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Item 1A. Risk Factors.

The Company operates in a rapidly changing environment that involves a number of risks. The following highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company’s business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect its business.

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Risks Associated with Peabody’s Operations

The Company’s profitability depends upon the prices it receives for its coal.

The coal industry is competitive, highly regulated and subject to periods of significant volatility. Declines in coal prices could materially and adversely affect the Company’s operating results and profitability and the value of its coal reserves and resources.

Coal prices are dependent upon factors beyond the Company’s control, including:

•demand for electricity and capacity utilization of electricity generating units (whether coal or non-coal);

•changes in the fuel consumption and dispatch patterns of electric power generators, whether based on economic or non-economic factors;

•competition with, and the availability, quality and price of coal and alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power;

•governmental regulations and taxes, including air emission or other environmental standards for coal-fueled power plants and renewable-energy mandates or subsidies;

•demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of the Company’s metallurgical coal contracts;

•competing steel-making technologies that do not use coal as a manufacturing input, such as electric arc furnaces;

•the proximity, capacity and cost of transportation and terminal facilities;

•global supply levels and production costs of thermal and metallurgical coal;

•tariffs, quotas, duties or other adverse changes to trade policy;

•global economic conditions, including inflationary pressures and foreign currency exchange rates;

•geopolitical developments and conflicts;

•weather patterns, severe weather and natural disasters;

•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases; and

•technological developments related to alternative energy sources, coal-to-liquids or gas conversion processes and CCUS.

Thermal coal represented the majority of the Company’s coal sales by volume during 2025 and 2024, with most of these sales to electric power generators. The demand for coal used in electricity generation is affected by many of the factors described above, but primarily by (i) overall demand for electricity; (ii) the availability, quality and price of competing fuels; (iii) utilization of all electricity generating units and the relative cost of producing electricity from multiple fuels, including coal; (iv) environmental and other governmental regulations, including those related to permitting; (v) litigation and judicial decisions; (vi) sociopolitical views on coal; and (vii) the coal inventories of utilities. Gas-fueled generation has displaced and could continue to displace coal-fueled generation (particularly at older, less efficient units) as regulatory costs and other factors, such as declines in the price of natural gas, impact the operating decisions of electric power generators. Some electric power generators have elected to close coal-fueled generation units given ongoing pressure to shift away from coal generation. Many new U.S. power plants are being fueled by natural gas because gas-fired plants have been less expensive to construct and operate, are easier to permit based on emissions profiles and face fewer public and governmental objections. Increasingly stringent regulations and stagnant electricity demand in recent years have further reduced the number of new power plants being built. In recent years, these trends have lowered demand for coal consumed by electric power generators and could continue to reduce the volume of thermal coal that the Company sells and the prices that it receives, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.

The Company also produces metallurgical coal for the global steel industry, which accounted for approximately 27% and 25% of its revenue in 2025 and 2024, respectively. Changes in governmental policies, regulations and steel industry conditions, including steel demand, could reduce demand for the Company’s metallurgical coal. The demand for foreign-produced steel both in international and U.S. markets is influenced in part by tariff rates on steel. Tariffs may affect the Company’s customers to the extent their steel imports are curtailed as a result of imposed tariffs.

Demand for metallurgical coal is also affected by the cyclical nature of the steel industry, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites and plastics. The steel industry continues to adopt production methods that do not use coal, such as electric arc furnaces. Lower international demand for metallurgical coal would reduce the volume of metallurgical coal Peabody sells and the prices that it receives, thereby reducing revenues and adversely impacting earnings and the value of its coal reserves. Foreign government policies related to coal production and consumption could also negatively impact pricing and demand for the Company’s products.

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If a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenue and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts.

Most of the Company’s sales are made under coal supply agreements, which are important to the stability and profitability of its operations. These agreements often form the basis for developing the coal reserves and resources required to meet contractual commitments, particularly in the U.S. For the year ended December 31, 2025, 25% of the Company’s revenue was derived from coal supply agreements with its five largest customers, which were primarily supplied under 19 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2025 to 2028.

Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. Prices may be revised based on inflation or deflation, price indices and/or changes in the factors affecting production costs, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure to reach an agreement on price adjustments may allow either party to terminate the contract. The Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of its expiring contracts.

Coal supply agreements typically include force majeure provisions allowing temporary suspension of performance by the Company or the customer during specified events beyond the parties’ control. Some coal supply agreements allow customers to vary required purchase volumes during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request amendments to allow for such variation. Most of the Company’s coal supply agreements contain provisions requiring the delivery of coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in penalties, including price adjustments, rejection of deliveries or contract termination. Moreover, certain agreements allow the Company’s customers to terminate their contracts if regulatory changes restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.

On an ongoing basis, the Company discusses the extension of existing agreements or new long-term agreements with various customers, but these negotiations may not be successful and customers may not continue purchasing coal from the Company under long-term supply agreements

The profitability the Company realizes from its coal supply agreements depends on a variety of factors, and price adjustment mechanisms may increase its exposure to short-term coal price volatility. If a substantial portion of the Company’s coal supply agreements were modified or terminated, the Company could be materially adversely affected if it cannot secure alternate buyers at comparable profitability levels. Coal prices can vary by mining region and country, and the Company cannot predict future market conditions or ensure that expiring long-term coal supply agreements will be replaced at similar prices or profit margins. In addition, the Company’s revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand, oversupply, cost of competing fuels or environmental and other governmental regulations.

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Risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company.

The Company’s mining operations are subject to conditions that can impact workforce safety, delay coal deliveries or increase costs at particular mines for varying lengths of time. These conditions include:

•elevated gas levels;

•fires and explosions, including from methane gas or coal dust;

•accidental mine water discharges;

•adverse weather, flooding and natural disasters;

•hazardous events such as roof falls and high wall or tailings dam failures;

•seismic activity, ground failures, rock bursts or structural cave-ins or slides;

•key equipment failures;

•supply chain constraints or unavailability of equipment parts;

•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits and geologic conditions impacting mine sequencing;

•delays in moving longwall equipment;

•unexpected maintenance problems; and

•unforeseen delays in implementation of mining technologies.

The Company maintains insurance policies that provide limited coverage for certain of these risks, which may mitigate their impact. However, there can be no assurance as to the amount or timing of any insurance recovery related to such losses.

The Company’s take-or-pay arrangements could unfavorably affect its profitability.

The Company has substantial take-or-pay arrangements with its port access and rail transportation providers, predominately in Australia, totaling $1.0 billion, with terms ranging up to 19 years. These agreements require the Company to pay a minimum amount for the delivery of coal regardless of actual usage. Although certain contracts allow previously paid amounts to be applied to future deliveries, these provisions have limitations and the Company may be unable to apply all such amounts so paid. The Company may also be unable to use all capacity for which it has previously paid. Additionally, these arrangements can incentivize continued coal deliveries during times when suspending operations might otherwise be economically preferable, effectively converting variable costs into fixed operating costs.

The Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets.

The value of the Company’s assets has periodically been affected by numerous uncertain factors, some of which are beyond the Company’s control, including adverse economic conditions; declining coal-fired electricity generation; lower-than-expected coal pricing; technical or geological operating difficulties; an inability to economically extract its coal reserves and resources; and unanticipated increases in operating costs. These factors may trigger the recognition of impairment charges in the future, which could have a substantial impact on the Company’s results of operations. Given the volatile and cyclical nature of coal markets, it is reasonably possible that the Company’s current estimates of projected future cash flows from its mining assets may change in the near term, which may result in the need for adjustments to the carrying value of its assets.

The Company’s ability to operate effectively could be impaired if it loses key personnel or fails to attract qualified personnel.

Peabody relies on a number of key personnel, and the loss of any such individuals, absent an orderly transition could have a material adverse effect. The Company believes that its future success also depends on its continued ability to attract and retain highly skilled and qualified personnel in tight labor markets, particularly those with mining experience. Peabody cannot provide assurance that key personnel will remain employed by the Company or that it will be able to attract and retain qualified personnel in the future. Failure to retain key personnel or attract qualified personnel could have a material adverse effect on the Company.

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The Company could be negatively affected if it fails to maintain satisfactory labor relations.

As of December 31, 2025, the Company employed approximately 5,400 people (excluding employees at discontinued operations), including approximately 4,200 hourly employees. Certain employees are represented by labor unions under collective bargaining agreements that are renegotiated periodically, creating a risk that future agreements may not be renewed on reasonably satisfactory terms. Approximately 39% of its hourly employees were represented by organized labor unions and generated approximately 18% of the Company’s 2025 coal production. Positive relations with employees and, where applicable, organized labor are important to the Company’s success. Unionization of currently non-union operations could increase the risk of work stoppages, reduced productivity and higher labor costs. Also, failure to maintain good relations or successfully negotiate union contracts could potentially result in labor disputes, strikes, work stoppages, slowdowns or other production disruptions that could negatively impact the Company’s profitability.

The Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations.

U.S. federal and state laws and Australian laws require the Company to provide financial assurances for mine reclamation; payment of workers’ compensation obligations, such as black lung liabilities; coal lease obligations; and other miscellaneous obligations. The Company has historically satisfied these requirements through third-party surety bonds or letters of credit. In recent years, the Company has also utilized deposits with regulatory authorities or cash-backed bank guarantees. As of December 31, 2025, the Company had $997.2 million of outstanding surety bonds; $227.2 million of letters of credit; $208.7 million of cash-backed bank guarantees; and $134.9 million of deposits with regulatory authorities in order to provide required financial assurances for post-mining reclamation, workers’ compensation and other insurance obligations, coal lease-related and other obligations and performance guarantees, in addition to collateral for sureties. Under the Company’s agreement with the providers of its surety portfolio, the Company has $383.6 million in cash held in trust accounts for the benefit of certain surety providers as of December 31, 2025.

The Company’s financial assurance obligations may increase or become more costly, and surety bonds or letters of credit may not be available to the Company, particularly as some banks and insurance companies have announced reduced support for thermal coal producers and other fossil fuel companies. Alternative forms of financial assurance such as self-bonding have been severely restricted or terminated in most of the regions where the Company operates. Failure to retain or obtain surety bonds, bank guarantees or letters of credit, or to provide suitable alternatives, could have a material adverse effect on the Company. That failure could result from a variety of factors including:

•limited availability, higher cost or unfavorable terms for new surety bonds, bank guarantees or letters of credit;

•an inability to provide or fund collateral; or

•a lack of available fronting banks in certain countries where the Company must provide financial assurances but its primary surety providers are not licensed or admitted.

As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the Company has a surety transaction support agreement with the providers of its surety bond portfolio that expires on December 31, 2026. The Company’s failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect its business and results of operations. Failure to maintain adequate bonding could invalidate the Company’s mining permits and halt mining operations, which could result in its inability to continue as a going concern.

If the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated.

The Company’s asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. The Company’s management and engineers periodically review these estimates. If its assumptions do not materialize as expected, actual cash expenditures and costs that the Company incurs could be materially different than currently estimated. Moreover, regulatory changes could increase the Company’s obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from its assumptions, which could have a material adverse effect on its results of operations and financial condition.

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The Company’s mining operations are extensively regulated, which imposes significant costs, and future regulations and developments or differing interpretations of existing regulations could increase those costs or limit its ability to produce coal.

The coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:

•royalty rates;

•workplace health and safety;

•limitations on land use;

•mine permitting and licensing requirements;

•reclamation and restoration of mining properties after mining is completed;

•the storage, treatment and disposal of wastes;

•remediation of contaminated soil, sediment and groundwater;

•air quality standards;

•water pollution;

•protection of human health, plant-life and wildlife, including endangered or threatened species and habitats;

•protection of wetlands;

•the discharge of materials into the environment; and

•the effects of mining on surface water and groundwater quality and availability.

Regulatory agencies may order a mine to be temporarily or permanently closed following significant health or safety incidents. Any such closure of one of the Company’s mines would disrupt production and sales and could require substantial expenditures to resume operations, potentially resulting in a material adverse effect on the Company’s financial condition, results of operations and cash flows.

New legislation, regulations or orders, as well as new administrative regulations or new interpretations by the relevant government of existing laws, regulations and approvals, related to royalty rates, employee health and safety or the environment may be adopted and may materially adversely affect the Company’s mining operations, its cost structure or its customers’ ability to use coal and may also require significant operational changes or increased costs for the Company or its customers. Some of the Company’s coal supply agreements contain provisions allowing a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on the Company’s financial condition and results of operations.

For additional information about the various regulations affecting the Company, see the sections entitled “Regulatory Matters - U.S.” and “Regulatory Matters - Australia.”

If litigation challenging “climate superfund” laws is unsuccessful, the Company may be required to make significant payments for alleged climate change damages.

If the Company becomes subject to “climate superfund” laws and related regulations such as those recently passed in New York and Vermont, it may be required to make significant payments to the relevant governments. These payments may be material and could adversely affect the Company’s results of operations, financial condition or cash flows.

The Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company.

The Company uses hazardous materials in its operations and periodically generates limited quantities of hazardous waste. Various laws, including CERCLA and RCRA in the U.S. and similar laws in other countries where the Company operates, impose liability relating to contamination by hazardous substances. Such liability may include costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at currently or formerly owned or operated properties, as well as sites where hazardous substances were sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.

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The Company may be unable to obtain, renew or maintain permits necessary for its operations, or may only be able to do so subject to conditions that limit the manner in which it runs its operations, which would reduce its production, cash flows and profitability.

Mining operations require numerous governmental permits and approvals. The permitting rules (and the interpretations of these rules) are complex, frequently changing and often subject to discretionary interpretations by regulators, making compliance more difficult or impractical at times. As part of the permitting process, the Company is required to prepare and present to governmental authorities detailed information on the potential impacts of proposed exploration or mining activities. Members of the public, including non-governmental organizations and opposition groups, have statutory rights to comment upon, object to or legally challenge permit applications, environmental impact statements or mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

Additionally, the Company’s operations may be affected by sites of cultural heritage significance to indigenous peoples located within or near mining areas. Mining permits may be rescinded or modified, or the Company may voluntarily adjust its mining plans, to mitigate against adverse impacts to such sites.

The costs, liabilities and potential delays associated with permitting requirements and any related opposition may be substantial and could postpone or disrupt exploration or production, adversely affecting the Company’s coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or may include conditions that restrict the Company’s ability to efficiently and economically conduct its mining activities, any of which would materially reduce its production, cash flows and profitability.

Concerns about the impacts of coal combustion on global climate are increasingly leading to conditions that have affected and could continue to affect demand for the Company’s products or its securities and its ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.

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. As a result, governments in the U.S. and abroad are considering or implementing laws and regulations aimed at reducing such emissions.

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’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.

Numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting the Company’s future financial results, liquidity and growth prospects.

Several non-governmental organizations have undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation and have filed lawsuits to stop or delay coal mining activities, including challenges to individual coal leases and the federal coal leasing program. Other lawsuits contest historical and pending regulatory approvals, permits and processes necessary for coal mining or the operation of coal-fueled power plants, including so-called “sue and settle” actions that have resulted in additional regulatory restrictions or processes being implemented without formal rulemaking.

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These and similar developments have made it more costly and difficult to maintain the Company’s operations. Resulting cost increases and/or substantial or prolonged declines in coal prices could reduce the Company’s revenue and profitability, cash flows, liquidity, and value of its coal reserves and resources, and could result in material losses.

The Company’s hedging activities do not cover certain risks and may expose it to earnings volatility and other risks.

The Company is subject to coal price volatility, price volatility on diesel fuel utilized in its mining operations and foreign currency exchange rate risk associated with the Australian dollar. The Company hedges certain of these risks through hedging arrangements and may continue in the future to enter into hedging arrangements, including economic hedging arrangements, to manage these risks or other exposures. Since the Company’s existing hedging arrangements do not receive cash flow hedge accounting treatment, all changes in fair value are reflected in current earnings.

The Company’s future success depends upon its ability to continue acquiring and developing coal reserves and resources that are economically recoverable.

Recoverable reserves and resources decline as coal is produced, and the Company has not yet applied for the permits required or developed the mines necessary to use all reported reserves and resources. Moreover, the amount of coal reserves and resources described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Actual production, revenue and expenditures with respect to its coal reserves and resources may vary materially from estimates.

The Company’s future success depends upon it conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves and resources. The Company’s current strategy includes increasing its coal reserves and resources through acquisitions of leases and producing properties and continuing to use its existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of the Company’s coal reserves and resources, potentially creating conflicts with other mineral interest holders. These parties could prevent, delay or increase the cost of developing the Company’s coal reserves and resources or seek damages alleging impairment of their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2025, the Company leased a total of 42,167 acres from the federal government subject to those limitations.

Planned mine development projects and acquisition activities may not yield significant additional reserves and resources, and the Company may not succeed in developing additional mines. Most mining operations are conducted on properties owned or leased by the Company, and defects in title or boundaries could materially and adversely affect the Company’s right to mine and result in unanticipated costs. Developing reserves and resources requires the Company to own the rights to the related surface property and receive various governmental permits, which may not be granted or renewed in a timely manner or at all. The Company may be unable to secure new leases, obtain mining contracts for properties containing additional coal reserves and resources or maintain its leasehold interest in properties on which mining operations have not commenced or have not met minimum quantity or product royalty requirements. From time to time, the Company has experienced litigation with lessors of its coal properties and with royalty holders, and its permit applications and federal and state coal leases have been challenged, causing production delays.

To the extent that the Company’s existing sources of liquidity are insufficient to fund its planned mine development projects or coal reserve and resource acquisition activities, the Company may need to access capital markets, which may be unavailable or available only on unfavorable terms. If the Company is unable to fund these activities, it may not be able to maintain or increase its existing production rates and could be forced to change its business strategy, which could have a material adverse effect on its financial condition, results of operations and cash flows.

The Company faces numerous uncertainties in estimating its coal reserves and resources and inaccuracies in its estimates could result in lower than expected revenue, higher than expected costs and decreased profitability.

Coal is economically recoverable only when the price at which it can be sold exceeds the costs and expenses of mining and selling the coal. The costs and expenses of mining and selling the coal are determined on a mine-by-mine basis, and as a result, the price at which its coal is economically recoverable varies based on the mine. Forecasts of the Company’s future performance rely in part on estimates of its recoverable coal reserves and resources, which are based on engineering, economic and geological data assembled and analyzed by Company personnel and third-party experts, which includes various engineers and geologists. The Company's estimates are also subject to SEC regulations regarding classification of reserves and resources, including subpart 1300 of Regulation S-K. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and resources and new drilling or other data received.

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Estimating the quantity, quality and economically recoverable coal reserves and resources involves numerous uncertainties, many of which are beyond the Company’s control. Estimates depend on a variety of factors and assumptions that, if incorrect, may result in an estimate that varies considerably from actual results. These include:

•geologic and mining conditions that may not be fully identified by available exploration data and may differ from the Company’s experience in areas it currently mines;

•demand for coal;

•current and future market prices for coal, contractual arrangements, operating costs and capital expenditures;

•severance and excise taxes, royalties and development and reclamation costs;

•future mining technology;

•regulatory requirements;

•the ability to obtain, maintain and renew all required permits;

•employee health and safety considerations; and

•historical production from comparable areas.

The conversion of reported mineral resources to mineral reserves or the reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed. Actual coal tonnage recovered, as well as related revenue and expenditures, from identified reserve and resource areas or properties may vary materially from estimates. Thus, these estimates may not accurately reflect its actual reserves and resources. Any material inaccuracy in the Company’s estimates related to its coal reserves and resources could result in lower than expected revenue, higher than expected costs or decreased profitability which could materially and adversely affect its business, results of operations, financial position and cash flows.

Joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company’s operating standards.

The Company participates in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Regardless of whether the Company holds a majority interest or maintains operational control, its partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, the Company’s; (2) seek to block actions that the Company believes are in its or the joint venture’s best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, any of which may adversely impact the Company’s results of operations and its liquidity or impair its ability to recover its investments.

In jointly controlled or non-managed ventures, the Company may provide expertise and advice but have limited control over compliance with its operational standards. The Company also utilizes contractors across its mining platform, and may be similarly limited in its ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to those of the Company could unfavorably affect safety results, operating costs and productivity and adversely impact its results of operations and reputation.

The Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect.

The Company provides postretirement health and life insurance benefits to eligible retirees, and its total accumulated postretirement benefit obligation was a liability of $121.1 million as of December 31, 2025, including $11.9 million classified as a current liability.

These obligations are actuarially determined using assumptions regarding discount rates, future cost trends, mortality tables, demographics and expected rates of return on plan assets. The discount rate is based on a hypothetical bond portfolio designed to approximate the timing of future cash flows necessary to service its liabilities. A decrease in the discount rate could increase the present value of these obligations, thereby raising future costs. The Company also makes assumptions about future medical cost trends based on historical claims data. If these assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could differ materially from its current estimates. Regulatory changes or modifications to government-provided healthcare benefits could further increase the Company’s obligation.

The Company develops its actuarial determinations of liabilities using actuarial mortality tables it believes best fit its population’s actual results. In deciding which mortality tables to use, the Company periodically reviews its population’s actual mortality experience and evaluates results against its current assumptions as well as consider recent mortality tables published by the Society of Actuaries Retirement Plans Experience Committee. If the Company’s mortality tables do not anticipate its population’s mortality experience as accurately as expected, actual cash expenditures and costs that the Company incurs could differ materially from its current estimates.

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Changes to trade policy, including tariff and customs regulations, or failure to comply with such regulations may have an adverse effect on the Company’s business, financial condition and results of operations.

As a multinational corporation, Peabody conducts a significant amount of business that could be impacted by changes in U.S. or foreign trade policies, including tariffs, international trade agreements and economic sanctions. Such changes may adversely impact the U.S. economy or certain sectors thereof; the economy of another country in which the Company operates or certain sectors thereof; or the coal industry and the global demand for coal. The Company cannot predict the extent to which the U.S. or other countries will impose new or additional quotas, duties, tariffs, taxes or other similar restrictions upon the import or export of its products, nor can it predict the terms of future trade policies or renegotiated trade agreements. The continued adoption or expansion of trade restrictions, the emergence of a trade war or other governmental actions related to tariffs or trade agreements could adversely affect demand for the Company’s coal, increase its costs, impact its customers and weaken the economies in which the Company operates. Any of these developments could have a material adverse effect on the Company’s business, financial condition and results of operations.

Peabody is exposed to risks associated with political or international conflicts.

Political or international conflicts can result in worldwide geopolitical and macroeconomic uncertainty. The Company cannot predict the ultimate impacts related to such conflicts. Prolonged or expanding conflicts could adversely affect macroeconomic conditions, including but not limited to, volatile coal pricing, trade flow disruptions resulting from sanctions, supply chain disruptions, increased costs, and decreased business spending. Furthermore, political or international conflicts could disrupt Peabody’s or its business partners’ global technology infrastructure, including through cybersecurity attacks or cyber-intrusions; lead to adverse changes in international trade policies and relations; increase regulatory enforcement; impede Peabody’s ability to implement and execute its business strategy; heighten terrorist activity risks; amplify exposure to foreign currency fluctuations; and cause constraints, volatility or disruption in capital markets. Any of these developments could have a material adverse effect on the Company’s business, results of operations, cash flows and financial condition.

Peabody could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if it experiences cybersecurity attacks or other security breaches that disrupt its operations or result in the dissemination of proprietary or confidential information about the Company, its customers or other third-parties.

Peabody has implemented physical and cybersecurity protocols intended to protect its operations, the Company’s and its counterparties’ confidential information and information related to identifiable individuals against unauthorized access. Despite such efforts, the Company may be subject to security breaches which could result in unauthorized access to its facilities or the information it is trying to protect.

Because Peabody operates energy-related assets, it faces heightened cybersecurity risks from sophisticated adversaries, including nation-state actors. The Company’s information systems, and those of key third parties, are vulnerable to malicious and intentional cyberattacks involving malware (such as ransomware), accidental or inadvertent incidents, the exploitation of security vulnerabilities or “bugs” in software or hardware, social engineering/phishing attacks, and insider malfeasance, among other scenarios. Cyberattacks are increasing in frequency and sophistication, due in part to the growing use of artificial intelligence (AI) tools. The use of AI by the Company, its customers or third parties may introduce additional vulnerabilities. As attack methodologies evolve rapidly and may evade detection, Peabody may be unable to anticipate, prevent, identify, investigate or remediate future incidents with its current resources.

Unauthorized physical access to Company facilities or electronic access to its information systems could result in, among other things, unfavorable publicity, litigation (including class actions), regulatory investigations or enforcement actions, loss of competitive advantages, operational disruptions, loss of customers, financial obligations for damages related to data theft or misuse and significant investigation and remediation costs. Any of these outcomes could have a substantial impact on the Company’s results of operations, financial condition or cash flows.

Peabody’s information and operational technology systems may be adversely affected by disruptions, damage, failure and risks associated with implementation and integration, including of new technologies.

Peabody could experience system or network disruptions if new or upgraded information or operational technology systems are defective, improperly installed or not effectively integrated into its operations. System modification failures could have a material adverse effect on the Company’s business, financial position and results of operations and could, if not successfully implemented, adversely impact the effectiveness of its internal control over financial reporting.

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Peabody initiated the process of upgrading its enterprise resource planning (ERP) system, which is expected to be completed during the first quarter of 2026. The upgraded ERP system may necessitate the implementation of new internal controls and modifications to existing internal control frameworks and procedures. Additionally, any disruptions in the upgrade process or operation of the upgraded ERP system could lead to business interruptions, negatively affecting the Company’s ability to serve customers and manage its operations efficiently, which could have a material adverse impact on the Company’s business, financial position and results of operations. Peabody has taken steps to mitigate these risks, including thorough testing and continuous monitoring of the upgrade process. However, there can be no assurance that these measures will be successful in preventing potential disruptions.

Further, Peabody increasingly relies on its information technology infrastructure for electronic communications among its worldwide operations, personnel, customers and suppliers, due in part to remote working and flexible working arrangements. These information technology systems, some of which are managed by third parties outside of the Company’s control, have been and may in the future be susceptible to damage, disruptions or shutdowns. As threats to information technology infrastructure evolve rapidly, existing controls and procedures may become inadequate, requiring the Company to devote additional resources to modify or enhance its systems in the future.

The Company is incorporating artificial intelligence technologies into its processes and these technologies may present business, compliance and reputational risks.

Peabody increasingly utilizes AI, machine learning, and automated decision-making to improve its processes. Issues arising from the development or use of these technologies, combined with an evolving and uncertain regulatory environment, may lead to increased governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability, or other adverse consequences that could adversely affect the Company’s business, results of operations and financial condition.

AI and machine-learning technology may also be improperly used by employees without the Company’s knowledge. Such misuse could result in unauthorized use or disclosure of confidential or proprietary information, or the generation of content that appears accurate but is in fact incorrect, misleading, biased, or otherwise flawed. These outcomes could harm Peabody’s reputation and expose the Company to additional risks. As AI becomes more prominent in the Company’s operations, Peabody may need to invest additional resources to enhance digital security, train employees, deploy protective technologies and engage third-party experts. The Company may face challenges in anticipating or mitigating all potential harms associated with AI.

It is not possible to predict all risks related to the use of AI, machine-learning and automated decision-making. Changes in regulatory frameworks or stakeholder expectations may limit the Company’s ability to develop or use such technologies or subject Peabody to liability. Failure to successfully integrate AI into business processes or to keep pace with rapidly evolving AI technologies, including attracting and retaining talented data scientists, data engineers, and programmers, could place Peabody at a competitive disadvantage.

The Company is subject to various general operating risks which may be fully or partially outside of its control.

The Company’s results of operations, financial position or cash flows could be adversely impacted by various general operating risks which may be fully or partially outside of its control. Such risks stem from internal and external sources and include:

•global economic recessions and/or credit market disruptions;

•rising inflation;

•pandemics or other widespread illnesses;

•deterioration of the creditworthiness of its customers or financial counterparties, and their ability to perform under contracts;

•inability of suppliers and other counterparties, including those related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the terms of their contracts with the Company;

•reduced availability or increased costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;

•disruptions or increased costs in coal transportation networks, including rail, barge, trucking, overland conveyor, ports and ocean-going vessels;

•new or increased forms of taxation imposed by federal, state, provincial or local governmental authorities, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes; and

•uncertainties associated with the Company’s global operating platform, including country and political risks, international regulatory requirements, and foreign currency fluctuations.

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Risks Related to Peabody’s Capital Structure

The Company may be able to incur more debt, including secured debt, which could increase the risks associated with its indebtedness.

As of December 31, 2025, the Company had approximately $320.0 million of unsecured indebtedness outstanding, excluding finance leases and debt issuance costs, and an additional $320.0 million in revolving commitments.

The Company may be able to incur additional indebtedness in the future, including secured debt. Although covenants under agreements governing the Company’s other indebtedness, including its revolving credit facility and finance leases, limit the Company’s ability to incur additional indebtedness, these restrictions are subject to a number of qualifications and exceptions. In addition, the agreements governing the Company’s other indebtedness do not limit the Company from incurring obligations that do not constitute indebtedness as defined therein.

The degree to which the Company is leveraged could have important consequences, including, but not limited to:

•making it more difficult to pay interest and satisfy its debt obligations;

•increasing borrowing costs;

•increasing vulnerability to general adverse economic, industry or regulatory conditions;

•requiring the dedication of a substantial portion of operating cash flow to be used for debt service, thereby reducing funds available for working capital, capital expenditures, business development or other general corporate requirements;

•limiting the Company’s ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements;

•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other forms of financing, particularly in weak credit markets;

•reducing flexibility in planning for, or reacting to, changes in its business and in the coal industry;

•causing a decline in the Company’s credit ratings; and

•placing the Company at a competitive disadvantage compared to less leveraged competitors.

The terms of the agreements and instruments governing the Company’s debt and surety bonding obligations impose restrictions that may limit its operating and financial flexibility.

The agreements governing the Company’s unsecured debt, revolving credit facility and surety bonding obligations contain certain restrictions and covenants which could adversely affect the Company’s ability to operate its business, as well as significantly affect its liquidity, and therefore could adversely affect its business, financial condition and results of operations.

These restrictions and covenants may limit, among other things, the Company’s ability to:

•incur additional indebtedness;

•pay dividends on or make distributions in respect of stock or make certain other restricted payments, such as share repurchases;

•make capital or other investments;

•enter into agreements that restrict distributions from certain subsidiaries;

•sell or otherwise dispose of assets;

•use for general purposes the cash received from certain allowable asset sales or disposals;

•enter into transactions with affiliates;

•create or incur liens;

•merge, consolidate or sell all or substantially all of its assets; and

•receive dividends or other payments from subsidiaries in certain cases.

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The Company’s ability to comply with these restrictions or covenants may be affected by events beyond its control. A breach of any of these restrictions or covenants together with the expiration of any applicable cure period, could result in a default. If any such default occurs, subject to applicable grace periods, the holders of the Company’s indebtedness may elect to declare such indebtedness, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. In addition, the lenders under the Company’s revolving credit facility could elect to require the cash collateralization of any outstanding letters of credit. If the Company’s indebtedness is accelerated, it may not have sufficient cash flows and capital resources to repay such indebtedness or be able to restructure or refinance such indebtedness. Even if the Company were able to restructure its indebtedness or obtain additional capital or new or replacement financing, it may not be on commercially reasonable terms or on terms that are acceptable to the Company.

In this regard, if the Company experiences a default under the terms of its unsecured debt, revolving credit facility or surety bonding obligations for any reason, its business, financial condition and results of operations could be materially and adversely affected. In addition, complying with such terms may make it more difficult for the Company to successfully execute its business strategy, including by making it more difficult to compete against competitors who are not subject to such financial restrictions.

The number and viability of financing and insurance alternatives available to the Company may be significantly impacted by unfavorable lending and investment policies adopted by financial institutions and insurance companies in response to concerns about the environmental impacts of coal combustion, and negative views around the Company’s environmental and social practices and related governance considerations could harm its perception among investors or result in the exclusion of its securities from consideration by those investors.

Certain banks, other financing sources and insurance companies have limited financing and insurance coverage for the development of new coal-fueled power plants and for coal producers and utilities that derive a majority of their revenue from coal, particularly thermal coal. This may adversely impact the future global demand for coal. Increasingly, such decisions are influenced by non-standardized sustainability scores, ratings and benchmarking studies provided by various organizations evaluating environmental, social and governance matters. Further, there have been efforts in recent years by members of the general financial and investment communities, including investment advisors, sovereign wealth funds, public pension funds, universities and other institutional investors, to promote divestment from fossil fuel extraction companies or companies with low sustainability ratings, and pressure lenders to restrict financing to such companies.

These efforts may have adverse consequences, including, but not limited to:

•restricting the Company’s access to capital and financial markets in the future;

•reducing the demand for, and the price of, its equity securities;

•increasing borrowing costs;

•causing a decline in the Company’s credit ratings;

•reducing the availability of, and/or increasing the cost of, third-party insurance;

•increasing the Company’s retention of risk through self-insurance;

•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and

•limiting flexibility in business development activities such as mergers, acquisitions and divestitures.

Various states have enacted, or are considering enacting, laws to sanction, or require public funds to divest from, financial institutions that restrict investments in fossil fuel companies based off of extra-regulatory environmental or social factors, or to require such institutions to provide “fair access” to financial services to companies regardless of industry. While similar federal regulations had been proposed in the past, they have either been suspended or repealed, and the future direction of such efforts remains uncertain. As such, the final status of efforts to divest or promote the divestment from the fossil fuel extraction market is unclear, but any such efforts may adversely affect the demand for and price of the Company’s securities and impact the Company’s access to the capital and financial markets.

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Risks Related to Ownership of Peabody’s Securities

The price of Peabody’s securities may be volatile.

The price of Peabody’s common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of its Common Stock regardless of the Company’s operating performance, including, among others:

•general market conditions;

•actual or anticipated fluctuations in Peabody’s quarterly and annual results and those of industry peers;

•industry cycles and trends;

•mergers and strategic alliances in the coal industry;

•changes in government regulation;

•potential or actual military conflicts or acts of terrorism;

•securities analysts’ failure to publish research or to accurately forecast the Company’s results;

•market perception of development projects;

•changes in accounting principles;

•announcements concerning Peabody or its competitors;

•trading activity by insiders or significant shareholders;

•limited or excess trading liquidity;

•operational incidents; and

•investor sentiment regarding the Company’s policies or efforts on environmental, social or governance matters.

As a result of these factors, investors in Peabody’s Common Stock may be unable to resell their stock at or above the price they paid or at all. Further, Peabody could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on its results of operations.

Peabody’s Common Stock is subject to dilution and may be subject to further dilution in the future.

Peabody’s Common Stock is subject to dilution from its convertible senior debt and its long-term incentive plan. In addition, Peabody may issue equity securities in connection with future investments, acquisitions or capital raising transactions. Such issuances or grants could constitute a significant portion of the then-outstanding Common Stock, which may result in significant dilution in ownership of Common Stock. Additionally, if Peabody does issue equity securities, new investors could gain rights preferences and privileges senior to the holders of Peabody’s Common Stock.

There may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests.

Circumstances may arise in which the interests of a significant stockholder may be in conflict with the interests of the Company’s other stakeholders. A significant stockholder may exert substantial influence over the Company to cause the Company to take action that aligns with their interests, for example, to pursue or prevent acquisitions, divestitures or other transactions, including the issuance or repurchase of additional shares or debt, that, in its judgment, could enhance its investment in Peabody or another company in which it invests. Such transactions may advance the interests of the significant stockholder and not necessarily those of other stakeholders, which might adversely affect Peabody or other holders of its Common Stock or debt instruments.

The future payment of dividends on Peabody’s stock or future repurchases of its stock is dependent on a number of factors and cannot be assured.

In 2023, the Company’s Board of Directors approved a shareholder return framework that includes share repurchases and cash dividends, and a share repurchase program authorizing repurchases of up to $1.0 billion of the Company’s common stock. Under the share repurchase program authorized by the Board, the Company may purchase shares of common stock from time to time at management’s discretion through open market purchases, privately negotiated transactions, block trades, accelerated or other structured share repurchase programs, or other means. The manner, timing and pricing of any share repurchase transactions will be based on a variety of factors, including market conditions, applicable legal requirements and alternative opportunities that the Company may have for the use or investment of capital. Future cash dividends and repurchases will depend upon Peabody’s earnings, economic conditions, liquidity and capital requirements, and other factors, including its leverage and other financial ratios. Accordingly, the Company cannot make any assurance that future dividends will be paid or future repurchases will be made.

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General Risk Factors

Acquisitions and divestitures are a potentially important part of the Company’s long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits.

Based on its set of investment criteria, the Company has engaged in, and may continue to pursue, acquisition or divestiture activity intended to enhance shareholder value or provide potential strategic benefits. If the Company fails to accurately estimate the future results and value of these assets or any other acquired or divested business or assets and the related risk associated with such a transaction, or are unable to successfully close any acquisition or integrate the businesses or assets it acquires, its business, financial condition or results of operations could be negatively affected. Moreover, any transactions the Company pursues could materially impact its liquidity and an acquisition could increase capital resource needs and may require it to incur indebtedness, seek equity capital or both. The Company may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in its assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions.

The outcome of arbitration proceedings related to the termination of agreements to acquire properties from Anglo American plc could adversely affect the Company’s business, results of operations, and its financial condition.

On November 25, 2024, Peabody entered into definitive agreements (the Purchase Agreements) with Anglo American plc, a United Kingdom public limited company (Anglo), to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia. On August 19, 2025, Peabody terminated the Purchase Agreements following Peabody’s prior delivery of a notice of a Material Adverse Change (MAC) as a result of an ignition event at the Moranbah North mine on March 31, 2025, which had led to the closure of the mine. Following Peabody’s termination of the Purchase Agreements, Anglo returned $29.0 million of the $75.0 million deposit previously paid by Peabody, and Peabody has demanded the outstanding portion of the deposit also be returned.

On September 23, 2025, various subsidiaries of Anglo initiated International Chamber of Commerce arbitration proceedings in London, United Kingdom, against Peabody and certain of its affiliates. Anglo’s complaint alleges, among other things, that Peabody wrongfully terminated the Purchase Agreements and seeks, among other things, declarations that the ignition event at the Moranbah North mine did not constitute a MAC, as well as damages for losses in an unspecified amount, plus costs and interest.

The outcome of these proceedings is inherently uncertain and may materially and adversely affect the Company’s business, results of operations, and/or its financial condition. While the Company remains confident that a MAC occurred, entitling the Company to terminate the Purchase Agreements, arbitration outcomes are unpredictable and may include monetary damages or other remedies unfavorable to the Company. Additionally, the costs associated with the arbitration process, including legal fees and potential settlement or award payments, could be significant. There can be no assurance as to the timing or final resolution of the arbitration proceedings.

The Company may not be able to fully utilize its deferred tax assets.

The Company is subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2025, the Company had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $1,616.5 million and $171.4 million, respectively, as described further in Note 7. “Income Taxes” to the accompanying consolidated financial statements. At that date, the Company also had recorded a valuation allowance of $1,469.2 million.

The Company’s ability to use its U.S. NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. An ownership change generally occurs if certain stockholders increase their aggregate percentage ownership of a corporation’s stock by more than 50 percentage points over their lowest percentage ownership at any time during the testing period, which is generally the three-year period preceding any potential ownership change.

Although the Company may be able to utilize some or all of those deferred tax assets in the future if it has income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that it will be able to do so. Further, the Company is presently unable to record tax benefits on future losses in the U.S. until such time as sufficient income is generated by its operations in those jurisdictions to support the realization of the related net deferred tax asset positions. The Company’s results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.

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Peabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

Provisions contained in Peabody’s certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire it, even if doing so might be beneficial to its stockholders. Provisions of Peabody’s by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of its Common Stock and may have the effect of delaying or preventing a change in control.

Diversity in interpretation and application of accounting literature in the mining industry may impact the Company’s reported financial results.

The mining industry has limited industry-specific accounting literature and, as a result, the Company understands diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, the Company may need to restate its reported results if the resulting interpretations differ materially from its current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of the Company’s significant accounting policies.

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

Risk Management and Strategy

Peabody uses digital technology to conduct its business operations and engage with its customers, vendors and partners. As the Company invests in technologies such as cloud, analytics, automation and artificial intelligence, it strives to provide the necessary controls to protect these digital assets from continuously evolving cybersecurity risks.

Peabody’s cybersecurity strategy emphasizes reduction of cybersecurity risk exposure and continuous improvement of its controls and policies based on industry recognized best practices for cybersecurity and information technology, including the National Institute of Standards and Technology (NIST) Cybersecurity Framework (CSF). This strategy includes: (i) proactive management of cybersecurity risk to ensure compliance with contractual, legal and regulatory requirements; (ii) performing due diligence on third parties to ensure they have sound cybersecurity practices in place; (iii) ensuring essential business services remain available during a business disruption; (iv) annual cybersecurity assessments to include NIST CSF maturity assessments, penetration testing and red team assessments, as well as table top exercises with subsequent remediation of key findings; (v) participation in Information Sharing and Collaboration industry groups; (vi) maintaining an updated cybersecurity policy and incident response plan; (vii) exercising cyber incident response plans and risk mitigation strategies to address potential incidents should they occur; and (viii) annual cybersecurity awareness training for all employees and directors, including formal training and simulated phishing events.

Third-party experts are engaged to conduct NIST CSF maturity assessments, penetration testing assessments, periodic red team assessments and table top exercises. At a minimum, at least one of these assessments is conducted annually by a third-party expert. Peabody also engages a third-party expert to assess the risk of its business and operational vendors.

Peabody’s enterprise risk management (ERM) framework considers cybersecurity risk alongside other company risks as part of the Company’s overall risk assessment process. The ERM team collaborates with the Chief Information Officer (CIO) to gather insights for assessing, identifying and managing cybersecurity threat risks, their severity and potential mitigations.

Governance

Peabody’s Board of Directors maintains direct oversight over cybersecurity risks and oversees an enterprise-wide approach to risk management, designed to support the achievement of organizational objectives to enhance long-term performance and stockholder value.The Board, as a whole, and through its committees, is responsible for the oversight of risk management and Peabody’s management is responsible for the day-to-day management of the risks the Company faces.Senior leadership, including Peabody’s CIO, regularly briefs the Board on cybersecurity matters and the Board is informed of cybersecurity incidents deemed to have a moderate or higher business impact, even if such incidents are determined to be immaterial, on an ongoing basis.

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Peabody’s global cybersecurity department is responsible for overall cybersecurity strategy, policy, operations and cybersecurity incident response.Team members who support the Company’s cybersecurity program invest in ongoing skills development including maintaining industry recognized certifications such as the ISC2 CISSP, GIAC GCIH, Comp TIA Security+, as well as platform specific certifications focused on Peabody’s current cybersecurity infrastructure.

Impact of cybersecurity risks on business strategy, results of operations or financial condition

While Peabody has experienced cybersecurity incidents in the past, to date none have materially affected the Company’s business strategy, results of operations or financial condition. Peabody continues to invest in the cybersecurity and resiliency of its networks and to enhance its internal controls and processes, which are designed to help protect its systems and infrastructure, and the information they contain.

For more information regarding the risks the Company faces from cybersecurity threats, refer to Item 1A. “Risk Factors.”

Item 2. Properties.

Coal Reserves and Resources

Information concerning the Company’s mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. Subpart 1300 of Regulation S-K requires disclosure of mineral resources, in addition to mineral reserves, both in the aggregate and for each of the Company’s individually material mining properties. The Company’s coal reserves and resources are estimated by individuals deemed Qualified Persons (QP) according to the standards set forth in subpart 1300 of Regulation S-K.

Mineral resources and reserves are defined in subpart 1300 of Regulation S-K as follows:

•Mineral resource. A concentration or occurrence of material of economic interest in or on the earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.

•Mineral reserve. An estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of a QP, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.

Under subpart 1300 of Regulation S-K, mineral resources may not be classified as mineral reserves unless the determination has been made by a QP that such mineral resources can be the basis of an economically viable project. The conversion of reported mineral resources to mineral reserves should not be assumed.

Coal resources are estimated from geological models constructed from an extensive historical database of drill holes and the Company’s ongoing drilling program. Data from individual drill holes is compiled in a computerized drill-hole database, including the depth, thickness and, where core drilling is used, the quality of the coal observed. For coal deposits, the density of a drill pattern is one of the important factors which determine whether the related coal will be classified as measured, indicated or inferred.

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Mineral resource classifications are differentiated under subpart 1300 of Regulation S-K, in part, as follows:

•Measured resource. That part of a mineral resource with the highest level of geological confidence; quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit.

•Indicated resource. That part of a mineral resource with a level of geological confidence between that of measured and inferred resources; quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit.

•Inferred resource. That part of a mineral resource with the lowest level of geological confidence; quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability.

The geological confidence surrounding resource classification is first determined by a drill hole spacing analysis performed by a QP using geostatistical techniques. A QP may also use qualitative analysis to determine the geologic confidence based on historical experience with a specific coal deposit. Resources are further evaluated using a set of structure and quality parameters to determine the reasonable prospects for economic extraction. The structure parameters include coal thickness, depth, dipping angle and strip ratio, among others. The quality parameters include ash and sulfur content, yield, and heat value, among others. Each coal deposit is different with respect to geology, potential mining methods, logistics and markets. The cut-off criteria of those structure and quality parameters are different for each deposit, and a QP generally forms those criteria based upon experience with the Company’s existing mining operations or adjacent operations with similar geological conditions. Other factors, such as coal control, or surface and underground obstacles are also considered in connection with resource estimates. The reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed.

The economically mineable part of a measured coal resource is considered a proven coal reserve and has the highest degree of assurance of economic viability. The economically mineable part of indicated, and sometimes measured, coal resources are considered probable coal reserves and have a moderate degree of assurance of economic viability.

For each mine or future mine, the Company develops Life-of-Mine (LOM) plans which employ a market-driven, risk-adjusted capital allocation process to guide long-term mine planning of active operations and development projects. QPs rely on LOM planning as an integral process for coal reserve and resource estimates. The LOM plans consider dilution and losses during mining and processing as recoverability factors to estimate saleable coal. The LOM plans are developed in consideration of market demands and operational constraints. The LOM plans project, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities and sales prices. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated to determine the economically viable coal in the LOM plans. Other factors impacting the assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in market conditions and mine closure activities.

The Company periodically reviews and updates coal reserve and resource estimates to reflect the production of coal, new drill hole data, the effects of mining activities, analysis of new engineering and geological data, changes in property control, modification of mining methods and other factors.

Mineral Rights

The Company controls coal rights through direct ownership and numerous lease agreements with government or private parties. The majority of the Company’s coal reserves and resources are controlled through lease agreements with the U.S. and Australian governments. In addition, surface rights are required to conduct certain mining-related activities. The Company holds the majority of the required surface rights to meet mid- to long-term production requirements. The additional surface rights to meet long-term production requirements are expected to be acquired as needed.

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The Company is party to numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover Peabody’s principal reserves in the Powder River Basin and other reserves and resources in Alabama, Colorado and New Mexico. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The OBBBA cuts federal coal royalty rates to 7% for both surface and underground mines starting July 4, 2025, and lasting through September 30, 2034.

The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2025, the Company leased 1,610 acres of federal land in Alabama, 1,360 acres in Colorado, 282 acres in New Mexico and 38,915 acres in Wyoming, for a total of 42,167 acres nationwide subject to those limitations. The Company also leases coal-mining properties from various state governments in the U.S.

Private U.S. coal leases normally have terms of between 10 and 20 years and usually give the Company the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many private U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of private U.S. leases are normally extended by active production at or near the end of the lease term. Private U.S. leases containing undeveloped coal properties may expire or these leases may be renewed periodically.

Mining and exploration in Australia are generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or court process. Surface rights are typically acquired directly from landowners through agreement or court determination, subject to some exceptions.

Pricing

The pricing information used in support of the Company’s coal reserve and resource estimates include internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected supply and demand fundamentals for steel production and electricity generation, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress-tested against independent third-party research (not commissioned by the Company) to confirm the conclusions reached through analytical processes, and that price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review.

Below is a description of some of the specific factors that the Company evaluates in developing price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in the price forecasts and realized factors could cause actual pricing to differ from the forecasts.

Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand and economic activity, inter-fuel competition in the electric power generation mix (such as from natural gas and renewable sources), changes in capacity (additions and retirements), competition from other producers, coal stockpiles and policy and regulations. Supply considerations impacting pricing include coal reserve and resource positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (greenfield developments or extensions at existing mines).

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In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production, new natural gas combined cycle generation capacity and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices.

Internationally, thermal coal-fueled generation also competes with alternative forms of electricity generation. The competitiveness and availability of generation fueled by natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Colombia, the U.S., Russia and South Africa, among others.

Metallurgical. Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions, government policies, demand for steel and competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by the coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.

Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, as well as country-specific policies restricting or promoting domestic supply. The competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others, is also an important price consideration.

In addition to the factors noted above, the prices which may be obtained at each mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.

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Costs

The cost estimates used to establish LOM plans are generally made according to internal processes that project future costs based on historical costs and expected trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax and other mining-related costs. Estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the Company’s operating costs include:

•Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Company geologists conduct the exploration program and provide geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods where the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control.

•Scale of operations and the equipment sizes. For surface mines, dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. Longwall operations are generally more cost-effective than room-and-pillar operations for underground mines.

•Commodity prices. For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof control represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models used to establish reserve and resource estimates.

•Target product quality. By targeting a premium quality product, mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In the Company’s LOM plans, product qualities are estimated to correspond to existing contracts and forecasted market demands.

•Transportation costs. Transportation costs vary by region. Most of the Company’s U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in U.S. thermal cost estimates. The Company’s seaborne operations typically sell coal at designated ports. The estimated costs for seaborne operations include rail and barge transportation and related fees at ports.

•Royalty costs. Royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historical costs.

•Exchange rates. Costs related to the Company’s Australian production are predominantly denominated in Australian dollars, while the Australian coal exported is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.

Summary of Coal Reserves and Resources

Peabody controlled an estimated 2.0 billion tons of coal reserves and 3.5 billion tons of coal resources as of December 31, 2025. Approximately 98% of the Company’s coal reserves and 95% of the Company’s coal resources are held under lease, and the remainder is held through fee ownership.

The following tables summarize the Company’s estimated coal reserves and resources as of December 31, 2025. The quantity of the coal resources is estimated on an in situ basis as attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as attributable to Peabody. The coal reserves and resources are reported on selected key quality parameters and on different moisture bases generally referenced by sales contracts for each mining property.

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SUMMARY COAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2025 (1)

(Tons in millions)

Peabody

Stage Mining Method Coal Type

P Producing S Surface Mine T Thermal

I Idle U Underground Mine C Coking

D Development P Pulverized Coal Injection

E Exploration

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SUMMARY COAL RESOURCES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2025 (1)

(Tons in millions)

Measured and Indicated Peabody

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Individual Property Disclosure

To determine the Company’s individually material mining operations in accordance with subpart 1300 of Regulation S-K, management considered both quantitative and qualitative factors, assessed in the context of the Company’s overall business and financial condition. Such assessment included the Company’s aggregate mining operations on all of its mining properties, regardless of the stage of production or the type of coal produced. Quantitative factors included, among others, mining operations’ relative contributions to the Company’s aggregate historical and estimated revenue, cash flows, and Adjusted EBITDA (as defined in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”) Qualitative factors may include, as applicable, strategic priorities, the regulatory environment, capital expansion plans and the long-term pricing outlook. The Company concluded that as of December 31, 2025, its individually material mines are North Antelope Rochelle Mine (NARM), Wilpinjong Mine and Centurion Mine. The Company will update its assessment of individually material mines on an annual basis.

The information that follows relating to such individually material mines is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (TRSs) relating to such properties prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein.

The changes for NARM and Centurion from the previous years are not material, thus no updates for the TRSs are included in this filing. Reference should be made to the full text of the TRS for NARM, incorporated herein by reference and made a part of Peabody’s Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 18, 2022. Reference should be made to the full text of the TRS for the Centurion Mine, incorporated herein by reference and made a part of Peabody’s filing on Form 8-K filed with the SEC on October 15, 2024.

The Wilpinjong Mine added 43 million tons of coal reserves, mainly from the exploration license EL9399, partially offset by production depletion. Reference should be made to the full text of the TRS for Wilpinjong Mine, incorporated herein by reference and made a part of this Annual Report on Form 10-K. The relevant TRS for Wilpinjong Mine is included as Exhibit 96.2 to this Annual Report on Form 10-K, and specific sections of such TRS are referenced below using the corresponding exhibit number.

North Antelope Rochelle Mine

NARM is a production-stage surface coal mine located sixty-five miles south of Gillette, Wyoming, USA. NARM is situated in the Gillette Coal Field on the east flank of the Powder River Basin. NARM began operations in 1999 after Peabody combined its interests in the formerly separate North Antelope Mine and Rochelle Mine.

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NARM extracts coal from the Wyodak-Anderson coal seam, which ranges from 60- to 80-feet thick and lies from 120 to 460 feet below the surface in the mining area. The Company has secured mineral rights through federal and state lease agreements which cover 30,159 acres. The typical royalty rate for federal and state coal leases is 12.5% of realized revenue. The OBBBA cuts federal coal royalty rates to 7% for both surface and underground mines starting July 4, 2025, and lasting through September 30, 2034. Generally, the leases continue indefinitely with periodic renewal, provided there is diligent coal production or other development within the lease area. As of December 31, 2025, all required licenses and permits were in place for the operations of NARM.

The mining operation consists of multiple open pits in four main mining areas, which allows for quality blending and other optimization strategies. Overburden is removed by dragline, truck and shovel, dozer and cast blasting methods. Coal is hauled by truck to one of five dump locations, where it is then crushed and conveyed to silos adjacent to rail loadouts for customer delivery. Coals of varying characteristics may be blended at a central blending facility along the loadout rail loop. Coal is sold unwashed, as a run-of-mine (ROM) product. NARM coal is well recognized for domestic thermal power generation.

The key supporting infrastructure for NARM includes rail services provided by the BNSF Railway Company and Union Pacific Corporation, road access via interstate and state highways and roads, electrical power from a dedicated substation with 230 kilovolt and 69 kilovolt transmission lines, and water supply from a mine dewatering system and deep wells. The mining industry in the Powder River Basin anchors numerous communities from which the mine attracts qualified personnel.

The property, plant, equipment and mine development assets of NARM had a net book value of approximately $362 million at December 31, 2025. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production.

The table below presents NARM coal reserve estimates at December 31, 2025, along with comparative quantities at December 31, 2024. NARM did not hold any coal resources as of December 31, 2025. These coal reserve estimates were supported by the analyses of 4,914 total drill holes within the coal lease area. The quantity of the coal reserves is estimated on a saleable product basis and deemed 100% attributable to Peabody. In addition to quantity, the table presents selected key quality parameters on an as-shipped basis.

NARM - SUMMARY OF COAL RESERVES (1)

(Tons in millions)

Coal Reserves (2)(3)(4) Tons %Ash %Sulfur Btu % Mine Yield(5) Tons

Year-over-year decrease (5) %

The year-over-year decrease in the quantity of coal reserves was driven by production depletion.

(3) The quality of coal reserves is estimated on an as-shipped basis.

Wilpinjong Mine

The Wilpinjong Mine is a production-stage surface thermal coal mine situated approximately 25 miles northeast of Mudgee in New South Wales, Australia. Peabody acquired the mine as part of its acquisition of Excel Coal Pty Ltd (Excel) in 2006. Excel began the development of Wilpinjong Mine in 2006 and it commenced production under Peabody ownership in 2007. A third-party contractor managed mining operations until 2013, when the Company converted the mine to owner-operated.

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The Wilpinjong Mine extracts coal from the Moolarben and Ulan coal seams which have a combined thickness from 6 to 10 meters and a typical waste depth of less than 80 meters in the Illawarra Coal Measures on the northwest margin of the Sydney Basin. The Company has secured three exploration licenses of 2,958 hectares and four mining leases of 3,790 hectares through the New South Wales Minister of Planning. The typical royalty rate is 10.8% of the value of coal recovered. The mining leases require renewal upon expiration in 2027 for 2,863 hectares and in 2039-2044 for 927 hectares. Renewal applications for two exploration licenses were approved in 2023, with the terms extended to December 2027 and March 2028, and the third was granted in May 2022 for an initial term of 6 years. As of December 31, 2025, all required licenses and permits were in place for the operations of Wilpinjong within the existing mining leases. A process to gain the necessary approvals to mine the reserves estimated within EL9399 is underway and is expected to be completed as required by the current mine plan.

Conventional open-cut mining methods are used at the Wilpinjong Coal Mine, with multiple pits at a low strip ratio allowing for relatively rapid pit advance. Overburden is removed by a combination of cast blasting, dozer and truck and excavator methods. Haul trucks transport coal to various hoppers and pads for blending and temporary storage, as necessary, and then to a coal handling and processing plant to be crushed and washed. Coal is conveyed to a rail loadout and transported by train to either domestic customers or to the Port of Newcastle and seaborne customers for thermal power generation.

The key supporting infrastructure for Wilpinjong Mine includes road access via public roads, port service at two terminals at the Port of Newcastle, above and below rail services, electrical power from a 66 kilovolt transmission line and water supply from captured surface runoff and deep wells. The mine’s proximity to other large coal producers in the region provides access to a significant pool of experienced mining personnel.

The property, plant, equipment and mine development assets of Wilpinjong Mine had a net book value of approximately $208 million at December 31, 2025. The mine’s operating equipment meets contemporary mining standards and is adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production.

The tables below present Wilpinjong Mine’s estimated coal reserves and resources at December 31, 2025, along with comparative quantities at December 31, 2024. These coal reserve and resource estimates were supported by the analyses of 1,460 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dried basis.

WILPINJONG MINE - SUMMARY OF COAL RESERVES AND RESOURCES (1)

(Tons in millions)

Coal Reserves (5)(6) Tons %Ash %Sulfur Kcal/kg % Mine Yield(7) Tons

Year-over-year increase 72 %

Coal Resources (2)(3)(4) Tons %Ash %Sulfur Kcal/kg Tons

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The year-over-year increase in the quantity of coal reserves was driven by the addition of reserves from Pit 9 and 10 within EL9399, partially offset by production depletion. The year-over-year decrease in the quantity of coal resources was mainly driven by conversion of coal resources to reserves within EL9399.

(2) The quality of coal resources is on an in situ, air-dry basis.

Centurion Mine

The Centurion Mine is an underground longwall metallurgical coal mine located 160 kilometers west-southwest of Mackay, Queensland, Australia. The Centurion Mine lies on the Collinsville Shelf on the western margin of the Bowen Basin in Central Queensland. White Mining Ltd developed the operation (then known as the North Goonyella Mine), including a rail loop, coal handling preparation plant and nearby accommodation village, following the grant of ML6949 in 1991. Peabody then acquired North Goonyella as part of an acquisition of RAG Australia Coal Pty Ltd’s coal assets in April 2004 and operated it until September 2018, when a fire in the mine halted operations. After the mine was idled in September 2018, plans to re-initiate production were developed with regulatory approval.

During the third quarter of 2022, Peabody initiated the development of the mine. In October 2023, Peabody entered into an agreement with Stanmore to purchase the southern area of Wards Well (ML1790 and ML70495) with the intent to expand underground operations to the north of the North Goonyella Mine footprint and eventually extend into Dabin (MDL3010). In December 2023, the mine was renamed the Centurion Mine. Development operations recommenced at the mine in June 2024, and longwall operations commenced in February 2026.

Centurion Mine extracts coal from the Goonyella Middle seam with future plans to extend into the Goonyella Lower B2 seam with mining depths ranging from 210 meters to 540 meters. The Company has secured mineral rights through state mineral leases and has an approved production rate for the operation of 10.2 Mtpa ROM coal that after processing, equates to approximately 7.6 Mtpa product coal. The Centurion Mine operates on a Mining Lease issued by the state government of Queensland. Tenement holders are bound by the Mineral Resources Act 1989 and the Mineral Resources Regulation 2013 which define the laws pertaining to coal exploration and mining in Queensland. Under the system administered by the Department of Natural Resources, Mines and Energy, tenements are held as either EPC (Exploration Permit Coal), MDL (Mineral Development Licence) or ML (Mining Lease).

Production from the Centurion Mine is subject to the Queensland government royalty charged on total revenue. In addition to this standard government royalty, there is also a special private royalty agreement established in relation to the sale of the property by a prior owner.

The Centurion Mining Lease, ML6949, encompasses a total of 3,293 hectares. The ML allows mining and sale of coal by both underground and open-cut methods. Overlapping this ML, Centurion also holds a petroleum lease, PL504, which enables the company to commercialize any coal seam gas (methane) that may be extracted within the lease area.

Centurion North is comprised of ML1790 and ML70495 (part of the Ward’s Well project which has been subdivided between Peabody and Stanmore) which encompasses surface areas of 2,723 hectares and 748 hectares, respectively. The Centurion North mine also comprises a small portion of MDL3010 (Dabin) which is owned by the West Burton Joint Venture (85% Peabody) and has a land area of 10,827 hectares.

Coal is produced primarily using longwall systems. The mine will also use continuous miner units for longwall development and limited production. Mined coal is processed through the on-site wash plant and conveyed to rail loadout facilities. Product coal is loaded to trains via an existing 1,000 tonne train loadout bin. The loaded trains then travel some 217 kilometers to the Port of Hay Point where they are bottom dumped to conveyor and onto stockpiles at Dalrymple Bay Coal Terminal. Shipping of coal to customers takes place on ocean-going vessels, often shared with other coal suppliers. Centurion coking coal is a premium hard coking coal with a mature brand name in the seaborne metallurgical marketplace and is well known in both the Atlantic and Pacific seaborne markets.

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The key supporting infrastructure for Centurion Mine includes road access via highways and roads, access to both the Goonyella and Newland Rail Systems, coal export terminals at the Port of Hay Point and the Port of Abbot Point, connection to a high voltage electricity grid that provides electricity to the existing facilities and water supplied from the 15 gigaliter capacity Burton Gorge Dam. Centurion also has a nearby accommodation village with housing and service amenities for a capacity of 440 workers located 19 kilometers east of the mine. The mine’s workforce is drawn primarily from the townships of Moranbah, Nebo and Mackay.

The property, plant, equipment and mine development assets of Centurion Mine had a net book value of approximately $1 billion at December 31, 2025. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. During the development process, the Company upgraded the mine’s coal transfer and handling facilities, purchased new mining equipment and made other capital investments to improve its prospective cost structure.

The tables below present Centurion Mine’s estimated coal reserves and resources at December 31, 2025, along with comparative quantities at December 31, 2024. These coal reserve and resource estimates were supported by the analyses of 2,065 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves are estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dry basis.

CENTURION MINE - SUMMARY OF COAL RESERVES AND RESOURCES (1)

(Tons in millions)

Coal Reserves (2)(5)(6) Tons %Ash %Sulfur %VM % Mine Yield(7) Tons

Year-over-year increase 1 %

Coal Resources (2)(3)(4)(5) Tons %Ash %Sulfur VM% Tons

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Internal Controls

The preparation of coal reserve and resource estimates is completed in accordance with the Company’s prescribed internal control procedures, which are designed specifically to ensure the reliability of such estimates presented herein. Annually, QPs and other employees review the estimates of mineral reserves and mineral resources, the supporting documentation and compliance with applicable internal controls. Such controls employ management systems, standardized procedures, workflow processes, multi-functional supervision and management approval, internal and external reviews, reconciliations and data security covering record keeping, chain of custody and data storage.

The internal controls for coal reserve and resource estimates also cover exploration activities, sample preparation and analysis, data verification, processing, metallurgical testing, recovery estimation, mine design and sequencing, and coal reserve and resource evaluations, with environmental, social and regulatory considerations. The quality assurance and control protocols over the assaying of drill hole samples are performed by reputable commercial laboratories following certification and accreditation programs established by the American Society for Testing and Materials or Australian National Association of Testing Authorities.

The coal reserve and resource estimates have inherent risks due to data accuracy, uncertainty from geological interpretation, mine plan assumptions, uncontrolled rights for mineral and surface properties, environmental challenges, uncertainty for future market supply and demand, and changes in laws and regulations. Management and QPs are aware of those risks that might directly impact the assessment of coal reserves and resources. The current coal reserves and resources are estimated based on the best information available and are subject to re-assessment when conditions change. Refer to Item 1A. “Risk Factors” for discussion of risks associated with the estimates of the Company’s coal reserves and resources.

Item 3. Legal Proceedings.

See Note 20. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of Peabody’s pending legal proceedings, which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Peabody’s “Safety and Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and environmental stewardship across the Company’s business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, risk management and assurance. Peabody also partners with other companies and certain governmental agencies to pursue new technologies that have the potential to improve its safety performance and provide better safety protection for employees.

Peabody continually monitors its safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Annual Report on Form 10-K.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Peabody’s Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 13, 2026 there were 187 holders of the Company’s Common Stock, as determined by counting its record holders and the number of participants reflected in a security position listing provided to the Company by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of Peabody’s Common Stock on behalf of their customers, the Company does not know the actual number of unique stockholders represented by these record holders.

Share Repurchase Program

On April 17, 2023, the Company announced that its Board of Directors authorized a share repurchase program (2023 Repurchase Program) authorizing repurchases of up to $1.0 billion of its common stock. The 2023 Repurchase Program superseded and replaced the previous repurchase program that had been announced in 2017.

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Under the 2023 Repurchase Program, the Company may purchase shares of common stock from time to time at the discretion of management through open market purchases, privately negotiated transactions, block trades, accelerated or other structured share repurchase programs, or other means. The manner, timing and pricing of any share repurchase transactions will be based on a variety of factors, including market conditions, applicable legal requirements, the Company’s capital structure and alternative opportunities that the Company may have for the use or investment of capital. Through December 31, 2025, the Company repurchased 23.8 million shares of its common stock under the 2023 Repurchase Program for $530.8 million (which included commissions paid of $0.4 million), leaving $469.6 million available for share repurchase.

Dividends

During the year ended December 31, 2025, the Company declared dividends per share of $0.300. On February 5, 2026, the Company declared an additional dividend per share of $0.075 to be paid on March 10, 2026 to shareholders of record as of February 23, 2026.

Share Relinquishments

The Company routinely allows employees to relinquish Common Stock to pay estimated taxes upon the vesting of restricted stock units and the payout of performance units that are settled in Common Stock under its equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of the Company’s Common Stock on the dates of the respective relinquishments.

Purchases of Equity Securities

The following table summarizes all share purchases for the three months ended December 31, 2025:

(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program Repurchase Program.

Stock Performance Graph

The following performance graph compares the cumulative total return on Peabody’s common stock with the cumulative total return of the S&P MidCap 400 Index and the S&P Metals and Mining Select Industry Index.

The graph assumes that the value of the investment in BTU and each index was $100 at December 31, 2020. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2025. These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved and are not intended to forecast or be indicative of possible future performance of the common stock.

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Item 6. Reserved.

Not applicable.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The Company’s discussion and analysis of the year ended December 31, 2025 compared to the year ended December 31, 2024 is included herein. For discussion and analysis of the year ended December 31, 2024 compared to the year ended December 31, 2023, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Peabody’s Annual Report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on February 20, 2025 and is incorporated by reference herein.

Non-GAAP Financial Measures

The following discussion of Peabody’s results of operations includes references to and analysis of Adjusted EBITDA and Total Segment Costs, which are financial measures not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by the chief operating decision maker, defined as Peabody’s President and Chief Executive Officer, as the primary financial metric to measure each segment’s operating performance against expected results and to allocate resources, including capital investment in mining operations and potential expansions. Total Segment Costs is also used by management as a component of a metric to measure each segment’s operating performance.

Also included in the following discussion of Peabody’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reportable segment. These metrics are used by management to measure each reportable segment’s operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reportable segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7.

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Peabody believes non-GAAP measures are used by investors to measure its operating performance. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7 for definitions and reconciliations to the most comparable measures under U.S. GAAP.

Overview

In 2025, Peabody sold 122.0 million tons of coal. As of December 31, 2025, the Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin and Other U.S. Thermal.

The Company’s seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of its thermal and metallurgical coal sold within Australia. Generally, revenue from individual countries varies year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. The Company classifies its seaborne mines within the Seaborne Thermal or Seaborne Metallurgical reportable segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Seaborne Thermal reportable segment is of a metallurgical grade. Similarly, a small portion of the coal mined by the Seaborne Metallurgical reportable segment is of a thermal grade. Additionally, the Company may market some of its metallurgical coal products as a thermal coal product from time to time depending on market conditions. Peabody’s Seaborne Thermal and Seaborne Metallurgical reportable segments contributed approximately 53% of the Company’s total Adjusted EBITDA from its mining operations during the year ended December 31, 2025.

The Company’s Seaborne Thermal operations consist of mines in New South Wales, Australia. The mines in that reportable segment utilize surface extraction processes to mine low-sulfur, high Btu thermal coal. Prior to September 2025, when the Wambo Underground Mine ceased production, the reportable segment also used underground extraction processes.

The Company’s Seaborne Metallurgical operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama, USA. The mines in that reportable segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and pulverized coal injection coal.

The Company’s thermal operations in the U.S. are focused on the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a relatively small portion sold as international exports as conditions warrant. The Company’s Powder River Basin operations consist of its mines in Wyoming. The mines in that reportable segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). The Company’s Other U.S. Thermal operations reflect the aggregation of its Illinois, Indiana, New Mexico and Colorado mining operations. The mines in that reportable segment are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, the Company’s Powder River Basin operations mine sub-bituminous coal deposits and its Other U.S. Thermal operations mine both bituminous and sub-bituminous coal deposits. Peabody’s Powder River Basin and Other U.S. Thermal reportable segments contributed approximately 47% of the Company’s total Adjusted EBITDA from its mining operations during the year ended December 31, 2025.

Corporate and Other includes selling and administrative expenses, results from equity method investments, trading and brokerage activities, minimum charges on certain transportation-related contracts, the closure of inactive mining sites, the impact of foreign currency remeasurement and certain commercial matters.

Resource Management. As of December 31, 2025, Peabody controlled approximately 2.0 billion tons of proven and probable coal reserves, 3.5 billion tons of coal resources and approximately 335,000 acres of surface property through ownership and lease agreements. The Company has an ongoing asset optimization program whereby its property management group regularly reviews these coal reserves, coal resources and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves, coal resources and surface lands. These surface lands include acres where Peabody has completed post-mining reclamation. In addition, the Company generates revenue through royalties from coal reserves and oil and gas rights leased to third parties, farm income from surface lands under third-party contracts and lease income from surface lands under contracts with renewable energy ventures.

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Middlemount Mine. Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and low-volatile pulverized coal injection (LV PCI) coal for sale into seaborne coal markets through Abbot Point Coal Terminal, with some capacity also secured at Dalrymple Bay Coal Terminal. Mining operations first commenced at the Middlemount Mine in late 2011. During the years ended December 31, 2025 and 2024, the mine sold 1.5 million and 1.3 million tons of coal, respectively (on a 50% basis).

Summary

Pricing during the year ended December 31, 2025 is set forth in the table below.

(1) Spot pricing expressed per metric tonne.

(2) Prompt month pricing expressed per short ton.

The seaborne pricing included in the table above is not necessarily indicative of the pricing the Company realized during the year ended December 31, 2025 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.

In the U.S., the pricing included in the table above is also not necessarily indicative of the pricing the Company realized during the year ended December 31, 2025 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company’s realized pricing.

Within the global coal industry, supply and demand for its products and the supplies used for mining are being impacted by recent changes to trade policy, including tariffs and customs regulations. As future developments related to trade policy, including additional or retaliatory tariffs, delays in implementing previously announced changes or ongoing negotiations between countries, are unknown, the global coal industry data for the year ended December 31, 2025 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, metallurgical coal prices were mixed during the year ended December 31, 2025. Globally, both steel production and pig iron production (which predominantly utilizes metallurgical coal) declined during the period. In China, lower domestic steel consumption constrained output, while producers in most other countries experienced competitive pressure from increased Chinese steel exports. India was an exception, expanding its steel making capabilities and increasing pig iron output versus the prior year. Metallurgical coal prices were influenced by lower global steel output in 2025, with premium hard coking coal prices averaging lower in 2025 than 2024. However, metallurgical coal supply curtailment events, such as wet weather disruptions in Australia and changing rates of Chinese coal production, at times contributed to seaborne metallurgical coal price support. In addition, geopolitical trends and trade policies, including tariff regimes, continue to influence global metallurgical trade flows. Looking forward, the seaborne metallurgical coal price may remain volatile based on China’s coal production policies, the pace of growth of the Indian steel industry, changing global trade policies and global supply curtailment actions.

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Within the seaborne thermal coal market, global thermal coal prices were mixed during the year ended December 31, 2025. In China, power generation increased year-over-year through December 31, 2025, however the share of renewables in the generation mix continued to grow, pressuring coal generation. In addition, domestic coal production increased slightly year-over-year, which led to weaker coal import demand through the year ended December 31, 2025. In India, steady domestic coal production, lower import demand and declining coal generation led to stable coal stockpiles. Looking forward, seaborne thermal coal prices may remain volatile based on the outcomes of China’s supply reforms, winter re-stocking activity in the Northern Hemisphere and volatility in global natural gas markets which can impact global thermal coal markets.

In the U.S., overall electricity demand increased over 2% year-over-year. Through the year ended December 31, 2025, electricity generation from thermal coal increased year-over-year, driven by higher natural gas prices and stronger total generation. Coal’s share of electricity generation increased to approximately 16% for the year ended December 31, 2025, while wind and solar’s combined generation share was at 19% and the share of natural gas generation declined to approximately 40%. U.S. coal inventories have declined through December 31, 2025, driven by stronger coal utilization, resulting in stockpiles declining 20 million tons below levels seen at the end of 2024.

Centurion Mine

During 2025, Peabody continued to advance the development of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia. Full-scale longwall production commenced in February 2026. The mine is expected to enhance both the quantity and quality of the Company’s production from the Seaborne Metallurgical reportable segment.

Arbitration Relating to Terminated Anglo Acquisition

On November 25, 2024, Peabody entered into Purchase Agreements with Anglo, to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia, including Anglo’s interests in the Moranbah North and Grosvenor mines, the Moranbah South development project, the Capcoal complex, the Roper Creek mine and the Dawson complex (comprising the Dawson Main/Central operating mine, the Dawson South operating mine, the Dawson South Exploration project and the Theodore South exploration project, collectively, the Dawson Assets). The Company agreed to, following the prospective closing of the Anglo acquisition, sell the Dawson Assets to Pt Bukit Makmur Mandiri Utama or one of its subsidiaries (BUMA).

On August 19, 2025, Peabody terminated the Purchase Agreements. The termination of the Purchase Agreements followed Peabody’s prior delivery of a notice of a MAC as a result of an ignition event at the Moranbah North mine on March 31, 2025, which had led to the closure of the mine. See Note 1. “Summary of Significant Accounting Policies” and Note 20. “Commitments and Contingencies” to the accompanying consolidated financial statements for further information.

On September 23, 2025, various subsidiaries of Anglo initiated International Chamber of Commerce arbitration proceedings in London, United Kingdom, against Peabody and certain of its affiliates. Anglo’s complaint alleges, among other things, that Peabody wrongfully terminated the Purchase Agreements and seeks, among other things, declarations that the ignition event at the Moranbah North mine did not constitute a MAC, as well as damages for losses in an unspecified amount, plus costs and interest. Peabody remains confident that a MAC occurred, and that it was entitled to terminate the Purchase Agreements.

Potential Recovery of Rare Earth Elements

Peabody has been evaluating the potential recovery of REEs and CMs, with substantial testing at its Powder River Basin operations. The Company is progressing its REE/CM initiative by conducting testing to evaluate mineral types and concentrations; developing flowsheets in conjunction with technology partners to support technical and economic assessments and produce rare earth products; and collaborating with governmental agencies and departments at the state and federal level. In February 2026, the Wyoming Energy Authority awarded Peabody funding of $6.25 million for a pilot plant using Peabody’s Powder River Basin coal for REE/CM processing.

Results of Operations

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

The decrease in results from continuing operations, net of income taxes for the year ended December 31, 2025 compared to the prior year ($449.6 million) was primarily driven by lower revenue ($375.2 million) due to lower seaborne coal pricing, the prior year insurance recovery at the Shoal Creek Mine ($109.5 million) and increased costs related to the terminated Anglo acquisition ($68.6 million). These unfavorable variances were partially offset by a lower income tax provision ($100.0 million) and lower operating costs and expenses ($86.0 million).

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Adjusted EBITDA for the year ended December 31, 2025 reflected a year-over-year decrease of $416.8 million.

Tons Sold

The following table presents tons sold:

(Decrease) Increase

Year Ended December 31, to Volumes

(Tons in millions)

Total tons sold from reportable segments 121.9 117.9 4.0 3.4 %

Corporate and Other 0.1 0.1 — — %

Supplemental Financial Data

The following table presents supplemental financial data by reportable segment:

Year Ended December 31, (Decrease) Increase

Revenue per Ton (1)

Costs per Ton (1) (2)

Adjusted EBITDA Margin per Ton (1) (2)

(1)This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.

(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; insurance recoveries; and certain other costs related to post-mining activities.

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Revenue

The following table presents revenue by reportable segment:

(Decrease) Increase

Year Ended December 31, to Revenue

(Dollars in millions)

Seaborne Thermal. The decrease in segment revenue during the year ended December 31, 2025 compared to the prior year was due to unfavorable realized prices ($245.0 million) and unfavorable volume ($60.4 million) due in part to reductions at the Wilpinjong Mine.

Seaborne Metallurgical. Segment revenue decreased during the year ended December 31, 2025 compared to the prior year due to unfavorable realized prices ($219.2 million), offset by favorable volume ($200.2 million) from the Shoal Creek and Centurion Mines.

Powder River Basin. Segment revenue increased during the year ended December 31, 2025 compared to the prior year due to favorable volume ($72.7 million) resulting from increased demand, offset by unfavorable realized prices ($18.5 million) which were driven by the impact of adjustments to cost pass-through contracts with certain customers resulting from the federal royalty rate reduction included in the OBBBA.

Other U.S. Thermal. The decrease in segment revenue during the year ended December 31, 2025 compared to the prior year was due to unfavorable volume ($43.2 million) resulting from decreased demand, dragline outages at the Bear Run Mine and challenging geological conditions at the Twentymile Mine; decreased revenue from sales contract cancellation settlements ($37.7 million); and unfavorable realized prices ($34.4 million).

Corporate and Other. Segment revenue increased during the year ended December 31, 2025 compared to the prior year due to higher results from trading activities ($7.6 million).

Segment Costs

The following table presents costs by reportable segment:

(Decrease) Increase

Year Ended December 31, to TotalSegment Costs

(Dollars in millions)

(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.

Seaborne Thermal. The decrease in Segment Costs during the year ended December 31, 2025 compared to the prior year was due to lower costs for labor, repairs and outside services ($73.9 million) resulting from timing of maintenance and operational improvements, lower sales related costs ($28.0 million) driven by both lower realized prices and volume, lower leasing expense ($9.0 million) and favorable commodity pricing ($8.0 million); offset by higher recognized costs resulting from sales volume outpacing production volume ($26.0 million).

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Seaborne Metallurgical. Segment Costs increased during the year ended December 31, 2025 compared to the prior year due to higher variable operational and sales related costs driven by increased volume (1.3 million tons).

Powder River Basin. The increase in Segment Costs during the year ended December 31, 2025 compared to the prior year was primarily due to higher costs for labor, repairs and outside services ($26.7 million) due in part to unplanned dragline outages, haul truck repairs and increased volume (4.9 million tons), offset by lower sales related costs ($16.4 million) which were largely driven by the federal royalty rate reduction on coal production included in the OBBBA.

Other U.S. Thermal. The decrease in Segment Costs during the year ended December 31, 2025 compared to the prior year was driven by lower volume (1.2 million tons) and lower costs for labor ($13.3 million).

Corporate and Other. Segment costs decreased during the year ended December 31, 2025 compared to the prior year primarily due to favorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral, offset by higher expense from trading activities and lower amortization of prior service credit.

Adjusted EBITDA

The following table presents Adjusted EBITDA for each of the Company’s reportable segments:

(Decrease) Increase to

Year Ended December 31, Adjusted EBITDA

(Dollars in millions)

(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.

Seaborne Thermal. Segment Adjusted EBITDA decreased during the year ended December 31, 2025 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($227.7 million) and unfavorable volume ($59.5 million), offset by favorable operational costs as described above.

Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the year ended December 31, 2025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($168.8 million) and the prior year Shoal Creek insurance recovery ($80.8 million), offset by favorable volume.

Powder River Basin. Segment Adjusted EBITDA increased during the year ended December 31, 2025 compared to the same period in the prior year as a result of favorable volume ($38.9 million); lower sales related costs ($16.4 million) as described above; and decreased overburden removal costs ($6.4 million). The increases were offset by higher costs for labor, repairs and outside services as described above.

Other U.S. Thermal. Segment Adjusted EBITDA decreased during the year ended December 31, 2025 compared to the same period in the prior year due to decreased sales contract cancellation settlements ($37.7 million) and lower realized prices net of sales price sensitive costs ($29.8 million).

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Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:

(Decrease) Increase

Year Ended December 31, to Income

(Dollars in millions)

Selling and administrative expenses (105.0) (91.0) (14.0) (15.4) %

Corporate and Other Adjusted EBITDA $ (70.9) $ (90.2) $ 19.3 21.4 %

(1)Middlemount’s results are before the impact of related changes in amortization of basis difference.

(2)Includes gains (losses) on certain surplus coal reserve, coal resource and surface land sales and property management costs and revenue.

(3)Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, results from the Company’s equity method investment in renewable energy joint ventures, costs associated with suspended operations, holding costs associated with the Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities.

Corporate and Other Adjusted EBITDA increased during the year ended December 31, 2025 compared to the same period in the prior year. Unfavorable variances in Middlemount’s results driven by lower sales pricing and higher selling and administrative expenses were partially offset by higher gains on equipment and land sales ($17.9 million). The increase in other items was driven by the favorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($62.7 million), offset by the lower amortization of prior service credit ($10.9 million) and unfavorable trading results ($6.5 million).

(Loss) Income From Continuing Operations, Net of Income Taxes

The following table presents (loss) income from continuing operations, net of income taxes:

(Decrease) Increase to Income

Year Ended December 31,

(Dollars in millions)

Depreciation, depletion and amortization (384.5) (343.0) (41.5) (12.1) %

Asset retirement obligation expenses (36.5) (48.9) 12.4 25.4 %

Costs related to terminated acquisition (78.9) (10.3) (68.6) (666.0) %

Shoal Creek insurance recovery - property damage — 28.7 (28.7) (100.0) %

Other operating loss (5.6) (3.7) (1.9) (51.4) %

Interest expense, net of capitalized interest (43.9) (46.9) 3.0 6.4 %

Take-or-pay contract-based intangible recognition 1.0 3.0 (2.0) (66.7) %

(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.

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Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reportable segment:

Decrease

Year Ended December 31, to Income

(Dollars in millions)

Additionally, the following table presents a summary of the Company’s weighted-average depletion rate per ton for active mines in each of its reportable segments:

Year Ended December 31,

Seaborne Metallurgical 3.37 2.89

Depreciation, depletion and amortization expense increased during the year ended December 31, 2025 compared to the same period in the prior year primarily due to increased depreciation resulting from asset additions and increased depletion expense primarily due to increased volume from the Shoal Creek and Centurion Mines. The changes in the weighted-average depletion rate per ton for the Seaborne Thermal, the Seaborne Metallurgical and the Other U.S. Thermal segments during the year ended December 31, 2025 compared to the same period in the prior year reflect the impact of volume and mix variances across the segments.

Asset Retirement Obligation Expenses. Asset retirement obligation expenses decreased during the year ended December 31, 2025 compared to the same period in the prior year due to favorable revisions to the estimates for closed mines.

Costs Related to Terminated Acquisition. These costs relate to the terminated acquisition of multiple metallurgical coal mines from Anglo. In addition to typical costs, such as legal and professional fees, the charges include commitment and duration fees on the bridge loan facility of $20.8 million and $25.9 million, respectively, during the year ended December 31, 2025. Refer to Note 1. “Summary of Significant Accounting Policies” and Note 20. “Commitments and Contingencies” to the accompanying consolidated financial statements for further information regarding the acquisition, which information is incorporated herein by reference.

Shoal Creek Insurance Recovery - Property Damage. During June 2024, the Company reached a settlement related to the Shoal Creek losses and recorded a $109.5 million insurance recovery, as discussed in Note 16. “Other Events” in the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to losses recognized at the time of the insurance recovery related to longwall development and equipment deemed inoperable within the affected area of the mine, which consisted of $28.7 million recognized during the year ended December 31, 2023. The remaining $80.8 million, applicable to incremental costs and business interruption recoveries, was included in Adjusted EBITDA for the year ended December 31, 2024.

Interest Income. The decrease in interest income during the year ended December 31, 2025 compared to the prior year was driven by lower average cash balances during the current period.

Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2025 was driven by the favorable impacts of changes for the postretirement benefit plans related to updated claims experience and favorable expected future claims costs, based upon recent Centers for Medicare and Medicaid Services direct subsidy announcements ($15.1 million) and mark-to-market gains on pension plan assets ($2.1 million). These increases were offset by negative adjustments to Peabody’s black lung compensation liabilities resulting from increased claims ($4.5 million), decreases to the discount rates for all actuarially determined liabilities ($3.9 million) and unfavorable impacts of medical trend updates for the postretirement benefit plans ($3.8 million).

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