BTU 10-K & 10-Q changes, risk factors and insider trading

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

The Companycoal operatesindustry inis a competitive andcompetitive, highly regulated industryand thatsubject hasto at times experienced strong headwinds. Current pricing levelsperiods of bothsignificant seaborne and domestic coal products may not be sustainable in the future.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.

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

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

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

•technological developments, including thosedevelopments related to alternative energy sources, those intended to convert coal-to-liquids or gas andconversion those aimed at capturing, usingprocesses and storing carbon dioxide.CCUS.

Thermal coal accounted forrepresented the majority of the Company’s coal sales by volume during 20242025 and 2023,2024, with the vast majoritymost of these sales to electric power generators. The demand for coal consumedused forin electric powerelectricity generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear, fuel oil and alternative energy sourcesfuels; (iii) utilization of all electricity generating units (whether using coal or not), includingand the relative cost of producing electricity from multiple fuels, including coal; (iv) stringent environmental and other governmental regulationsregulations, including those related to permitting; (v) otherlitigation and judicial decisions; (vi) sociopolitical views on coal; and (vivii) the coal inventories of utilities. Gas-fueled generation has displaced and could continue to displace coal-fueled generation (particularly fromat older, less efficient coal-fueled generation units) as current and potentially increasing regulatory costs and other factors, such as declines in the price of natural gas, impact the operating decisions of electric power generators. In addition, someSome electric power generators have made decisionselected to close coal-fueled generation units given ongoing pressure to shift away from coal generation. Many ofnew the newU.S. power plants in the U.S. are being fueled by natural gas because gas-fired plants have been less expensive to construct and operate, permits to construct these plants are easier to obtainpermit based on emissions profiles and electricface power generators may facefewer public and governmental pressure to generate a larger portion of their electricity from natural gas-fueled units and alternative energy sources.objections. Increasingly stringent regulations along withand stagnant electricity demand in recent years have alsofurther reduced the number of new power plants being built. In recent years, these trends have reduced demand for the Company’s coal and the related prices. Lowerlowered demand for coal consumed by electric power generators has reduced and could continue to reduce the volume of thermal coal that the Company sells and the prices that it receives for the thermal coal,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 that is used infor the global steel industry.industry, Metallurgical coalwhich accounted for approximately 25%27% and 26%25% of its revenue in 20242025 and 2023,2024, respectively. Changes in governmental policies andpolicies, regulations and changessteel inindustry theconditions, including steel industry, including the demand for steel,demand, could reduce the demand for the Company’s metallurgical coal. The demand for foreign-produced steel both in foreigninternational and U.S. markets andis in the U.S. market dependsinfluenced in part on factors such asby tariff rates on steel. TheTariffs may affect the Company’s customers may be affected by imposed tariffs to the extent their steel imports into other countries are curtailed as a result of imposed tariffs.

In addition, the steel industry’s demandDemand for metallurgical coal is also affected by a number of factors, including the variablecyclical nature of thatthe industry’ssteel business,industry, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites and plastics. The steel industry increasingly relies on processescontinues to makeadopt steelproduction methods that do not use coal as a manufacturing input,coal, such as electric arc furnaces. Lower international demand for metallurgical coal in international markets would reduce the amountvolume of metallurgical coal that Peabody sells and the prices that it receives for 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.

Most of the Company’s sales are made under coal supply agreements, which are important to the stability and profitability of its operations. TheThese executionagreements ofoften a satisfactory coal supply agreement is frequentlyform the basis onfor whichdeveloping the Company undertakes the development of coal reserves and resources required to bemeet suppliedcontractual under the contract,commitments, particularly in the U.S. For the year ended December 31, 2024,2025, 25% of the CompanyCompany’s revenue was derived 27% of its revenue from coal supply agreements fromwith its five largest customers.customers, Those five customerswhich were primarily supplied primarilyunder from 1619 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 20242025 to 2028.

Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. The Company may adjust these contract prices based on inflation or deflation, price indices and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. The Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of its expiring contracts. Coal supply agreements also typically containinclude force majeure provisions allowing temporary suspension of performance by the Company or the customer during the duration of specified events beyond the controlparties’ of the affected party.control. Some coal supply agreements allow customers to vary therequired purchase volumes of coal that they are required to purchase during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request that the Company amend the agreementsamendments to allow for such variation. Most of itsthe Company’s coal supply agreements contain provisions requiring the Companydelivery to deliverof coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or terminationcontract of the contracts.termination. Moreover, some of thesecertain agreements allow the Company’s customers to terminate their contracts inif the event ofregulatory changes in regulations affecting the coal industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.

On an ongoing basis, the Company discusses the extension of existing agreements or 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 operating profitsprofitability the Company realizes from its coal sold under supply agreements dependdepends on a variety of factors.factors, In addition,and price adjustment and other contract provisionsmechanisms 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, itthe Company could be materially adversely affected to the extent thatif it iscannot unable to findsecure alternate buyers for its coal at thecomparable sameprofitability levellevels. ofCoal profitability.prices Prices for coalcan vary by mining region and country.country, As a result,and the Company cannot predict the future strengthmarket of the coal industry overallconditions or by mining region and cannot provide assuranceensure that it will be able to replace existingexpiring long-term coal supply agreements will be replaced at the samesimilar prices or with similar profit margins when they expire.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 anddemand, oversupply, cost of competing fuels andor environmental and other governmental regulations.

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

•adverse weather, flooding and natural disasters;

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

•supply chain constraints or unavailability of equipment or parts of the type, quantity and/or size needed to meet production expectations;

•delays in moving its longwall equipment;

•unforeseen delays in implementation of mining technologies that are new to its operations.technologies.

The Company maintains insurance policies that provide limited coverage for somecertain of thethese risks referenced above,risks, which may lessenmitigate thetheir impact associated with these risks.impact. However, there can be no assurance as to the amount or timing of recovery under itsany insurance policiesrecovery inrelated connectionto withsuch losses associated with these risks.losses.

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,years. thatThese commitagreements require the Company to pay a minimum amount for the delivery of coal evenregardless ifof thoseactual commitmentsusage. goAlthough unused. The take-or-pay provisions in thesecertain contracts sometimes allow thepreviously Companypaid amounts to applybe amountsapplied paidto for subsequentfuture deliveries, but these provisions have limitations and the Company may not be ableunable to apply all such amounts so paidpaid. in all cases. Also, theThe Company may notalso be ableunable to utilizeuse the amount ofall capacity for which it has previously paid. Additionally, thethese Companyarrangements maycan continueincentivize to delivercontinued coal deliveries during times when itsuspending operations might otherwise be optimaleconomically to suspend operations because these take-or-pay provisionspreferable, effectively convert aconverting variable costcosts of selling coal to ainto fixed operating cost.costs.

The value of the Company’s assets havehas from time to timeperiodically been adversely affected by numerous uncertain factors, some of which are beyond the Company’s control, including unfavorable changes in theadverse economic environments in which it operatesconditions; declining coal-fired electricity generation; lower-than-expected coal pricing; technical andor geological operating difficulties; an inability to economically extract its coal reserves and resources; and unanticipated increases in operating costs. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on the Company’s results of operations. 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.

Peabody managesrelies its business withon a number of key personnel, and the loss of whomany such individuals, absent an orderly transition could have a material adverse effecteffect. on the Company, absent the completion of an orderly transition. In addition, theThe Company believes that its future success willalso depend greatlydepends on its continued ability to attract and retain highly skilled and qualified personnel in tight labor markets, particularly personnelthose with mining experience. Peabody cannot provide assurance that key personnel will continue to beremain 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.

As of December 31, 2024,2025, the Company hademployed approximately 5,6005,400 employeespeople (excluding employees that were employed at discontinued operations classified as discontinued), which includedincluding approximately 4,3004,200 hourly employees. TheCertain Companyemployees isare partyrepresented to labor agreements with variousby labor unions thatunder representcollective certain of its employees. Such laborbargaining agreements that are negotiatedrenegotiated periodically, and,creating therefore, the Company is subject to thea risk that thesefuture agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 40%39% of its hourly employees were represented by organized labor unions and generated approximately 21%18% of itsthe Company’s 2025 coal productionproduction. forPositive the year ended December 31, 2024. Relationsrelations with its employees and, where applicable, organized labor are important to the Company’s success. If some or allUnionization of its currentcurrently non-union operations werecould to become unionized,increase the Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if the Company failsfailure to maintain good relations or successfully negotiate union contracts with its employees who are represented by unions, the Company could potentially experienceresult in labor disputes, strikes, work stoppages, slowdowns or other production disruptions in production that could negatively impact itsthe Company’s profitability.

U.S. federal and state laws and Australian laws require the Company to provide financial assurances related to requirements to reclaim lands used for miningmine reclamation; topayment pay federal and stateof workers’ compensation,compensation obligations, such as black lung liabilities; to provide financial assurances for coal lease obligations; and to satisfy other miscellaneous obligations. Historically, the primary methods theThe Company has usedhistorically tosatisfied meetthese thoserequirements obligations are to provide athrough third-party surety bondbonds or a letterletters of credit. In recent years, the Company has also utilized deposits with regulatory authorities or cash-backed bank guarantees. As of December 31, 2024,2025, the Company had $1,017.5$997.2 million of outstanding surety bonds; $262.3$227.2 million of letters of credit with third parties; $168.5$208.7 million of cash-backed bank guarantees; and $127.6$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 $394.6$383.6 million in cash held in trust accounts for the benefit of certain surety providers as of December 31, 2024.2025.

The Company’s financial assurance obligations may increase or become more costly due to a number of factors,costly, and surety bonds andor letters of credit may not be available to the Company, particularly in light ofas some banks and insurance companies’companies have announced unwillingness toreduced 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 itsthe minesCompany reside.operates. The Company’s failureFailure to retain,retain or inability to obtain,obtain surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative,alternatives, could have a material adverse effect on it.the Company. That failure could result from a variety of factors including:

•lack oflimited availability, higher expensecost or unfavorable market terms offor new surety bonds, bank guarantees or letters of credit;

•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.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.

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

Regulatory agencies have the authority under certain circumstances following significant health and safety incidents tomay order a mine to be temporarily or permanently closed.closed Infollowing thesignificant eventhealth thator safety incidents. Any such agencies ordered the closingclosure of one of the Company’s mines,mines itswould disrupt production and sale of coal would be disruptedsales and itcould mayrequire besubstantial requiredexpenditures to incurresume cashoperations, outlayspotentially toresulting re-open the mine. Any of these actions could havein a material adverse effect on the Company’s financial condition, results of operations and cash flows.

New legislation, regulations or ordersorders, as well as new administrative regulations or new interpretations by the relevant government of existing laws, regulations and approvals, related to theroyalty environment orrates, 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. New legislation, such as the “climate superfund” laws recently passed in New Yorkcoal and Vermont, or administrative regulations (or new interpretations by the relevant government of existing laws, regulations and approvals), including proposals related to the protection of the environment or the reduction of GHG emissions that would further regulate and tax the coal industry, may also require significant operational changes or increased costs for the Company or its customers to change operations significantly or incur increased costs.customers. Some of the Company’s coal supply agreements contain provisions that allowallowing a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on the Company’s financial condition and results of operations. If the Company is determined to be subject to “climate superfund” laws and related regulations, it may be required to make significant payments to the relevant governments. These payments may be material and could adversely affect the Company’s results of operations, financial condition or cash flows.

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

The Company’sCompany operations currently useuses hazardous materials in its operations and generateperiodically generates limited quantities of hazardous wasteswaste. from time to time. A number ofVarious laws, including CERCLA and RCRA in the U.S. and similar laws in other countries where the Company operates, impose liability relating to contamination by hazardous substances. Such liability may involve theinclude costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly,currently asor well as currently,formerly owned or operated properties, andas atwell propertiesas tosites whichwhere hazardous substances have beenwere sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.

The Company may be unable to obtain, renew or maintain permits necessary for its operations, or themay Company mayonly be unableable to obtain,do renewso orsubject maintain such permits withoutto conditions onthat limit the manner in which it runs its operations, which would reduce its production, cash flows and profitability.

NumerousMining operations require numerous governmental permits and approvals are required for mining operations.approvals. The permitting rules,rules (and the interpretations of these rules,rules) are complex, change frequently changing and are often subject to discretionary interpretations by regulators, all of which may makemaking compliance more difficult or impractical.impractical at times. As part of thisthe permitting process, when the Company applies for permits and approvals, it is required to prepare and present to governmental authorities datadetailed pertaininginformation toon the potential impactimpacts or effect that anyof proposed exploration for or productionmining activities. Members of coal may have upon the environment. The public, including non-governmental organizations,organizations and opposition groups and individuals,groups, have statutory rights to comment uponupon, and submit objectionsobject to requestedor permits and approvals (including modifications and renewals of certain permits and approvals) and otherwise engage in the permitting process, including bringing citizens’ lawsuits tolegally challenge thepermit issuance of permits, the validity ofapplications, environmental impact statements or the performance of mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.

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

The costs, liabilities and requirementspotential delays associated with these permitting requirements and any related opposition may be extensivesubstantial and time-consumingcould and may delay commencementpostpone or continuation ofdisrupt exploration or production which wouldproduction, adversely affectaffecting the Company’s coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may beinclude conditioned in a mannerconditions that may restrict the Company’s ability to efficiently and economically conduct its mining activities, any of which would materially reduce its production, cash flows and profitability.

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 reportingreportable segment. These metrics are used by management to measure each reportingreportable segment’s operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reportingreportable 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.

In 2025, Peabody sold 122.0 million tons of coal. As of December 31, 2024,2025, the Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin,Basin and Other U.S. Thermal and Corporate and Other.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 70%53% of the Company’s total Adjusted EBITDA from its mining operations during the year ended December 31, 2024.2025.

The Company’s Seaborne Thermal operations consist of mines in New South Wales, Australia. The mines in that reportable segment utilize both surface and underground 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 operating segmentsoperations 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 30%47% of the Company’s total Adjusted EBITDA from its mining operations during the year ended December 31, 2024.2025.

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

(1) PricesSpot pricing expressed per metric tonne.

(2) PricesPrompt month pricing expressed per short ton.

Within the global coal industry, supply and demand for its products and the supplies used for mining continueare to bebeing impacted by therecent ongoingchanges Russian-Ukrainianto conflict.trade policy, including tariffs and customs regulations. As future developments related to thetrade Russian-Ukrainianpolicy, conflictincluding andadditional geopoliticalor instabilityretaliatory tariffs, delays in keyimplementing energypreviously producingannounced regionschanges or ongoing negotiations between countries, are unknown, the global coal industry data for the twelve monthsyear ended December 31, 20242025 presented herein may not be indicative of their ultimate impacts.

In the U.S., overall electricity demand increased approximatelyover 3%2% year-over-year. Through the twelve monthsyear ended December 31, 2024,2025, electricity generation from thermal coal hasincreased decreased year-over-yearyear-over-year, driven by continued lowhigher natural gas prices and stronger renewabletotal generation. Coal’s share of electricity generation has declinedincreased to approximately 15%16% for the twelve monthsyear ended December 31, 2024,2025, while wind and solar’s combined generation share iswas at 17%19% and the share of natural gas generation hasdeclined remainedto levelapproximately at 43%.40%. U.S. coal inventories have modestly declined through December 31, 2024,2025, withdriven by stronger coal utilization, resulting in stockpiles lessdeclining than 1020 million tons below levels seen at the end of 2023. During the twelve months ended December 31, 2024, utility consumption of PRB coal has declined compared to the prior year period.2024.

The decrease in incomeresults from continuing operations, net of income taxes for the year ended December 31, 20242025 compared to the prior year ($408.7$449.6 million) was primarily driven by lower revenue ($710.0$375.2 million) due to lower seaborne coal pricing, volume decreases in the U.S. thermal segments and no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year. This unfavorable variance was partially offset by a lower income tax provision ($200.0 million) and the currentprior 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).

The following table presents tons sold by operating segment:

The following table presents supplemental financial data by operatingreportable segment:

The following table presents revenue by reportingreportable segment:

Seaborne Thermal. The decrease in segment revenue during the year ended December 31, 20242025 compared to the prior year was due to unfavorable realized prices ($228.0$245.0 million), offsetand by favorableunfavorable volume ($112.2$60.4 million). due in part to reductions at the Wilpinjong Mine.

Seaborne Metallurgical. Segment revenue decreased during the year ended December 31, 20242025 compared to the prior year due to unfavorable realized prices and volume ($356.3$219.2 million) from the Australian operations. These decreases were partially, offset by favorable resultsvolume ($200.2 million) from the Shoal Creek Mineand ($110.0Centurion million) due to favorable volume which offset unfavorable realized prices.Mines.

Powder River Basin. Segment revenue decreasedincreased during the year ended December 31, 20242025 compared to the prior year primarily due to unfavorablefavorable volume ($100.2$72.7 million) resulting from decreasedincreased demanddemand, offset by unfavorable realized prices ($18.5 million) which were driven by lowthe naturalimpact gasof pricingadjustments andto mildcost weather.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, 20242025 compared to the prior year was due to unfavorable volume ($49.8$43.2 million) resulting from decreased demanddemand, drivendragline byoutages lowat naturalthe gasBear pricingRun Mine and mildchallenging weathergeological andconditions unfavorableat realizedthe pricesTwentymile ($34.9Mine; million), partially offset by increaseddecreased revenue from sales contract cancellation settlements ($19.1$37.7 million); and unfavorable realized prices ($34.4 million).

Corporate and Other. Segment revenue decreasedincreased during the year ended December 31, 20242025 compared to the prior year due to nohigher unrealized mark-to-market gainsresults from derivativetrading contracts related to forecasted sales in the current yearactivities ($159.0 million) as all derivative contracts settled in 2023 and prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($25.9$7.6 million).

The following table presents costs by reportingreportable segment:

Seaborne Thermal. The increasedecrease in segmentSegment costsCosts during the year ended December 31, 20242025 compared to the prior year was primarilydue drivento by favorable volume (0.9 million tons) which resulted in higher sales related costs ($16.9 million) and higher variablelower costs for labor, repairs and outside services ($12.8$73.9 million), slightlyresulting offsetfrom 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 ($8.4$8.0 million); offset by higher recognized costs resulting from sales volume outpacing production volume ($26.0 million).

CorporateSeaborne and Other.Metallurgical. Segment costsCosts increased during the year ended December 31, 20242025 compared to the prior year primarily due to unfavorablehigher foreignvariable currencyoperational rateand changes.sales related costs driven by increased volume (1.3 million tons).

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

Seaborne Thermal. Segment Adjusted EBITDA decreased during the year ended December 31, 20242025 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($225.2$227.7 million) and unfavorable volume ($59.5 million), partially offset by favorable volumeoperational andcosts mixas variancesdescribed ($58.0 million).above.

Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the year ended December 31, 20242025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($294.5$168.8 million) and unfavorable operational costs ($106.3 million). These decreases were offset by favorable volume ($112.0 million), despite the lockprior outages during 2024, driven by increased production from the Shoal Creek Mine following the fire in the first quarter of 2023, and theyear Shoal Creek insurance recovery ($80.8 million)., offset by favorable volume.

Powder River Basin. Segment Adjusted EBITDA decreasedincreased during the year ended December 31, 20242025 compared to the same period in the prior year as a result of unfavorablefavorable volume ($50.3$38.9 million); lower sales related costs ($16.4 million) as described above; and increaseddecreased leaseoverburden spendremoval costs ($14.3$6.4 million). TheseThe decreasesincreases were offset by lowerhigher costs for labor, repairs and outside services ($32.3as million)described and favorable commodity pricing ($21.7 million).above.

Other U.S. Thermal. Segment Adjusted EBITDA decreased during the year ended December 31, 20242025 compared to the same period in the prior year due to unfavorabledecreased volumesales contract cancellation settlements ($63.1$37.7 million) and lower realized prices net of sales price sensitive costs ($34.5$29.8 million). These decreases were offset by increased sales contract cancellation settlements ($19.1 million) and lower costs for labor, repairs and outside services ($12.0 million).

Peabody is a leading producer of metallurgical and thermal coal. In 2025, Peabody sold 122.0 million tons of coal. February 2026 marked the start-up of the Centurion Mine in the Seaborne Metallurgical segment. As a result, theThe Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia at MarchJune 31,30, 2026. Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia.

Pricing during the three months ended MarchJune 31,30, 2026 is set forth in the table below.

The seaborne pricing included in the table above is not necessarily indicative of the pricing the Company realized during the three months ended MarchJune 31,30, 2026 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 three months ended MarchJune 31,30, 2026 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 geopolitical events and changes to trade policy, including tariffs and customs regulations. As future developments related to geopolitical events and 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 threesix months ended MarchJune 31,30, 2026 presented herein may not be indicative of their ultimate impacts.

In the U.S., overall electricity demand increased just under 1% year-over-year through the threesix months ended MarchJune 31,30, 2026. Through the first threesix months of 2026, electricity generation from thermal coal decreased year-over-year, driven by lower natural gas prices, stronger renewable generation and milder winterspring weathertemperatures in coal-heavy markets in the U.S. Coal’s share of electricity generation decreased to approximately 16%14% for the threesix months ended MarchJune 31,30, 2026, while wind and solar’s combined generation share wasincreased atto 20%22% and the share of natural gas generation remained stable at approximately 37%. U.S. coal inventories have increased slightlyalmost 10 million tons compared to the end of 2025 through MarchJune 31,30, 2026.

Arbitration Relating to Terminated Anglo American plc (Anglo) Acquisition

On November 25, 2024, Peabody entered into definitive agreements (the Purchase Agreements) with Anglo American plc (Anglo), to acquire afrom portionAnglo of thecertain assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia,Australia (collectively, the Assets), 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).subsidiaries.

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 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 $46.0 million of the deposit also be returned. See Note 13. “Commitments and Contingencies” to the accompanying unaudited condensed 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. At that time, Anglo’s complaint alleges,alleged, among other things, that Peabody wrongfully terminated the Purchase Agreements and seeks,sought, 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. PeabodyOn remainsJune confident5, that2026, aAnglo MACfiled occurred,its andStatement of Claim, in which it purported to quantify, for the first time in the arbitration proceedings, the damages that it wasis entitleddemanding toat terminateapproximately $755.0 million. This amount primarily consists of $628.4 million in claimed losses, representing what Anglo contends is the Purchasedifference Agreements.in value of the Assets between November 25, 2024 and August 19, 2025, with the remainder consisting of Anglo’s claimed additional costs and interest on such claimed losses and costs.

Potential Recovery of Rare Earth Elements (REEsREE)

During the initial longwall commissioning, mechanical and electrical issues were encountered at the Centurion Mine. The issues were resolved, but the disruptions constrained cutting speeds which contributed to temporary challenges to roof conditions. The Companyoperating team has implemented aeffective comprehensiveprocesses responseto planaddress focusedface conditions while maintaining production momentum and is working through the remaining roof control issues. With operational constraints significantly reduced, Peabody's focus is on proactive strata management,achieving targeted equipment optimization and deployment of additional technical and operational resources. The Company anticipates completing commissioning and production ramp-up in the second quarter of 2026 and running at full longwall production rates during the second half of 2026.rates.

Three and Six Months Ended MarchJune 31,30, 2026 Compared to the Three and Six Months Ended MarchJune 31,30, 2025

The decrease in results from continuing operations, net of income taxes for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year ($63.7$60.3 million and $124.0 million, respectively) was driven by higher operating costs and expenses ($94.5$164.5 million) and $259.0 million, respectively), induced conversion expense recognized in the current year ($17.2 million, three and six months), higher depreciation, depletion and amortization ($17.4$14.1 million and $31.5 million, respectively), reduced net gains on disposals ($10.4 million and $3.9 million, respectively), increased losses from equity affiliates ($9.0 million and $8.0 million, respectively) and lower net periodic benefit credits ($7.1 million and $14.1 million, respectively). ThisThe unfavorable variancevariances waswere partially offset by higher revenue ($36.3$113.1 million and $149.4 million, respectively) primarily driven by favorable volumepricing, increased tax benefits ($34.3 million and mix$55.2 variancesmillion, respectively) and lower year-over-yearcosts incomerelated taxesto the terminated acquisition ($20.9$16.5 million and $15.9 million, respectively).

Adjusted EBITDA for the three and six months ended MarchJune 31,30, 2026 reflected a year-over-year decrease of $61.5$69.3 million.million and $130.8 million, respectively.

Seaborne Thermal. Segment revenue decreasedincreased during the three months ended MarchJune 31,30, 2026 compared to the same period in the prior year due to favorable realized prices ($63.6 million), offset by unfavorable volume ($91.8$28.1 million) driven by reductions at the Wilpinjong Mine due to mine sequencing and the closure of the Wambo Underground Mine in September 2025,2025. partiallySegment revenue decreased during the six months ended June 30, 2026 compared to the same period in the prior year due to unfavorable volume, as previously described ($118.2 million), offset by favorable realized prices ($24.2$86.1 million).

Seaborne Metallurgical. Segment revenue increased during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year due to favorable volumerealized prices ($39.8$77.3 million) primarily from the Shoal Creek and Centurion$96.9 Minesmillion, respectively) and favorable realized pricesvolume ($23.1$28.8 million and $72.1 million, respectively). driven largely by the start-up of the Centurion Mine.

Powder River Basin. Segment revenue increaseddecreased during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year due to favorableunfavorable volume ($22.6$48.8 million and $26.2 million, respectively) resulting from decreased demand driven by increasedmild demand.weather Thein increasethe wasU.S. offset byand unfavorable realized prices ($8.7$3.1 million and $11.8 million, respectively) 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 One Big Beautiful Bill Act of 2025 (OBBBA).

Other U.S. Thermal. Segment revenue increased during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year due to favorable volume ($10.3$4.4 million and $14.4 million, respectively) driven by increased demand and favorable realized prices ($5.5$3.7 million and $9.5 million, respectively).

Corporate and Other. The increase in revenue during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year was primarily driven by higher resultsrevenue from trading activities.

Other U.S.Seaborne Thermal. Segment Costs increased during the three months ended MarchJune 31,30, 2026 compared to the same period in the prior year primarily due to higherincreased variablecommodities operational costsexpense ($9.9$17.1 million) which was driven by increasedhigher fuel pricing. Segment Costs decreased during the six months ended June 30, 2026 compared to the same period in the prior year due to decreased volume (0.22.0 million tons) which drove both lower sales related costs ($17.2 million) and variable costs ($10.7 million). These decreases were offset by increased commodities expense ($19.1 million).

Corporate and Other. The increase to Segment Costs during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year was primarily driven by higher expenses related to trading and brokerage activities ($16.4 million and $23.4 million, respectively), the unfavorable remeasurement of foreign currency ($15.1 million and $8.5 million, respectively) and lower net periodic benefit credit, excluding service cost due to the final amortization in the prior year of a previously established prior service credit ($7.0$7.1 million and $14.1 million, respectively).

Seaborne Thermal. Segment Adjusted EBITDA increased during the three months ended June 30, 2026 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($64.3 million), offset by unfavorable production costs ($20.3 million) driven by mine sequencing at the Wilpinjong Mine, higher commodities expense as described above and the unfavorable impact of higher foreign exchange rates on expenses ($8.5 million). Segment Adjusted EBITDA decreased during the threesix months ended MarchJune 31,30, 2026 compared to the same period in the prior year due to unfavorable volumeproduction costs ($30.8$49.4 million), unfavorable operational costs at the Wilpinjong Mine ($22.8 million)primarily driven by mine sequencing at the Wilpinjong Mine, unfavorable volume ($28.8 million), higher commodities expense as described above and the unfavorable impact of higher foreign exchange rates on expenses ($10.2$19.0 million). These decreases were offset by higher realized prices net of sales sensitive costs ($31.5$94.5 million).

Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year due to higherunfavorable production costs for($61.4 labor, repairsmillion and outside$102.3 services,million, respectively) primarily driven by longwall commissioning activities at the Centurion Mine, the unfavorable impact of higher foreign exchange rates on expenses ($16.4 million and $28.6 million, respectively) and higher commodities expense as described above,above. These decreases were offset by higher realized prices net of sales sensitive costs ($27.4$54.0 million and $69.6 million, respectively) and favorable volume ($12.0$26.3 million and $41.5 million, respectively).

Powder River Basin. Segment Adjusted EBITDA decreased for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year due to unfavorable volume ($28.0 million and $14.8 million, respectively), higher commodity pricing and usage as described above, increased in-pit inventory as the workforce focused on preparatory efforts in light of reduced customer demand ($11.4 million and $14.9 million, respectively) and higher leasing expense and costs for labor, repairs and outside services and commodities as described above,above. These decreases were offset by favorable volume ($12.5 million) and lower sales related costs as described above.

Other U.S. Thermal. Segment Adjusted EBITDA increased during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year primarily due to higher realized prices net of sales sensitivelower costs ($4.1for million)repairs and outside services as described above and favorable volume ($2.4$10.4 million and $16.5 million, respectively), offset by increasedhigher commodity pricing and usage ($3.4as million).described above.

Corporate and Other Adjusted EBITDA increaseddecreased during the three months ended MarchJune 31,30, 2026 compared to the same period in the prior year due to favorableunfavorable variances in Middlemount’s results driven by lower production and higher fuel costs, partially offset by higher sales pricing; and higherlower gains on equipment and land sales ($6.5$10.4 million). These increases were offset by higher selling and administrative expenses. The decrease in other items was driven by lower net periodic benefit credit, excluding service cost, as described above ($7.0 million), offset by the favorableunfavorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($6.5$15.1 million) and lower net periodic benefit credit, excluding service cost, as described above ($7.1 million).

Depreciation, depletion and amortization expense increased during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year primarily due to increased depreciation and amortization resulting from shortened mine lives. The decrease in the weighted-average depletion rate per ton for the Seaborne Thermal segment during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year reflects the increased quantity of proven and probable coal reserves at the Wilpinjong Mine resulting from the conversion of coal resources to proven and probable reserves. The increase in the weighted-average depletion rate per ton for the Seaborne Metallurgical segment during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year reflects the impact of volume and mix variances across the segment. The decrease in the weighted-average depletion rate per ton for the Other U.S. Thermal segment during the three and six months ended June 30, 2026 compared to the same periods in the prior year reflects the impact of volume and mix variances across the segment.

Interest Income. The decrease in income during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year was driven by lower average cash balances during the current period.

Unrealized (Losses) Gains on Foreign Currency Option Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.

Income Tax Benefit (Provision). The decreaseincrease in the income tax benefit (provision) during the three months ended MarchJune 31,30, 2026 compared to the same period in the prior year was primarily due to lower expected pretax income. The increase in the income tax benefit recorded during the six months ended June 30, 2026 compared to the same period in the prior year was driven by expected pretax losses in the current year compared to expected pretax income in the prior year. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information.

Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests during the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in the prior year was primarily driven by income associated with Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.

Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 122.0 million and 138.7121.7 million for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and 122.0 million and 122.3 million for the six months ended June 30, 2026 and 2025, respectively.

Mercury and Air Toxic Standards (MATS). In 2012, the U.S. Environmental Protection Agency (EPA) published the final MATS rule, which revised the New Source Performance Standards for nitrogen oxide, sulfur dioxide and fine particulate matter (PM) for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs.

On March 6, 2023, the EPA issued a final rule which reaffirmed its determination to regulate coal- and oil-fired electric generating units (EGUs) under Clean Air ActCAA section 112, including the regulation of HAPs from EGUs after considering cost. On April 24, 2023, the EPA proposed to amend the 2012 MATS rule and require an additional two-thirds reduction in the filterable PM emission of non-mercury HAP metals from existing coal-fired power plants and to reduce the mercury standard for lignite plants by 70%. On May 7, 2024, the EPA finalized a MATS rule which significantly tightened the filterable PM emissions limit for existing coal-fired EGU’s, lowering the standard from 0.030 lb/MMBtu to 0.010 lb/MMBtu for all coal-fired power plants and lowered the mercury emission standard for lignite-fired EGUs. The EPA, however, subsequently repealed both the lower filterable PM emission limits and the lower mercury standards for lignite plants. 91. Fed. Reg 9088 (February 24, 2026). This rule wasbecame effective on April 27, 2026. The rule has been challenged in the U.S. Court of Appeals for the DistrictD.C. ofCircuit. ColumbiaAir CircuitAlliance Houston v. EPA, No. 26-1070 (and consolidated case) (D.C. Circuit)Cir. infiled NorthMarch Dakota30, v. EPA (D.C. Cir., No. 24-11192026). The EPA proposed on June 17, 2025 to repeal parts of the final 2024 MATS rule regarding filterable PM standards and revise the mercury standard for existing lignite-fired EGUs. This rule was finalized on February 24, 2026 (91 Fed. Reg. 9088) and became effective on April 27, 2026.

Clean Water Act (CWA) Water Quality Certification Rule. The EPA issued a final rule in 2020 that would have limited state and tribal regulators’ certification authority under CWA Section 401 by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances. On September 27, 2023, the EPA finalized a superseding rule that would expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. That rule took effect on November 27, 2023. Challenges to the 2023 rule remain pending in the U.S. District Court for the Western District of Louisiana. On January 15, 2026, the EPA published proposed revisions to the 2023 rule in the Federal Register, and the EPA announced that it planned to propose and finalize changes later in 2026.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs. In 2020, the EPA finalized revisions to certain requirements in the 2015 rule. On May 9, 2024, the EPA published a final rule that would have established more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments. The final revised effluent limitations guidelines would have significantly increased costs for many coal-fueled steam electric power plants. In addition, the finalized final rule allowed EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim. The final rule remains subject to numerous legal challenges that have been consolidated in the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit).; due to the reconsideration process currently ongoing, however (see below), the proceedings are currently being held in abeyance. If the Eighth Circuit affirms the final rule, it could influence fuel switching or additional coal generating unit retirements by the end of 2034. On December 31, 2025, the EPA published a final Deadline Extensions Rule that extends seven compliance deadlines in the 2024 rule. The EPA is allowing EGUs six additional years (until December 31, 2031) to determine whether to submit a notice of planned participation for the permanent cessation of coal combustion. The EPA further extended the deadlines by five years (to December 31, 2034) for direct discharging EGUs to comply with zero-discharge limitations for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate. Finally, the EPA is allowing EGUs that discharge to wastewater treatment plants an additional year-and-a-half to seven-and-a-half years to comply with zero-discharge limitations for those same wastestreams. The Deadline Extensions Rule has been challenged by multiple parties, with the litigation consolidated in the U.S. Court of Appeals for the Second Circuit. A motion to transfer the consolidated petitions to the Eighth Circuit is pending. If the Deadline Extensions Rule is vacated, the 2024 rule’s deadlines could become operative again. The EPA also issued a No Action Assurance memorandum announcing it will not pursue enforcement actions for certain permit violations by EGUs not yet in compliance with permit requirements related to the 2020 and 2024 rules, if those EGUs satisfy certain conditions. InOn parallel,May 18, 2026, the EPA announcedpublished thata itproposed plansrule to proposeclarify a Reconsideration Rule in 2026 to revise someapplicability of theunmanaged limitationscombustion andresidual standardsleachate inlimitations. the91 2024Fed. rule.Reg. 28487 (May 18, 2026).