NYSE: BTU

Mining Locations

The maps that follow display Peabody’s active and development mine locations as of December 31, 2025. 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
2025 Form 10-K

2

Table of Contents

U.S. Locations

Peabody Energy Corporation
2025 Form 10-K

3

Table of Contents

Australian Locations

Peabody Energy Corporation
2025 Form 10-K

4

Table of Contents

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 reportable segment in descending order, as determined by tons produced in 2025.

Production

Segment/Mining ComplexLocationMine TypeMining MethodCoal TypePrimary Transport MethodProcessing

PlantsYear Ended December 31,

202520242023

Seaborne Thermal(Tons in millions)

WilpinjongNew South WalesSD, T/STR, EVYes10.5 12.6 12.0

Wambo Open-Cut (1)
New South WalesST/ST, CR, EVYes3.5 3.3 2.6

Wambo Underground (2)
New South WalesULWT, CR, EVYes0.8 1.4 1.2

Seaborne Metallurgical

Coppabella (3)
QueenslandSDL, D, T/SPR, EVYes2.0 1.7 2.2

Shoal Creek (4)
AlabamaULWCB, EVYes1.8 2.1 0.6

MetropolitanNew South WalesULWC, P, TR, EVYes1.7 1.8 2.2

Moorvale (3)
QueenslandSD, T/SC, P, TR, EVYes1.2 1.5 2.2

Centurion (5)
QueenslandULWCR, EVYes0.6 0.2 —

Middlemount (6)
QueenslandSD, T/SC, PR, EVYes— — —

Powder River Basin

North Antelope RochelleWyomingSDL, D, T/STRNo65.0 59.7 62.0

CaballoWyomingSD, T/STRNo11.7 10.8 15.3

RawhideWyomingSD, T/STRNo7.8 9.1 9.8

Other U.S. Thermal

Bear RunIndianaSDL, D, T/STTr, R, EVYes4.7 5.0 5.5

Wild BoarIndianaSHW, DL, D, T/STTr, R, R/B, T/BYes2.1 1.8 1.9

Gateway NorthIllinoisUCMTTr, R, R/B, T/B, EVYes2.0 2.1 2.5

El Segundo/Lee RanchNew MexicoSDL, D, T/STRNo1.8 2.4 3.4

TwentymileColoradoULWTR, Tr, EVYes1.8 1.0 1.3

Francisco UndergroundIndianaUCMTRYes1.3 1.6 2.0

Legend:

SSurface MineBBarge

UUnderground MineTrTruck

HWHighwall MinerR/BRail to Barge

DLDraglineT/BTruck to Barge

DDozer/CastingT/RTruck to Rail

T/STruck and ShovelEVExport Vessel

LWLongwallTThermal/Steam

CMContinuous MinerCCoking

RRailPPulverized 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. Mine ceased production in September 2025.

(3)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.

(4)The mine experienced a fire in March 2023 and restarted production in June 2023.

(5)Development of the mine began in 2023. The first development coal was produced in June 2024. Longwall mining commenced in February 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 1.4 million, 1.3 million and 1.2 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
2025 Form 10-K

5

Table of Contents

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 87%, 90% and 92% of the Company’s worldwide sales from its mining operations (by volume) for the years ended December 31, 2025, 2024 and 2023, respectively.

For the year ended December 31, 2025, Peabody derived 25% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 19 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2025 to 2028. Peabody’s largest customer in 2025 contributed revenue of approximately $291 million, or approximately 8% of Peabody’s total revenue from coal supply agreements, and has contracts expiring in 2026.

Backlog. Peabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 238 million and 153 million tons of coal as of January 1, 2026 and 2025, respectively. Contracts in backlog have remaining terms ranging from one to seven years and represent approximately two years of production based on the Company’s 2025 production volume of 120.3 million tons. Approximately 64% of its backlog is expected to be filled beyond 2026.

Seaborne Operations. Revenue from Peabody’s Seaborne Thermal and Seaborne Metallurgical reportable segments represented approximately 51%, 55% and 56% of the Company’s total revenue from coal supply agreements for the years ended December 31, 2025, 2024 and 2023, respectively, during which periods the coal mining activities of those segments contributed approximately 20%, 20% 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 50% in 2025.

U.S. Thermal Operations. Revenue from Peabody’s Powder River Basin and Other U.S. Thermal reportable segments, in aggregate, represented approximately 49%, 45% and 44% of the Company’s revenue from coal supply agreements for the years ended December 31, 2025, 2024 and 2023, respectively, during which periods the coal mining activities of those segments contributed approximately 80%, 80% 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 reportable 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).

Peabody Energy Corporation
2025 Form 10-K

6

Table of Contents

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. negatively impacted Peabody’s sales volume and transportation costs at the Shoal Creek Mine. The lock outages were largely resolved during the second half of 2024; however, there are several planned outages in 2026 for maintenance to permanently repair the locks. As the timing and duration of these outages is generally known, Peabody is planning to manage its inventories accordingly so that coal will be available during the times when the locks are open. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.

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.

No tons were exported from U.S. thermal operations during the years ended December 31, 2025, 2024 and 2023. Peabody routinely assesses the export market for its U.S. thermal coal, including options along both the Gulf Coast and the West Coast.

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 2025, lead times for parts and components required for surface and underground mining equipment remained at normal levels. While tariff impacts have not been significant, ongoing engagement with the supply base focuses on assessing potential future tariff implications and identifying mitigation strategies. Peabody continues to leverage its global purchasing power and comprehensive planning 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.

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; 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
2025 Form 10-K

7

Table of Contents

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 $3.62 per mmBtu in 2025, versus $2.41 and $2.66 per mmBtu in 2024 and 2023, 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 2025, approximately 3 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by approximately forty-six 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 2026 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 vary 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 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 2025.

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 Summit; 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; New Hope; 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. In 2025 global metallurgical coal trade flows were influenced by 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; QCoal; Warrior Met Coal; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.

Human Capital

Peabody had approximately 5,400 employees as of December 31, 2025, including approximately 4,200 hourly employees. Additional information on its employees and related labor relations matters is contained in Note 18. “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, 2025, 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 office in Brisbane.

Peabody strives to create a strong, united workforce with a commitment to safety as a way of life. In 2025, the Company achieved a global safety incidence rate of 0.71 incidents per 200,000 hours worked, which set an all-time record for the lowest incidence rate in Peabody’s history for the second consecutive year after achieving a global safety incidence rate of 0.81 in 2024. In comparison to the 2024 U.S. industry average, the Company’s 2025 incidence rate was 76% better than the industry average rate of 2.96 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).

Peabody Energy Corporation
2025 Form 10-K

8

Table of Contents

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 42% 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 30% 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. Grech64President and Chief Executive Officer

Mark A. Spurbeck52Executive Vice President and Chief Financial Officer

Darren R. Yeates65Executive Vice President and Chief Operating Officer

Scott T. Jarboe52Chief Administrative Officer and Corporate Secretary

Patrick J. Forkin III67Executive Vice President, Global Strategy and Peabody Development

Malcolm Roberts52Executive Vice President and Chief Commercial Officer

(1) As of February 13, 2026.

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 is a board member of America's Power, the National Mining Association and Blue Danube Incorporated, and also is a member of the Coal Industry Advisory Board of the International Energy Agency. He is an appointed member on the Surface Transportation Board Rail Energy Transportation Advisory Committee. In January 2026, Mr. Grech was appointed Chair of the National Coal Council. 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. He has executive responsibility for 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
2025 Form 10-K

9

Table of Contents

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 and procurement. 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 Executive Vice President, Global Strategy and Peabody Development in September 2025, after serving as Chief Development Officer since July 2022. He has executive responsibility for global strategy and all non-coal mining related commercial activities including gas generation, rare earth elements, coal generation opportunities 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 conventional and renewable 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 Executive Vice President and Chief Commercial Officer in September 2025 after serving as Chief Marketing Officer since May 2023. He has responsibility for global commercial strategy including sales, marketing and corporate development. 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
2025 Form 10-K

10

Table of Contents

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. The current excise tax rates are 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. Peabody recognized expense related to the tax of $54.6 million, $52.2 million and $57.4 million for the years ended December 31, 2025, 2024 and 2023, 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 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. During February 2025, the Trump Administration issued letters to impacted companies that the 60-day deadline to provide information was no longer applicable and that no additional information was required at this time. They also announced that the OWCP would provide additional guidance in due course.

The changed requirements for security posted to self-insure black lung liabilities could result in the Company being required to post additional security of approximately $40 million 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.

Recent Announcement by the U.S. Environmental Protection Agency (EPA). In response to an executive order issued by President Trump requiring agencies to identify regulations for regulatory roll back, the EPA announced on March 12, 2025, that it will reconsider several EPA actions, including:

•Regulation of greenhouse gas (GHG) emissions from new and existing fossil fuel-fired electric generating units (EGUs);

•National Ambient Air Quality Standards for fine particulate matter (PM);

•Cross State Air Pollution Rule (CSAPR);

•Mercury and Air Toxic Standards (MATS);

•Implementation of the Regional Haze Program;

•Final September 2023 rule clarifying the scope of federal regulatory authority over wetland and non-navigable waters;

•Final rule regarding effluent limitations guidelines for the steam electric power generating industry; and

•Rules for disposal of coal combustion residuals.

Peabody Energy Corporation
2025 Form 10-K

11

Table of Contents

Peabody will continue to monitor these items, as changes could have significant impact on the U.S. coal mining industry, Peabody’s mining operations and 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.

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 $878.6 million as of December 31, 2025. 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 $476.4 million as of December 31, 2025. 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-mined coal, respectively. The Company recognized expense related to the fees of $21.4 million, $20.4 million and $22.2 million for the years ended December 31, 2025, 2024 and 2023, 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.

Peabody Energy Corporation
2025 Form 10-K

12

Table of Contents

National Ambient Air Quality Standards (NAAQS). The CAA requires the 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-fired 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). Concurrently, per its March 12, 2025 announcement, the EPA continues to reconsider the 2024 standard.

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.

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 GHG 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.

Peabody Energy Corporation
2025 Form 10-K

13

Table of Contents

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). 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).

On June 17, 2025, in accordance with the agency’s earlier March 12, 2025 announcement, the EPA proposed to repeal all GHG emissions standards for new and existing fossil fuel-fired power plants and, in the alternative, to repeal emission guidelines for existing fossil fuel-fired power plants and requirements for modified coal-fired steam generating to use CCS technology. Relatedly, on August 1, 2025, the EPA published a proposed rule to reconsider a 2009 endangerment finding regarding the regulation of GHGs under the CAA. In the 2009 action, the EPA found that current and projected atmospheric concentrations of six GHGs were reasonably anticipated to endanger public health and welfare and that GHG emissions from new motor vehicles contributed to air pollution that threatened public health and welfare. These determinations formed the basis for subsequent regulation of GHGs from new motor vehicles under section 202 of the CAA. On February 12, 2026, the EPA finalized its rescission of the 2009 endangerment finding and also finalized the repeal of all subsequent GHG emission standards.

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.

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. Per the March 12, 2025 announcement, this rule remains under review by the EPA.

Mercury and Air Toxic Standards. 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.

Peabody Energy Corporation
2025 Form 10-K

14

Table of Contents

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 PM 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). Per its March 12, 2025 announcement, the EPA proposed on June 17, 2025 to repeal parts of the final 2024 MATS rule regarding filterable PM standards and revise the mercury standard for existing lignite-fired EGUs.

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, the EPA proposed to revise the due date for plans (for the third regional haze implementation period) from July 31, 2028 to July 31, 2031. As noted above, on March 12, 2025, the EPA announced plans to “restructure” the regional haze program. On September 29, 2025, the EPA issued an Advance Notice of Proposed Rulemaking to “streamlining regulatory requirements impacting states’ visibility improvement obligations under the Clean Air Act.”

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.

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. In response to executive orders aimed at reinvigorating the coal industry and increasing domestic mineral production and the passage of the One Big Beautiful Bill Act, the Bureau of Land Management announced on September 29, 2025, that is making up to 13.1 million acres of federal coal available for lease, lowering royalty rates and streamlining approvals for projects in Montana, Wyoming, Tennessee and beyond. Earlier in the year, the Department of the Interior announced it was officially ending its moratorium on federal coal leasing, and the Interior Secretary issued Order 3418 directing actions to review and revise resource management plans restricting coal leasing.

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.

Peabody Energy Corporation
2025 Form 10-K

15

Table of Contents

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. On November 20, 2025, the EPA and the Corps proposed additional revisions to the regulatory definition to further align the regulations with Sackett. The agencies took comments on the proposed revisions through January 5, 2026, and they plan to take final action later in 2026.

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. On July 1, 2025, the EPA published a notice in the Federal Register inviting stakeholder feedback on the 2023 rule. The agency is currently working on proposed revisions to the 2023 rule and plans to propose and finalize changes in 2026.

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 U.S. Court of Appeals for the Eighth Circuit (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. On December 31, 2025, the EPA published a final Deadline Extensions Rule that extends seven compliance deadlines in the 2024 rule. The EPA is allowing EGUs six additional years (until December 31, 2031) to determine whether to submit a notice of planned participation for the permanent cessation of coal combustion. The EPA further extended the deadlines by five years (to December 31, 2034) for direct discharging EGUs to comply with zero-discharge limitations for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate. Finally, the EPA is allowing EGUs that discharge to wastewater treatment plants an additional year-and-a-half to seven-and-a-half years to comply with zero-discharge limitations for those same wastestreams. The EPA also issued a No Action Assurance memorandum announcing it will not pursue enforcement actions for certain permit violations by EGUs not yet in compliance with permit requirements related to the 2020 and 2024 rules, if those EGUs satisfy certain conditions.

Peabody Energy Corporation
2025 Form 10-K

16

Table of Contents

National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. Peabody must provide information to agencies when it proposes actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. Since July 2020, the White House Council on Environmental Quality (CEQ) has revised its longstanding NEPA regulations on several occasions. On January 20, 2025, President Trump issued Executive Order 14154, which directed the CEQ to propose rescinding its NEPA regulations and to provide guidance to federal agencies on implementing NEPA and to coordinate the revision of the agencies’ own implementing regulations. On February 25, 2025, the CEQ published an Interim Final Rule removing all CEQ NEPA regulations from the Code of Federal Regulations, and the CEQ adopted that rule as final on January 8, 2026. The CEQ has clarified that individual agencies are free to continue following or to amend their own NEPA implementation procedures, which largely conformed to the CEQ’s regulations. On May 28, 2025, the CEQ withdrew its January 9, 2023 interim guidance on consideration of GHG emissions and climate change when conducting environmental reviews pursuant to NEPA. On September 29, 2025, the CEQ issued guidance requiring all heads of federal departments and agencies to revise (or to establish) NEPA implementation procedures consistent with Executive Order 14154, the 2023 and 2025 statutory amendments to NEPA and the U.S. Supreme Court’s May 29, 2025 decision in Seven County Infrastructure Coalition v. Eagle County, Colorado. The CEQ emphasized the need for agencies to streamline procedures and ensure that the NEPA process does not go on for too long in time or in volume.

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 November 28, 2025, the EPA proposed to extend, by three years, the compliance deadline in the 2020 amendments for owners and operators to complete closure of unlined impoundments larger than 40 acres. 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. On November 21, 2025, the agencies published four proposed rules to restore the ESA regulations to their 2019 and 2020 framework. The agencies accepted comments on the proposed rules through December 22, 2025.

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
2025 Form 10-K

17

Table of Contents

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 intended to enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules required 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 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. On March 27, 2025, the SEC announced that it would end its defense of the final rules. On April 24, 2025, the Eighth Circuit directed the SEC to provide a status update in the ongoing litigation concerning the final rules. On July 23, 2025, the SEC indicated that it does not intend to review or reconsider the final rules but requested that the Eighth Circuit proceed with the litigation and decide the case. In September 2025, the Court declined to issue a ruling and is instead keeping the litigation on hold, noting that it is the SEC’s “responsibility to determine whether its Final Rules will be rescinded, repealed, modified, or defended in litigation.”

One Big Beautiful Bill Act of 2025 (OBBBA). The OBBBA was signed into law on July 4, 2025. Several provisions of the legislation affect the Company’s consolidated operations, financial condition or cash flows, including a reduction to the federal royalty rate on coal production and the addition of metallurgical coal which is suitable for use in the production of steel to the list of critical minerals eligible for the Section 45X tax credit through 2029 at a rate of 2.5% of production costs. Peabody realized benefits of approximately $19 million during the year ended December 31, 2025 related to the federal royalty reduction provisions of the legislation. Peabody estimates an annual benefit of approximately $5 million related to the Section 45X tax credit which will be recognized against applicable production costs in the consolidated statements of operations. The Company will continue to evaluate the effect of the OBBBA as more guidance is issued.

Complaints Filed Against “Climate Superfund Laws” and Announced State Actions. On April 30 and May 1, 2025, respectively, the U.S. Department of Justice filed complaints for declaratory and injunctive relief against the states of Michigan and Hawaii regarding alleged liability of fossil fuel companies for past GHG emissions and against New York and Vermont for “climate superfund” laws. These complaints allege that existing litigation and state laws interfere with federal law, including the CAA, and with interstate and foreign commerce. The Company will monitor this litigation and its potential impact on the U.S. coal mining industry, its mining operations and customers.

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.

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.

Peabody Energy Corporation
2025 Form 10-K

18

Table of Contents

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 Climate Change, Energy, the Environment and Water (DCCEEW) is responsible for NGER Act-related policy developments and review, including with respect to Australia’s key emissions reductions policy, the Safeguard Mechanism (enacted through the NGER Act and other legislation). Under the Safeguard Mechanism, site-specific baseline emissions for heavy emitting facilities are prescribed as benchmarks for year-on-year improvement (4.9% each year to 2030, following which the decline rates from July 1, 2030 will be set for each year in five-year blocks by the DCCEEW), as well as a weighted integration of the industry average emission baseline. Proponents earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits (Safeguard Mechanism Credits or Australian Carbon Credit Units (an Australian Government incentive)) to offset emissions. A ceiling for the price of Australian Carbon Credit Units of $75 Australian dollars per tonne of CO2 equivalent was fixed in 2023-2024, with that ceiling increasing with the Consumer Price Index plus 2% each year (the price ceiling being $79.20 Australian dollars per tonne of CO2 equivalent for 2024-2025).

The Safeguard Mechanism also includes additional emission reduction measures including a cap on overall net emissions from facilities covered by the scheme through 2030, a cap of net zero tonnes CO2 for any financial year beginning after June 30, 2049, and a requirement that where the Minister for Environment and Water grants an approval under the EPBC Act to a new or expanded facility covered by the scheme, they are 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.

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. Development of the model to comply with the updated act is underway (utilizing guidance from the Australian coal industry’s research association (ACARP)) to ensure Peabody will meet its future reporting obligations for the reporting of fugitive emissions. As the modelling is not yet complete, Peabody expects to have further understanding of the financial impacts resulting from the change in reporting methodology later in 2026. Along with the development of the model and change to reporting obligations, the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 includes language giving the Clean Energy Regulator discretion to vary a facility’s emission intensity determination in instances where the transition to a higher order reporting methodology results in a material change to the facility’s determination. This consideration is undertaken at or near the time of reporting under the NGER Act, due October 31 annually, and may further influence impacts of the revised NGER Act on open-cut coal mines.

Industrial Relations Laws. A national industrial relations system, the Fair Work Act and National Employment Standards, applies to all private sector employers and employees where the employer is a corporation. The matters regulated under the national system include general employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes as well as other matters affecting the employment relationship. 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, which set terms and conditions of employment.

On December 7, 2023, the Fair Work Legislation Amendment (Closing Loopholes) Bill 2023 was passed by the Australian Federal Parliament. The legislation allows unions, employees and/or hosts to make application to the Fair Work Commission (the Commission) for a ‘regulated labour hire arrangement order’ that, if successful, requires labor hire employers to provide similar wages and conditions to regulated workers as those provided to employees of the host. Orders have been made in relation to labor hire employers who provide labor to Peabody Energy Australia PCI Mine Management Pty Ltd (now a regulated host) at its Coppabella Mine and to Helensburgh Coal Pty Ltd (now a regulated host) at the Metropolitan Mine, increasing Peabody’s operating cost.

Industrial relations laws are generally enforceable by Court action, and penalties can apply for breach.

Peabody Energy Corporation
2025 Form 10-K

19

Table of Contents

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.

Both New South Wales (NSW) and Queensland have additional state-specific legislation in place that enables Aboriginal people to claim freehold title to available land currently owned by the state government. If and when title to any claimable land is transferred to the relevant Aboriginal people, then ongoing consultation and compensation arrangements will need to be in place with the new landowner. There is claimable land within proximity to all Company operations in NSW and Queensland and accordingly, as and when any claims are processed by the respective state government, the Company will need to progress consultation and compensation arrangements to ensure that its access rights are maintained. The Company continues to monitor the progress of any claims that have the potential to impact its operations.

Aboriginal and Torres Strait Islander Heritage Protection Act 1984 (ATSIHP). The purpose of the ATSIHP Act is to ensure the preservation and protection from harm or desecration of areas and objects in Australia and in Australian waters, that are of particular significance to Aboriginal people. Under the ATSIHP Act, the Commonwealth Minister for Indigenous Australians can make declarations in relation to areas or objects for the purposes of protecting Aboriginal and Torres Strait Islander heritage. Declarations are made in response to applications made by an Aboriginal person or group showing that the area or object is significant with respect to Aboriginal culture and is under threat of injury or desecration. Such a declaration may prevent any development being carried out on the relevant area of land. In 2024, the Commonwealth Minister made a declaration under the ATSIHP Act over an area that had been approved under state and federal environmental and planning laws for a gold mining project in NSW. 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. Hearings into the matter commenced December 2025, and the case remains before the Federal Court. The Company will monitor any legal precedents set in this case that have the potential to impact its operations.

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 $346.1 million as of December 31, 2025. 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 $278.5 million as of December 31, 2025. 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), 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.

Peabody Energy Corporation
2025 Form 10-K

20

Table of Contents

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.

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 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 NSW EPA has proposed additional reforms that may result in additional prescriptive climate change mitigation requirements for high-emitting facilities including coal mines. These proposals include the phasing in of new climate mitigation requirements into existing environmental protection licenses (EPLs) for mining operations that emit more than 25,000 tonnes of CO2 equivalent (scope 1 and scope 2) per year; new reporting obligations for mining operations that may include an obligation to report annual climate change emissions and prepare three-yearly Climate Change Mitigation and Adaptation Plans; and prescriptive mitigation measures requiring coal mine operators to address fugitive methane emissions and reduce emissions from diesel combustion. Peabody will monitor the passage of these reforms and assess potential impacts on its operations.

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 March 2025, the Biodiversity Conservation Amendment (Biodiversity Offsets Scheme) Act 2024 commenced. This amendment act implements 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 changes to the biodiversity offset laws have affected approval processes and timeframes for 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 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 is currently reviewing the statement; however, no date has been set for the release of an updated statement.

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 8.8% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 9.8% for underground mines and 10.8% for open-cut mines.

Peabody Energy Corporation
2025 Form 10-K

21

Table of Contents

NSW Industrial Manslaughter Laws. The Work Health and Safety Act 2011 include the offense of industrial manslaughter. The offense applies 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 act allows an alternative finding of guilt: if a person is charged with industrial manslaughter is not found guilty of that offense, but the court is satisfied they committed an offense under section 31 (Gross negligence or reckless conduct— Category 1) of the NSW Work Health Safety Act, they may instead be 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.

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), 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 environmental protection order (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.

The EP Act and the Water Act 2000 provide 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 allow the regulator to issue an 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).

The Mineral and Energy Resources (Financial Provisioning) Act 2018 contains financial assurance (FA) framework and progressive rehabilitation requirements. The FA framework provides for 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.

Progressive rehabilitation requirements 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.

Peabody Energy Corporation
2025 Form 10-K

22

Table of Contents

Queensland Residual Risk Laws. Queensland’s residual risk framework under the EP Act and Mineral and Energy Resources (Financial Provisioning) Act 2018 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 includes 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. Resources Safety and Health Queensland (RSHQ) administers the Coal Mining Safety and Health Act 1999 and other safety legislation covering inspectorates for coal and mineral mines, quarries, explosives, and petroleum and gas. The act also establishes an independent Work Health and Safety Prosecutor for serious offenses. In early 2025, Queensland appointed its first Mining and Resources Coroner, responsible for investigating fatalities and issuing safety recommendations, with mandatory inquests for deaths in the industry. Further, on November 19, 2025, the Queensland Minister for Natural Resources and Mines introduced the Independent Review of RSHQ Report. Additional reforms and restructuring of RSHQ are expected as the government responds to the Report’s recommendations.

Queensland Industrial Manslaughter Laws. In Queensland, section 48D of the CMSH Act provides that a PCBU or a "senior officer" of an of an employer for a coal mine, commits an offense if their negligent conduct causes the death of a worker. Industrial manslaughter attracts maximum penalties of 20 years imprisonment for an individual and $10 million for a body corporate. The offense applies where a worker dies (or is injured and later dies) in the course of work, the senior officer’s conduct causes the death of the coal mine worker, and the senior officer is negligent about causing the death of the coal mine worker by the conduct. A similar duty applies to an employer for a coal mine under section 48C of the CMSH Act. "Senior officer” for this Queensland offense means an executive officer of the corporation, being a person who is concerned with, or takes part in, the corporation’s management, whether or not the person is a director or the person’s position is given the name of executive officer. It is intended to capture those at the highest levels with authority to create and influence safety culture and resource allocation.

Queensland Coal Royalties. In Queensland coal royalties are applied according to a progressive, tiered system where higher percentage rates are applied as coal prices rise. On July 1, 2022, the former Labor administration in Queensland 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. The increased rates increased royalty costs for Peabody’s Queensland operations. Despite advocacy by the coal sector, the current Liberal National Party administration has committed to maintaining the current system. The Company will continue to advocate for royalty reductions and monitor the government’s actions on this issue.

Peabody Energy Corporation
2025 Form 10-K

23

Table of Contents

Risks Related to Global Climate Change

Peabody will continue to balance a growing demand for energy and steel with initiatives to reduce GHG emissions that mitigate risk, align with its customers’ commitments and meet its regulatory obligations. The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2).

Peabody’s Board of Directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing solutions for a global reduction of GHG emissions, and the Company supports advanced coal technologies to align with the commitments of its customers and mitigate regulatory risk.

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 in steelmaking and 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:

•Disruptions to production resulting from increased, adverse weather events;

•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.

Peabody Energy Corporation
2025 Form 10-K

24

Table of Contents

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.

Public and scientific attention to climate issues, including findings in reports such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change, has increased scrutiny of GHG emissions, particularly CO2 emissions from coal-fueled power generation. In turn, increasing attention from governments has been paid to global climate issues and to GHG emissions, including emissions of CO2 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.

Future legislation or regulations, such as carbon taxes or other emissions-reduction measures, could prompt electricity generators to shift from coal to other fuel sources. Policies that limit financing for the development of new coal-fueled power plants could adversely impact long-term global demand. The potential financial impact of these developments on Peabody will depend upon the degree to which any such laws or regulations reduce coal use, which in turn will be influenced by the specific requirements of any new laws or regulations, the timing of their implementation, the development and acceptance of CCUS technologies, and the availability of alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting emissions-related requirements, and several major coal-using countries, including China, India and Japan, have incorporated such technologies into 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.

The Company’s Board of Directors and management periodically 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 but aid in assessing the strength of current mitigations implemented by the Company and resilience to identified risks.

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, approved legislation, the Inflation Reduction Act of 2022, that provided 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 also undertook several steps to regulate GHG emissions under existing law, primarily the CAA. These efforts and subsequent actions during 2025 affecting these measures are described under “Regulatory Matters - U.S.” 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. 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
2025 Form 10-K

25

Table of Contents

In recent years, both foreign and domestic banks, insurance companies and large investors have curtailed or ended 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. On January 20, 2025, U.S. President Donald Trump announced the withdrawal of the U.S. from the Paris Agreement. On January 7, 2026, U.S. President Donald Trump directed executive departments and agencies of the U.S. government to withdraw from a number of international organizations, including the UNFCCC.

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.