms of electricity generation. The competitiveness and availability of natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Colombia, the U.S., Russia and South Africa, among others. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, among others. Global thermal coal markets were turbulent during 2022 and 2023, due in part to the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries. Economic sanctions have continued to influence trade flows of thermal coal in 2024.
In addition to its alternative fuel source competitors, Peabody’s principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners; American Consolidated Natural Resources, Inc.; Core Natural Resources, Inc.; Eagle Specialty Materials LLC; Foresight Energy; Hallador Energy; Kiewit; and Navajo Transitional Energy Company LLC, among others. Major international direct coal supply competitors (listed alphabetically) include Adaro Energy; BHP; Bumi Resources; China Shenhua Energy; Coal India Limited; Drummond Company; Glencore; SUEK; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.
Metallurgical Coal. Demand for Peabody’s metallurgical coal products is impacted by economic conditions; government policies; demand for steel; and competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces. The Company competes on the basis of coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.
Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, and the competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others. Trade flow disruptions occurred during 2022 and 2023 related to sanctions imposed on Russian coal imports.
Major international direct competitors (listed alphabetically) include Anglo American; BHP; Core Natural Resources, Inc.; Foxleigh; Glencore; Jellinbah; KRU; Oak Grove Mine; Stanmore; Warrior Met Coal; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.
Human Capital
Peabody had approximately 5,600 employees as of December 31, 2024, including approximately 4,300 hourly employees. Additional information on its employees and related labor relations matters is contained in Note 19. “Management - Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference. Peabody endeavors to engage with its organized workforce and foster strong relationships with those organizations built on trust and communication.
As of December 31, 2024, approximately 3,500 of Peabody’s employees are located in the U.S., with the remainder primarily located in Australia. About 94% of its team members work for mine operations in the U.S. and Australia, while the remaining are based out of its global headquarters in St. Louis or its business offices in Brisbane and Beijing.
Peabody strives to create a strong, united workforce with a commitment to safety as a way of life. In 2024, the Company achieved a global safety incidence rate of 0.81 incidents per 200,000 hours worked, which was 73% better than the 2023 U.S. industry average incidence rate of 2.98 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).
Peabody Energy Corporation 2024 Form 10-K
Peabody strives to offer a work environment that recognizes and develops employees. Peabody seeks a workforce that is comprised of diverse backgrounds, thoughts and experiences as a means to drive innovation and excellence within its business. Such diversity may also serve to mitigate risks to the business in the current tight labor market. The Company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. Peabody believes in fostering a work environment built on mutual trust, respect and engagement. Peabody invests in its employees through health and wellness programs, competitive total rewards and development opportunities. Peabody actively seeks employees' feedback, including through surveys and focus groups on its employee value proposition.
The typical Peabody employee has approximately seven and a half years of experience with the Company, and approximately 46% of all Peabody employees remain employed with the company for more than five years. The Company offers a variety of learning events, including mentoring and development programs to aid its employees in their career growth. During the past five years, approximately 28% of open positions and 63% of director and above positions have been filled by internal candidates through promotions or lateral career development opportunities.
Information About Our Executive Officers
Set forth below are the names, ages and positions of Peabody’s executive officers. Executive officers are appointed by, and hold office at the discretion of, Peabody’s Board of Directors (the Board), subject to the terms of any employment agreements.
Name Age (1)
Position (1)
James C. Grech 63 President and Chief Executive Officer
Mark A. Spurbeck 51 Executive Vice President and Chief Financial Officer
Darren R. Yeates 64 Executive Vice President and Chief Operating Officer
Scott T. Jarboe 51 Chief Administrative Officer and Corporate Secretary
Patrick J. Forkin III 66 Chief Development Officer
Malcolm Roberts 51 Chief Marketing Officer
(1) As of February 14, 2025.
James C. Grech was named Peabody’s President and Chief Executive Officer in June 2021. He has over 30 years of experience in the coal and natural resources industry. Mr. Grech served as Chief Executive Officer and a member of the Board of Directors of Wolverine Fuels, LLC, a thermal coal producer and marketer based in Sandy, Utah, from July 2018 until May 2021. Prior to joining Wolverine Fuels, LLC, Mr. Grech served as President of Nexus Gas Transmission from October 2016 to July 2018, and previously held the position of Chief Commercial Officer and Executive Vice President of Consol Energy. Mr. Grech brings a strong operational, commercial and financial background in both mining and other energy business operations and has extensive utilities and capital markets experience. He serves as a director of Blue Danube. Mr. Grech holds a Bachelor of Science in Electrical Engineering from Lawrence Technological University and an MBA from the University of Michigan.
Mark A. Spurbeck was named Peabody’s Executive Vice President and Chief Financial Officer in June 2020, after serving in an interim capacity from January 2020 through June 2020. He oversees finance, treasury, tax, internal audit, financial reporting, financial planning, risk and mine finance, corporate accounting functions, investor relations and corporate communications, information technology and shared services. Mr. Spurbeck has more than 25 years of accounting and financial experience, most recently serving as the Company’s Senior Vice President and Chief Accounting Officer from early 2018 to January 2020. Prior to joining Peabody, Mr. Spurbeck served as Vice President of Finance and Chief Accounting Officer at Coeur Mining, Inc., a diversified precious metals producer, from March 2013 to January 2018. He also previously held multiple financial positions at Newmont Mining Corporation, a leading gold and copper producer, First Data Corporation, a financial services company, and Deloitte LLP, an international accounting, tax and advisory firm. Mr. Spurbeck is a Certified Public Accountant (inactive) and holds a Bachelor’s Degree in Accounting from Hillsdale College.
Peabody Energy Corporation 2024 Form 10-K
Darren R. Yeates was named Peabody’s Executive Vice President and Chief Operating Officer in October 2020. He has executive responsibility for global operations including health, safety and environment, mine operations, technical, procurement, and sales and marketing. Mr. Yeates has over 40 years of mining industry experience. From May 2018 to December 2019, Mr. Yeates served as Chief Operating Officer of MACH Energy Australia, a developer and supplier of thermal coal to both the Australian domestic and Asian export markets. From January 2014 until June 2016, Mr. Yeates served as the Chief Executive Officer of GVK Hancock Coal, a joint venture developing the vast potential of the Galilee Basin in Central Queensland. Prior to that, he spent over 22 years with Rio Tinto, a global mining group, including as Acting Managing Director and Chief Operating Officer for Coal Australia, General Manager Ports and Infrastructure for Pilbara Iron and General Manager Tarong Coal. Prior to joining Rio Tinto, Mr. Yeates worked for six years for BHP, a mining, metals and petroleum company, in coal operations and metalliferous exploration. Mr. Yeates holds a Bachelor of Engineering (Mining) from the University of Queensland, a Graduate Diploma in Management from the University of Central Queensland and a Graduate Diploma of Applied Finance and Investment from the Securities Institute of Australia. He holds an Executive MBA from the Monash Mt Eliza Business School and is a Fellow of the Australian Institute of Company Directors.
Scott T. Jarboe was named Peabody’s Chief Administrative Officer and Corporate Secretary in November 2021 after serving as Chief Legal Officer and Corporate Secretary since March 2020. He leads the Company’s global human resources, legal, government affairs, and ethics and compliance functions. Mr. Jarboe joined Peabody in 2010 and has served in a variety of legal roles. Previously, Mr. Jarboe practiced law with Husch Blackwell LLP and Bryan Cave LLP. Mr. Jarboe holds a Bachelor of Arts Degree from the University of Kansas, a Master’s Degree from the University of Missouri - Kansas City and a Juris Doctor degree from Washington University School of Law.
Patrick J. Forkin III was named Chief Development Officer in July 2022 after serving as Senior Vice President - Corporate Development and Strategy since November 2017. He leads global strategy, mergers and acquisitions, portfolio management and renewable energy development. Mr. Forkin joined Peabody in 2010 and has served in a variety of roles. He has an extensive background in corporate finance, the energy industry, mergers and acquisitions and equity market research. Prior to joining Peabody, Mr. Forkin was in senior leadership roles at a U.S. solar development company and investment banking firms specializing in renewable and conventional energy. He spent the first nine years of his career at Deloitte LLP. Mr. Forkin holds a Bachelor of Science degree in Accountancy from the University of Illinois at Urbana-Champaign and is a Certified Public Accountant (inactive).
Malcolm Roberts was named Chief Marketing Officer in May 2023. He has responsibility for all Peabody sales, marketing and logistics. Mr. Roberts joined Peabody in 2021 as Executive General Manager - Sales & Marketing. He has more than 25 years of experience in the resources and commodities industry, focused on the energy and steel sector, with roles encompassing key aspects of the value chain including finance, commercial, trading and sales and marketing. During the period of October 2018 to June 2020, Mr. Roberts was a senior trading lead within the trading division of Heidelberg Cement, a company with global operations in the cement and concrete industry. His responsibilities included leading a team of traders focused on the trading of solid fuel and other cementitious products. Prior to that, Mr. Roberts spent thirteen years in sales and marketing roles with Rio Tinto primarily within their Energy Product Group, including eleven years in leadership roles covering Rio Tinto’s global coal sales, marketing, trading, logistics and analytics functions, encompassing both metallurgical and thermal coal. Prior to this, Mr. Roberts worked within sales and marketing and finance roles in both mining and manufacturing industries. Mr. Roberts holds an undergraduate degree in Commerce and Management from Lincoln University in New Zealand and is a CA member of Chartered Accountants Australia and New Zealand.
Regulatory Matters - U.S.
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant requirements mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. Peabody believes that it has obtained all permits currently required to conduct its present mining operations.
The Company endeavors to conduct its mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. The Company continually monitors the laws and regulations for changes resulting from updated legislation, judicial decisions and changes in governmental administrations.
Peabody Energy Corporation 2024 Form 10-K
Mine Safety and Health
Peabody is subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.
MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA employs various enforcement measures for noncompliance, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine.
In Part I, Item 4. “Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, the Company provides additional details on MSHA compliance.
Black Lung (Coal Workers’ Pneumoconiosis)
Black Lung Benefits. Under the U.S. Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator who was the last to employ a claimant for a cumulative year of employment, with the last day worked for the operator after July 1, 1973, must pay federal black lung benefits and medical expenses to claimants whose claims for benefits are allowed. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The federal black lung program also includes automatic survivor benefits paid upon the death of a miner with an awarded black lung claim and a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.
The trust fund has been funded by an excise tax on U.S. production. From January 1, 2022 through September 30, 2022 the excise tax rates were set at 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal. Effective October 1, 2022, the excise tax rates were set at 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal due to the enactment of the Inflation Reduction Act of 2022.
Peabody recognized expense related to the tax of $52.2 million, $57.4 million and $32.4 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Black Lung Benefits Act Self-Insurance Requirements. The Black Lung Benefits Act requires each coal mine operator to secure the payment of its potential benefits liability by either qualifying as a self-insurer or by purchasing and maintaining a commercial insurance contract. The Department of Labor’s (DOL) Office of Workers’ Compensation Programs (OWCP) is responsible for authorizing coal mine operators to self-insure and for setting the security amounts. As part of its ongoing efforts to reform the self-insurance program to ensure that operators are adequately securing their liabilities, the OWCP finalized a rule on December 12, 2024 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts.
The changed requirements for security posted to self-insure black lung liabilities could result in the Company being required to post additional security for its obligations.
Environmental Laws and Regulations
Peabody is subject to various federal, state, local and tribal environmental laws and regulations. These laws and regulations place substantial requirements on its coal mining operations and require regular inspection and monitoring of its mines and other facilities to ensure compliance. The Company is also affected by various other federal, state, local and tribal environmental laws and regulations that impact its customers.
Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSMRE), established mining, environmental protection and reclamation standards for surface mining and underground mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from OSMRE or from the respective state regulatory authority. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority, with oversight from OSMRE. States in which Peabody has active mining operations have achieved primacy control of enforcement through federal authorization. In Arizona, where Peabody performs reclamation work on tribal lands, the Company is regulated by OSMRE because the tribes do not have SMCRA authorization.
Peabody Energy Corporation 2024 Form 10-K
SMCRA provides for three categories of bonds: surety bonds, collateral bonds and self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.
The Company’s total reclamation bonding requirements in the U.S. were $893.1 million as of December 31, 2024. The bond requirements for a mine represent the calculated cost to reclaim the current operations of a mine if it ceased to operate in the current period. The cost calculation for each bond must be completed according to the regulatory authority of each state or OSMRE. The Company’s asset retirement obligations calculated in accordance with generally accepted accounting principles for its active and inactive U.S. operations were $473.3 million as of December 31, 2024. The bond requirement amount for the Company’s U.S. operations significantly exceeds the financial liability for final mine reclamation because the asset retirement obligation liability is discounted from the end of the mine’s economic life to the balance sheet date in recognition that the final reclamation cash outlay is projected to be a number of years away. The bond amount, in contrast with the asset retirement obligation, presumes reclamation begins immediately, as well as different assumptions related to the cost of equipment and services utilized in the reclamation process.
After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation bonding requirements.
In situations where the Company’s coal resources are federally owned, the U.S. Bureau of Land Management oversees a substantive exploration and leasing process. If surface land is managed by the U.S. Forest Service, that agency serves as the cooperating agency during the federal coal leasing process. Federal coal leases also require an approved federal mining permit under the signature of the Assistant Secretary of the Department of the Interior.
The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically based on changes in federal legislation. Pursuant to the Abandoned Mine Land Reclamation Amendments of 2021, which Congress enacted on November 15, 2021 as part of the Infrastructure Investment and Jobs Act, from October 1, 2021 through September 30, 2034, the fee is $0.224 and $0.096 per ton of surface-mined and underground-mine coal, respectively. The Company recognized expense related to the fees of $20.4 million, $22.2 million and $21.7 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect the Company’s U.S. coal mining operations both directly and indirectly.
National Ambient Air Quality Standards (NAAQS). The CAA requires the United States 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 µg/m3 to 9.0 µg/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 revised PM 2.5 standard has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in Kentucky v. EPA, (D.C. Cir., No. 24-1050).
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 2015 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.
Peabody Energy Corporation 2024 Form 10-K
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 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.
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.
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 in West Virginia v. EPA (D.C. Cir., No. 24-1120). 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. 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. A companion rule that addresses how states may implement CO2 emission limits for existing power plants has also been challenged in West Virginia v. EPA (D.C. Cir., No. 24-1009).
EPA’s Permitting Regulations for Major Emission Sources. Coal-fired and other fossil-fuel fired power plants (as well as industrial facilities) may also be subject to emission limits contained in required CAA permits. These limits may be imposed through the Prevention of Significant Deterioration (PSD) program for newly constructed facilities that are considered to be major sources, as well as for existing facilities that undergo major modifications. The CAA also requires such facilities to obtain a title V operating permit. In general, most permits are issued by state environmental agencies that either implement EPA permitting programs or have an EPA-approved state program.
Peabody Energy Corporation 2024 Form 10-K
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.
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, which the EPA subsequently did on December 10, 2024.
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 May 7, 2024, the EPA finalized a 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 for all coal-fired power plants. This rule was challenged in the D.C. Circuit in North Dakota v. EPA (D.C. Cir., No. 24-1119).
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, but these statutory deadlines have not been met. On March 29, 2024, the EPA published a proposed consent decree under which deadlines (for the second 10-year regional haze implementation period) 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 judgment in the U.S. District Court for the District of Columbia which was granted. On December 31, 2024, EPA proposed to revise the due date for plans (for the third regional haze implementation period) from July 31, 2028 to July 31, 2031.
New Source Review (NSR). The CAA imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification. These requirements are contained in the CAA’s PSD and Nonattainment New Source Review programs, generally referred to as NSR.
The EPA has taken action on a number of different rules and guidance affecting the interpretation and application of NSR. These rules and guidance may affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis.
Peabody Energy Corporation 2024 Form 10-K
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, but the Department of Interior revoked Order 3349 in April 2021, which mooted litigation related to Order 3349. In November 2024, the Bureau of Land Management issued amended resource management plans for lands in Wyoming and Montana, which state that no federal coal will be available for future leasing in the Powder River Basin. Montana and Wyoming challenged those decisions in a federal district court on December 11, 2024.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into jurisdictional waters. The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain permits from the Corps to place dredged or fill material in or mine through jurisdictional waters of the U.S.
States are empowered to develop and apply water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. Standards vary from state to state. Additionally, through the CWA Section 401 certification program, state and tribal regulators have approval authority over federal permits or licenses that might result in a discharge to their waters. State and tribal regulators consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.
CWA Definition of “Waters of the United States”. On January 18, 2023, the EPA and the Corps finalized a revised definition of “Waters of the United States” to clarify the scope of federal regulatory authority under the CWA. Several courts preliminarily enjoined that rule in 27 states. In addition, on May 25, 2023, the U.S. Supreme Court issued its decision in Sackett v. EPA, No. 21-454, which significantly narrowed the scope of federal regulatory authority over wetlands and non-navigable waters. The agencies finalized a rule on September 8, 2023, to conform key aspects of the regulatory definition to the Sackett decision. Pending litigation over the January 2023 definition has resumed and is ongoing, as the September 2023 final rule did not address many of the claims at issue in those cases.
CWA Water Quality Certification Rule. The EPA issued a final rule in 2020 that would have limited state and tribal regulators’ certification authority under CWA Section 401 by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances. On September 27, 2023, the EPA finalized a superseding rule that would expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. That rule took effect on November 27, 2023. Challenges to the 2023 rule remain pending in the U.S. District Court for the Western District of Louisiana.
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.
Peabody Energy Corporation 2024 Form 10-K
National Environmental Policy Act. NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. Peabody must provide information to agencies when it proposes actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality (CEQ) issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. That final rule sought to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule. On April 20, 2022, however, the CEQ published the final Phase 1 rule that partially amended the 2020 rule by restoring key provisions of the pre-2020 NEPA regulations. The CEQ proposed a Phase 2 rule on July 31, 2023 that makes broader changes to the 2020 rule, and it finalized the Phase 2 rule on May 1, 2024. Separately, the CEQ published NEPA Guidance on Consideration of Greenhouse Gas Emissions and Climate Change on January 9, 2023. The interim guidance was effective immediately, though the agency accepted comments on the guidance. CEQ expected to issue final guidance in April 2024, but it withdrew the guidance from the regulatory review process on November 19, 2024. Finally, on November 12, 2024, a divided panel of the D.C. Circuit held that the CEQ lacks authority to issue legally binding regulations implementing NEPA in Marin Audubon Society v. Federal Aviation Administration, No. 23-1067. Although the federal government and environmental groups have sought rehearing of that decision, litigants in other pending NEPA cases are citing it for the holding that CEQ regulations are not binding.
Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA. While coal combustion residuals (CCR or coal ash) are exempted from regulation as hazardous waste, there are various EPA-imposed requirements regarding CCR management.
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 postponed the expected issuance date for a final rule until December 2024 and it has not yet issued a final rule. 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.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.
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 first 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 first 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.
Use of Explosives. Peabody’s surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, it incurs costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule.
Peabody Energy Corporation 2024 Form 10-K
Federal Report on Climate Change. On November 29, 2023, the U.S. Global Change Research Program, a working group comprised of thirteen U.S. governmental departments and agencies, issued parts of the Fifth National Climate Assessment. The report addresses “projected vulnerabilities, risks and impacts associated with climate change across the United States and provides examples of response actions in many communities.” While there are no explicit regulatory actions that flow from the issuance of the report, both the legislative and executive branches of government may rely on its conclusions to shape and justify policies and actions going forward.
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.
State Climate Change Legislation. On May 30, 2024, Vermont’s S259, referred to as the Climate Superfund Act, became law and on December 26, 2024, the governor of New York signed S02129, known as the Climate Change Superfund Act (collectively, the Climate Change Laws). The Climate Change Laws aim to require payments from entities deemed “responsible parties” to fund infrastructure projects meant to address climate change in New York. The New York law defines a “responsible party” as an entity that “engaged in the trade or business of extracting fossil fuel or refining crude oil” from January 1, 2000 to December 31, 2018 and that is determined to be accountable for more than 1 billion metric tons of certain greenhouse gas emissions. Responsible party does not include any person lacking “sufficient connection with the state to satisfy the nexus” of the U.S. Constitution. The Vermont law contains a similar definition of a responsible party, except that Vermont’s covered period extends from 1995 to 2024. Both states have stated that they will enact future regulations to carry out the provisions of the law.
On December 30, 2024, the U.S. Chamber of Commerce and American Petroleum Institute filed a lawsuit in the District of Vermont challenging the state’s Climate Superfund Act arguing that the law violates constitutional principles, including federal preemption, interstate commerce and due process, while also imposing excessive fines and an unconstitutional taking.
Additionally, on February 6, 2025, a group of 22 states, led by West Virginia, filed a lawsuit against New York State over its Climate Change Superfund Act, arguing that the law’s $75 billion penalty on fossil fuel producers unfairly shifts costs onto out-of-state energy producers and consumers and violates multiple constitutional protections. The plaintiffs also claim that New York is overstepping its jurisdiction by imposing retroactive fines and discriminatory sanctions, potentially threatening U.S. energy independence.
The Company expects the Climate Change Laws will continue to be challenged. The impacts of these laws are currently being assessed.
Regulatory Matters - Australia
The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed. The Company continually monitors the laws and regulations for changes resulting from updated legislation, judicial decisions and changes in governmental administrations.
Australian Federal Government
Environmental Laws. The environmental impacts of Australian mining projects are regulated by both state and federal governments. Federal laws apply if a project is likely to significantly impact a Matter of National Environmental Significance (for example, a water resource, an endangered species or particular protected places). Such mining projects are required to obtain approval under the Commonwealth Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act).
Environmental approval processes involve complex issues that, on occasion, require lengthy studies and documentation and are subject to legal challenge.
Peabody Energy Corporation 2024 Form 10-K
There are bilateral agreements in place between the Federal Government and the Queensland and New South Wales State Governments that allow the environmental assessment process at the State level to be relied upon for a decision under the EPBC Act.
In Queensland and New South Wales, the development of a mine requires both the grant of a right to extract the resource and an approval which authorizes the environmental impact. These approvals are obtained under separate legislation for separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required.
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 prescribed 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 2023-2024, 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.
On March 27, 2023, the Australian federal government announced several additional emission reduction measures in the Safeguard Mechanism (Crediting) Amendments Bill 2023 passed by the federal Parliament on March 30, 2023. The legislation introduced a cap on overall net emissions from facilities covered by the scheme through 2030. The legislation also set a cap of net zero tonnes carbon dioxide equivalent for any financial year beginning after June 30, 2049. In addition, if the Minister for Environment and Water grants an approval under the Environment Protection and Biodiversity Conservation Act 1999 (Cth) (EPBC Act) to a new or expanded facility covered by the scheme, the Minister will be required to give an estimate of the facility's Scope 1 emissions to the Minister for Climate Change, the Climate Change Secretary and the Climate Change Authority for assessment against scheme targets. The legislation became effective on July 1, 2023.
Industrial Relations Laws. A national industrial relations system, the Fair Work Act and National Employment Standards, applies to all employers and employees. The matters regulated under the national system include general employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes. Most of the hourly workers employed in the Company’s mines are also covered by the Black Coal Mining Industry Award and company specific enterprise agreements approved under the national system.
In December 2022, the federal government passed The Fair Work Legislation Amendment (Secure Jobs, Better Pay) Act 2022, which amends the Fair Work Act. The legislation introduced several changes to workplace laws in Australia including changes to enterprise agreement making and termination; when industrial action can be taken; and access to multi-employer bargaining or single interest employer authorizations. Following this amendment, the Wambo Underground Mine and four other mines in New South Wales were served with an application for a single interest employer authorization which was granted by the Fair Work Commission against three employers including Peabody. The three employers have appealed the authorization with the hearing currently scheduled for March 2025.
On December 7, 2023, the Fair Work Legislation Amendment (Closing Loopholes) Bill 2023 was passed by the Australian Federal Parliament. The bill allows unions and/or employees to make application to the Fair Work Commission for a ‘regulated labour hire arrangement order’ that, if successful, requires employers to provide similar wages and conditions to regulated workers as those provided to permanent employees, unless the Fair Work Commission is satisfied that it is not fair and reasonable to do so. Various union applications for regulated labor hire arrangements to apply at Australian coal mining operations are currently being considered by Australia’s Fair Work Commission.
Peabody Energy Corporation 2024 Form 10-K
Native Title and Cultural Heritage Laws. Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.
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 unviable and has initiated Federal Court proceedings seeking a judicial review of the decision-making process. The first hearing is scheduled for March 4, 2025.
Australian Mine Rehabilitation (Reclamation) Laws. Mine reclamation in Australia is regulated by state-specific legislation. The Company operates in both Queensland and New South Wales state jurisdictions. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding or, in certain circumstances, make alternative financial contributions to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so. Self-bonding is not permitted. Peabody’s mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements. This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under the Company’s collateralized letter of credit program and accounts receivable securitization program.
Peabody’s reclamation bonding requirements in Australia were $303.7 million as of December 31, 2024. The bond requirements represent the states’ calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state. The cost calculation for each bond must be completed according to the regulatory authority of each state. The Company’s asset retirement obligations calculated in accordance with U.S. generally accepted accounting principles for its active and inactive Australian operations were $250.4 million as of December 31, 2024. The total bonding requirements for the Company’s Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is projected to be a number of years away, whereas the bonding amount represents the states’ calculated cost of reclamation if a mine ceases to operate immediately as well as different costs assumptions.
New South Wales Government
In New South Wales, laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines and Petroleum Sites) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulation 2021, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Biodiversity Conservation Act 2016 (BC Act), Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Land Management Act 2016, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks and Wildlife Act 1974.
NSW Environmental Laws. Under the NSW Environmental Planning and Assessment (EPA) Act 1979 applications for new planning consents or modifications to existing consents are evaluated in consideration of the likely impacts of the development, the suitability of the site, the provisions of environmental planning instruments and the public interest, amongst other matters. New applications for mining projects are generally determined by the NSW Independent Planning Commission, whereas modifications to existing consents are determined under delegation by the NSW Department of Planning, Housing and Infrastructure. Any modification to an existing planning consent must be substantially the same as the approved development, otherwise a new consent is required.
Peabody Energy Corporation 2024 Form 10-K
In December 2023, the Climate Change (Net Zero Future) Act 2023 commenced, which legislates NSW Government’s target to achieve net zero GHG emissions by 2050 and interim targets of a 50% reduction on 2005 levels by 2030 and a 70% reduction by 2035. In June 2024, the New South Wales Minister for Planning and Public Spaces requested the New South Wales Independent Planning Commission to consider the NSW Government’s emissions reduction targets and the Act’s guiding principles in its assessment of new planning applications. The NSW Environment Protection Authority (EPA) released its final NSW Guide for Large Emitters in January 2025, which applies to new applications or significant modifications for large emitting premises, such as mining operations. The NSW Guide for Large Emitters sets out the assessment requirements including a need to implement reasonable and feasible emissions reduction technologies, set long-term and interim emission goals for the project and describe any greenhouse gas offset strategies.
The Biodiversity Conservation Act 2016 (BC Act) regulates biodiversity assessment and offsetting requirements for mining projects in New South Wales. Biodiversity offsets can be provided through security of land-based offsets, purchase of offset credits through a market system, or payment into a government-administered Biodiversity Conservation Fund. In December 2024, the Biodiversity Conservation Amendment (Biodiversity Offsets Scheme) Bill 2024 passed New South Wales Parliament. This Bill legislates a transition of the biodiversity offset scheme to “net positive biodiversity outcomes”. It also requires proponents of projects to take all reasonable measures to firstly avoid, and then minimize, impacts on biodiversity values. The recent changes to the biodiversity offset laws will affect approval processes and timeframes for future NSW mining projects.
NSW Reclamation Laws. The Mining Act 1992 (Mining Act) is administered by New South Wales Resources within the Department of Primary Industries and Regional Development and the New South Wales Resources Regulator. The Mining Act authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the EPA Act and other ancillary approvals and licenses.
Through the Mining Act, environmental protection and reclamation are regulated by standard conditions in all mining leases. These conditions include requirements for the submission of reclamation outcome documents, a reclamation risk assessment and a forward program that includes a schedule of mining activities for the next three years, and a requirement that the reclamation of land disturbed by mining must occur as soon as reasonably practicable after the disturbance occurs. Mines are required to publicly report their reclamation performance on an annual basis and are subject to regular inspections by the NSW Resources Regulator.
Through the forward program process, a reclamation cost estimate is calculated annually to determine the amount of the security deposit (bond) required to cover the cost of reclamation based on the activities proposed over the forward program period.
NSW Strategic Statement on Coal Exploration and Mining. The New South Wales (NSW) Government released a Strategic Statement on Coal Exploration and Mining in June 2020 which provides a high level framework for the government's policy approach to the future of the coal sector. The NSW Government has committed to a review of the Statement this year, however no specific date has been set for commencement of the review.
NSW Coal Royalty Laws. In New South Wales, a coal royalty is charged as a percentage of the value of coal production (total revenue less allowable deductions). This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines. As part of its 2023-2024 state budget the newly elected New South Wales government announced that from July 1, 2024 it would be increasing each of these rates by 2.6% to 8.8% for deep underground mines, 9.8% for underground mines and 10.8% for open-cut mines. The future impacts of this royalty rate rise on Peabody’s NSW mining operations is being assessed.
NSW Coal Directions. The State of New South Wales (NSW) 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.
Peabody Energy Corporation 2024 Form 10-K
NSW Industrial Manslaughter Laws. On June 20, 2024, the Work Health and Safety Amendment (Industrial Manslaughter) Bill 2024 (Bill) passed the NSW Parliament. The Bill amends the Work Health and Safety Act 2011 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.
NSW Workplace Safety Laws. In New South Wales, a respirable crystalline silica workplace exposure standard of 0.05 mg/m3 applies; a respirable coal dust workplace exposure standard of 1.5 mg/m3 applies and mines must report exceedances of these standards to the NSW Resources Regulator. Additionally, the NSW government requires an exposure standard for diesel particulate matter of 0.1 mg/m3. Underground coal mine operators must also develop and implement safety management systems and procedures to minimize worker exposures to carbon dioxide, ensuring no worker is exposed to an 8-hour time-weighted average atmospheric concentration of carbon dioxide that is greater than 30,000 parts per million for short-term exposure or 12.500 parts per million otherwise.
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 NSW 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. The remaining charge was discontinued. A sentencing hearing was held in November 2024 and the judgment has been reserved. The judgment is expected in the second quarter of 2025.
Queensland Government
In Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 2008, Planning Act 2016, Coal Mining Safety and Health Act 1999, Minerals and Energy Resources (Common Provisions) Act 2014, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Biosecurity Act 2014, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959.
A guideline has been issued that provides more certainty to the industry on the circumstances in which an EPO may be issued.
Queensland Environmental and Rehabilitation (Reclamation) Laws. The EP Act is administered by the Department of the Environment, Tourism, Science and Innovation which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA. All mining operations must be carried out in a manner so as to ensure compliance with the conditions in the EA. Mines must submit an annual return reporting on their EA compliance.
In November 2016, amendments to the EP Act and the Water Act 2000 provided for regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction.
The ‘chain of responsibility’ provisions of the EP Act, which became effective in April 2016, allow the regulator to issue an environmental protection order (EPO) to a related person of a company in two circumstances: (a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later); or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company).
In November 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 which introduced an updated financial assurance (FA) framework and progressive rehabilitation requirements. The new FA framework created a pooled fund covering most mines and most of the total industry liability, plus other options for providing FA if not part of the pooled fund (for example, allowing insurance bonds or cash). The percentage rate of the total rehabilitation cost payable into the pooled fund takes into account the financial strength of the holder of the EA for the mine and the project strength of the mine. The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which does not provide for discounting.
Peabody Energy Corporation 2024 Form 10-K
The new progressive rehabilitation requirements, which commenced on November 1, 2019, require each mine to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation require regulatory approval. If there is to remain an area within the mine that does not have a post-mining land use (referred to as a non-use management area or NUMA) then each such NUMA will need to pass a public interest evaluation test as part of the approval process. An example of a NUMA is the void that remains after open-cut mining activities have been completed. Under the legislation, an existing mine was exempt from the requirement to justify its NUMAs to the extent that its existing approvals provided for such areas.
Queensland Residual Risk Laws. On August 20, 2020, the Environmental Protection and Other Legislation Amendment Act (Queensland) 2020 (EPOLA Act) became law, amending the residual risk framework that aims to ensure that any remaining risks on former resource sites are appropriately identified, costed and managed. On completion of all mining activities, the holder of the EA for the mine can apply to surrender the EA once all conditions, requirements and rehabilitation obligations have been met. When approving the surrender, the government can request a residual risk payment from the holder of the EA for the mine to cover potential rehabilitation or maintenance costs incurred after the surrender has been accepted. It contemplates two approaches for determining residual risk payments. Depending on the level of risk of a particular site, a cost calculator tool might be used or a panel of appropriately qualified experts might undertake a qualitative and quantitative risk assessment.
Queensland Mine Permitting Laws. Queensland planning policies address matters of Queensland state interest and must be adhered to during mining project approvals. The Mineral Resources Act 1989 is the principal legislation that regulates mining exploration, extraction and processing in Queensland, including coal mining. The Act was amended in 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements, and the coordination of activities and access to private and public land.
Queensland Occupational Health and Safety Laws. Queensland legislation requires Peabody to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.
In Queensland, workplace exposure standards for respirable crystalline silica require workplaces to observe an eight hour, time-weighted average airborne concentration of 0.05 mg/m3 and 1.5 mg/m3 for respirable coal dust. The workplace exposure standard for CO2 requires coal mine operators to ensure workers are not exposed to greater than 30,000 ppm for short-term exposure or 12.500 ppm otherwise.
Queensland Mine Safety Laws. On July 1, 2020, the Resources Safety and Health Queensland Act 2020 became effective. It establishes Resources Safety and Health Queensland (RSHQ) as a statutory body designed to ensure independence of the mining safety and health regulator. RSHQ includes inspectorates for coal mines, mineral mines and quarries, explosives and petroleum and gas. The new law seeks to enhance the role of advisory committees to identify, quantify and prioritize safety and health issues in the mining and quarrying industries. It also provides for an independent Work Health and Safety Prosecutor to prosecute serious offenses under resources safety legislation.
Queensland Industrial Manslaughter Laws. On May 20, 2020, the Queensland Parliament passed laws that introduced the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are senior officers and companies in the mining industry. Individuals face a maximum prison sentence of 20 years and companies can be fined up to $13 million Australian dollars. The bill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity.
Queensland Coal Royalties. On and from July 1, 2022, the Queensland government introduced three new royalty tiers for coal produced and sold from the state. The new tier rates are 20% for the portion of prices above $175 Australian dollars per tonne; 30% for the portion of prices above $225 Australian dollars per tonne; and a 40% tier for the portion of prices above $300 Australian dollars per tonne.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to GHG emissions. The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2).
Peabody Energy Corporation 2024 Form 10-K
Peabody’s Board of Directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing global climate change solutions, and the Company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal.
The Board has ultimate oversight for climate-related risk and opportunity assessments, and has delegated certain aspects of these assessments to subject matter committees of the Board. In addition, the Board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the Board of Directors and Peabody’s global workforce turns those objectives into meaningful actions.
Management believes that the Company’s external communications, including environmental regulatory filings and public notices, SEC filings, its annual Sustainability Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress towards mitigating these risks. All such communications are subject to oversight and review protocols established by Peabody’s Board and executive leadership team.
The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements.
The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the policies of financial institutions and other private companies as related to safety, sustainability, human capital and governance practices. The Company has experienced, or may in the future experience, negative effects on its results of operations due to the following specific risks as a result of such factors:
•Reduced utilization or closure of existing coal-fired electricity generating plants;
•Electricity generators switching from coal to alternative fuels, when feasible;
•Increased costs associated with regulatory compliance;
•Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;
•Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes;
•Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions;
•Disruption to operations or markets due to anti-coal activism and litigation;
•Reputational damage associated with involvement in GHG emissions; and
•Increased cost and reputational damage related to climate litigation.
With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks:
•Disruption to water supplies vital to mining operations;
•Disruption to transportation and other supply chain activities;
•Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and
•Electrical grid failures and power outages.
While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:
•Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and CCUS technologies;
•Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and
•The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.
Peabody Energy Corporation 2024 Form 10-K
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention has been paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change, and volatility in the regulatory space is likely to continue. Such developments are described below in the section “Regulations Related to Global Climate Change” within this Item 1.
The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, and ongoing actions to limit such emissions, such as carbon taxes, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.
From time to time, the Company’s Board of Directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.
Regulations Related to Global Climate Change
In the U.S., Congress has considered legislation addressing global climate issues and GHG emissions, but to date, no new comprehensive, regulatory legislation has been signed into law. The U.S. Congress, however, has approved legislation, the Inflation Reduction Act of 2022, that will provide substantial tax incentives, grants and loan guarantees for energy infrastructure, solar panels, wind turbines, nuclear and geothermal energy, hydrogen projects and carbon capture and storage. While it is possible that the U.S. will adopt additional climate legislation in the future, the timing and specific requirements of any such legislation are uncertain.
The EPA has also undertaken several steps to regulate GHG emissions under existing law, primarily the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” The EPA has indicated that it will continue these efforts and proceed with new regulations affecting GHG emissions from fossil fuel-fired electric generation, methane emissions from oil and gas production and carbon emissions from light and heavy-duty vehicles.
At the same time, a number of states in the U.S. have adopted programs to regulate GHG emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, and Pennsylvania joined in 2022. RGGI is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. California and the Canadian province of Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating.
Several other U.S. states have enacted legislation establishing GHG emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.
Peabody Energy Corporation 2024 Form 10-K
Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.
Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and the Company regularly discloses information regarding its production-related emissions in its annual Sustainability Report. The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal.
The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of GHG emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. In December 2012, Australia signed on to the second commitment period. During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reduction contributions after the second commitment period ends in 2020 (the Paris Agreement). The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global GHG emissions. On January 20, 2021, the U.S. reentered the Paris Agreement by accepting the agreement and all of its articles and clauses, after having announced its withdrawal from the agreement in November 2019.
In June 2022, the new Australian federal government announced plans to legislate for a 43% reduction in Australia’s GHG emissions by 2030 and to introduce changes by mid-2023 that will require heavy emitting companies producing more than 100,000 tonnes of carbon emissions annually to accelerate their emissions reduction activities. On September 13, 2022, the Australian government passed the Climate Change Act 2022 to set the GHG emissions reduction targets into law.
In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (legislated through the National Greenhouse and Energy Reporting Act 2007 (Cth)). Refer to the section “Regulatory Matters - Australia” within this Item 1 for discussion of the reforms.
Available Information
Peabody files or furnishes annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC. These materials are available free of charge through the Company’s website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information included on the Company’s website does not constitute part of this document. These materials may also be accessed through the SEC’s website (www.sec.gov).
In addition, copies of the Company’s filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors.
The Company operates in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company’s business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect its business.
Risks Associated with Peabody’s Operations
The Company’s profitability depends upon the prices it receives for its coal.
The Company operates in a competitive and highly regulated industry that has at times experienced strong headwinds. Current pricing levels of both seaborne and domestic coal products may not be sustainable in the future. Declines in coal prices could materially and adversely affect the Company’s operating results and profitability and the value of its coal reserves and resources.
Peabody Energy Corporation 2024 Form 10-K
Coal prices are dependent upon factors beyond the Company’s control, including:
•the demand for electricity and capacity utilization of electricity generating units (whether coal or non-coal);
•changes in the fuel consumption and dispatch patterns of electric power generators, whether based on economic or non-economic factors;
•the proximity, capacity and cost of transportation and terminal facilities;
•competition with and the availability, quality and price of coal and alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power;
•governmental regulations and taxes, including tariffs or other trade restrictions as well as those establishing air emission standards for coal-fueled power plants or mandating or subsidizing increased use of electricity from renewable energy sources;
•the strength of the global economy, including the relative exchange rates of U.S. dollars for foreign currencies;
•the unknown geopolitical consequences of current and future political and military conflicts, including between Russia and Ukraine;
•the global supply and production costs of thermal and metallurgical coal;
•the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of the Company’s metallurgical coal contracts;
•weather patterns, severe weather and natural disasters;
•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases;
•competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces; and
•technological developments, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.
Thermal coal accounted for the majority of the Company’s coal sales by volume during 2024 and 2023, with the vast majority of these sales to electric power generators. The demand for coal consumed for electric power generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear, fuel oil and alternative energy sources; (iii) utilization of all electricity generating units (whether using coal or not), including the relative cost of producing electricity from multiple fuels, including coal; (iv) stringent environmental and other governmental regulations; (v) other sociopolitical views on coal; and (vi) the coal inventories of utilities. Gas-fueled generation has displaced and could continue to displace coal-fueled generation (particularly from older, less efficient coal-fueled generation units) as current and potentially increasing regulatory costs and other factors, such as declines in the price of natural gas, impact the operating decisions of electric power generators. In addition, some electric power generators have made decisions to close coal-fueled generation units given ongoing pressure to shift away from coal generation. Many of the new power plants in the U.S. are being fueled by natural gas because gas-fired plants have been less expensive to construct and operate, permits to construct these plants are easier to obtain based on emissions profiles and electric power generators may face public and governmental pressure to generate a larger portion of their electricity from natural gas-fueled units and alternative energy sources. Increasingly stringent regulations along with stagnant electricity demand in recent years have also reduced the number of new power plants being built. In recent years, these trends have reduced demand for the Company’s coal and the related prices. Lower demand for coal consumed by electric power generators has reduced and could continue to reduce the volume of thermal coal that the Company sells and the prices that it receives for the thermal coal, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.
The Company produces metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 25% and 26% of its revenue in 2024 and 2023, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for the Company’s metallurgical coal. The demand for foreign-produced steel both in foreign markets and in the U.S. market depends in part on factors such as tariff rates on steel. The Company’s customers may be affected by imposed tariffs to the extent their imports into other countries are curtailed as a result of tariffs.
In addition, the steel industry’s demand for metallurgical coal is affected by a number of factors, including the variable nature of that industry’s business, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites and plastics. The steel industry increasingly relies on processes to make steel that do not use coal as a manufacturing input, such as electric arc furnaces. Lower demand for metallurgical coal in international markets would reduce the amount of metallurgical coal that Peabody sells and the prices that it receives for it, thereby reducing revenues and adversely impacting earnings and the value of its coal reserves. Foreign government policies related to coal production and consumption could also negatively impact pricing and demand for the Company’s products.
Peabody Energy Corporation 2024 Form 10-K
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.
Most of the Company’s sales are made under coal supply agreements, which are important to the stability and profitability of its operations. The execution of a satisfactory coal supply agreement is frequently the basis on which the Company undertakes the development of coal reserves and resources required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2024, the Company derived 27% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 16 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2024 to 2028.
Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. The Company may adjust these contract prices based on inflation or deflation, price indices and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. The Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of its expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the Company or the customer during the duration of specified events beyond the control of the affected party. Some coal supply agreements allow customers to vary the volumes of coal that they are required to purchase during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request that the Company amend the agreements to allow for such variation. Most of its coal supply agreements contain provisions requiring the Company to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow the Company’s customers to terminate their contracts in the event of changes in regulations affecting the coal industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.
On an ongoing basis, the Company discusses the extension of existing agreements or entering into new long-term agreements with various customers, but these negotiations may not be successful and these customers may not continue to purchase coal from the Company under long-term supply agreements.
The operating profits the Company realizes from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase its exposure to short-term coal price volatility. If a substantial portion of the Company’s coal supply agreements were modified or terminated, it could be materially adversely affected to the extent that it is unable to find alternate buyers for its coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, the Company cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that it will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, the Company’s revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand and oversupply, cost of competing fuels and environmental and other governmental regulations.
Peabody Energy Corporation 2024 Form 10-K
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 mining operations are subject to conditions that can impact the safety of its workforce, delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:
•elevated gas levels;
•fires and explosions, including from methane gas or coal dust;
•accidental mine water discharges;
•weather, flooding and natural disasters;
•hazardous events such as roof falls and high wall or tailings dam failures;
•seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•key equipment failures;
•supply chain constraints or unavailability of equipment or parts of the type, quantity and/or size needed to meet production expectations;
•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits and geologic conditions impacting mine sequencing;
•delays in moving its longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to its operations.
The Company maintains insurance policies that provide limited coverage for some of the risks referenced above, which may lessen the impact associated with these risks. However, there can be no assurance as to the amount or timing of recovery under its insurance policies in connection with losses associated with these risks.
The Company’s take-or-pay arrangements could unfavorably affect its profitability.
The Company has substantial take-or-pay arrangements with its port access and rail transportation providers, predominately in Australia, totaling $1.0 billion, with terms ranging up to 19 years, that commit the Company to pay a minimum amount for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow the Company to apply amounts paid for subsequent deliveries, but these provisions have limitations and the Company may not be able to apply all such amounts so paid in all cases. Also, the Company may not be able to utilize the amount of capacity for which it has previously paid. Additionally, the Company may continue to deliver coal during times when it might otherwise be optimal to suspend operations because these take-or-pay provisions effectively convert a variable cost of selling coal to a fixed operating cost.
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 value of the Company’s assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond the Company’s control, including unfavorable changes in the economic environments in which it operates; declining coal-fired electricity generation; lower-than-expected coal pricing; technical and geological operating difficulties; an inability to economically extract its coal reserves and resources; and unanticipated increases in operating costs. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on the Company’s results of operations.
Because of the volatile and cyclical nature of coal markets, it is reasonably possible that the Company’s current estimates of projected future cash flows from its mining assets may change in the near term, which may result in the need for adjustments to the carrying value of its assets.
The Company’s ability to operate effectively could be impaired if it loses key personnel or fails to attract qualified personnel.
Peabody manages its business with a number of key personnel, the loss of whom could have a material adverse effect on the Company, absent the completion of an orderly transition. In addition, the Company believes that its future success will depend greatly on its continued ability to attract and retain highly skilled and qualified personnel in tight labor markets, particularly personnel with mining experience. Peabody cannot provide assurance that key personnel will continue to be employed by the Company or that it will be able to attract and retain qualified personnel in the future. Failure to retain key personnel or attract qualified personnel could have a material adverse effect on the Company.
Peabody Energy Corporation 2024 Form 10-K
The Company could be negatively affected if it fails to maintain satisfactory labor relations.
As of December 31, 2024, the Company had approximately 5,600 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 4,300 hourly employees. The Company is party to labor agreements with various labor unions that represent certain of its employees. Such labor agreements are negotiated periodically, and, therefore, the Company is subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 40% of its hourly employees were represented by organized labor unions and generated approximately 21% of its coal production for the year ended December 31, 2024. Relations with its employees and, where applicable, organized labor are important to the Company’s success. If some or all of its current non-union operations were to become unionized, the Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if the Company fails to maintain good relations or successfully negotiate contracts with its employees who are represented by unions, the Company could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact its profitability.
The Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations.
U.S. federal and state laws and Australian laws require the Company to provide financial assurances related to requirements to reclaim lands used for mining; to pay federal and state workers’ compensation, such as black lung liabilities; to provide financial assurances for coal lease obligations; and to satisfy other miscellaneous obligations. Historically, the primary methods the Company has used to meet those obligations are to provide a third-party surety bond or a letter of credit. In recent years, the Company has also utilized deposits with regulatory authorities or cash-backed bank guarantees. As of December 31, 2024, the Company had $1,017.5 million of outstanding surety bonds; $262.3 million of letters of credit with third parties; $168.5 million of cash-backed bank guarantees; and $127.6 million of deposits with regulatory authorities in order to provide required financial assurances for post-mining reclamation, workers’ compensation and other insurance obligations, coal lease-related and other obligations and performance guarantees, in addition to collateral for sureties. Under the Company’s agreement with the providers of its surety portfolio, the Company has $394.6 million in cash held in trust accounts for the benefit of certain surety providers as of December 31, 2024.
The Company’s financial assurance obligations may increase or become more costly due to a number of factors, and surety bonds and letters of credit may not be available to the Company, particularly in light of some banks and insurance companies’ announced unwillingness to support thermal coal producers and other fossil fuel companies. Alternative forms of financial assurance such as self-bonding have been severely restricted or terminated in most of the regions where its mines reside. The Company’s failure to retain, or inability to obtain, surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, could have a material adverse effect on it. That failure could result from a variety of factors including:
•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit;
•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit; and
•lack of available fronting banks in certain countries where the Company must provide financial assurances but its primary surety providers are not licensed or admitted.
As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the Company has a surety transaction support agreement with the providers of its surety bond portfolio. The Company’s failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect its business and results of operations.
The Company’s failure to maintain adequate bonding would invalidate its mining permits and prevent mining operations from continuing, which could result in its inability to continue as a going concern.
Peabody Energy Corporation 2024 Form 10-K
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 asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. The Company’s management and engineers periodically review these estimates. If its assumptions do not materialize as expected, actual cash expenditures and costs that the Company incurs could be materially different than currently estimated. Moreover, regulatory changes could increase the Company’s obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from its assumptions, which could have a material adverse effect on its results of operations and financial condition.
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 coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:
•workplace health and safety;
•limitations on land use;
•mine permitting and licensing requirements;
•reclamation and restoration of mining properties after mining is completed;
•the storage, treatment and disposal of wastes;
•remediation of contaminated soil, sediment and groundwater;
•air quality standards;
•water pollution;
•protection of human health, plant-life and wildlife, including endangered or threatened species and habitats;
•protection of wetlands;
•the discharge of materials into the environment; and
•the effects of mining on surface water and groundwater quality and availability.
Regulatory agencies have the authority under certain circumstances following significant health and safety incidents to order a mine to be temporarily or permanently closed. In the event that such agencies ordered the closing of one of the Company’s mines, its production and sale of coal would be disrupted and it may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on the Company’s financial condition, results of operations and cash flows.
New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect the Company’s mining operations, its cost structure or its customers’ ability to use coal. New legislation, such as the “climate superfund” laws recently passed in New York and Vermont, or administrative regulations (or new interpretations by the relevant government of existing laws, regulations and approvals), including proposals related to the protection of the environment or the reduction of GHG emissions that would further regulate and tax the coal industry, may also require the Company or its customers to change operations significantly or incur increased costs. Some of the Company’s coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on the Company’s financial condition and results of operations. If the Company is determined to be subject to “climate superfund” laws and related regulations, it may be required to make significant payments to the relevant governments. These payments may be material and could adversely affect the Company’s results of operations, financial condition or cash flows.
For additional information about the various regulations affecting the Company, see the sections entitled “Regulatory Matters -U.S.” and “Regulatory Matters - Australia.”
Peabody Energy Corporation 2024 Form 10-K
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’s operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including CERCLA and RCRA in the U.S. and similar laws in other countries where the Company operates, impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.
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.
Numerous governmental permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this permitting process, when the Company applies for permits and approvals, it is required to prepare and present to governmental authorities data pertaining to the potential impact or effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals (including modifications and renewals of certain permits and approvals) and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or the performance of mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.
Additionally, the Company’s operations may be affected by sites within or near mining areas that have cultural heritage significance to indigenous peoples, and its mining permits may be rescinded or modified, or its mining plans may be voluntarily adjusted, to mitigate against adverse impacts to such sites.
The costs, liabilities and requirements associated with these permitting requirements and any related opposition may be extensive and time-consuming and may delay commencement or continuation of exploration or production which would adversely affect the Company’s coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict the Company’s ability to efficiently and economically conduct its mining activities, any of which would materially 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.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention has been paid to global climate issues and to emissions of GHGs, including emissions of CO2 from coal combustion by power plants.
The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, and ongoing actions to limit such emissions, such as carbon taxes, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement.
Peabody Energy Corporation 2024 Form 10-K
From time to time, the Company’s Board of Directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.
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.
Several non-governmental organizations have undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation in the U.S. and across the globe. In an effort to stop or delay coal mining activities, activist groups have brought lawsuits challenging the issuance of individual coal leases and challenging the federal coal leasing program more broadly. Other lawsuits challenge historical and pending regulatory approvals, permits and processes that are necessary to conduct coal mining operations or to operate coal-fueled power plants, including so-called “sue and settle” lawsuits where regulatory authorities in the past have reached private agreements with environmental activists that often involve additional regulatory restrictions or processes being implemented without formal rulemaking.
The effect of these and other similar developments has made it more costly and difficult to maintain the Company’s business. These cost increases and/or substantial or extended declines in the prices the Company receives for its coal due to these or other factors could reduce its revenue and profitability, cash flows, liquidity, and value of its coal reserves and resources, and could result in material losses.
The Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks.
The Company is subject to coal price volatility, price volatility on diesel fuel utilized in its mining operations and foreign currency exchange rate risk associated with the Australian dollar. The Company hedges certain of these risks through hedging arrangements and may continue in the future to enter into hedging arrangements, including economic hedging arrangements, to manage these risks or other exposures. Since the Company’s existing hedging arrangements do not receive cash flow hedge accounting treatment, all changes in fair value are reflected in current earnings.
The Company’s future success depends upon its ability to continue acquiring and developing coal reserves and resources that are economically recoverable.
The Company’s recoverable reserves and resources decline as it produces coal. The Company has not yet applied for the permits required or developed the mines necessary to use all of its reserves and resources. Moreover, the amount of coal reserves and resources described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Actual production, revenue and expenditures with respect to its coal reserves and resources may vary materially from estimates.
The Company’s future success depends upon it conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves and resources. The Company’s current strategy includes increasing its coal reserves and resources through acquisitions of government and other leases and producing properties and continuing to use its existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of the Company’s coal reserves and resources, potentially creating conflicting interests between it and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing the Company’s coal reserves and resources. These lessees may also seek damages from the Company based on claims that its coal mining operations impair their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2024, the Company leased a total of 44,287 acres from the federal government subject to those limitations.
Peabody Energy Corporation 2024 Form 10-K
The Company’s planned mine development projects and acquisition activities may not result in significant additional reserves and resources, and it may not have success developing additional mines. Most of its mining operations are conducted on properties owned or leased by the Company. Its right to mine some of its coal reserves and resources may be materially adversely affected if defects in title or boundaries exist. In order to conduct its mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, in order to develop its reserves and resources, the Company must also own the rights to the related surface property and receive various governmental permits. The Company cannot predict whether it will continue to receive the permits or appropriate land access necessary for it to operate profitably in the future. The Company may not be able to negotiate or secure new leases from the government or from private parties, obtain mining contracts for properties containing additional coal reserves and resources or maintain its leasehold interest in properties on which mining operations have not commenced or have not met minimum quantity or product royalty requirements. From time to time, the Company has experienced litigation with lessors of its coal properties and with royalty holders. In addition, from time to time, its permit applications and federal and state coal leases have been challenged, causing production delays.
To the extent that the Company’s existing sources of liquidity are not sufficient to fund its planned mine development projects or coal reserve and resource acquisition activities, it may require access to capital markets, which may not be available to it or, if available, may not be available on satisfactory terms. If the Company is unable to fund these activities, it may not be able to maintain or increase its existing production rates and could be forced to change its business strategy, which could have a material adverse effect on its financial condition, results of operations and cash flows.
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.
Coal is economically recoverable when the price at which the Company’s coal can be sold exceeds the costs and expenses of mining and selling the coal. The costs and expenses of mining and selling the coal are determined on a mine-by-mine basis, and as a result, the price at which its coal is economically recoverable varies based on the mine. Forecasts of the Company’s future performance are based on, among other things, estimates of its recoverable coal reserves and resources. The Company bases its reserve and resource information on engineering, economic and geological data assembled and analyzed by its staff and third parties, which includes various engineers and geologists. The Company's estimates are also subject to SEC regulations regarding classification of reserves and resources, including subpart 1300 of Regulation S-K. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and resources and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves and resources, including many factors beyond the Company’s control.
Estimates of economically recoverable coal reserves and resources necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:
•geologic and mining conditions, which may not be fully identified by available exploration data and may differ from the Company’s experience in areas it currently mines;
•demand for coal;
•current and future market prices for coal, contractual arrangements, operating costs and capital expenditures;
•severance and excise taxes, royalties and development and reclamation costs;
•future mining technology improvements;
•the effects of regulation by governmental agencies;
•the ability to obtain, maintain and renew all required permits;
•employee health and safety; and
•historical production from the area compared with production from other producing areas.
The conversion of reported mineral resources to mineral reserves should not be assumed, and the reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed. As such, actual coal tonnage recovered from identified reserve and resource areas or properties and revenue and expenditures with respect to the Company’s coal reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect its actual reserves and resources. Any material inaccuracy in the Company’s estimates related to its coal reserves and resources could result in lower than expected revenue, higher than expected costs or decreased profitability which could materially and adversely affect its business, results of operations, financial position and cash flows.
Peabody Energy Corporation 2024 Form 10-K
Joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company’s operating standards.
The Company participates in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not the Company holds majority interests or maintains operational control in its joint ventures, its partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, the Company’s; (2) seek to block actions that the Company believes are in its or the joint venture’s best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact the Company’s results of operations and its liquidity or impair its ability to recover its investments.
Where the Company’s joint ventures are jointly controlled or not managed by it, the Company may provide expertise and advice but have limited control over compliance with its operational standards. The Company also utilizes contractors across its mining platform, and may be similarly limited in its ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to those of the Company could unfavorably affect safety results, operating costs and productivity and adversely impact its results of operations and reputation.
The Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect.
The Company pays postretirement health and life insurance benefits to eligible retirees. Its total accumulated postretirement benefit obligation related to such benefits was a liability of $134.1 million as of December 31, 2024, of which $13.7 million was classified as a current liability.
These liabilities are actuarially determined. The Company uses various actuarial assumptions, including the discount rate, future cost trends, mortality tables, demographic assumptions and expected rates of return on plan assets to estimate the costs and obligations for these items. Its discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service its liabilities. A decrease in the discount rate used to determine its postretirement benefit obligations could result in an increase in the valuation of these obligations, thereby increasing the cost in subsequent fiscal years. The Company has made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Its medical trend assumption is developed by annually examining the historical trend of its cost per claim data. If the Company’s assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could differ materially from its current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase its obligation to satisfy these or additional obligations. The Company develops its actuarial determinations of liabilities using actuarial mortality tables it believes best fit its population’s actual results. In deciding which mortality tables to use, the Company periodically reviews its population’s actual mortality experience and evaluates results against its current assumptions as well as consider recent mortality tables published by the Society of Actuaries Retirement Plans Experience Committee in order to select mortality tables for use in its year end valuations. If the Company’s mortality tables do not anticipate its population’s mortality experience as accurately as expected, actual cash expenditures and costs that the Company incurs could differ materially from its current estimates.
High inflation or imposed tariffs could result in higher costs and decreased profitability.
In recent years the Company has been adversely impacted by inflation, which has increased the cost of materials, labor, equipment, freight, fuel and other cost categories. Tariffs could also increase the cost of new equipment purchases as well as parts and components to service the Company’s equipment fleet.
The Company’s efforts to recover inflation-based cost increases from its customers may be hampered as a result of the structure of its contracts and the contract bidding process as well as the competitive industries, economic conditions and countries in which the Company operates. Accordingly, substantial inflation or tariffs may result in a material adverse impact on the Company’s costs, profitability and financial results.
The Company’s business, results of operations, financial condition and prospects could be materially and adversely affected by pandemics or other widespread illnesses and the related effects on public health.
The Company’s operations are susceptible to widespread outbreaks of illness or other public health issues. Pandemic illnesses could have a material adverse effect on the Company’s business, results of operations, financial condition and prospects, including its ability to comply with restrictions and covenants under its debt and surety bonding obligations.
Peabody Energy Corporation 2024 Form 10-K
Pandemics or other widespread illnesses could result in governmental mandates requiring shutdowns of facilities for indefinite periods; serious health issues and absenteeism within the workforce; and disruptions to supply chain and distribution channels impacting both vendors and customers. As a result, the Company could face increased costs or decreased sales. Adverse changes in the general domestic and global economic conditions and disrupted domestic and international credit markets, could negatively affect its customers’ ability to pay the Company as well as its ability to access capital that could negatively affect its liquidity. Despite its efforts to manage these potential impacts, their ultimate impact would also depend on factors beyond the Company’s knowledge or control, including the duration and severity of the pandemic as well as third-party actions taken to contain its spread and mitigate its public health effects. These factors could have a material adverse effect on its business, financial condition, results of operations and prospects.
Peabody is exposed to risks associated with political or international conflicts.
Political or international conflicts can result in worldwide geopolitical and macroeconomic uncertainty, as has been the case with the ongoing conflict between Russia and Ukraine, the Israel-Hamas conflict and escalating tensions in the Middle East. The Company is unable to predict the ultimate impacts related to such conflicts. If a conflict continues for a significant time or expands to other countries, it could have adverse effects on macroeconomic conditions, including but not limited to, turbulent coal pricing and trade flow disruptions resulting from sanctions imposed on coal imports; supply chain disruptions; increased costs; and decreased business spending. Furthermore, political or international conflicts could give rise to disruptions to Peabody or its business partners’ global technology infrastructure, including through cybersecurity attack or cyber intrusion; adverse changes in international trade policies and relations; regulatory enforcement; Peabody’s ability to implement and execute its business strategy; terrorist activities; Peabody’s exposure to foreign currency fluctuations; and constraints, volatility, or disruption in the capital markets, any of which could have a material adverse effect on the Company’s business, results of operations, cash flows and financial condition.
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 has implemented security protocols and systems with the intent of maintaining the physical and cyber security of its operations and protecting the Company’s and its counterparties’ confidential information and information related to identifiable individuals against unauthorized access. Despite such efforts, the Company may be subject to security breaches which could result in unauthorized access to its facilities or the information it is trying to protect.
The Company is in an industry and business involving energy-related assets that is at a relatively greater risk of security breaches by sophisticated adversaries, such as nation state actors, as compared to other targets. The Company’s information systems and those of important third parties are vulnerable to malicious and intentional cyberattacks involving malware (such as ransomware), accidental or inadvertent incidents, the exploitation of security vulnerabilities or “bugs” in software or hardware, social engineering/phishing attacks, and malfeasance by insiders, among other scenarios. Both the frequency and magnitude of cybersecurity attacks is expected to increase, and attackers are increasingly sophisticated. As a result, Peabody may be unable to anticipate, detect or prevent future attacks at its current resource levels, particularly as the methodologies utilized by attackers change frequently or are not recognized until launched, and Peabody may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools (such as artificial intelligence and machine learning) designed to circumvent controls, avoid detection, and remove or obfuscate forensic evidence.
Unauthorized physical access to one of the Company’s facilities or electronic access to its information systems could result in, among other things, unfavorable publicity, litigation (including class action) by affected parties, regulatory investigations and enforcement, damage to sources of competitive advantage, disruptions to its operations, loss of customers, financial obligations for damages related to the theft or misuse of such information and costs to investigate and remediate such security vulnerabilities, any of which could have a substantial impact on the Company’s results of operations, financial condition or cash flows.
Peabody’s information and operational technology systems may be adversely affected by disruptions, damage, failure and risks associated with implementation and integration, including of new technologies.
Peabody could be adversely affected by system or network disruptions if new or upgraded information or operational technology systems are defective, not installed properly or not properly integrated into its operations. System modification failures could have a material adverse effect on the Company’s business, financial position and results of operations and could, if not successfully implemented, adversely impact the effectiveness of its internal control over financial reporting.
Peabody Energy Corporation 2024 Form 10-K
Further, Peabody increasingly depends on its information technology infrastructure for electronic communications among its operations, personnel, customers and suppliers around the world, including as a result of remote working and flexible working arrangements. These information technology systems, some of which are managed by third parties that the Company does not control, have been and may in the future be susceptible to damage, disruptions or shutdowns. As threats to its information technology infrastructure continue to rapidly evolve, the Company’s controls and procedures may become inadequate and the Company may be required to devote additional resources to modifying or enhancing its systems in the future.
The Company is subject to various general operating risks which may be fully or partially outside of its control.
The Company’s results of operations, financial position or cash flows could be adversely impacted by various general operating risks which may be fully or partially outside of its control. Such risks stem from internal and external sources and include:
•global economic recessions and/or credit market disruptions;
•deterioration of the creditworthiness of its customers or counterparties to financial instruments, and their ability to perform under contracts;
•inability of suppliers and other counterparties, including those related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the terms of their contracts with the Company;
•decreases in the availability or increases in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
•disruption to, or increased costs within, the transportation chain for coal, including rail, barge, trucking, overland conveyor, ports and ocean-going vessels;
•new or increased forms of taxation imposed by federal, state, provincial or local governmental authorities, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes; and
•uncertainties associated with the Company’s global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates.
Risks Related to Peabody’s Capital Structure
The Company may be able to incur more debt, including secured debt, which could increase the risks associated with its indebtedness.
As of December 31, 2024, the Company had approximately $329.3 million of unsecured indebtedness outstanding, excluding finance leases and debt issuance costs, and an additional $320.0 million in revolving commitments.
The Company may be able to incur additional indebtedness in the future, including secured debt. Although covenants under agreements governing the Company’s other indebtedness, including its revolving credit facility and finance leases, limit the Company’s ability to incur additional indebtedness, these restrictions are subject to a number of qualifications and exceptions. In addition, the agreements governing the Company’s other indebtedness do not limit the Company from incurring obligations that do not constitute indebtedness as defined therein.
The degree to which the Company is leveraged could have important consequences, including, but not limited to:
•making it more difficult for the Company to pay interest and satisfy its debt obligations;
•increasing the cost of borrowing;
•increasing the Company’s vulnerability to general adverse economic and industry or regulatory conditions;
•requiring the dedication of a substantial portion of the Company’s cash flow from operations to the payment of principal and interest on the Company’s indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, business development or other general corporate requirements;
•limiting the Company’s ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing, particularly during periods in which credit markets are weak;
•limiting the Company’s flexibility in planning for, or reacting to, changes in its business and in the coal industry;
•causing a decline in the Company’s credit ratings; and
•placing the Company at a competitive disadvantage compared to less leveraged competitors.
Peabody Energy Corporation 2024 Form 10-K
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 agreements governing the Company’s unsecured debt, revolving credit facility and surety bonding obligations contain certain restrictions and covenants, which are described below and which could adversely affect the Company’s ability to operate its business, as well as significantly affect its liquidity, and therefore could adversely affect its business, financial condition and results of operations.
These restrictions and covenants may limit, among other things, the Company’s ability to:
•incur additional indebtedness;
•pay dividends on or make distributions in respect of stock or make certain other restricted payments, such as share repurchases;
•make capital or other investments;
•enter into agreements that restrict distributions from certain subsidiaries;
•sell or otherwise dispose of assets;
•use for general purposes the cash received from certain allowable asset sales or disposals;
•enter into transactions with affiliates;
•create or incur liens;
•merge, consolidate or sell all or substantially all of its assets; and
•receive dividends or other payments from subsidiaries in certain cases.
The Company’s ability to comply with these restrictions or covenants may be affected by events beyond its control. A breach of any of these restrictions or covenants together with the expiration of any cure period, if applicable, could result in a default. If any such default occurs, subject to applicable grace periods, the holders of the Company’s indebtedness may elect to declare such indebtedness, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. In addition, the lenders under the Company’s revolving credit facility could elect to require the cash collateralization of any outstanding letters of credit. If the Company’s indebtedness is accelerated, the Company may not have sufficient cash flows and capital resources to repay such indebtedness or be able to restructure or refinance such indebtedness. Even if the Company were able to restructure its indebtedness or obtain additional capital or new or replacement financing, it may not be on commercially reasonable terms or on terms that are acceptable to the Company.
In this regard, if the Company experiences a default under the terms of its unsecured debt, revolving credit facility or surety bonding obligations for any reason, its business, financial condition and results of operations could be materially and adversely affected. In addition, complying with such terms may make it more difficult for the Company to successfully execute its business strategy, including by making it more difficult to compete against competitors who are not subject to such financial restrictions.
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.
Certain banks, other financing sources and insurance companies have taken actions to limit available financing and insurance coverage for the development of new coal-fueled power plants and coal producers and utilities that derive a majority of their revenue from coal, and particularly from thermal coal. This may adversely impact the future global demand for coal. Increasingly, the actions of such financial institutions and insurance companies are informed by non-standardized “sustainability” scores, ratings and benchmarking studies provided by various organizations that assess environmental, social and governance matters. Further, there have been efforts in recent years by members of the general financial and investment communities, including investment advisors, sovereign wealth funds, public pension funds, universities and other institutional investors, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, or that have low ratings or scores in studies and assessments of the type noted above, including coal producers. These entities also have been pressuring lenders to limit financing available to such companies.
Peabody Energy Corporation 2024 Form 10-K
These efforts may have adverse consequences, including, but not limited to:
•restricting the Company’s ability to access capital and financial markets in the future;
•reducing the demand and price for its equity securities;
•increasing the cost of borrowing;
•causing a decline in the Company’s credit ratings;
•reducing the availability, and/or increasing the cost of, third-party insurance;
•increasing the Company’s retention of risk through self-insurance;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and
•limiting the Company’s flexibility in business development activities such as mergers, acquisitions and divestitures.
Various states have enacted, or are considering enacting, laws to sanction, or require public funds to divest, from financial institutions that restrict investments in fossil fuel companies based off of extra-regulatory environmental or social factors, or to require such institutions to provide “fair access” to financial services to companies regardless of industry. While similar regulations had been developed by the federal government in the past, and could be again in the future, the previously developed federal regulations have either been suspended or repealed. As such, the final status of efforts to divest or promote the divestment from the fossil fuel extraction market is unclear, but any such efforts may adversely affect the demand for and price of the Company’s securities and impact the Company’s access to the capital and financial markets.
Additionally, in March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks and other information. To the extent this rule is finalized as proposed, the Company and/or its customers could incur increased costs related to the assessment and disclosure of climate-related information. Certain states, such as California, are also adopting or considering adopting climate change-related disclosure requirements. Enhanced climate disclosure requirements could also accelerate any trend by certain stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain carbon intensive sectors.
Risks Related to Ownership of Peabody’s Securities
The price of Peabody’s securities may be volatile.
The price of Peabody’s common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of its Common Stock regardless of its operating performance, including, among others:
•general economic conditions within the U.S. and internationally, including inflationary pressures and changes in interest rates;
•general market conditions;
•actual or anticipated fluctuations in Peabody’s quarterly and annual results and those of other public companies in its industry;
•industry cycles and trends;
•mergers and strategic alliances in the coal industry;
•changes in government regulation;
•potential or actual military conflicts or acts of terrorism;
•the failure of securities analysts to publish research about Peabody or to accurately predict the results it actually achieves;
•changes in accounting principles;
•announcements concerning Peabody or its competitors;
•the purchase and sale of shares of its Common Stock by significant shareholders;
•lack of or excess of trading liquidity;
•operational incidents; and
•investor sentiment with respect to the Company’s policies or efforts on environmental, social or governance matters.
As a result of all of these factors, investors in Peabody’s Common Stock may not be able to resell their stock at or above the price they paid or at all. Further, Peabody could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on its results of operation.
Peabody Energy Corporation 2024 Form 10-K
Peabody’s Common Stock is subject to dilution and may be subject to further dilution in the future.
Peabody’s Common Stock is subject to dilution from its convertible senior debt and its long-term incentive plan. In addition, Peabody may issue equity securities in connection with future investments, acquisitions or capital raising transactions. Such issuances or grants could constitute a significant portion of the then-outstanding Common Stock, which may result in significant dilution in ownership of Common Stock.
There may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests.
Circumstances may arise in which the interests of a significant stockholder may be in conflict with the interests of the Company’s other stakeholders. A significant stockholder may exert substantial influence over the Company to cause the Company to take action that aligns with their interests, for example, to pursue or prevent acquisitions, divestitures or other transactions, including the issuance or repurchase of additional shares or debt, that, in its judgment, could enhance its investment in Peabody or another company in which it invests. Such transactions may advance the interests of the significant stockholder and not necessarily those of other stakeholders, which might adversely affect Peabody or other holders of its Common Stock or debt instruments.
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.
In 2023, the Company’s Board of Directors approved a shareholder return framework, which includes share repurchases and cash dividends, and a share repurchase program authorizing repurchases of up to $1.0 billion of the Company’s common stock. Under the share repurchase program authorized by the Board, 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 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. The payment of future cash dividends and future repurchases will depend upon Peabody’s earnings, economic conditions, liquidity and capital requirements, and other factors, including its leverage and other financial ratios. Accordingly, the Company cannot make any assurance that future dividends will be paid or future repurchases will be made.
General Risk Factors
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.
The Company has engaged in, and may continue to engage in acquisition or divestiture activity, such as its recent conditional acquisition of Anglo’s metallurgical coal assets in Queensland’s Bowen Basin and the related divestiture of a portion of the assets to Pt Bukit Makmur Mandiri Utama (BUMA), based on its set of investment criteria to produce outcomes that increase shareholder value or provide potential strategic benefits. If the Company fails to accurately estimate the future results and value of these assets or any other acquired or divested business or assets and the related risk associated with such a transaction, or are unable to successfully integrate the businesses or assets it acquires, its business, financial condition or results of operations could be negatively affected. Moreover, any transactions the Company pursues could materially impact its liquidity and an acquisition could increase capital resource needs and may require it to incur indebtedness, seek equity capital or both. The Company may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in its assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions.
The Company may not be able to fully utilize its deferred tax assets.
The Company is subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2024, the Company had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $1,520.0 million and $140.0 million, respectively, as described further in Note 8. “Income Taxes” to the accompanying consolidated financial statements. At that date, the Company also had recorded a valuation allowance of $1,420.9 million.
The Company’s ability to use its U.S. NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. An ownership change generally occurs if certain stockholders increase their aggregate percentage ownership of a corporation’s stock by more than 50 percentage points over their lowest percentage ownership at any time during the testing period, which is generally the three-year period preceding any potential ownership change.
Peabody Energy Corporation 2024 Form 10-K
Although the Company may be able to utilize some or all of those deferred tax assets in the future if it has income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that it will be able to do so. Further, the Company is presently unable to record tax benefits on future losses in the U.S. until such time as sufficient income is generated by its operations in those jurisdictions to support the realization of the related net deferred tax asset positions. The Company’s results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.
Peabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in Peabody’s certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire it, even if doing so might be beneficial to its stockholders. Provisions of Peabody’s by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of its Common Stock and may have the effect of delaying or preventing a change in control.
Diversity in interpretation and application of accounting literature in the mining industry may impact the Company’s reported financial results.
The mining industry has limited industry-specific accounting literature and, as a result, the Company understands diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, the Company may need to restate its reported results if the resulting interpretations differ from its current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of the Company’s significant accounting policies.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
None.

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ITEM 2. PROPERTIES
Item 2. Properties.
Coal Reserves and Resources
Information concerning the Company’s mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. Subpart 1300 of Regulation S-K requires disclosure of mineral resources, in addition to mineral reserves, both in the aggregate and for each of the Company’s individually material mining properties. The Company’s coal reserves and resources are estimated by individuals deemed Qualified Persons (QP) according to the standards set forth in subpart 1300 of Regulation S-K.
Mineral resources and reserves are defined in subpart 1300 of Regulation S-K as follows:
•Mineral resource. A concentration or occurrence of material of economic interest in or on the earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.
•Mineral reserve. An estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of a QP, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.
Under subpart 1300 of Regulation S-K, mineral resources may not be classified as mineral reserves unless the determination has been made by a QP that such mineral resources can be the basis of an economically viable project. The conversion of reported mineral resources to mineral reserves should not be assumed.
Coal resources are estimated from geological models constructed from an extensive historical database of drill holes and the Company’s ongoing drilling program. Data from individual drill holes is compiled in a computerized drill-hole database, including the depth, thickness and, where core drilling is used, the quality of the coal observed. For coal deposits, the density of a drill pattern is one of the important factors which determine whether the related coal will be classified as measured, indicated, or inferred.
Mineral resource classifications are differentiated under subpart 1300 of Regulation S-K, in part, as follows:
•Measured resource. That part of a mineral resource with the highest level of geological confidence; quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit.
Peabody Energy Corporation 2024 Form 10-K
•Indicated resource. That part of a mineral resource with a level of geological confidence between that of measured and inferred resources; quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit.
•Inferred resource. That part of a mineral resource with the lowest level of geological confidence; quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability.
The geological confidence surrounding resource classification is first determined by a drill hole spacing analysis performed by a QP using geostatistical techniques. A QP may also use qualitative analysis to determine the geologic confidence based on historical experience with a specific coal deposit. Resources are further evaluated using a set of structure and quality parameters to determine the reasonable prospects for economic extraction. The structure parameters include coal thickness, depth, dipping angle, and strip ratio, among others. The quality parameters include ash and sulfur content, yield, and heat value, among others. Each coal deposit is different with respect to geology, potential mining methods, logistics, and markets. The cut-off criteria of those structure and quality parameters are different for each deposit, and a QP generally forms those criteria based upon experience with the Company’s existing mining operations or adjacent operations with similar geological conditions. Other factors, such as coal control, or surface and underground obstacles are also considered in connection with resource estimates. The reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed.
The economically mineable part of a measured coal resource is considered a proven coal reserve and has the highest degree of assurance of economic viability. The economically mineable part of indicated, and sometimes measured, coal resources are considered probable coal reserves and have a moderate degree of assurance of economic viability.
For each mine or future mine, the Company develops Life-of-Mine (LOM) plans which employ a market-driven, risk-adjusted capital allocation process to guide long-term mine planning of active operations and development projects. QPs rely on LOM planning as an integral process for coal reserve and resource estimates. The LOM plans consider dilution and losses during mining and processing as recoverability factors to estimate saleable coal. The LOM plans are developed in consideration of market demands and operational constraints. The LOM plans project, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities and sales prices. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated to determine the economically viable coal in the LOM plans. Other factors impacting the assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in market conditions and mine closure activities.
The Company periodically reviews and updates coal reserve and resource estimates to reflect the production of coal, new drill hole data, the effects of mining activities, analysis of new engineering and geological data, changes in property control, modification of mining methods and other factors.
Mineral Rights
The Company controls coal rights through direct ownership and numerous lease agreements with government or private parties. The majority of the Company’s coal reserves and resources are controlled through lease agreements with the U.S. and Australian governments. In addition, surface rights are required to conduct certain mining-related activities. The Company holds the majority of the required surface rights to meet mid- to long-term production requirements. The additional surface rights to meet long-term production requirements are expected to be acquired as needed.
Peabody Energy Corporation 2024 Form 10-K
The Company is party to numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover Peabody’s principal reserves in the Powder River Basin and other reserves and resources in Alabama, Colorado and New Mexico. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2024, the Company leased 1,610 acres of federal land in Alabama, 3,480 acres in Colorado, 282 acres in New Mexico and 38,915 acres in Wyoming, for a total of 44,287 acres nationwide subject to those limitations. The Company also leases coal-mining properties from various state governments in the U.S.
Private U.S. coal leases normally have terms of between 10 and 20 years and usually give the Company the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many private U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of private U.S. leases are normally extended by active production at or near the end of the lease term. Private U.S. leases containing undeveloped coal properties may expire or these leases may be renewed periodically.
Mining and exploration in Australia are generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or court process. Surface rights are typically acquired directly from landowners through agreement or court determination, subject to some exceptions.
Pricing
The pricing information used in support of the Company’s coal reserve and resource estimates include internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected supply and demand fundamentals for steel production and electricity generation, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress-tested against independent third-party research (not commissioned by the Company) to confirm the conclusions reached through analytical processes, and that price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review.
Below is a description of some of the specific factors that the Company evaluates in developing price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in the price forecasts and realized factors could cause actual pricing to differ from the forecasts.
Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand and economic activity, inter-fuel competition in the electric power generation mix (such as from natural gas and renewable sources), changes in capacity (additions and retirements), competition from other producers, coal stockpiles and policy and regulations. Supply considerations impacting pricing include coal reserve and resource positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (greenfield developments or extensions at existing mines).
In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production, new natural gas combined cycle generation capacity and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices.
Peabody Energy Corporation 2024 Form 10-K
Internationally, thermal coal-fueled generation also competes with alternative forms of electricity generation. The competitiveness and availability of generation fueled by natural gas, oil, nuclear, hydro, wind, solar and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others.
Metallurgical. Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions, government policies and demand for steel, and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by the coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support, and reliability of supply.
Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, as well as country-specific policies restricting or promoting domestic supply. The competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others, is also an important price consideration.
In addition to the factors noted above, the prices which may be obtained at each mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.
Peabody Energy Corporation 2024 Form 10-K
Costs
The cost estimates used to establish LOM plans are generally made according to internal processes that project future costs based on historical costs and expected trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax and other mining-related costs. Estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the Company’s operating costs include:
•Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Company geologists conduct the exploration program and provide geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control.
•Scale of operations and the equipment sizes. For surface mines, dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. Longwall operations are generally more cost-effective than room-and-pillar operations for underground mines.
•Commodity prices. For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof control represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models used to establish reserve and resource estimates.
•Target product quality. By targeting a premium quality product, mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In the Company’s LOM plans, product qualities are estimated to correspond to existing contracts and forecasted market demands.
•Transportation costs. Transportation costs vary by region. Most of the Company’s U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in U.S. thermal cost estimates. The Company’s seaborne operations typically sell coal at designated ports. The estimated costs for seaborne operations include rail and barge transportation and related fees at ports.
•Royalty costs. Royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historical costs.
•Exchange rates. Costs related to the Company’s Australian production are predominantly denominated in Australian dollars, while the Australian coal exported is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.
Summary of Coal Reserves and Resources
Peabody controlled an estimated 2.1 billion tons of coal reserves and 3.6 billion tons of coal resources as of December 31, 2024. Approximately 97% of the Company’s coal reserves and 96% of the Company’s coal resources are held under lease, and the remainder is held through fee ownership.
The following tables summarize the Company’s estimated coal reserves and resources as of December 31, 2024. The quantity of the coal resources is estimated on an in situ basis as attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as attributable to Peabody. The coal reserves and resources are reported on selected key quality parameters and on different moisture bases generally referenced by sales contracts for each mining property.
Peabody Energy Corporation 2024 Form 10-K
SUMMARY COAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2024 (1)
(Tons in millions)
Peabody
Mining Coal Proven Coal Reserves Probable Coal Reserves Total Coal Reserves Interest
Segment / Mining Complex Country State Stage Method Type Amount Quality Amount Quality Amount Quality (10)
Seaborne Thermal:(2)(4)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Wilpinjong AUS NSW P S T 43 24.5 0.5 5,927 3 32.9 0.4 5,208 46 25.0 0.5 5,880 100 %
Wambo Opencut (9)
AUS NSW P S T/C 27 11.3 0.3 6,412 2 11.1 0.3 6,434 29 11.3 0.3 6,414 50 %
Wambo Underground AUS NSW P U T/C 1 12.2 0.4 6,473 - - - - 1 12.2 0.4 6,473 100 %
South Wambo AUS NSW E U T/C - - - - 74 9.8 0.3 7,034 74 9.8 0.3 7,034 100 %
Total 71 79 150
Seaborne Metallurgical:(3)(4)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Shoal Creek USA AL P U C 13 9.6 0.7 30.4 3 9.6 0.7 30.4 16 9.6 0.7 30.4 100 %
Coppabella AUS QLD P S P 6 9.0 0.2 9.9 32 9.6 0.2 10.4 38 9.5 0.2 10.3 73.3 %
Moorvale AUS QLD P S C/P/T 6 11.1 0.3 17.0 - - - - 6 11.1 0.3 17.0 73.3 %
Metropolitan AUS NSW P U C/P/T 1 11.5 0.4 18.9 10 11.8 0.4 18.8 11 11.8 0.4 18.8 100 %
Centurion AUS QLD D U C 84 8.0 0.5 21.7 107 7.8 0.5 20.6 191 7.9 0.5 21.1 100 %
Middlemount (9)
AUS QLD P S C/P 25 10.3 0.4 18.0 10 10.3 0.4 18.0 35 10.3 0.4 18.0 50.0 %
Total 135 162 297
Powder River Basin:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
North Antelope Rochelle USA WY P S T 1,212 4.6 0.2 8,900 88 4.7 0.2 8,910 1,300 4.6 0.2 8,900 100 %
Caballo USA WY P S T 136 5.2 0.3 8,470 32 5.7 0.4 8,305 168 5.3 0.3 8,440 100 %
Rawhide USA WY P S T 78 5.7 0.3 8,285 2 5.3 0.3 8,360 80 5.7 0.3 8,290 100 %
Total 1,426 122 1,548
Other U.S. Thermal:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Bear Run USA IN P S T 51 10.3 3.1 11,070 18 9.5 2.5 11,050 69 10.1 2.9 11,065 100 %
Lee Ranch USA NM P S T 7 17.5 0.9 9,271 1 16.0 0.8 9,477 8 17.3 0.9 9,297 100 %
Gateway North USA IL P U T 19 8.8 2.9 10,919 3 8.9 2.9 10,916 22 8.9 2.9 10,917 100 %
Twentymile USA CO P U T 8 10.8 0.4 11,260 1 11.0 0.5 11,260 9 10.8 0.4 11,260 100 %
Wild Boar USA IN P S T 6 8.8 2.7 10,990 6 9.0 3.0 11,050 12 8.9 2.9 11,020 100 %
Francisco Underground USA IN P U T 1 9.4 3.2 11,490 1 9.3 3.3 11,530 2 9.4 3.3 11,510 100 %
Total 92 30 122
Grand total 1,724 393 2,117
Stage Mining Method Coal Type
P Producing S Surface Mine T Thermal
I Idle U Underground Mine C Coking
D Development P Pulverized Coal Injection
E Exploration
Peabody Energy Corporation 2024 Form 10-K
SUMMARY COAL RESOURCES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2024 (1)
(Tons in millions)
Measured and Indicated Peabody
Mining Coal Measured Coal Resources Indicated Coal Resources Coal Resources Inferred Coal Resources Interest
Deposit Country State Stage Method Type Amount Quality Amount Quality Amount Quality Amount Quality (10)
Seaborne Thermal:(2)(4)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Wilpinjong AUS NSW P S T 137 23.4 0.5 6,018 59 25.3 0.5 5,872 196 24.0 0.5 5,974 9 26.5 0.5 5,767 100 %
Wambo Opencut (9)
AUS NSW P S/U T/C 223 20.9 0.4 5,825 181 21.5 0.4 5,813 404 21.2 0.4 5,820 273 20.3 0.4 5,865 50 %
South Wambo AUS NSW E U T/C 219 21.5 0.3 6,068 83 27.2 0.3 5,571 302 23.1 0.3 5,931 47 36.3 0.3 4,745 100 %
Total 579 323 902 329
Seaborne Metallurgical:(3)(4)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Shoal Creek USA AL P U C 37 9.6 0.7 24.8 34 9.6 0.7 24.8 71 9.6 0.7 24.8 6 9.6 0.7 24.8 100 %
Metropolitan AUS NSW P U C/P/T 7 15.4 0.4 18.6 8 15.3 0.3 18.7 15 15.3 0.4 18.6 2 16.0 0.3 19.0 100 %
Coppabella AUS QLD P S P 12 15.9 0.3 13.2 39 16.0 0.3 12.6 51 16.0 0.3 12.7 50 15.7 0.3 12.6 73.3 %
Moorvale AUS QLD P S C/P/T 22 18.8 0.3 17.3 17 17.6 0.3 18.6 39 18.3 0.3 17.9 6 16.4 0.3 17.1 73.3 %
Centurion AUS QLD E U C 96 20.7 0.5 21.9 485 17.9 0.5 19.6 581 18.4 0.5 20.0 286 21.1 0.5 18.9 100 %
Coppabella North AUS QLD E U P 255 15.8 0.3 14.6 102 16.8 0.3 14.6 357 16.1 0.3 14.6 12 16.5 0.3 14.3 75.5 %
Yeerun AUS QLD E S P 16 16.0 0.4 14.3 57 16.2 0.5 15.0 73 16.2 0.4 14.8 46 17.8 0.5 14.7 83.0 %
Moorvale North AUS QLD E S P 21 26.0 0.4 12.9 25 24.5 0.5 13.2 46 25.2 0.4 13.1 25 23.2 0.5 13.4 73.3 %
Gundyer AUS QLD E U P - - - - 54 16.4 0.2 19.7 54 16.4 0.2 19.7 70 18.3 0.2 18.3 90.0 %
Total 466 821 1,287 503
Powder River Basin:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Caballo USA WY P S T 143 5.0 0.3 8,525 114 5.2 0.4 8,240 257 5.1 0.3 8,440 2 5.5 0.4 8,370 100 %
Rawhide USA WY P S T 13 5.5 0.4 8,120 95 5.2 0.3 8,355 108 5.2 0.3 8,330 7 5.8 0.4 8,235 100 %
Total 156 209 365 9
Other U.S. Thermal:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Bear Run USA IN P S T 75 14.9 3.8 10,800 81 16.6 3.7 10,485 156 15.8 3.8 10,635 25 15.7 3.5 10,645 100 %
Francisco Underground USA IN P U T 6 14.0 5.3 11,245 5 13.5 5.4 11,310 11 13.8 5.3 11,270 - - - - 100 %
Gateway North USA IL P U T 29 12.8 4.0 10,603 15 12.9 4.0 10,606 44 12.9 4.0 10,604 - - - - 100 %
Lee Ranch USA NM P S T 1 12.4 1.1 10,038 6 11.8 1.0 10,044 7 11.9 1.0 10,043 3 13.4 1.2 9,787 100 %
Wild Boar USA IN P S T - - - - 3 11.7 5.5 11,390 3 11.7 5.5 11,390 1 12.1 5.3 11,290 100 %
Total 111 110 221 29
Grand total 1,312 1,463 2,775 870
Peabody Energy Corporation 2024 Form 10-K
(1)
The sales price assumptions supporting economic recoverability vary depending upon factors such as coal quality and existing customer volume commitments. For the five-year period 2025 through 2029, the estimated sales prices for seaborne metallurgical mines are based upon estimated premium hard coking coal benchmark prices ranging from $200 to $215 per tonne. The estimated sales prices for seaborne thermal mines are based upon estimated Newcastle benchmark prices ranging from $100 to $121 per tonne for the same period. For U.S. domestic thermal mines, the estimated sales prices for the same period range from approximately $10.25 to $70.00 per ton. Subsequent to 2029, for all mines, sales price escalation is assumed at 2.0% to 3.0% per annum through the end of each LOM plan.
(2)
The moisture condition for Seaborne Thermal segment coal quality is on an air-dry basis, except for the Wambo Opencut Mine, which is estimated on an as-shipped basis for coal reserves and an in situ moisture basis for coal resources.
(3)
The moisture condition for the Seaborne Metallurgical segment coal quality is on an air-dry basis, except for the Shoal Creek Mine, which is on a dry basis.
(4)
The quantities for Australian coal reserves are estimated on an as-shipped moisture basis; quantities for Australian coal resources are estimated on an in situ moisture basis.
(5)
The quality and quantity estimates for U.S. thermal coal reserves are calculated on as-shipped moisture basis; the quality and quantity estimates for U.S. thermal coal resources are calculated on an in situ moisture basis.
(6)
Kcal/kg (kilocalories per kilogram) is the net calorific value (net heating value) of coal, except for the Wambo Opencut Mine which is estimated as gross calorific value.
(7)
VM (volatile matter) represents the proportion of certain organic and mineral components in coal, for example, water, carbon dioxide or sulfur dioxide. Volatile matter is inversely related to coal rank.
(8)
Btu (British thermal unit) is the gross heating value of coal per pound, which includes the weight of moisture in coal on an as-sold basis. The range of variability of the moisture content in coal may affect the actual shipped Btu content.
(9)
Reserve and resource data is maintained and provided by joint venture managing partners utilizing the Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves.
(10)
The quantities of coal reserves and resources are disclosed at Peabody’s proportional ownership share.
Individual Property Disclosure
To determine the Company’s individually material mining operations in accordance with subpart 1300 of Regulation S-K, management considered both quantitative and qualitative factors, assessed in the context of the Company’s overall business and financial condition. Such assessment included the Company’s aggregate mining operations on all of its mining properties, regardless of the stage of production or the type of coal produced. Quantitative factors included, among others, mining operations’ relative contributions to the Company’s aggregate historical and estimated revenue, cash flows, and Adjusted EBITDA (as defined in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”) Qualitative factors may include, as applicable, strategic priorities, the regulatory environment, capital expansion plans, and the long-term pricing outlook. The Company concluded that as of December 31, 2024, its individually material mines are North Antelope Rochelle Mine (NARM), Wilpinjong Mine and Centurion Mine. The Company will update its assessment of individually material mines on an annual basis.
The information that follows relating to such individually material mines is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (TRSs) relating to such properties prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein.
The changes for NARM and Wilpinjong from the previous years are not material, thus no updates for the TRSs are included in this filing. Reference should be made to the full text of the TRS, incorporated herein by reference, made a part of Peabody’s Annual Report on Form 10-K for the year ended December 31, 2021 and December 31, 2023 respectively, which was filed with the SEC on February 18, 2022 and February 23, 2024.
Reference should be made to the full text of the TRS for the Centurion Mine, incorporated herein by reference and made a part of Peabody’s filing on Form 8-K filed with the SEC on October 15, 2024.
Peabody Energy Corporation 2024 Form 10-K
North Antelope Rochelle Mine
The North Antelope Rochelle Mine (NARM) is a production-stage surface coal mine located sixty-five miles south of Gillette, Wyoming, USA. NARM is situated in the Gillette Coal Field on the east flank of the Powder River Basin. NARM began operations in 1999 after Peabody combined its interests in the formerly separate North Antelope Mine and Rochelle Mine.
NARM extracts coal from the Wyodak-Anderson coal seam, which ranges from 60- to 80-feet thick and lies from 100 to 400 feet below the surface in the mining area. The Company has secured mineral rights through Federal and State lease agreements which cover 30,159 acres. The typical royalty rate for Federal and State coal leases is 12.5% of realized revenue. Generally, the leases continue indefinitely with periodic renewal, provided there is diligent coal production or other development within the lease area. As of December 31, 2024, all required licenses and permits were in place for the operations of NARM.
The mining operation consists of multiple open pits in four main mining areas, which allows for quality blending and other optimization strategies. Overburden is removed by dragline, truck and shovel, dozer and cast blasting methods. Coal is hauled by truck to one of five dump locations, where it is then crushed and conveyed to silos adjacent to rail load-outs for customer delivery. Coals of varying characteristics may be blended at a central blending facility along the loadout rail loop. Coal is sold unwashed, as a run-of-mine (ROM) product. NARM coal is well recognized for domestic thermal power generation.
The key supporting infrastructure for NARM includes rail services provided by the BNSF Railway Company and Union Pacific Corporation, road access via interstate and state highways and roads, electrical power from a dedicated substation with 230kV and 69kV transmission lines, and water supply from a mine dewatering system and deep wells. The mining industry in the Powder River Basin anchors numerous communities from which the mine attracts qualified personnel.
The property, plant, equipment and mine development assets of NARM had a net book value of approximately $362 million at December 31, 2024. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls, and necessary capital replacements are generally included in the LOM plan to support future production.
Peabody Energy Corporation 2024 Form 10-K
The table below presents NARM coal reserve estimates at December 31, 2024, along with comparative quantities at December 31, 2023. NARM did not hold any coal resources as of December 31, 2024. These coal reserve estimates were supported by the analyses of 4,884 total drill holes within the coal lease area. The quantity of the coal reserves is estimated on a saleable product basis and deemed 100% attributable to Peabody. In addition to quantity, the table presents selected key quality parameters on an as-shipped basis.
NARM - SUMMARY OF COAL RESERVES (1)
(Tons in millions)
December 31, 2024 December 31, 2023
Coal Reserves (2)(3)(4)
Tons %Ash %Sulfur Btu % Mine Yield(5)
Tons
Proven 1,212 4.6 0.2 8,900 100 % 1,261
Probable 88 4.7 0.2 8,910 100 % 103
Total 1,300 1,364
Year-over-year decrease (5) %
The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
(1)
Economic recoverability is based upon an estimated average sales price per ton of $14.57 for the five-year period ending December 31, 2029 and assumed escalation of 2.0% per annum during the subsequent period through the end of the LOM plan.
(2)
The cut-off grade and metallurgical recovery are not limiting factors for coal reserve estimates due to consistent coal thickness and established trends of coal quality in the leased area. The strip ratio increases gradually, but the existing pit length allows an average mineable strip ratio. Besides the results of drill hole analyses, the main limiting factors include surface infrastructure and lease boundaries.
(3)
The quality of coal reserves is estimated on an as-shipped basis.
(4)
The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration 92% mining recovery. The results of the LOM planning process demonstrate the economic recoverability of the coal reserve estimates.
(5)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons, with processing loss considered.
Peabody Energy Corporation 2024 Form 10-K
Wilpinjong Mine
The Wilpinjong Mine is a production-stage surface thermal coal mine situated approximately 25 miles northeast of Mudgee in New South Wales, Australia. Peabody acquired the mine as part of its acquisition of Excel Coal Pty Ltd (Excel) in 2006. Excel began the development of Wilpinjong Mine in 2006 and it commenced production under Peabody ownership in 2007. A third-party contractor managed mining operations until 2013, when the Company converted the mine to owner-operated.
The Wilpinjong Mine extracts coal from the Moolarben and Ulan coal seams which have a combined thickness from 6 to 10 meters and a typical waste depth of less than 80 meters in the Illawarra Coal Measures on the northwest margin of the Sydney Basin. The Company has secured three exploration licenses of 2,958 hectares and four mining leases of 3,790 hectares through the New South Wales Minister of Planning. The typical royalty rate is 10.8% of the value of coal recovered. The mining leases require renewal upon expiration in 2027 for 2,863 hectares and in 2039-2044 for 927 hectares. Renewal applications for two exploration licenses were approved in 2023, with the terms extended to December 2027 and March 2028, and the third was granted in May 2022 for an initial term of 6 years. As of December 31, 2024, all required licenses and permits were in place for the operations of Wilpinjong.
Conventional open cut mining methods are used at the Wilpinjong Coal Mine, with multiple pits at a low strip ratio allowing for relatively rapid pit advance. Overburden is removed by a combination of cast blasting, dozer, and truck and excavator methods. Haul trucks transport coal to various hoppers and pads for blending and temporary storage, as necessary, and then to a coal handling and processing plant to be crushed and washed. Coal is conveyed to a rail loadout and transported by train to either domestic customers or to the Port of Newcastle and seaborne customers for thermal power generation.
The key supporting infrastructure for Wilpinjong Mine includes road access via public roads, port service at two terminals at the Port of Newcastle, above and below rail services, electrical power from a 66kV transmission line, and water supply from captured surface runoff and deep wells. The mine’s proximity to other large coal producers in the region provides access to a significant pool of experienced mining personnel.
The property, plant, equipment and mine development assets of Wilpinjong Mine had a net book value of approximately $266 million at December 31, 2024. The mine’s operating equipment meets contemporary mining standards and is adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production.
Peabody Energy Corporation 2024 Form 10-K
The tables below present Wilpinjong Mine’s estimated coal reserves and resources at December 31, 2024, along with comparative quantities at December 31, 2023. These coal reserve and resource estimates were supported by the analyses of 1,271 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dried basis.
WILPINJONG MINE - SUMMARY OF COAL RESERVES AND RESOURCES (1)
(Tons in millions)
December 31, 2024 December 31, 2023
Coal Reserves (5)(6)
Tons %Ash %Sulfur Kcal/kg % Mine Yield(7)
Tons
Proven 43 24.5 0.5 5,927 84 % 54
Probable 3 32.9 0.4 5,208 84 % 3
Total 46 57
Year-over-year decrease (19) %
December 31, 2024 December 31, 2023
Coal Resources (2)(3)(4)
Tons %Ash %Sulfur Kcal/kg Tons
Measured 137 23.4 0.5 6,018 103
Indicated 59 25.3 0.5 5,872 25
Measured and indicated 196 24.0 0.5 5,974 128
Inferred 9 26.5 0.5 5,767 6
Total 205 134
The year-over-year decrease in the quantity of coal reserves was driven by production depletion. The year-over-year increase in the quantity of coal resources was driven by inclusion of areas with the lease EL9399.
(1)
Economic recoverability is based upon product-specific estimated average sales prices per tonne of $61.36 for the five-year period ending December 31, 2029 and assumed escalation of 2.0% to 3.0% per annum during the subsequent period through the end of the LOM plan.
(2)
The quality of coal resources is on an in situ, air-dry basis.
(3)
The quantity of coal resource estimates is on an in situ basis, which does not take into consideration coal loss during mining and processing.
(4)
Besides the results from drill hole analyses, the raw ash is a key quality parameter that is relevant to both the cut-off grade and metallurgical recovery. The resource is limited by a maximum of 50% raw ash (air-dry basis). Due to the relatively consistent coal thickness and shallow depth, no other geological limiting factors are applied except for known geological anomalies such as paleochannels and igneous intrusion.
(5)
The quality of coal reserves is based on an air-dry basis. It is the laboratory results from the core samples with adjustments that reflect the reconciliation results from actual production.
(6)
The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration of mining and processing loss. The economic results from the LOM planning process demonstrate the economic viability of the coal reserve estimate.
(7)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
Peabody Energy Corporation 2024 Form 10-K
Centurion Mine
The Centurion Mine is an underground longwall metallurgical coal mine located 160 kilometers WSW of Mackay, Queensland, Australia. The Centurion Mine lies on the Collinsville Shelf on the western margin of the Bowen Basin in Central Queensland. White Mining Ltd developed the operation (then known as the North Goonyella Mine), including a rail loop, coal handling preparation plant (CHPP) and nearby accommodation village, following the grant of ML6949 in 1991. Peabody then acquired North Goonyella as part of an acquisition of RAG’s coal assets in April of 2004 and operated it until September of 2018, when a fire in the mine halted operations. The mine has been idled since that time while plans to re-initiate production with regulatory approval were developed.
During the third quarter of 2022, Peabody initiated the development of the mine. In October 2023, Peabody entered into an agreement with Stanmore to purchase the southern area of Wards Well (ML 1790 and ML 70495) with the intent to expand underground operations to the North of the North Goonyella Mine footprint and eventually extend into Dabin (MDL 3010). In December 2023, the mine was renamed the Centurion Mine. Development operations recommenced at the mine in June 2024, with Longwall operations scheduled to commence in early 2026.
Centurion Mine will extract coal from the Goonyella Middle seam with future plans to extend into the Goonyella Lower B2 (GLB2) seam with mining depths ranging from 210 meters to 540 meters. The Company has secured mineral rights through state mineral leases and has an approved production rate for the operation of 10.2 Mtpa ROM coal that after processing, equates to approximately 7.6 Mtpa product coal. The Centurion Mine operates on a Mining Lease issued by the State Government of Queensland. Tenement holders are bound by the Mineral Resources Act 1989 and the Mineral Resources Regulation 2013 which define the laws pertaining to coal exploration and mining in Queensland. Under the system administered by the Department of Natural Resources, Mines and Energy (DNRME), tenements are held as either EPC (Exploration Permit Coal), MDL (Mineral Development Licence) or ML (Mining Lease).
Production from the Centurion Coal Mine will be subject to the Queensland Government Royalty charged on total revenue. In addition to this standard Government royalty, there is also a special private Royalty agreement established in relation to the sale of the property by a prior owner.
The Centurion Mining Lease, ML6949, encompasses a total of 3,293 hectares. The ML allows mining and sale of coal by both underground and open cut methods. Overlapping this Mining Lease, Centurion also holds a Petroleum Lease, PL504, which enables the company to commercialize any coal seam gas (methane) that may be extracted within the lease area.
Peabody Energy Corporation 2024 Form 10-K
Centurion North is comprised of ML1790 and ML70495 (part of the Ward’s Well project which has been subdivided between Peabody and Stanmore) which encompasses surface areas of 2,723 hectares and 748 hectares, respectively. The Centurion North mine also comprises a small portion of MDL3010 (Dabin) which is owned by the West Burton Joint Venture (85% Peabody) and has a land area of 10,827 hectares.
Coal will be produced primarily using longwall systems. The mine will also use continuous miner units for longwall development and limited production. Mined coal will be processed through the on-site wash plant and conveyed to rail loadout facilities. Product coal will be loaded to train via an existing 1,000t Train Loadout Bin. The loaded trains will then travel some 217km to the Port of Hay Point where it will be bottom dumped to conveyor and onto stockpiles at Dalrymple Bay Coal Terminal (DBCT). Shipping of coal to customers will take place on an ocean-going vessel, often shared with other coal suppliers. Centurion Coking coal is a premium Hard Coking Coal (PHCC) with a mature brand name in the seaborne metallurgical marketplace and is well known in both the Atlantic and Pacific seaborne markets.
The key supporting infrastructure for Centurion Mine includes road access via highways and roads, access to both the Goonyella and Newland Rail Systems, coal export terminals at the Port of Hay Point and the Port of Abbot Point, connection to a High Voltage electricity grid that provides electricity to the existing facilities, and water supplied from the 15GL capacity Burton Gorge Dam. Centurion also has a nearby accommodation village with housing and service amenities for a capacity of 440 workers located 19km east of the mine. The mine’s workforce is drawn primarily from the townships of Moranbah, Nebo and Mackay.
The property, plant, equipment and mine development assets of Centurion Mine had a net book value of approximately $758 million at December 31, 2024. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. While the mine was idled since 2018, the Company upgraded the mine’s coal transfer and handling facilities, purchased new mining equipment and made other capital investments to improve its prospective cost structure.
Peabody Energy Corporation 2024 Form 10-K
The tables below present Centurion Mine’s estimated coal reserves and resources at December 31, 2024, along with comparative quantities at December 31, 2023. These coal reserve and resource estimates were supported by the analyses of 2,065 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves are estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dry basis.
CENTURION MINE - SUMMARY OF COAL RESERVES AND RESOURCES (1)
(Tons in millions)
December 31, 2024 December 31, 2023
Coal Reserves (2)(5)(6)
Tons %Ash %Sulfur %VM % Mine Yield(7)
Tons
Proven 84 8.0 0.5 21.7 81 % 46
Probable 107 7.8 0.5 20.6 82 % 23
Total 191 69
Year-over-year increase 177 %
December 31, 2024 December 31, 2023
Coal Resources (2)(3)(4)(5)
Tons %Ash %Sulfur VM% Tons
Measured 96 20.7 0.5 21.9 -
Indicated 485 17.9 0.5 19.6 2
Measured and indicated 581 18.4 0.5 20.0 2
Inferred 286 21.1 0.5 18.9 8
Total 867 10
The year-over-year increase in the quantity of coal reserves and resources was driven by the Wards Well acquisition in April 2024.
(1)
Economic recoverability is based upon an estimated average sales price per tonne of $210 for the LOM plan.
(2)
The quality of coal reserves and resources are estimated on an air-dry basis.
(3)
The quantity of coal resource estimates are on an in situ basis, which doesn’t take into consideration coal loss during mining and processing.
(4)
The coal resource boundary is established by considering various factors, including results from drill hole analyses, mining lease, coal control, geological features, faults and other surface features.
(5)
The cut-off grade and metallurgical recovery are not limiting factors for the coal reserve and resource estimates due to relatively consistent coal quality and float recovery from the lab results within the assessed area. The Lease boundary, surface infrastructures, and the base of weathering are the main limiting factors.
(6)
The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration of unmined coal (pillars, etc.), coal loss during mining and processing, and additional washing recovery. The results from the LOM planning process demonstrate the economic recoverability of the coal reserve estimate.
(7)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
Internal Controls
The preparation of coal reserve and resource estimates is completed in accordance with the Company’s prescribed internal control procedures, which are designed specifically to ensure the reliability of such estimates presented herein. Annually, QPs and other employees review the estimates of mineral reserves and mineral resources, the supporting documentation, and compliance with applicable internal controls. Such controls employ management systems, standardized procedures, workflow processes, multi-functional supervision and management approval, internal and external reviews, reconciliations, and data security covering record keeping, chain of custody and data storage.
The internal controls for coal reserve and resource estimates also cover exploration activities, sample preparation and analysis, data verification, processing, metallurgical testing, recovery estimation, mine design and sequencing, and coal reserve and resource evaluations, with environmental, social and regulatory considerations. The quality assurance and control protocols over the assaying of drill hole samples are performed by reputable commercial laboratories following certification and accreditation programs established by the American Society for Testing and Materials (ASTM) or Australian National Association of Testing Authorities (NATA).
Peabody Energy Corporation 2024 Form 10-K
The coal reserve and resource estimates have inherent risks due to data accuracy, uncertainty from geological interpretation, mine plan assumptions, uncontrolled rights for mineral and surface properties, environmental challenges, uncertainty for future market supply and demand, and changes in laws and regulations. Management and QPs are aware of those risks that might directly impact the assessment of coal reserves and resources. The current coal reserves and resources are estimated based on the best information available and are subject to re-assessment when conditions change. Refer to Item 1A. “Risk Factors” for discussion of risks associated with the estimates of the Company’s coal reserves and resources.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
See Note 21. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of Peabody’s pending legal proceedings, which information is incorporated herein by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
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 Annual Report on Form 10-K.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Peabody’s Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 14, 2025 there were 170 holders of the Company’s Common Stock, as determined by counting its record holders and the number of participants reflected in a security position listing provided to the Company by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of Peabody’s Common Stock on behalf of their customers, the Company does not know the actual number of unique shareholders represented by these record holders.
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. The 2023 Repurchase Program superseded and replaced the previous repurchase program that had been announced in 2017.
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 manner, timing and pricing of any share repurchase transactions will be based on a variety of factors, including market conditions, applicable legal requirements, the Company’s capital structure and alternative opportunities that the Company may have for the use or investment of capital. Through December 31, 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 year ended December 31, 2024, the Company declared dividends per share of $0.300. On February 6, 2025, the Company declared an additional dividend per share of $0.075 to be paid on March 11, 2025 to shareholders of record as of February 19, 2025.
Peabody Energy Corporation 2024 Form 10-K
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.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended December 31, 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 of Shares that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions)
October 1 through October 31, 2024
57 $ 26.32 - $ 469.6
November 1 through November 30, 2024
151 26.48 - 469.6
December 1 through December 31, 2024
- - - 469.6
Total
208 26.44 -
(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program Repurchase Program.
Stock Performance Graph
The following performance graph compares the cumulative total return on Peabody’s common stock with the cumulative total return of the S&P MidCap 400 Index and the S&P Metals and Mining Select Industry Index.
The graph assumes that the value of the investment in BTU and each index was $100 at December 31, 2019. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2024. These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved and are not intended to forecast or be indicative of possible future performance of the common stock.
Peabody Energy Corporation 2024 Form 10-K

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved.
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The Company’s discussion and analysis of the year ended December 31, 2024 compared to the year ended December 31, 2023 is included herein. For discussion and analysis of the year ended December 31, 2023 compared to the year ended December 31, 2022, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Peabody’s Annual Report on Form 10-K for the year ended December 31, 2023, which was filed with the SEC on February 23, 2024 and is incorporated by reference herein.
Non-GAAP Financial Measures
The following discussion of Peabody’s results of operations includes references to and analysis of Adjusted EBITDA and Total 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, defined as Peabody’s President and Chief Executive Officer, as the primary financial metric to measure each segment’s operating performance against expected results and to allocate resources, including capital investment in mining operations and potential expansions. Total Segment Costs is also used by management as a component of a metric to measure each segment’s operating performance.
Peabody Energy Corporation 2024 Form 10-K
Also included in the following discussion of Peabody’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 reporting segment’s 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 Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7.
Peabody believes non-GAAP 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 7 for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Overview
In 2024, Peabody produced and sold 118.1 million and 118.0 million tons of coal, respectively, from continuing operations.
As of December 31, 2024, 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 seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of its thermal and metallurgical coal sold within Australia. Generally, revenue from individual countries varies year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. The Company classifies its seaborne mines within the Seaborne Thermal or Seaborne Metallurgical segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Seaborne Thermal segment is of a metallurgical grade. Similarly, a small portion of the coal mined by the Seaborne Metallurgical segment is of a thermal grade. Additionally, the Company may market some of its metallurgical coal products as a thermal coal product from time to time depending on market conditions. Peabody’s Seaborne Thermal and Seaborne Metallurgical segments contributed approximately 70% of the Company’s total Adjusted EBITDA from its mining operations during the year ended December 31, 2024.
The Company’s Seaborne Thermal operations consist of mines in New South Wales, Australia. The mines in that segment utilize both surface and underground extraction processes to mine low-sulfur, high Btu thermal coal.
The Company’s Seaborne Metallurgical operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama, USA. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and pulverized coal injection coal.
The Company’s thermal operating segments in the U.S. are focused on the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a relatively small portion sold as international exports as conditions warrant. The Company’s Powder River Basin operations consist of its mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). The Company’s Other U.S. Thermal operations reflect the aggregation of its Illinois, Indiana, New Mexico and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, the Company’s Powder River Basin operations mine sub-bituminous coal deposits and its Other U.S. Thermal operations mine both bituminous and sub-bituminous coal deposits. Peabody’s Powder River Basin and Other U.S. Thermal segments contributed approximately 30% of the Company’s total Adjusted EBITDA from its mining operations during the year ended December 31, 2024.
The Company’s Corporate and Other segment includes selling and administrative expenses, results from equity method investments, trading and brokerage activities, minimum charges on certain transportation-related contracts, the closure of inactive mining sites, the impact of foreign currency remeasurement and certain commercial matters.
Peabody Energy Corporation 2024 Form 10-K
Resource Management. As of December 31, 2024, Peabody controlled approximately 2.1 billion tons of proven and probable coal reserves, 3.6 billion tons of coal resources and approximately 345,000 acres of surface property through ownership and lease agreements. The Company has an ongoing asset optimization program whereby its property management group regularly reviews these coal reserves, coal resources and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves, coal resources and surface lands. These surface lands include acres where Peabody has completed post-mining reclamation. In addition, the Company generates revenue through royalties from coal reserves and oil and gas rights leased to third parties, farm income from surface lands under third-party contracts and lease income from surface lands under contracts with renewable energy ventures.
Middlemount Mine. Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and low-volatile pulverized coal injection (LV PCI) coal for sale into seaborne coal markets through Abbot Point Coal Terminal, with some capacity also secured at Dalrymple Bay Coal Terminal. Mining operations first commenced at the Middlemount Mine in late 2011. During the years ended December 31, 2024 and 2023, the mine sold 1.3 million and 1.2 million tons of coal, respectively (on a 50% basis).
Summary
Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 index thermal coal, and prompt month pricing for PRB 8,800 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the year ended December 31, 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 year ended December 31, 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 year ended December 31, 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.
High Low Average December 31, 2024 February 14, 2025
Premium HCC (1)
$ 338.10 $ 180.00 $ 240.37 $ 196.50 $ 190.25
Premium PCI coal (1)
200.00 140.00 165.04 150.00 141.00
Newcastle index thermal coal (1)
150.05 116.08 135.24 119.75 101.80
API 5 index thermal coal (1)
96.66 81.77 89.23 84.00 77.51
PRB 8,800 Btu/Lb coal (2)
14.10 13.40 13.74 14.10 14.20
Illinois Basin 11,500 Btu/Lb coal (2)
44.00 40.00 41.61 43.25 43.50
(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 twelve months ended December 31, 2024 presented herein may not be indicative of their ultimate impacts.
Peabody Energy Corporation 2024 Form 10-K
Within the seaborne metallurgical coal market, coking coal prices retreated from a high base during the twelve months ended December 31, 2024. Parts of the global steel market reported tepid demand and thin profit margins during this period, restricting demand growth for metallurgical coal. In China, weakness in the property sector contributed to lower domestic steel demand and steel production in 2024 and supported increased steel exports. The increased availability of competitively priced Chinese imports has placed pressure on steel margins for steel producers in other countries. Despite this, India recorded year-over-year steel production growth supported by increased domestic demand and commissioning of new steelmaking facilities. Meanwhile, the global supply of coking coal has been generally sufficient to meet coking coal demand during the twelve months ended December 31, 2024, despite various supply disruption events such as shipping interruptions at the U.S.’s Baltimore, Maryland port. In the PCI segment, prices traded at a wide discount to coking coal early in the year, caused in part by reduced steel making productivity targets under thin margin conditions. PCI price relativities to coking coal have since improved. Overall, the market for metallurgical coal remains marginally 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 have remained relatively stable throughout the twelve months ended December 31, 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 only grown slightly, which has driven stronger coal import demand year-over-year through the twelve months ended December 31, 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 winter weather outlooks in the Northern Hemisphere, lower industrial activity, as well as volatile global natural gas markets.
In the U.S., overall electricity demand increased approximately 3% year-over-year. Through the twelve months ended December 31, 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 twelve months ended December 31, 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 modestly declined through December 31, 2024, with stockpiles less than 10 million tons below levels seen at the end of 2023. During the twelve months ended December 31, 2024, utility consumption of PRB coal has declined compared to the prior year period.
Planned Acquisition
On November 25, 2024, Peabody entered into definitive agreements with Anglo, to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia, including the Moranbah North and Grosvenor mines, the Moranbah South development project, the Capcoal complex, the Roper Creek mine and the Dawson complex (comprising the Dawson Main/Central, Dawson South, Dawson South Exploration and Theodore South exploration mines, collectively, the Dawson Assets). Following the prospective closing of the Anglo acquisition, the Company is contracted to sell the Dawson Assets to BUMA.
Peabody has secured a bridge facility commitment to finance the acquisition. The Company intends to replace the bridge facility with permanent financing, including debt capacity, additional investment by existing joint venture partners and other financing to supplement as warranted.
The acquisition is expected to close in the second quarter of 2025, subject to regulatory approvals, completion of preemptive rights processes and satisfaction of other customary closing conditions. See Note 10. “Long-term Debt” and Note 17. “Other Events” for further information.
Centurion Mine
Peabody’s development of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, continues to advance as planned. During the year ended December 31, 2024, four continuous miners units were put into production and the first development coal was produced, washed and sold. The Company is targeting the commencement of longwall production in the first quarter of 2026. Approximately $300 million of the $489 million of capital expenditures to reach longwall production had been completed as of December 31, 2024.
Other
Wards Well Acquisition. On April 16, 2024 the Company acquired 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 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.
Peabody Energy Corporation 2024 Form 10-K
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. 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 and recognized a $109.5 million insurance recovery, which the Company included in its results of operations during the year ended December 31, 2024.
Results of Operations
Year Ended December 31, 2024 Compared to Year Ended December 31, 2023
The decrease in income from continuing operations, net of income taxes for the year ended December 31, 2024 compared to the prior year ($408.7 million) was primarily driven by lower revenue ($710.0 million) due to lower seaborne coal pricing, volume decreases in the U.S. thermal segments and no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year. This unfavorable variance was partially offset by a lower income tax provision ($200.0 million) and the current year insurance recovery at the Shoal Creek Mine ($109.5 million).
Adjusted EBITDA for the year ended December 31, 2024 reflected a year-over-year decrease of $492.2 million.
Tons Sold
The following table presents tons sold by operating segment:
Increase (Decrease)
Year Ended December 31, to Volumes
2024 2023 Tons %
(Tons in millions)
Seaborne Thermal 16.4 15.5 0.9 5.8 %
Seaborne Metallurgical 7.3 6.9 0.4 5.8 %
Powder River Basin 79.6 87.2 (7.6) (8.7) %
Other U.S. Thermal 14.6 16.2 (1.6) (9.9) %
Total tons sold from operating segments 117.9 125.8 (7.9) (6.3) %
Corporate and Other 0.1 0.4 (0.3) (75.0) %
Total tons sold 118.0 126.2 (8.2) (6.5) %
Peabody Energy Corporation 2024 Form 10-K
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Year Ended December 31, (Decrease) Increase
2024 2023 $ %
Revenue per Ton (1)
Seaborne Thermal $ 73.88 $ 85.94 $ (12.06) (14.0) %
Seaborne Metallurgical 144.97 188.66 (43.69) (23.2) %
Powder River Basin 13.81 13.74 0.07 0.5 %
Other U.S. Thermal 56.38 54.77 1.61 2.9 %
Costs per Ton (1) (2)
Seaborne Thermal $ 47.71 $ 48.66 $ (0.95) (2.0) %
Seaborne Metallurgical 122.77 125.18 (2.41) (1.9) %
Powder River Basin 12.07 11.98 0.09 0.8 %
Other U.S. Thermal 46.04 41.98 4.06 9.7 %
Adjusted EBITDA Margin per Ton (1) (2)
Seaborne Thermal $ 26.17 $ 37.28 $ (11.11) (29.8) %
Seaborne Metallurgical 22.20 63.48 (41.28) (65.0) %
Powder River Basin 1.74 1.76 (0.02) (1.1) %
Other U.S. Thermal 10.34 12.79 (2.45) (19.2) %
(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:
Decrease
Year Ended December 31, to Revenue
2024 2023 $ %
(Dollars in millions)
Seaborne Thermal $ 1,213.9 $ 1,329.7 $ (115.8) (8.7) %
Seaborne Metallurgical 1,055.6 1,301.9 (246.3) (18.9) %
Powder River Basin 1,098.8 1,198.1 (99.3) (8.3) %
Other U.S. Thermal 822.6 888.2 (65.6) (7.4) %
Corporate and Other 45.8 228.8 (183.0) (80.0) %
Revenue $ 4,236.7 $ 4,946.7 $ (710.0) (14.4) %
Seaborne Thermal. The decrease in segment revenue during the year ended December 31, 2024 compared to the prior year was due to unfavorable realized prices ($228.0 million), offset by favorable volume ($112.2 million).
Seaborne Metallurgical. Segment revenue decreased during the year ended December 31, 2024 compared to the prior year due to unfavorable realized prices and volume ($356.3 million) from the Australian operations. These decreases were partially offset by favorable results from the Shoal Creek Mine ($110.0 million) due to favorable volume which offset unfavorable realized prices.
Powder River Basin. Segment revenue decreased during the year ended December 31, 2024 compared to the prior year primarily due to unfavorable volume ($100.2 million) resulting from decreased demand driven by low natural gas pricing and mild weather.
Peabody Energy Corporation 2024 Form 10-K
Other U.S. Thermal. The decrease in segment revenue during the year ended December 31, 2024 compared to the prior year was due to unfavorable volume ($49.8 million) resulting from decreased demand driven by low natural gas pricing and mild weather and unfavorable realized prices ($34.9 million), partially offset by increased revenue from sales contract cancellation settlements ($19.1 million).
Corporate and Other. Segment revenue decreased during the year ended December 31, 2024 compared to 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 ($25.9 million).
Segment Costs
The following table presents costs by reporting segment:
Increase (Decrease)
Year Ended December 31, to Total
Segment Costs
2024 2023 $ %
(Dollars in millions)
Seaborne Thermal $ 783.9 $ 752.9 $ 31.0 4.1 %
Seaborne Metallurgical 893.9 863.8 30.1 3.5 %
Powder River Basin 960.2 1,044.4 (84.2) (8.1) %
Other U.S. Thermal 671.8 680.7 (8.9) (1.3) %
Corporate and Other 64.5 11.6 52.9 456.0 %
Total Segment Costs (1)
$ 3,374.3 $ 3,353.4 $ 20.9 0.6 %
(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. The increase in segment costs during the year ended December 31, 2024 compared to the prior year was primarily driven by favorable volume (0.9 million tons) which resulted in higher sales related costs ($16.9 million) and higher variable costs for labor, repairs and outside services ($12.8 million), slightly offset by favorable commodity pricing ($8.4 million).
Seaborne Metallurgical. Segment costs increased during the year ended December 31, 2024 compared to the prior year due to increased volume from the Shoal Creek Mine ($56.1 million), higher costs at the Australian operations primarily due to production challenges ($21.3 million) and increased taxes and insurance ($11.0 million) driven by Australian carbon taxes. The increases were offset by lower sales related costs ($66.2 million) at the Australian operations due to lower sales volumes and lower pricing.
Powder River Basin. The decrease in segment costs during the year ended December 31, 2024 compared to the prior year was primarily driven by unfavorable volume (7.6 million tons) which resulted in lower sales price sensitive costs ($44.4 million) and lower variable costs for labor, repairs and outside services ($32.3 million) and favorable commodity pricing ($21.7 million). These decreases were partially offset by increased lease spend ($14.3 million).
Other U.S. Thermal. The decrease in segment costs during the year ended December 31, 2024 compared to the prior year was primarily driven by lower costs for labor, repairs and outside services due to lower sales volume (1.6 million tons).
Corporate and Other. Segment costs increased during the year ended December 31, 2024 compared to the prior year primarily due to unfavorable foreign currency rate changes.
Peabody Energy Corporation 2024 Form 10-K
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of the Company’s reporting segments:
Decrease to
Year Ended December 31, Adjusted EBITDA
2024 2023 $ %
(Dollars in millions)
Seaborne Thermal $ 430.0 $ 576.8 $ (146.8) (25.5) %
Seaborne Metallurgical 242.5 438.1 (195.6) (44.6) %
Powder River Basin 138.6 153.7 (15.1) (9.8) %
Other U.S. Thermal 150.8 207.5 (56.7) (27.3) %
Corporate and Other (90.2) (12.2) (78.0) (639.3) %
Adjusted EBITDA (1)
$ 871.7 $ 1,363.9 $ (492.2) (36.1) %
(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 decreased during the year ended December 31, 2024 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($225.2 million), partially offset by favorable volume and mix variances ($58.0 million).
Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the year ended December 31, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($294.5 million) and unfavorable operational costs ($106.3 million). These decreases were offset by favorable volume ($112.0 million), despite the lock outages during 2024, driven by increased production from the Shoal Creek Mine following the fire in the first quarter of 2023, and the Shoal Creek insurance recovery ($80.8 million).
Powder River Basin. Segment Adjusted EBITDA decreased during the year ended December 31, 2024 compared to the same period in the prior year as a result of unfavorable volume ($50.3 million) and increased lease spend ($14.3 million). These decreases were offset by lower costs for labor, repairs and outside services ($32.3 million) and favorable commodity pricing ($21.7 million).
Other U.S. Thermal. Segment Adjusted EBITDA decreased during the year ended December 31, 2024 compared to the same period in the prior year due to unfavorable volume ($63.1 million) and lower realized prices net of sales price sensitive costs ($34.5 million). These decreases were offset by increased sales contract cancellation settlements ($19.1 million) and lower costs for labor, repairs and outside services ($12.0 million).
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
Decrease
Year Ended December 31, to Income
2024 2023 $ %
(Dollars in millions)
Middlemount (1)
$ 13.1 $ 13.2 $ (0.1) (0.8) %
Resource management activities (2)
19.2 21.0 (1.8) (8.6) %
Selling and administrative expenses
(91.0) (90.7) (0.3) (0.3) %
Other items, net (3)
(31.5) 44.3 (75.8) (171.1) %
Corporate and Other Adjusted EBITDA $ (90.2) $ (12.2) $ (78.0) (639.3) %
(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 renewable energy joint ventures, 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.
Peabody Energy Corporation 2024 Form 10-K
Corporate and Other Adjusted EBITDA decreased during the year ended December 31, 2024 compared to the same period in the prior year due to the unfavorable net impact of foreign currency rate changes ($28.4 million), prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($25.9 million) and unfavorable trading results ($19.0 million).
Income From Continuing Operations, Net of Income Taxes
The following table presents income from continuing operations, net of income taxes:
(Decrease) Increase to Income
Year Ended December 31,
2024 2023 $ %
(Dollars in millions)
Adjusted EBITDA (1)
$ 871.7 $ 1,363.9 $ (492.2) (36.1) %
Depreciation, depletion and amortization
(343.0) (321.4) (21.6) (6.7) %
Asset retirement obligation expenses (48.9) (50.5) 1.6 3.2 %
Restructuring charges (4.4) (3.3) (1.1) (33.3) %
Transaction costs related to business combinations (10.3) - (10.3) n.m.
Asset impairment - (2.0) 2.0 100.0 %
Provision for NARM and Shoal Creek losses (3.7) (40.9) 37.2 91.0 %
Shoal Creek insurance recovery - property damage 28.7 - 28.7 n.m.
Changes in amortization of basis difference related to equity affiliates 1.8 1.6 0.2 12.5 %
Interest expense, net of capitalized interest (46.9) (59.8) 12.9 21.6 %
Net loss on early debt extinguishment - (8.8) 8.8 100.0 %
Interest income 71.0 76.8 (5.8) (7.6) %
Net mark-to-market adjustment on actuarially determined liabilities
6.1 0.3 5.8 1,933.3 %
Unrealized gains on derivative contracts related to forecasted sales - 159.0 (159.0) (100.0) %
Unrealized (losses) gains on foreign currency option contracts (9.0) 7.4 (16.4) (221.6) %
Take-or-pay contract-based intangible recognition 3.0 2.5 0.5 20.0 %
Income tax provision (108.8) (308.8) 200.0 64.8 %
Income from continuing operations, net of income taxes $ 407.3 $ 816.0 $ (408.7) (50.1) %
(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:
(Decrease) Increase
Year Ended December 31, to Income
2024 2023 $ %
(Dollars in millions)
Seaborne Thermal $ (121.9) $ (103.7) $ (18.2) (17.6) %
Seaborne Metallurgical (93.2) (91.5) (1.7) (1.9) %
Powder River Basin (55.3) (48.8) (6.5) (13.3) %
Other U.S. Thermal (64.8) (69.0) 4.2 6.1 %
Corporate and Other
(7.8) (8.4) 0.6 7.1 %
Total $ (343.0) $ (321.4) $ (21.6) (6.7) %
Peabody Energy Corporation 2024 Form 10-K
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:
Year Ended December 31,
2024 2023
Seaborne Thermal $ 2.14 $ 2.13
Seaborne Metallurgical 2.89 2.16
Powder River Basin 0.35 0.31
Other U.S. Thermal 1.63 1.23
Depreciation, depletion and amortization expense increased during the year ended December 31, 2024 compared to the same period in the prior year primarily due to increased depreciation resulting from asset additions and shortened mine lives. Depletion expense increased primarily as a result of increased volume from the Shoal Creek Mine. The increases in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S. Thermal segments during the year ended December 31, 2024 compared to the same period in the prior year reflect the impact of volume and mix variances across the segments.
Transaction Costs Related to Business Combinations. The charges recorded during the current year period relate to the planned acquisition of multiple metallurgical coal mines from Anglo which was announced during the fourth quarter of 2024. Refer to Note 17. “Other Events” to the accompanying consolidated financial statements for further information regarding the planned acquisition, which information is incorporated herein by reference.
Provision for NARM and Shoal Creek Losses. The provision recorded during the prior year period was for losses related to the events at the NARM and Shoal Creek Mines as discussed in Note 17. “Other Events” to the accompanying consolidated financial statements. Incremental repair costs related to the tornado damage at NARM were recorded during the year ended December 31, 2024.
Shoal Creek Insurance Recovery - Property Damage. During June 2024, the Company reached a settlement related to the Shoal Creek losses and recorded a $109.5 million insurance recovery, as discussed in Note 17. “Other Events” in the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to losses recognized at the time of the insurance recovery related to longwall development and equipment deemed inoperable within the affected area of the mine, 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 year ended December 31, 2024.
Interest Expense, Net of Capitalized Interest. The decrease in interest expense during the year ended December 31, 2024 compared to the prior year was driven by lower interest and fees for financial assurance instruments and the capitalization of interest related to the development of the Centurion Mine.
Net Loss on Early Debt Extinguishment. The net loss on early debt extinguishment recognized during the prior year was primarily related to the Company’s terminated letter of credit facility, as further discussed in Note 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to the accompanying consolidated financial statements.
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2024 was driven by the favorable impacts of changes for the postretirement benefit plans related to updated claims experience ($12.4 million) and increases to the discount rates for all actuarially determined liabilities ($5.7 million). These increases were offset by negative adjustments to Peabody’s black lung and traumatic workers’ compensation liabilities resulting from increased claims ($8.8 million) and mark-to-market losses on pension plan assets ($5.4 million).
The gain recorded during the year ended December 31, 2023 was driven by the favorable impacts of changes for the postretirement benefit plans related to updated claims experience ($5.4 million) and mark-to-market gains on pension and postretirement benefit plan assets ($3.9 million). These increases were offset by decreases to the discount rates for all actuarially determined liabilities ($6.4 million) and a negative adjustment related to Peabody’s black lung liabilities ($2.6 million).
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 discussed in Note 6. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements, all derivative contracts related to forecasted coal sales settled in 2023.
Peabody Energy Corporation 2024 Form 10-K
Unrealized (Losses) Gains on Foreign Currency Option Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
Income Tax Provision. The decrease in the income tax provision recorded during the year ended December 31, 2024 compared to the prior year period was primarily due to lower pretax income. Refer to Note 8. “Income Taxes” to the accompanying consolidated financial statements for additional information.
Net Income Attributable to Common Stockholders
The following table presents net income attributable to common stockholders:
Decrease
Year Ended December 31, to Income
2024 2023 $ %
(Dollars in millions)
Income from continuing operations, net of income taxes $ 407.3 $ 816.0 $ (408.7) (50.1) %
Loss from discontinued operations, net of income taxes (3.8) (0.4) (3.4) (850.0) %
Net income 403.5 815.6 (412.1) (50.5) %
Less: Net income attributable to noncontrolling interests 32.6 56.0 (23.4) (41.8) %
Net income attributable to common stockholders $ 370.9 $ 759.6 $ (388.7) (51.2) %
Net Income Attributable to Noncontrolling Interests. The decrease in net income attributable to noncontrolling interests during the year ended December 31, 2024 compared to the prior year period 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:
Decrease to
Year Ended December 31, EPS
2024 2023 $ %
Diluted EPS attributable to common stockholders:
Income from continuing operations $ 2.73 $ 5.00 $ (2.27) (45.4) %
Loss from discontinued operations (0.03) - (0.03) n.m.
Net income attributable to common stockholders $ 2.70 $ 5.00 $ (2.30) (46.0) %
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 141.9 million and 154.3 million for the years ended December 31, 2024 and 2023, respectively.
Peabody Energy Corporation 2024 Form 10-K
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 the segments’ operating performance, as displayed in the reconciliations below.
Year Ended December 31,
2024 2023
(Dollars in millions)
Income from continuing operations, net of income taxes $ 407.3 $ 816.0
Depreciation, depletion and amortization
343.0 321.4
Asset retirement obligation expenses 48.9 50.5
Restructuring charges 4.4 3.3
Transaction costs related to business combinations 10.3 -
Asset impairment - 2.0
Provision for NARM and Shoal Creek losses 3.7 40.9
Shoal Creek insurance recovery - property damage (28.7) -
Changes in amortization of basis difference related to equity affiliates (1.8) (1.6)
Interest expense, net of capitalized interest 46.9 59.8
Net loss on early debt extinguishment - 8.8
Interest income (71.0) (76.8)
Net mark-to-market adjustment on actuarially determined liabilities
(6.1) (0.3)
Unrealized gains on derivative contracts related to forecasted sales - (159.0)
Unrealized losses (gains) on foreign currency option contracts 9.0 (7.4)
Take-or-pay contract-based intangible recognition (3.0) (2.5)
Income tax provision 108.8 308.8
Total Adjusted EBITDA $ 871.7 $ 1,363.9
Total 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:
Year Ended December 31,
2024 2023
(Dollars in millions)
Operating costs and expenses $ 3,420.9 $ 3,385.1
Unrealized (losses) gains on foreign currency option contracts (9.0) 7.4
Take-or-pay contract-based intangible recognition 3.0 2.5
Net periodic benefit credit, excluding service cost (40.6) (41.6)
Total Segment Costs $ 3,374.3 $ 3,353.4
The following table presents Total Segment Costs by reporting segment:
Year Ended December 31,
2024 2023
(Dollars in millions)
Seaborne Thermal $ 783.9 $ 752.9
Seaborne Metallurgical 893.9 863.8
Powder River Basin 960.2 1,044.4
Other U.S. Thermal 671.8 680.7
Corporate and Other 64.5 11.6
Total Segment Costs $ 3,374.3 $ 3,353.4
Peabody Energy Corporation 2024 Form 10-K
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 Segment Costs and Adjusted EBITDA by operating segment:
Year Ended December 31, 2024
Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold 16.4 7.3 79.6 14.6
Revenue $ 1,213.9 $ 1,055.6 $ 1,098.8 $ 822.6
Total Segment Costs 783.9 893.9 960.2 671.8
Adjusted EBITDA, excluding Shoal Creek insurance recovery $ 430.0 $ 161.7 $ 138.6 $ 150.8
Shoal Creek insurance recovery - business interruption - 80.8 - -
Adjusted EBITDA $ 430.0 $ 242.5 $ 138.6 $ 150.8
Revenue per Ton $ 73.88 $ 144.97 $ 13.81 $ 56.38
Costs per Ton
47.71 122.77 12.07 46.04
Adjusted EBITDA Margin per Ton
$ 26.17 $ 22.20 $ 1.74 $ 10.34
Year Ended December 31, 2023
Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold 15.5 6.9 87.2 16.2
Revenue $ 1,329.7 $ 1,301.9 $ 1,198.1 $ 888.2
Total Segment Costs 752.9 863.8 1,044.4 680.7
Adjusted EBITDA
$ 576.8 $ 438.1 $ 153.7 $ 207.5
Revenue per Ton $ 85.94 $ 188.66 $ 13.74 $ 54.77
Costs per Ton
48.66 125.18 11.98 41.98
Adjusted EBITDA Margin per Ton
$ 37.28 $ 63.48 $ 1.76 $ 12.79
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.
Peabody Energy Corporation 2024 Form 10-K
Liquidity
As of December 31, 2024, the Company’s cash and cash equivalents balances totaled $700.4 million, including approximately $397 million held by U.S. subsidiaries, approximately $291 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 year ended December 31, 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.
The Company’s available liquidity increased to $1,072.5 million as of December 31, 2024 from $1,059.7 million as of December 31, 2023. Available liquidity was comprised of the following:
December 31,
2024 2023
(Dollars in millions)
Cash and cash equivalents $ 700.4 $ 969.3
Revolving credit facility availability 233.7 -
Accounts receivable securitization program availability 138.4 90.4
Total liquidity $ 1,072.5 $ 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 $37.6 million during the year ended December 31, 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 based upon bonding levels which 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 $495.5 million at December 31, 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 December 31, 2024.
At December 31, 2024, the Company’s maximum aggregate collateral amount was $522.0 million, which was comprised of $394.6 million in trust accounts and letters of credit of $127.4 million held for the benefit of certain surety providers. 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 December 31, 2024, letters of credit of $115.6 million were outstanding under the agreement, which were collateralized by cash of $119.1 million.
Peabody Energy Corporation 2024 Form 10-K
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 December 31, 2024, the bank guarantee facilities were backed by cash of $168.5 million.
Revolving Credit Facility
The Company established a new revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto.
The 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. On November 25, 2024, the Company amended the 2024 Credit Agreement to, among other things, permit Peabody’s planned acquisition of multiple coal mines from Anglo, the related bridge loan facility and the incurrence of additional indebtedness to finance the acquisition, to the extent applicable.
As of December 31, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $86.3 million outstanding as of December 31, 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 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees.” Availability under the 2024 Credit Agreement was $233.7 million at December 31, 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
For 2025, the Company is targeting total capital expenditures of approximately $450 million. Approximately $280 million of such amount is appropriated to major projects and growth capital expenditures, including approximately $250 million for the Company’s Centurion Mine, which includes capital expenditures to reach longwall production and capital expenditures to develop Centurion North.
Indebtedness
The Company’s total indebtedness as of December 31, 2024 and 2023 is presented in the table below.
December 31,
Debt Instrument (defined below, as applicable) 2024 2023
(Dollars in millions)
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) $ 320.0 $ 320.0
BUMA Loan Note 9.3 -
Finance lease obligations 25.1 22.3
Less: Debt issuance costs (6.3) (8.1)
348.1 334.2
Less: Current portion of long-term debt 15.8 13.5
Long-term debt $ 332.3 $ 320.7
The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at December 31, 2024, of approximately $27 million in 2025, $18 million in 2026, $13 million in 2027, $326 million in 2028, less than $1 million in 2029 and $9 million thereafter.
Peabody Energy Corporation 2024 Form 10-K
Cash paid for interest, net of capitalized interest related to the Company’s indebtedness and financial assurance instruments amounted to $37.6 million, $61.9 million and $118.5 million during the years ended December 31, 2024, 2023, and 2022, 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.
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 fourth quarter ended December 31, 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 will not be convertible during the first quarter of 2025.
Bridge Loan Facility
Concurrently with its entry into definitive agreements to acquire the Anglo assets, the Company entered into a bridge loan facility commitment letter (the Bridge Commitment Letter, and the senior secured 364-day bridge facility provided for therein, the Bridge Facility), pursuant to which the lenders, agreed to provide the Bridge Facility to the Company in the amount of up to $2.075 billion in order to finance the planned acquisition in part. The Company expects to replace the Bridge Facility with permanent financing prior to the closing date, but there can be no assurance such financing will occur and any such expectation is subject to market conditions.
To the extent borrowings are made under the Bridge Facility, any loans would bear interest at a SOFR plus an applicable margin of 8.00% or a base rate plus an applicable margin of 7.00%, at the Company’s option. Such applicable margin would increase by an additional 0.75% on the date that is 90 days following the closing date of the planned acquisition. Any borrowings under the Bridge Facility would mature 364 days from the initial funding date, which would be on or around the closing date of the planned acquisition.
The availability of borrowings under the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of this type. Any definitive financing documentation for the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of this type. Upon execution of any definitive financing documentation for the Bridge Facility, the Bridge Facility will be guaranteed by substantially all U.S. subsidiaries of the Company and secured by substantially all assets of the Company, its U.S. subsidiaries and, subject to certain conditions, certain of the Company’s Australian subsidiaries.
Accounts Receivable Securitization Program
As described in Note 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” of the accompanying 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 December 31, 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 December 31, 2024.
The accounts receivable securitization program was amended in January 2025 to extend its maturity to January 2028.
Other Requirements
The Company will incur significant future cash outflows for certain liabilities related to its prior mining activities and former employees. Such cash flows pertain to postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and end-of-mine closure costs and exploration obligations and are estimated to amount to approximately $100 million in 2025, $100 million in 2026, $150 million in 2027, $90 million in 2028, $140 million in 2029 and $1,275 million thereafter.
Peabody Energy Corporation 2024 Form 10-K
The Company has various short- and long-term take-or-pay arrangements in Australia and the U.S. associated with rail and port commitments for the delivery of coal, including amounts relating to export facilities. The estimated future cash flows associated with such arrangements are approximately $86 million in 2025, $90 million in 2026, $90 million in 2027, $90 million in 2028, $70 million in 2029 and $555 million thereafter.
The Company’s operating lease commitments, excluding potential contingent rental amounts, will require cash payments of approximately $38 million in 2025, $34 million in 2026, $29 million in 2027, $23 million in 2028, $6 million in 2029 and $3 million thereafter.
Covenant Compliance
The Company was compliant with all relevant covenants under its debt and other finance agreements at December 31, 2024.
Cash Flows
The following table summarizes the Company’s cash flows for the years ended December 31, 2024 and 2023, as reported in the accompanying consolidated financial statements.
Year Ended December 31,
2024 2023
(Dollars in millions)
Net cash provided by operating activities $ 606.5 $ 1,035.5
Net cash used in investing activities (598.1) (342.6)
Net cash used in financing activities (276.0) (460.3)
Net change in cash, cash equivalents and restricted cash (267.6) 232.6
Cash, cash equivalents and restricted cash at beginning of period 1,650.2 1,417.6
Cash, cash equivalents and restricted cash at end of period $ 1,382.6 $ 1,650.2
Operating Activities. The decrease in net cash provided by operating activities for the year ended December 31, 2024 compared to the prior year was driven by a year-over-year decrease in operating cash flow from working capital ($359.7 million), primarily attributable to changes in accounts payable and accrued expenses ($305.1 million) driven by income tax payments and accounts receivable ($66.5 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 the Shoal Creek insurance recovery excluding proceeds attributable to equipment losses ($98.6 million), decreases in cash used for collateral requirements ($348.7 million) and discontinued operations ($74.5 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 year ended December 31, 2024 compared to the prior year was driven by the acquisition of Wards Well ($143.8 million), the deposit for the planned Anglo acquisition ($75.0 million) and higher capital expenditures driven by the Centurion Mine development ($53.0 million). These variances were partially offset by the Shoal Creek insurance recovery attributable to equipment losses ($10.9 million).
Financing Activities. The decrease in net cash used in financing activities for the year ended December 31, 2024 compared to the prior year was primarily driven by decreases in common stock repurchases ($164.6 million) and distributions to noncontrolling interest ($24.2 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 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 consolidated balance sheets.
Peabody Energy Corporation 2024 Form 10-K
The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk:
December 31, 2024
Reclamation Support Other Support (1)
Total
(Dollars in millions)
Surety bonds $ 925.1 $ 92.4 $ 1,017.5
Letters of credit (2)
55.2 91.5 146.7
980.3 183.9 1,164.2
Less: Letters of credit in support of surety bonds (3)
(55.2) (0.1) (55.3)
Obligations supported, net $ 925.1 $ 183.8 $ 1,108.9
(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 $809.8 million of restricted cash and other balances serving as collateral which are included in the accompanying consolidated balance sheets at December 31, 2024, as described in Note 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” of the accompanying 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 $147.8 million during the year ended December 31, 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 December 31, 2024, the Company had total asset retirement obligations of $723.7 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 year ended December 31, 2024, primarily due to an approximate $110 million reduction in U.S. reclamation bonding requirements. At December 31, 2024, the Company’s reclamation bonding requirements were supported by approximately $700 million of restricted cash and other balances serving as collateral, which substantially supports the financial liability for final mine reclamation as calculated in accordance with U.S. GAAP.
Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to the accompanying consolidated financial statements for a discussion of the Company’s accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.
Critical Accounting Policies and Estimates
The Company’s discussion and analysis of its financial condition, results of operations, liquidity and capital resources is based upon its consolidated 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.
Peabody Energy Corporation 2024 Form 10-K
Asset Retirement Obligations. The Company’s asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws and regulations in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, escalated for inflation and then discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. If the Company’s assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could be materially different than currently estimated. Moreover, regulatory changes could increase its obligation to perform reclamation and mine closing activities. Amortization associated with the Company’s asset retirement obligation assets of $20.8 million for the year ended December 31, 2024 was included in “Depreciation, depletion and amortization” in the Company’s consolidated statements of operations. Asset retirement obligation expense, consisting of both accretion expense and changes in estimates for the Company’s inactive locations, for the year ended December 31, 2024 was $48.9 million and payments totaled $51.7 million. See Note 12. “Asset Retirement Obligations” to the accompanying consolidated financial statements for additional information regarding the Company’s asset retirement obligations.
Impairment of Long-Lived Assets. The Company evaluates its long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. The Company generally does not view short-term declines in thermal and metallurgical coal prices as an indicator of impairment for conducting impairment tests because of historic price volatility. However, the Company generally views a sustained trend of depressed coal pricing (for example, over periods exceeding one year) as a potential indicator of impairment. Because of the volatile and cyclical nature of coal prices and demand, it is reasonably possible that coal prices may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in the Company’s operating costs, may result in the need for future adjustments to the carrying value of its long-lived mining assets and mining-related investments.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For its active mining operations, the Company generally groups such assets at the mine level, or the mining complex level for mines that share infrastructure. For its development and exploration properties and portfolio of surface land and coal reserve and resource holdings, the Company considers several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of a sale to a third party.
When indicators of impairment are present, the Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows in the LOM plan expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for the Company’s individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves and resources, surface lands and undeveloped coal properties excluded from its long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company’s long-lived mining assets are derived from those developed in connection with its planning and budgeting process. The Company believes its assumptions to be consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying its projections and fair value estimates include those surrounding future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves and resources, surface lands and undeveloped coal properties excluded from the Company’s long-range mine planning (which generally constitute Level 2 inputs under the fair value hierarchy).
No impairment charges related to long-lived assets were recorded for the year ended December 31, 2024. When necessary, the assumptions used are based on the Company’s best knowledge at the time it prepares its analysis but can vary significantly due to the volatile and cyclical nature of coal prices and demand, regulatory issues, unforeseen mining conditions, commodity prices and cost of labor. These factors may cause the Company to be unable to recover all or a portion of the carrying value of its long-lived assets.
Peabody Energy Corporation 2024 Form 10-K
The Company identified certain assets with an aggregate carrying value of approximately $208 million at December 31, 2024 in its Other U.S. Thermal segment whose recoverability is most sensitive to customer concentration risk.
See Note 3. “Asset Impairment” to the accompanying consolidated financial statements for additional information regarding impairment charges.
Income Taxes. The Company recognizes deferred tax assets and liabilities for the temporary difference between the consolidated financial carrying amounts of existing assets and liabilities and their respective tax bases and consideration of operating loss and tax credit carryforwards. Deferred income taxes are measured using enacted rates in effect for the year in which temporary differences are expected to be recovered or settled. The impact on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are provided to reduce deferred tax assets to the amount that will be more likely than not realized. The Company makes judgments and estimates regarding the amount and timing of the reversal of taxable temporary differences, the impact of tax planning strategies and expected future taxable income.
Uncertainty exists regarding tax positions taken in previously filed tax returns which remain subject to examination, along with positions expected to be taken in future returns. The Company recognizes the tax benefit from uncertain tax positions when it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. Adjustments are made to the uncertain tax positions when facts and circumstances change, such as the closing of a tax audit; change in applicable tax laws, including tax case rulings and legislative guidance; or expiration of the applicable statute of limitations.
See Note 8. “Income Taxes” to the accompanying consolidated financial statements for additional information regarding valuation allowances and unrecognized tax benefits.
Contingent liabilities. From time to time, Peabody is subject to legal and environmental matters related to its continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, the Company is required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses.
A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. Peabody accrues for legal and environmental matters within “Operating costs and expenses” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. If a range of possible loss exists and no anticipated loss within the range is more likely than any other anticipated loss, the Company records the accrual at the low end of the range, in accordance with Accounting Standards Codification 450, “Contingencies.”
Peabody provides disclosure surrounding loss contingencies when it believes that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs.
Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the Company’s consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense as incurred. The Company includes the interest component of any litigation-related penalties within “Interest expense” in its consolidated statements of operations. See Note 21. “Commitments and Contingencies” to the accompanying consolidated financial statements for further discussion of the Company’s contingent liabilities.
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The potential for changes in the market value of the Company’s coal and freight-related trading, crude oil, diesel fuel and foreign currency contract portfolios, as applicable, and exposure to interest rate changes is referred to as “market risk.” The Company attempts to manage market price risks through diversification, controlling position sizes and executing hedging strategies. Due to a lack of quoted market prices and the long-term, illiquid nature of the positions, the Company has not quantified market price risk related to its non-trading, long-term coal supply agreement portfolio.
Peabody Energy Corporation 2024 Form 10-K
Coal Trading Activities and Related Commodity Price Risk
Peabody engages in direct and brokered trading of physical coal and freight-related commodities in over-the-counter (OTC) markets. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. Peabody actively measures, monitors, manages and hedges market price risk due to current and anticipated trading activities to remain within risk limits prescribed by management. Peabody also uses its coal trading and brokerage platform to support various coal production-related activities. These transactions may involve coal to be produced from its mines, coal sourcing arrangements with third-party mining companies, joint venture positions with producers or offtake agreements with producers. While the support activities (such as the forward sale of coal to be produced and/or purchased) may ultimately involve instruments sensitive to market price risk, the sourcing of coal in these arrangements does not involve market risk sensitive instruments.
Peabody also monitors other types of risk associated with its coal trading activities, including credit, market liquidity and counterparty nonperformance.
Credit and Nonperformance Risk
The fair values of Peabody’s derivative instruments utilized for corporate hedging and coal trading activities reflect adjustments for credit risk, as necessary. The Company’s exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. Its policy is to independently evaluate each counterparty’s creditworthiness prior to entering into transactions and to regularly monitor exposures. Peabody manages its counterparty risk from its hedging activities related to foreign currency and fuel exposures, as applicable, through established credit standards, diversification of counterparties, utilization of investment grade commercial banks, adherence to established tenor limits based on counterparty creditworthiness and continual monitoring of that creditworthiness. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), Peabody has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for Peabody’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, Peabody seeks to enter into netting agreements with counterparties that permit it to offset asset and liability positions with such counterparties and, to the extent required, Peabody will post or receive margin amounts associated with exchange-cleared and certain OTC positions. Peabody also continually monitors counterparty and contract nonperformance risk, if present, on a case-by-case basis.
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 consolidated financial statements. As of December 31, 2024, the Company held average rate options with an aggregate notional amount of $388.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar operating expenditures over the nine-month period ending September 30, 2025. As of December 31, 2024, the Company also held purchased collars with an aggregate notional amount of $528.0 million Australian dollars related to anticipated Australian dollar operating expenditures during the nine-month period ending September 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 $195 to $205 million for the next twelve months. Based upon the Australian dollar/U.S. dollar exchange rate at December 31, 2024, the currency option contracts outstanding at that date would limit the Company’s exposure to approximately $194 million with respect to a $0.10 increase in the exchange rate, while the Company would benefit by approximately $154 million with respect to a $0.10 decrease in the exchange rate for the next twelve months.
Although Peabody believes its Australian dollar monetary asset position acts as a hedge to offset 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.
Peabody Energy Corporation 2024 Form 10-K
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. Sales under such agreements comprised approximately 90%, 92% and 85% of its worldwide sales from its mining operations (by volume) for the years ended December 31, 2024, 2023 and 2022, respectively. As of December 31, 2024, the Company had approximately 85 million tons of U.S. thermal coal priced and committed for 2025. This includes approximately 71 million tons of PRB coal and 14 million tons of other U.S. thermal coal. The Company has the flexibility to increase volumes should demand warrant. Peabody is estimating full year 2025 thermal coal sales volumes from its Seaborne Thermal segment of 14.2 million to 15.2 million tons comprised of thermal export volume of 8.8 million to 9.8 million tons and domestic volume of 5.4 million tons. Peabody is estimating full year 2025 metallurgical coal sales from its Seaborne Metallurgical segment of 8.0 million to 9.0 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 December 31, 2024, the Company had no coal derivative contracts related to its forecasted sales. Historically, such financial contracts have included futures and forwards.
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 $22 million based on its expected usage.
As of December 31, 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 contracts 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 December 31, 2024, a one percentage point decrease in interest rates would result in a decrease of approximately $14 million to interest income for the next twelve months.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
See Part IV, Item 15. “Exhibits and Financial Statement Schedules” of this report for the information required by this Item 8, which information is incorporated by reference herein.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Peabody’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 the principal executive officer and principal accounting officer, on a timely basis. As of December 31, 2024, the end of the period covered by this Annual Report on Form 10-K, the Company carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures. Based upon that evaluation, Peabody’s Chief Executive Officer and Chief Financial Officer have concluded that such disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of December 31, 2024 were effective to provide reasonable assurance that the desired control objectives were achieved.
Peabody Energy Corporation 2024 Form 10-K
Changes in Internal Control Over Financial Reporting
Peabody periodically reviews its internal control over financial reporting as part of its efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, Peabody routinely reviews its system of internal control over financial reporting to identify potential changes to its processes and systems that may improve controls and increase efficiency, while ensuring that the Company maintains an effective internal control environment. Changes may include such activities as implementing new systems; consolidating the activities of acquired business units; migrating certain processes to its shared services organizations and/or managed third parties; formalizing and refining policies, procedures and control documentation requirements; improving segregation of duties and adding monitoring controls. In addition, when Peabody acquires new businesses, it incorporate its controls and procedures into the acquired business as part of its integration activities.
There have been no changes in Peabody’s internal control over financial reporting that occurred during the three months ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. An evaluation of the effectiveness of the design and operation of the Company’s internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, as of the end of the period covered by this report was performed under the supervision and with the participation of management, including its Chief Executive Officer and Chief Financial Officer. This evaluation is performed to determine if the Company’s internal controls over financial reporting provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2024.
Peabody’s independent registered public accounting firm, Ernst & Young LLP, has audited the consolidated financial statements included in this annual report and issued an attestation report on Peabody’s internal control over financial reporting, as included herein.
/s/ James C. Grech /s/ Mark A. Spurbeck
James C. Grech
President and Chief Executive Officer
Mark A. Spurbeck
Executive Vice President and Chief Financial Officer
February 20, 2025
Peabody Energy Corporation 2024 Form 10-K
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Peabody Energy Corporation
Opinion on Internal Control Over Financial Reporting
We have audited Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Peabody Energy Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”) and our report dated February 20, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young, LLP
St. Louis, Missouri
February 20, 2025
Peabody Energy Corporation 2024 Form 10-K

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
Securities Trading Plans of Directors and Executive Officers
On December 2, 2024, Scott T. Jarboe, Chief Administrative Officer and Corporate Secretary, adopted a Rule 10b5-1 trading arrangement (as such term is defined in Item 408 of Regulation S-K), which is designed to be in effect until January 28, 2026, subject to customary exceptions. Mr. Jarboe’s Rule 10b5-1 trading arrangement calls for potential sales of a percentage of shares that he could receive upon the future vesting of certain outstanding equity awards, net of any shares withheld by Peabody to satisfy applicable taxes. The number of shares to be withheld, and thus the exact maximum number of shares to be sold pursuant to Mr. Jarboe’s Rule 10b5-1 trading arrangement, can only be determined upon the occurrence of the future vesting events. For purposes of this disclosure, without subtracting any shares to be withheld upon future vesting events, the maximum aggregate number of shares to be sold pursuant to Mr. Jarboe’s Rule 10b5-1 trading arrangement is 12,441.
Except as set forth above, during the three months ended December 31, 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 those terms are defined in Item 408 of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10.Directors, Executive Officers and Corporate Governance.
The information required by Item 401 of Regulation S-K is included under the caption Proposal 1 - “Election of Directors” in Peabody’s 2025 Proxy Statement and in Part I, Item 1. “Business” of this report under the caption “Information About Our Executive Officers.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Stock Ownership,” “Additional Information Concerning the Board of Directors - Corporate Governance - Code of Business Conduct and Ethics” and “Additional Information Concerning the Board of Directors - Committee Overview - Audit Committee” in Peabody’s 2025 Proxy Statement. Such information is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.Executive Compensation.
The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included under the captions “Additional Information Concerning the Board of Directors - Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee Interlocks and Insider Participation,” “Compensation Committee Report,” “Risk Assessment in Compensation Programs,” “Executive Compensation Tables,” “Pay Ratio Disclosure” and “Pay Versus Performance Disclosure” in Peabody’s 2025 Proxy Statement and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by Item 403 of Regulation S-K is included under the caption “Stock Ownership - Security Ownership of Directors and Management and Certain Beneficial Owners” in Peabody’s 2025 Proxy Statement and is incorporated herein by reference.
Peabody Energy Corporation 2024 Form 10-K
Equity Compensation Plan Information
As required by Item 201(d) of Regulation S-K, the following table provides information regarding Peabody’s equity compensation plans as of December 31, 2024:
(a)
Number of Securities
to be Issued
upon Exercise of
Outstanding Options,
Warrants and Rights Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding
Securities
Reflected in Column
(a))
Plan Category
Equity compensation plans approved by security holders
411,571 (1)
$ - (2)
5,451,805
Equity compensation plans not approved by security holders
- - -
Total 411,571 $ - 5,451,805
(1)Shares issuable pursuant to outstanding performance units and vested but not issued deferred stock units. Performance units are shown at target and could change based on actual metrics achieved.
(2)The weighted-average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards.
Refer to Note 16. “Share-Based Compensation” to the accompanying consolidated financial statements for additional information regarding the material features of Peabody’s current equity compensation plans.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.Certain Relationships and Related Transactions, and Director Independence.
The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Review of Related Person Transactions” and “Additional Information Concerning the Board of Directors - Board Independence” in Peabody’s 2025 Proxy Statement and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14.Principal Accountant Fees and Services.
The information required by Item 9(e) of Schedule 14A is included under the caption “Audit Fees” in Peabody’s 2025 Proxy Statement and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15.Exhibits and Financial Statement Schedules.
(a) Documents Filed as Part of the Report
(1) Financial Statements.
The following consolidated financial statements of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are included herein on the pages indicated:
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Consolidated Statements of Operations - For the Years Ended December 31, 2024, 2023 and 2022
Consolidated Statements of Comprehensive Income - For the Years Ended December 31, 2024, 2023 and 2022
Consolidated Balance Sheets - December 31, 2024 and 2023
Consolidated Statements of Cash Flows - For the Years Ended December 31, 2024, 2023 and 2022
Consolidated Statements of Changes in Stockholders’ Equity - For the Years Ended December 31, 2024, 2023 and 2022
Notes to Consolidated Financial Statements
Peabody Energy Corporation 2024 Form 10-K
(2) Financial Statement Schedules.
The following financial statement schedule of Peabody Energy Corporation is at the page indicated:
Page
Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are not applicable and, therefore, have been omitted.
(3) Exhibits.
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
Exhibit No. Description of Exhibit
2.1 Sale and Purchase Agreement dated as of October 26, 2023 by and between Stanmore SMC Pty Ltd, a wholly-owned subsidiary of Stanmore Resources Limited and Peabody (Bowen) Pty Ltd, a wholly-owned subsidiary of Peabody Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed October 27, 2023).
2.2 Put and Call Option Deed between Stanmore SMC Pty Ltd and Peabody (Bowen) Pty Ltd. (Incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K, filed October 27, 2023).
2.3 ‡ Share Purchase Agreement, dated as of November 25, 2024, by and among Peabody Energy Corporation, Anglo American Netherlands B.V., Anglo American Services (UK) Ltd. and Peabody SMC Pty Ltd (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed November 29, 2024).
2.4 ‡ Share and Asset Purchase Agreement, dated as of November 25, 2024, by and among Peabody Energy Corporation, Anglo American Netherlands B.V., Moranbah North Coal Pty Ltd., Anglo American Steelmaking Coal Assets Eastern Australia Limited, Anglo American Steelmaking Coal Holdings Limited, Anglo American Services (UK) Ltd. and Peabody MNG Pty Ltd (Incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K, filed November 29, 2024).
2.5 ‡ Option Deed, dated as of November 25, 2024, by and among Peabody SMC Pty Ltd, Peabody Australia Holdco Pty Ltd, PT Bukit Makmur Internasional and PT Delta Dunia Makmur Tbk (Incorporated by reference to Exhibit 2.3 of the Registrant’s Current Report on Form 8-K, filed November 29, 2024).
2.6 ‡ Dawson Loan Note Deed, dated as of November 25, 2024, by and among Peabody SMC Pty Ltd and PT Bukit Makmur Internasional (Incorporated by reference to Exhibit 2.4 of the Registrant’s Current Report on Form 8-K, filed November 29, 2024).
3.1 Fourth Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed April 3, 2017).
3.2 Second Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed December 8, 2023).
4.1 Specimen of stock certificate representing the Registrant’s common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 to Amendment No. 4 to the Registrant’s Form S-1 Registration Statement No. 333-55412, filed May 1, 2001).
4.2† Description of Securities
4.3 Indenture, dated as of March 1, 2022, between Peabody Energy Corporation and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on March 1, 2022).
10.1 Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.2 Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.3 Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.4 Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.5 Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.6 Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 to the Registrant’s Form S-4 Registration Statement No. 333-59073, filed September 8, 1998).
Peabody Energy Corporation 2024 Form 10-K
10.7 Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1998).
10.8 Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004).
10.9 Federal Coal Lease WYW150210: North Antelope Rochelle Mine (Incorporated by reference to Exhibit 10.8 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
10.10 Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
10.11 Federal Coal Lease Readjustment WYW78633: Caballo (Incorporated by reference to Exhibit 10.24 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.12 Transfer by Assignment and Assumption of Federal Coal Lease WYW172657: Caballo West (Incorporated by reference to Exhibit 10.25 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.13 Federal Coal Lease WYW176095: Porcupine South (Incorporated by reference to Exhibit 10.26 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.14 Federal Coal Lease WYW173408: North Porcupine (Incorporated by reference to Exhibit 10.27 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.15 Federal Coal Lease WYW172413: School Creek (Incorporated by reference to Exhibit 10.28 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.16 Separation Agreement, Plan of Reorganization and Distribution, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.17 Tax Separation Agreement, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.18 Coal Act Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.19 Salaried Employee Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.20 Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by reference to Exhibit 10.6 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.21 Settlement Agreement entered into as of October 24, 2013, by and among Patriot Coal Corporation, on behalf of itself and its affiliates, the Registrant, on behalf of itself and its affiliates, and the United Mine Workers of America, on behalf of itself and the UMWA Employees and UMWA Retirees (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 30, 2013).
10.22 Purchase and Sale Agreement, dated as of November 20, 2015, by and between Four Star Holdings, LLC and Western Megawatt Resources, LLC (Incorporated by reference to Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2015).
10.23* Variation of Employment Contract, dated August 11, 2021, between Peabody Energy Australia Coal Pty Ltd and Darren R. Yeates (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K, filed August 13, 2021).
10.24* Amendment and Restatement of Contract of Employment, dated December 27, 2024, between Peabody Energy Australia Coal Pty Ltd and Darren R. Yeates (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed December 30, 2024).
10.25* Peabody Energy Corporation 2019 Executive Severance Plan. (Incorporated by reference to Exhibit 10.32 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.26 Limited Waiver to Purchase and Sale Agreement by and between Four Star Holdings, LLC and Western Megawatt Resources, LLC dated March 30, 2016 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed March 31, 2016).
10.27 Fifth Amended and Restated Receivables Purchase Agreement, dated as of March 25, 2016, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed March 31, 2016).
Peabody Energy Corporation 2024 Form 10-K
10.28 First Amendment to the Fifth Amended and Restated Receivables Purchase Agreement, dated as of April 12, 2016, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as the Sole Purchaser, Committed Purchaser, LC Bank and LC Participant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 13, 2016).
10.29 Second Amendment to the Fifth Amended and Restated Receivables Purchase Agreement, dated as of April 18, 2016, by and among Peabody Energy Corporation, P&L Receivables Company, LLC, the various Sub-Servicers listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as the Sole Purchaser, Committed Purchaser, LC Bank and LC Participant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 22, 2016).
10.30 Sixth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of June 30, 2020, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.31 Receivables Purchase Facility Commitment Letter entered into as of January 27, 2017, by and among the Registrant, P&L Receivables Company, LLC and PNC Bank, National Association (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2017).
10.32 Notice Letter and Term Sheet dated as of February 15, 2017, for Amendments to the Receivables Purchase Facility Commitment Letter entered into as of January 27, 2017, by and among the Registrant, P&L Receivables Company, LLC and PNC Bank, National Association (Incorporated by reference to Exhibit 10.128 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2016).
10.33 Settlement Agreement dated as of March 13, 2017 by and among the Registrant, certain subsidiaries of the Registrant, and the United Mine Workers of America 1974 Pension Plan and Trust (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on March 17, 2017).
10.34 Sixth Amended and Restated Receivables Purchase Agreement, dated as of April 3, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed April 3, 2017).
10.35 First Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of June 30, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various parties identified on the signature pages thereto as Sub-Servicers, Metropolitan Collieries Pty Ltd, and PNC Bank, National Association, as Administrator and as the sole Purchaser Agent, Committed Purchaser, LC Bank and LC Participant on the date thereof (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q, filed August 14, 2017).
10.36 Second Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of December 13, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, Regions Bank, and PNC Bank, National Association, as Administrator and as the sole Purchaser Agent, Committed Purchaser, LC Bank and LC Participant on the date thereof (Incorporated by reference to Exhibit 10.57 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017).
10.37 Fifth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of April 3, 2019, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 4, 2019).
10.38 Credit Agreement dated as of April 3, 2017, among the Registrant, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, and the other lenders party thereto (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
10.39 Amendment No. 1 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of the Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of September 18, 2017 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed September 18, 2017).
10.40 Amendment No. 2 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of November 17, 2017 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed November 20, 2017).
10.41 Amendment No. 3 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of December 18, 2017 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 19, 2017).
Peabody Energy Corporation 2024 Form 10-K
10.42 Amendment No. 4 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of April 11, 2018 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 11, 2018).
10.43 Amendment No. 5 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of June 27, 2018 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
10.44 Amendment No. 6 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the incremental revolving lenders party thereto, Goldman Sachs Bank USA, as existing administrative agent, and JPMorgan Chase Bank, N.A., as successor administrative agent, dated as of September 17, 2019 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.45 Amendment No. 7 to Credit Agreement by and among Peabody Energy Corporation, the subsidiaries of the Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto, and JPMorgan Chase Bank, N.A., as successor administrative agent, dated as of September 17, 2019 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.46 Amendment No. 8 to Credit Agreement by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent, dated as of January 29, 2021 (as successor to Goldman Sachs Bank USA in its capacity as administrative agent) (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
10.47* Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 4.6 of the Registrant’s Registration Statement on Form S-8, filed April 3, 2017).
10.48 Registration Rights Agreement, dated as of April 3. 2017, among the Registrant and the stockholders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed, April 3, 2017).
10.49 Form of Indemnification Agreement (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.50* Form of Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
10.51* Form of Restrictive Covenant Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.8 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
10.52* Form of Deferred Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.12 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.53* Form of Performance Share Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan. (Incorporated by reference to Exhibit 10.68 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017).
10.54 Form of Indemnification Agreement (Incorporated by reference to Exhibit 10.73 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.55* Form of Deferred Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.74 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.56* Form of Restricted Stock Unit Agreement (ELT Level 2019 Special Award) under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.75 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.57* Form of Restricted Stock Unit Agreement (Director Level and Above 2019 Special Award) under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.76 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.58* Form of Deferred Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.59* Form of Restricted Stock Unit Agreement (Director Level and Above 2020 Off-Cycle Award) under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.60* Form of Performance Share Units Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
Peabody Energy Corporation 2024 Form 10-K
10.61* Form of Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.5 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.62* Form of 2021 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 5, 2021).
10.63* Form of Amendment No. 1 to 2021 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on March 5, 2021).
10.64* Form of 2022 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (US Employees) (Incorporated by reference to Exhibit 10.75 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.65* Form of 2022 Performance-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (US Employees) (Incorporated by reference to Exhibit 10.76 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.66* Form of 2022 Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (US Employees) (Incorporated by reference to Exhibit 10.77 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.67* Form of 2022 Global Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees) (Incorporated by reference to Exhibit 10.78 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.68* Offer of Restricted Stock Units to Australian Resident Grantees under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees) (Incorporated by reference to Exhibit 10.79 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.69* Form of 2022 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees) (Incorporated by reference to Exhibit 10.80 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.70* Form of 2022 Performance-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees) (Incorporated by reference to Exhibit 10.81 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.71* † Form of 2025 Performance Unit Agreement (with cash) (ELT Level) under the Peabody Energy Corporation 2017 Incentive Plan.
10.72* † Form of 2025 Restricted Stock Unit Agreement (ELT Level) under the Peabody Energy Corporation 2017 Incentive Plan.
10.73* † Form of 2025 Service-Based Cash Award Agreement (ELT Level) under the Peabody Energy Corporation 2017 Incentive Plan.
10.74 Agreement, dated as of February 4, 2020, by and among Peabody Energy Corporation, Elliott Investment Management L.P., Elliott Associates, L.P. and Elliott International, L.P. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed February 5, 2020).
10.75 Management Services Agreement, dated as of August 4, 2020, by and between Peabody Investments Corp. and each of the Client Companies listed on the signature page thereto (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.76 Management Services Agreement, dated as of August 4, 2020, by and between Peabody Energy Australia Pty Ltd and each of the Client Companies listed on the signature page thereto (Incorporated by reference to Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.77 Transaction Support Agreement, dated as of November 6, 2020, between Peabody Energy Corporation, certain subsidiaries of Peabody Energy Corporation and the Participating Sureties (Incorporated by reference to Exhibit 10.5 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).
10.78 Transaction Support Agreement, dated as of December 24, 2020, between Peabody, certain subsidiaries of Peabody, the Revolving Lenders, the Administrative Agent, and the Consenting Noteholders (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 28, 2020).
10.79 Amended and Restated Transaction Support Agreement, dated as of December 31, 2020, between Peabody, certain subsidiaries of Peabody, the Revolving Lenders, the Administrative Agent, and the Consenting Noteholders (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed January 4, 2021).
10.80 First Amendment to Amended and Restated Transaction Support Agreement, dated as of January 29, 2021, between Peabody, certain subsidiaries of Peabody, the Revolving Lenders, the Administrative Agent, and the Consenting Noteholders (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
Peabody Energy Corporation 2024 Form 10-K
10.81 Agreement for Irrevocable Standby Letters of Credit, dated as of February 17, 2022, between Peabody and Goldman Sachs Bank USA (Incorporated by reference to Exhibit 10.89 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022).
10.82 Eighth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of January 28, 2022, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, PNC Bank, National Association, as Administrator and as LC Bank and PNC Capital Markets LLC, as Structuring Agent (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 31, 2022).
10.83 Commitment Agreement, dated March 23, 2022, by and among Peabody Investments Corp., The Prudential Insurance Company of America and Fiduciary Counselors Inc. (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 10-Q, filed May 5, 2022).
10.84 Ninth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of February 13, 2023, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, PNC Bank, National Association, as Administrator and as LC Bank and PNC Capital Markets LLC, as Structuring Agent (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed February 14, 2023).
10.85 Amendment to Surety Transaction Support Agreement and Surety Term Sheet, dated as of April 14, 2023, by and among Peabody Energy Corporation, certain subsidiaries of Peabody Energy Corporation party thereto and the providers of its surety program (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed April 17, 2023).
10.86* Peabody Investments Corp. 2023 Supplemental Employee Retirement Account (Incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed August 3, 2023).
10.87 Credit Agreement, dated as of January 18, 2024, among Peabody Energy Corporation, certain subsidiaries of Peabody Energy Corporation party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 1.1 of the Registrant’s Current Report on Form 8-K file January 18, 2024).
10.88 Amendment No. 1 to Credit Agreement, dated as of November 25, 2024, by and among Peabody Energy Corporation, PNC Bank, National Association, as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed November 25, 2024).
19.1† Insider Trading Policy, effective as of February 23, 2023
21† List of Subsidiaries.
23.1† Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
23.2† Consents of Qualified Persons for Technical Report Summary for the North Antelope Rochelle Mine.
23.3† Consents of Qualified Persons for Technical Report Summary for the Wilpinjong Mine.
23.4† Consents of Qualified Persons for Technical Report Summary for the Centurion Mine.
31.1† Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2† Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1† Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer.
32.2† Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer.
95† Mine Safety Disclosure required by Item 104 of Regulation S-K.
96.1 Technical Report Summary for the North Antelope Rochelle Mine, effective as of December 31, 2021 (Incorporated by reference to Exhibit 96.1 of the Registrant’s Annual Report on Form 10-K, filed February 18, 2022)
96.2 Technical Report Summary for the Wilpinjong Mine, effective as of December 31, 2023 (Incorporated by reference to Exhibit 96.2 of the Registrant’s Annual Report on Form 10-K, filed February 23, 2024)
96.3 Technical Report Summary for the Centurion Mine, effective as of October 15, 2024 (Incorporated by reference to Exhibit 96.1 of the Registrant’s Current Report on Form 8-K, filed October 15, 2024)
97 Peabody Energy Corporation Clawback Policy, effective as of August 3, 2023 (Incorporated by reference to Exhibit 97 of the Registrant’s Annual Report on Form 10-K, filed February 23, 2024)
101.INS Inline 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.SCH Inline XBRL Taxonomy Extension Schema Document
Peabody Energy Corporation 2024 Form 10-K
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 Cover Page Interactive Data File (embedded within the Inline XBRL document).
* These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(a)(3) and 15(b) of this report.
† Filed herewith.
‡ Certain portions of this exhibit have been redacted pursuant to Regulation S-K, Item 601(a)(6) and Item 601(b)(2)(ii). This exhibit excludes certain immaterial schedules and exhibits pursuant to the provisions of Regulation S-K, Item 601(a)(5). A copy of any of the omitted information, schedules and exhibits pursuant to Regulation S-K, Item 601(a)(5), Item 601(a)(6) and Item 601(b)(2)(ii), as applicable, will be furnished to the Securities and Exchange Commission upon request.
Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the Company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.