What changed in this filing

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Item 2. Management’s Discussion and Analysis

2026-05-06 compared with 2025-11-07 · 198 added, 346 removed, 363 unchanged (60% of the section changed)

11 unchanged sentences

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in the Company’s other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect its results contained in Item 1A.

“Risk Factors” of Part II of this Quarterly Report on Form 10-Q, Item 1A.

“Risk Factors” of Part II of its Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2025 filed with the SEC on May 8, 2025 and Item 1A.

“Risk Factors” of Part II of this Quarterly Report on Form 10-Q and Item 1A.

“Risk Factors” and Item 3.

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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.

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.

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In 2025, Peabody sold 122.0 million tons of coal.

Since December 31, 2024, the Wambo Underground Mine in the Seaborne Thermal Mining segment shipped its final tons.

As a result, the Company owned interests in 16 active coal mining operations located in the United States (U.S.) and Australia at September 30, 2025.

February 2026 marked the start-up of the Centurion Mine in the Seaborne Metallurgical segment.

As a result, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia at March 31, 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.

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Refer to Note 14.

“Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of the Company’s Corporate and Other operating segment.

Pricing during the three months ended September 30, 2025 is set forth in the table below.

High Low Average September 30, 2025 November 3, 2025

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

High Low Average March 31, 2026 May 1, 2026

Premium low-vol hard coking coal (Premium HCC) (1)

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(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 three months ended September 30, 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 seaborne pricing included in the table above is not necessarily indicative of the pricing the Company realized during the three months ended March 31, 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 September 30, 2025 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors.

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 March 31, 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.

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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 nine months ended September 30, 2025 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, coking coal prices relevant to Australian operations finished the quarter higher.

The quarter saw increased coal buying activity from India after its monsoon season, signs of supply rationalization in China’s steel and coal industries following China’s anti-involution policy announcement made in July, ongoing unplanned mine outages at non-Peabody mines and lower Chinese steel exports quarter-over-quarter.

Looking forward, the seaborne metallurgical coal price may remain volatile based on the outcomes of China’s supply reforms, the pace of growth of the Indian steel industry, changing global trade policies and global supply curtailment actions.

Within the seaborne thermal coal market, global thermal coal prices were mixed during the nine months ended September 30, 2025.

In China, power generation has increased year-over-year through September 30, 2025, however the share of renewables in the generation mix continues to grow, pressuring coal generation.

In addition, domestic coal production has been stronger year-over-year, which has led to weaker coal import demand through the nine months ended September 30, 2025.

In India, steady domestic coal production, lower import demand and declining coal generation has led to stable coal stockpiles.

Looking forward, seaborne thermal coal prices may remain volatile based on the outcomes of China’s supply reforms, potential re-stocking activity in the Northern Hemisphere as winter approaches 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 nine months ended September 30, 2025, electricity generation from thermal coal has increased year-over-year, driven by higher natural gas prices and stronger total generation.

Coal’s share of electricity generation has increased to approximately 16% for the nine months ended September 30, 2025, while wind and solar’s combined generation share is at 19% and the share of natural gas generation has declined to approximately 41%.

coal inventories have declined through September 30, 2025, driven by stronger summer demand, resulting in stockpiles declining over 20 million tons below levels seen at the end of 2024.

Centurion Mine

Peabody’s development of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, continues to advance as planned, making progress toward full-scale longwall production in February 2026.

Labor Relations

After industrial action at the Metropolitan Mine beginning in mid-June 2025, employees returned to work on August 1, 2025.

The Company negotiated an enterprise agreement with the Mining and Energy Union and employees, which the employees accepted on August 13, 2025.

The enterprise agreement was ratified with the Fair Work Commission on September 10, 2025.

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 three months ended March 31, 2026 presented herein may not be indicative of their ultimate impacts.

The seaborne metallurgical coal market experienced weather-related disruptions in Australia and supply tightness in key product segments.

This, combined with steady import demand from key metallurgical coal import markets, contributed to the increases in average quarterly pricing for premium coking coal (17%) and PCI (15%) during the three months ended March 31, 2026 as compared to the three months ended December 31, 2025.

In China, the continued implementation of anti-involution policies, mandated steel production limits and the introduction of steel export quotas have the potential to lead to decreased Chinese steel exports, while increasing steel-trade protectionism is supportive of steel production and seaborne metallurgical coal demand in markets outside of China.

The biggest steel growth market, India, continued to see an increase in crude steel output in the quarter.

Recent geopolitical events have increased the cost of seaborne energy, which has the potential to significantly impact the global ferrous complex, by placing upward pressure on raw material costs and downward pressure on steel product pricing through weakened downstream demand.

Looking forward, the seaborne metallurgical coal price may remain volatile based on mining rates in Australia, geopolitical events, Chinese supply reforms and the pace of growth of the Indian steel industry.

Within the seaborne thermal coal market, global thermal coal prices started the year stable but increased during the three months ended March 31, 2026, due to the closure of the Strait of Hormuz and the conflict in the Middle East.

The conflict has elevated global liquefied natural gas (LNG) prices and created volatility in global thermal energy markets.

In China, power generation increased year-over-year through March 31, 2026, which has resulted in stronger thermal generation year-over-year.

However, both domestic coal production and coal imports have remained flat year-over-year through the three months ended March 31, 2026.

In India, stronger domestic coal production, lower import demand and slightly lower coal generation led to stable coal stockpiles.

Looking forward, seaborne thermal coal prices may remain volatile based on accessibility to shipping in the Strait of Hormuz and the duration of the ongoing conflict in the Middle East.

Approximately 20% of global LNG exports flow through the Strait of Hormuz, which has created volatility in the global LNG market, a main competitor of global coal generation.

In addition, summer re-stocking activity in the Northern Hemisphere may impact global thermal coal markets in the coming months.

In the U.S., overall electricity demand increased just under 1% year-over-year through the three months ended March 31, 2026.

Through the first three months of 2026, electricity generation from thermal coal decreased year-over-year, driven by lower natural gas prices, stronger renewable generation and milder winter weather in coal-heavy markets in the U.S.

Coal’s share of electricity generation decreased to approximately 16% for the three months ended March 31, 2026, while wind and solar’s combined generation share was at 20% and the share of natural gas generation remained stable at approximately 37%.

coal inventories have increased slightly compared to the end of 2025 through March 31, 2026.

Arbitration Relating to Terminated Anglo American Acquisition

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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.

“Long-term Debt” and Note 14.

“Commitments and Contingencies” to the accompanying unaudited condensed consolidated financial statements for further information.

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Potential Recovery of Rare Earth Elements (REEs)

Peabody has been evaluating the potential recovery of REEs at its mines within the Powder River Basin.

The Company is progressing its REE initiative and intends to advance the characterization of REEs and critical minerals in its feedstock;

continue discussions with the U.S.

administration regarding critical minerals policies and priorities;

and engage in multiple workstreams as the Company moves through the evaluation process.

Peabody is advancing its evaluation of the potential recovery of REEs and critical minerals through ongoing testing to evaluate mineral types and concentrations at certain of its operations.

The Company has continued to progress technical and economic studies, advance commercial partnerships and pursue multiple federal and state funding pathways to support domestic supply chain development.

Centurion Update

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 Company implemented a comprehensive response plan focused on proactive strata management, 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.

Results of Operations

Three and Nine Months Ended September 30, 2025 Compared to the Three and Nine Months Ended September 30, 2024

The decrease in results from continuing operations, net of income taxes for the three and nine months ended September 30, 2025 compared to the same periods in the prior year ($179.1 million and $422.9 million, respectively) was driven by lower revenue primarily due to lower seaborne coal pricing ($75.9 million and $274.4 million, respectively), higher operating costs and expenses (three months, $51.1 million), current year costs related to the terminated Anglo acquisition ($54.0 million and $75.2 million, respectively) and the prior year insurance recovery at the Shoal Creek Mine (nine months, $109.5 million).

This unfavorable variance was partially offset by lower year-over-year income tax provisions ($29.1 million and $86.4 million, respectively).

Adjusted EBITDA for the three and nine months ended September 30, 2025 reflected a year-over-year decrease of $125.3 million and $358.2 million, respectively.

The following table presents tons sold by operating segment:

Three Months Ended September 30, Increase (Decrease)

to Volumes Nine Months Ended September 30, (Decrease) Increase

2025 2024 Tons % 2025 2024 Tons %

(Tons in millions) (Tons in millions)

Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025

The decrease in results from continuing operations, net of income taxes for the three months ended March 31, 2026 compared to the same period in the prior year ($63.7 million) was driven by higher operating costs and expenses ($94.5 million) and depreciation, depletion and amortization ($17.4 million).

This unfavorable variance was partially offset by higher revenue ($36.3 million) driven by favorable volume and mix variances and lower year-over-year income taxes ($20.9 million).

Adjusted EBITDA for the three months ended March 31, 2026 reflected a year-over-year decrease of $61.5 million.

The following table presents tons sold:

Three Months Ended March 31, (Decrease) Increase

2026 2025 Tons %

(Tons in millions)

Seaborne Thermal 3.0 4.4 (1.4) (32) %

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Corporate and Other 0.1 — 0.1 n.m.

— 0.1 (0.1) (100) %

Total tons sold 29.6 28.9 0.7 2 %

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The following table presents supplemental financial data by reportable segment:

Three Months Ended September 30, (Decrease)

Increase Nine Months Ended September 30, (Decrease)

Three Months Ended March 31, Increase

2026 2025 $ %

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amortization of take-or-pay contract-based intangibles;

insurance recoveries;

and certain other costs related to post-mining activities.

The following table presents revenue by reportable segment:

Three Months Ended September 30, (Decrease) Increase to Revenue Nine Months Ended September 30, (Decrease) Increase to Revenue

The following table presents revenue by segment:

Three Months Ended March 31, (Decrease) Increase to Revenue

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 197.5 $ 265.1 $ (67.6) (25) %

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Seaborne Thermal.

Segment revenue decreased during the three and nine months ended September 30, 2025 compared to the same periods in the prior year due to unfavorable realized prices ($72.8 million and $213.5 million, respectively), offset by favorable mix variances ($2.3 million and $11.8 million, respectively).

Segment revenue decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to unfavorable volume ($91.8 million) driven by reductions at the Wilpinjong Mine due to mine sequencing and the closure of the Wambo Underground Mine in September 2025, partially offset by favorable realized prices ($24.2 million).

Seaborne Metallurgical.

Segment revenue increased during the three months ended September 30, 2025 compared to the same period in the prior year due to favorable volume ($74.6 million) primarily from the Shoal Creek and Centurion Mines, offset by unfavorable realized prices ($58.2 million).

Segment revenue decreased during the nine months ended September 30, 2025 compared to the same period in the prior year due to unfavorable realized prices ($221.7 million), offset by favorable volume ($169.1 million) from the Shoal Creek and Centurion Mines.

Segment revenue increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable volume ($39.8 million) primarily from the Shoal Creek and Centurion Mines and favorable realized prices ($23.1 million).

Powder River Basin.

Segment revenue decreased during the three months ended September 30, 2025 compared to the same period in the prior year due to unfavorable realized prices ($10.3 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 One Big Beautiful Bill Act of 2025 (OBBBA).

The decrease was offset by favorable volume ($6.4 million) driven by increased demand.

Segment revenue increased during the nine months ended September 30, 2025 compared to the same period in the prior year due to favorable volume ($80.2 million) resulting from increased demand, offset by unfavorable realized prices ($8.8 million) which were driven by the impact of the federal royalty rate reduction.

Segment revenue decreased during the three and nine months ended September 30, 2025 compared to the same periods in the prior year due to unfavorable volume ($11.6 million and $48.6 million, respectively) resulting from decreased demand, a dragline outage at the Bear Run Mine and challenging geological issues at the Twentymile Mine;

unfavorable realized prices ($10.4 million and $28.0 million, respectively);

and decreased revenue from sales contract cancellation settlements ($2.7 million and $17.9 million, respectively).

Segment revenue increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable volume ($22.6 million) driven by increased demand.

The increase was offset by unfavorable realized prices ($8.7 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 One Big Beautiful Bill Act of 2025 (OBBBA).

Segment revenue increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable volume ($10.3 million) driven by increased demand and favorable realized prices ($5.5 million).

Corporate and Other.

The increase in segment revenue during the three and nine months ended September 30, 2025 compared to the same periods in the prior year was driven by higher results from trading activities.

The increase in revenue during the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by higher results from trading activities.

Segment Costs

The following table presents costs by reportable segment:

Three Months Ended September 30, Increase (Decrease) to Total Segment Costs Nine Months Ended September 30, (Decrease) Increase to Total Segment Costs

The following table presents costs by segment:

Three Months Ended March 31, (Decrease) Increase to Total Segment Costs

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 149.0 $ 180.9 $ (31.9) (18) %

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Seaborne Thermal.

Segment Costs increased during the three months ended September 30, 2025 compared to the same period in the prior year due to higher recognized costs resulting from sales volume outpacing production volume ($41.3 million).

This increase was offset by lower costs for labor, repairs and outside services ($22.5 million), lower sales related costs ($3.8 million) driven by lower realized prices and favorable commodity pricing ($2.4 million).

Segment costs decreased during the nine months ended September 30, 2025 compared to the same period in the prior year due to lower costs for labor, repairs and outside services ($57.5 million) resulting from timing of maintenance and operational improvements, favorable commodity pricing ($9.8 million), lower sales related costs ($9.1 million) driven by both lower realized prices and volume and lower leasing expense ($6.4 million);

offset by higher recognized costs resulting from sales volume outpacing production volume ($53.7 million).

Segment Costs decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to lower variable operational costs ($17.1 million) and lower sales related costs ($15.1 million), which were both driven by decreased volume (1.4 million tons).

Seaborne Metallurgical.

Segment Costs increased during the three and nine months ended September 30, 2025 compared to the same periods in the prior year due to higher variable operational and sales related costs driven by increased volumes (0.4 million tons and 1.0 million tons, respectively).

Segment Costs increased during the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services ($63.2 million) driven by challenging longwall commissioning conditions at the Centurion Mine and higher sales related costs ($15.0 million) resulting from increased volume (0.2 million tons) and higher realized pricing.

Powder River Basin.

Segment Costs decreased during the three months ended September 30, 2025 compared to the same period in the prior year primarily due to lower sales related costs ($16.3 million) which were largely driven by the federal royalty rate reduction on coal production included in the OBBBA, offset by higher costs for labor, repairs and outside services ($13.6 million) due in part to unplanned dragline outages, haul truck repairs and increased headcount.

Segment Costs increased during the nine months ended September 30, 2025 compared to the same period in the prior year primarily due to higher costs for labor, repairs and outside services ($20.1 million) due in part to unplanned dragline outages, haul truck repairs and increased headcount.

The decrease in Segment Costs during the three and nine months ended September 30, 2025 compared to the same periods in the prior year was driven by lower volume (0.3 million tons and 1.2 million tons, respectively) and lower costs for labor ($0.5 million and $9.4 million, respectively).

Segment Costs increased during the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services ($22.6 million) as the result of higher volume (1.6 million tons) and planned equipment outages and higher costs for commodities ($12.2 million).

These increases were offset by lower sales related costs ($11.5 million) which were largely driven by the federal royalty rate reduction on coal production included in the OBBBA.

Segment Costs increased during the three months ended March 31, 2026 compared to the same period in the prior year primarily due to higher variable operational costs ($9.9 million) driven by increased volume (0.2 million tons).

Corporate and Other.

Segment Costs increased during the three months ended September 30, 2025 compared to the same period in the prior year primarily due to unfavorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral, and higher expense from trading activities.

Segment Costs increased during the nine months ended September 30, 2025 compared to the same period in the prior year primarily due to lower credits for net periodic benefits, excluding service costs and higher expense from trading activities.

These increases were offset by favorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral.

The increase to Segment Costs during the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by 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 million).

Adjusted EBITDA

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

Three Months Ended September 30, Decrease to Segment Adjusted EBITDA Nine Months Ended September 30, (Decrease) Increase to Segment Adjusted EBITDA

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

Three Months Ended March 31, (Decrease) Increase to Segment Adjusted EBITDA

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 48.5 $ 84.2 $ (35.7) (42) %

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Seaborne Thermal.

Segment Adjusted EBITDA decreased during the three months ended September 30, 2025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($69.2 million) and unfavorable operational costs ($18.5 million).

Segment Adjusted EBITDA decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to unfavorable volume ($30.8 million), unfavorable operational costs at the Wilpinjong Mine ($22.8 million) driven by mine sequencing and the unfavorable impact of higher foreign exchange rates on expenses ($10.2 million).

These decreases were offset by higher realized prices net of sales sensitive costs ($31.5 million).

Seaborne Metallurgical.

Segment Adjusted EBITDA was flat for the three months ended September 30, 2025 compared to the same period in the prior year as favorable operational costs ($20.9 million), driven by the prior year impacts of wet weather in Australia and a longwall move at the Shoal Creek Mine, were offset by lower realized prices net of sales price sensitive costs ($23.8 million).

Segment Adjusted EBITDA decreased during the nine months ended September 30, 2025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($169.8 million) and the prior year Shoal Creek insurance recovery ($80.8 million), offset by favorable operational costs ($45.3 million).

Segment Adjusted EBITDA decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services, as described above, offset by higher realized prices net of sales sensitive costs ($27.4 million) and favorable volume ($12.0 million).

Powder River Basin.

Segment Adjusted EBITDA was flat for the three months ended September 30, 2025 compared to the same period in the prior year as the decrease in Segment Costs was offset by the decrease in revenue, as described in the sections above.

Segment Adjusted EBITDA increased during the nine months ended September 30, 2025 compared to the same period in the prior year due to favorable volume ($42.5 million), decreased overburden removal costs ($12.9 million) and higher realized prices net of sales sensitive costs ($10.6 million) which were largely driven by the net impact of the federal royalty rate reduction.

The increases were offset by higher costs for materials, services, repairs and labor ($20.1 million).

Segment Adjusted EBITDA decreased during the three months ended September 30, 2025 compared to the same period in the prior year primarily driven by higher costs for materials, services and repairs ($8.4 million) due in part to the dragline outage at the Bear Run Mine and the longwall move at the Twentymile Mine in the current period and lower realized prices net of sales price sensitive costs ($8.3 million).

Segment Adjusted EBITDA decreased during the nine months ended September 30, 2025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($23.2 million), higher costs for materials, services and repairs ($21.3 million) due in part to the dragline outage at the Bear Run Mine and challenging geological issues at the Twentymile Mine and decreased sales contract cancellation settlements ($17.9 million).

Segment Adjusted EBITDA decreased for the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services and commodities as described above, offset by favorable volume ($12.5 million) and lower sales related costs as described above.

Segment Adjusted EBITDA increased during the three months ended March 31, 2026 compared to the same period in the prior year primarily due to higher realized prices net of sales sensitive costs ($4.1 million) and favorable volume ($2.4 million), offset by increased commodity pricing and usage ($3.4 million).

Corporate and Other Adjusted EBITDA.

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

Three Months Ended September 30, (Decrease) Increase to Adjusted EBITDA Nine Months Ended September 30, (Decrease) Increase to Adjusted EBITDA

Three Months Ended March 31, Increase (Decrease) to Adjusted EBITDA

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Middlemount (1)

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(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 decreased during the three months ended September 30, 2025 compared to the same period in the prior year due to unfavorable variances in Middlemount’s results driven by lower sales pricing;

higher selling and administrative expenses;

and unfavorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($12.7 million).

Corporate and Other Adjusted EBITDA increased slightly during the nine months ended September 30, 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 offset by higher gains on equipment and land sales ($15.6 million);

favorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($15.8 million);

and favorable results from the Company’s equity method investment in renewable energy joint ventures ($11.1 million).

(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 other equity method investments, 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 three months ended March 31, 2026 compared to the same period in the prior year due to favorable variances in Middlemount’s results driven by higher sales pricing and higher gains on equipment and land sales ($6.5 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 favorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($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:

Three Months Ended September 30, (Decrease) Increase to Income Nine Months Ended September 30, (Decrease) Increase to Income

Three Months Ended March 31, (Decrease) Increase to Income

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Adjusted EBITDA (1)

3 unchanged sentences

Restructuring charges (1.1) (1.7) 0.6 35 %

Costs related to terminated acquisition (54.0) — (54.0) n.m.

(75.2) — (75.2) n.m.

Provision for NARM loss — — — n.m.

— (3.7) 3.7 100 %

Shoal Creek insurance recovery - property damage — — — n.m.

— 28.7 (28.7) (100) %

Costs related to terminated acquisition (3.0) (2.4) (0.6) (25) %

Changes in amortization of basis difference related to equity affiliates 0.6 0.6 — — %

1 unchanged sentence

Interest income 13.1 15.4 (2.3) (15) %

Unrealized (losses) gains on foreign currency option contracts (2.3) 3.7 (6.0) (162) % 6.1 0.4 5.7 1,425 %

Unrealized gains on foreign currency option contracts 0.3 4.3 (4.0) (93) %

Take-or-pay contract-based intangible recognition — 0.2 (0.2) (100) %

4 unchanged sentences

Depreciation, Depletion and Amortization.

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

Three Months Ended September 30, Increase (Decrease) to Income Nine Months Ended September 30, Decrease to Income

The following table presents a summary of depreciation, depletion and amortization expense by segment:

Three Months Ended March 31, Increase (Decrease) to Income

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ (21.8) $ (33.4) $ 11.6 35 %

6 unchanged sentences

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:

Three Months Ended September 30, Nine Months Ended September 30,

2025 2024 2025 2024

Three Months Ended March 31,

Seaborne Thermal $ 1.04 $ 2.00

2 unchanged sentences

Thermal 1.76 1.82

Depreciation, depletion and amortization expense increased during the three and nine months ended September 30, 2025 compared to the same periods 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 both the Seaborne Metallurgical and the Other U.S.

Thermal segments during the three and nine months ended September 30, 2025 compared to the same periods in the prior year reflect the impact of volume and mix variances across the segments.

Restructuring Charges.

The increase in restructuring charges during the current year is due to the closure of the Wambo Underground Mine which occurred during the three months ended September 30, 2025.

Costs Related to Terminated Acquisition.

The charges recorded during the current year 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 $36.3 million and $46.7 million for the three and nine months ended September 30, 2025, respectively.

Refer to Note 14.

“Commitments and Contingencies” in the accompanying unaudited condensed consolidated financial statements for further information regarding the acquisition.

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 11.

“Other Events” in the accompanying unaudited condensed consolidated financial statements.

Of this amount, Adjusted EBITDA excluded 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 nine months ended September 30, 2024.

Depreciation, depletion and amortization expense increased during the three months ended March 31, 2026 compared to the same period 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 months ended March 31, 2026 compared to the same period in the prior year reflects the increased quantity of proven and probable coal reserves 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 months ended March 31, 2026 compared to the same period 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 nine months ended September 30, 2025 compared to the same periods 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.

The decrease in income during the three months ended March 31, 2026 compared to the same period in the prior year was driven by lower average cash balances during the current period.

Unrealized Gains on Foreign Currency Option Contracts.

Unrealized gains primarily relate to mark-to-market activity on foreign currency option contracts.

For additional information, refer to Note 6.

1 unchanged sentence

Income Tax Benefit (Provision).

The decrease in the income tax benefit (provision) during the three and nine months ended September 30, 2025 compared to the same periods in the prior year was primarily due to lower expected pretax income.

The decrease in the income tax benefit (provision) during the three months ended March 31, 2026 compared to the same period in the prior year was primarily due to lower expected pretax income.

Refer to Note 8.

2 unchanged sentences

The following table presents net (loss) income attributable to common stockholders:

Three Months Ended September 30, (Decrease) Increase

to Income Nine Months Ended September 30, (Decrease) Increase

Three Months Ended March 31, (Decrease) Increase

2026 2025 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

(Loss) income from continuing operations, net of income taxes $ (25.4) $ 38.3 $ (63.7) (166) %

4 unchanged sentences

Net Income Attributable to Noncontrolling Interests.

The decrease in net income attributable to noncontrolling interests during the three and nine months ended September 30, 2025 compared to the same periods in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.

The increase in net income attributable to noncontrolling interests during the three months ended March 31, 2026 compared to the same period 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 Earnings per Share (EPS)

The following table presents diluted EPS:

Three Months Ended September 30, Decrease to EPS Nine Months Ended September 30, (Decrease) Increase

Three Months Ended March 31, Decrease to EPS

2026 2025 $ %

2 unchanged sentences

Loss from discontinued operations (0.01) — (0.01) n.m.

(0.01) (0.03) 0.02 67 %

Net (loss) income attributable to common stockholders $ (0.27) $ 0.27 $ (0.54) (200) %

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 121.7 million and 141.6 million for the three months ended September 30, 2025 and 2024, respectively, and 121.7 million and 143.1 million for the nine months ended September 30, 2025 and 2024, respectively.

Diluted EPS reflects weighted average diluted common shares outstanding of 122.0 million and 138.7 million for the three months ended March 31, 2026 and 2025, respectively.

Reconciliation of Non-GAAP Financial Measures

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Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the reportable segments’ operating performance, as displayed in the reconciliations below.

Three Months Ended September 30, Nine Months Ended September 30,

2025 2024 2025 2024

Three Months Ended March 31,

(Dollars in millions)

1 unchanged sentence

Depreciation, depletion and amortization

100.0 84.7 285.5 247.4

Asset retirement obligation expenses

13.9 12.9 41.3 38.7

Restructuring charges

4.0 1.9 9.2 2.1

Costs related to terminated acquisition 3.0 2.4

Provision for NARM loss — — — 3.7

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

Changes in amortization of basis difference related to equity affiliates (0.6) (0.6)

2 unchanged sentences

(13.1) (15.4)

Unrealized losses (gains) on foreign currency option contracts 2.3 (3.7) (6.1) (0.4)

Unrealized gains on foreign currency option contracts (0.3) (4.3)

Take-or-pay contract-based intangible recognition

(0.3) (0.8) (0.8) (2.3)

Income tax (benefit) provision (16.0) 4.9

2 unchanged sentences

Total Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its reportable segments’ operating performance, as displayed in the reconciliations below.

Three Months Ended September 30, Nine Months Ended September 30,

2025 2024 2025 2024

Three Months Ended March 31,

(Dollars in millions)

1 unchanged sentence

$ 864.7 $ 770.2

Unrealized (losses) gains on foreign currency option contracts (2.3) 3.7 6.1 0.4

Unrealized gains on foreign currency option contracts 0.3 4.3

Take-or-pay contract-based intangible recognition

0.3 0.8 0.8 2.3

Net periodic benefit credit, excluding service cost (0.4) (7.4)

Total Segment Costs $ 864.6 $ 767.3

Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment (excluding insurance recoveries), respectively, divided by segment tons sold.

Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold.

Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton.

The following tables present tons sold, revenue, Total Segment Costs and Adjusted EBITDA by reportable segment:

Three Months Ended September 30, 2025

Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S.

(Amounts in millions, except per ton data)

Tons sold 4.1 2.1 22.6 3.7

Revenue $ 242.7 $ 258.9 $ 301.4 $ 192.0

Total Segment Costs 201.7 231.1 249.7 185.1

Adjusted EBITDA $ 41.0 $ 27.8 $ 51.7 $ 6.9

Revenue per Ton $ 59.25 $ 121.34 $ 13.36 $ 51.77

Costs per Ton 49.23 108.31 11.07 49.90

Adjusted EBITDA Margin per Ton $ 10.02 $ 13.03 $ 2.29 $ 1.87

Three Months Ended September 30, 2024

Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S.

(Amounts in millions, except per ton data)

Tons sold 4.1 1.7 22.1 4.0

Revenue $ 313.2 $ 242.5 $ 305.3 $ 216.7

Total Segment Costs 193.2 214.7 253.6 188.3

Adjusted EBITDA $ 120.0 $ 27.8 $ 51.7 $ 28.4

Revenue per Ton $ 76.21 $ 144.60 $ 13.84 $ 53.52

Costs per Ton 47.01 128.04 11.50 46.50

Adjusted EBITDA Margin per Ton $ 29.20 $ 16.56 $ 2.34 $ 7.02

Nine Months Ended September 30, 2025

Three Months Ended March 31, 2026

Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S.

7 unchanged sentences

Adjusted EBITDA Margin per Ton $ 16.35 $ (3.44) $ 1.12 $ 11.42

Nine Months Ended September 30, 2024

Three Months Ended March 31, 2025

Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S.

3 unchanged sentences

Total Segment Costs 180.9 206.9 239.3 135.8

Adjusted EBITDA, excluding Shoal Creek insurance recovery $ 318.2 $ 138.9 $ 85.9 $ 110.3

Shoal Creek insurance recovery - business interruption — 80.8 — —

Adjusted EBITDA $ 84.2 $ 13.2 $ 36.3 $ 32.9

7 unchanged sentences

Regulatory Matters - U.S.

Black Lung Benefits Act Self-Insurance Requirements .

The Black Lung Benefits Act requires each coal mine operator to secure the payment of its potential benefits liability by either qualifying as a self-insurer or by purchasing and maintaining a commercial insurance contract.

The Department of Labor’s Office of Workers’ Compensation Programs (OWCP) is responsible for authorizing coal mine operators to self-insure and for setting the security amounts.

As part of its ongoing efforts to reform the self-insurance program to ensure that operators are adequately securing their liabilities, the OWCP finalized a rule on December 12, 2024 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts.

The changed requirements for security posted to self-insure black lung liabilities could result in the Company being required to post additional security for its obligations.

During February 2025, the Trump Administration issued letters to impacted companies that the 60-day deadline to provide information was no longer applicable and that no additional information was required at this time.

They also announced that OWCP would provide additional guidance in due course.

Recent Announcement by the U.S.

Environmental Protection Agency (EPA).

In response to an executive order issued by President Trump requiring agencies to identify regulations for regulatory roll back, the EPA announced on March 12, 2025, that it will reconsider several EPA actions, including:

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

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

• Cross State Air Pollution Rule (CSAPR);

Mercury and Air Toxic Standards (MATS) .

• Implementation of the Regional Haze Program;

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

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

• Rules for disposal of coal combustion residuals.

On June 17, 2025, in accordance with the agency’s earlier announcement, the EPA proposed to repeal all GHG emissions standards for new and existing fossil fuel-fired power plants and, in the alternative, to repeal emission guidelines for existing fossil fuel-fired power plants and requirements for modified coal-fired steam generating to use carbon capture and sequestration technology.

In addition, on June 17, 2025, the EPA proposed to repeal parts of a final 2024 MATS rule regarding filterable PM standards and requirements and a revised mercury standard for existing lignite-fired EGUs.

Both actions are currently pending.

On August 1, 2025, the EPA published a proposed rule to reconsider a 2009 endangerment finding regarding the regulation of GHGs under the Clean Air Act (CAA).

In the 2009 action, the EPA found that current and projected atmospheric concentrations of six GHGs were reasonably anticipated to endanger public health and welfare and that GHG emissions from new motor vehicles contributed to air pollution that threatened public health and welfare.

These determinations formed the basis for subsequent regulation of GHGs from new motor vehicles under section 202 of the CAA.

The EPA is proposing to rescind the 2009 endangerment finding and to fully repeal vehicle rules based on GHG emissions.

On September 29, 2025, the EPA released a pre-publication version of a direct final rule to extend the date for existing steam electric power plants to decide whether to submit a notice of planned participation for the permanent cessation of coal combustion subcategory in the 2024 Supplemental Steam Electric Reconsideration Rule.

On that same day, the EPA released a pre-publication version of a related proposed rule to extend seven deadlines in the 2024 rule.

Peabody will continue to monitor these items as changes could have significant impact on the U.S.

coal mining industry, Peabody’s mining operations and its customers.

Regional Haze .

The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from man-made air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal.

States are required to revise plans every 10 years, but these statutory deadlines have not been met.

On March 29, 2024, the EPA published a proposed consent decree under which deadlines (for the second 10-year regional haze implementation period) would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026).

The EPA subsequently filed a motion to approve the consent judgment in the U.S.

District Court for the District of Columbia which was granted.

On December 31, 2024, the EPA proposed to revise the due date for plans (for the third regional haze implementation period) from July 31, 2028 to July 31, 2031.

As noted above, the EPA has also announced plans to “restructure” the regional haze program and, on September 29, 2025, issued an Advance Notice of Proposed Rulemaking to “streamlining regulatory requirements impacting states’ visibility improvement obligations under the Clean Air Act.”

Complaints Filed Against “Climate Superfund Laws” and Announced State Actions .

On April 30 and May 1, 2025, respectively, the U.S.

Department of Justice filed complaints for declaratory and injunctive relief against the states of Michigan and Hawaii regarding alleged liability of fossil fuel companies for past GHG emissions and against New York and Vermont for “climate superfund” laws.

These complaints allege that existing litigation and state laws interfere with federal law, including the CAA, and with interstate and foreign commerce.

The Company will monitor this litigation and its potential impact on the U.S.

coal mining industry, its mining operations and customers.

National Environmental Policy Act (NEPA) .

NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement.

Peabody must provide information to agencies when it proposes actions that will be under the authority of the federal government.

The NEPA process involves public participation and can involve lengthy timeframes.

Since July 2020, the White House Council on Environmental Quality (CEQ) has revised its longstanding NEPA regulations on several occasions.

On January 20, 2025, President Trump issued Executive Order 14154, which directed the CEQ to propose rescinding its NEPA regulations and to provide guidance to federal agencies on implementing NEPA and to coordinate the revision of the agencies’ own implementing regulations.

On February 25, 2025, the CEQ published an Interim Final Rule removing all CEQ NEPA regulations from the Code of Federal Regulations.

The CEQ has clarified that individual agencies are free to continue following or to amend their own NEPA implementation procedures, which largely conformed to the CEQ’s regulations.

On May 28, 2025, the CEQ withdrew its January 9, 2023 interim guidance on consideration of GHG emissions and climate change when conducting environmental reviews pursuant to NEPA.

On September 29, 2025, the CEQ issued guidance requiring all heads of federal departments and agencies to revise (or to establish) NEPA implementation procedures consistent with Executive Order 14154, the 2023 and 2025 statutory amendments to NEPA and the U.S.

Supreme Court’s May 29, 2025 decision in Seven County Infrastructure Coalition v.

Eagle County, Colorado .

The CEQ emphasized the need for agencies to streamline procedures and ensure that the NEPA process does not go on for too long in time or in volume.

SEC Climate-Related Disclosures .

On March 6, 2024, the SEC adopted final rules it expected would enhance and standardize climate-related disclosures by public companies and in public offerings.

Specifically, the final rules required disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition;

certain GHG emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider;

and certain climate-related financial metrics to be included in a company’s audited financial statements.

The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the U.S.

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 Act 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.

This rule was challenged in the U.S.

Court of Appeals for the District of Columbia Circuit (D.C.

Circuit) in North Dakota v.

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.

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).

On April 4, 2024, the SEC voluntarily stayed implementation of the final rules pending such judicial review.

On March 27, 2025, the SEC announced that it would end its defense of the final rules.

On April 24, 2025, the Eighth Circuit directed the SEC to provide a status update in the ongoing litigation concerning the final rules.

On July 23, 2025, the SEC indicated that it does not intend to review or reconsider the final rules but requested that the Eighth Circuit proceed with the litigation and decide the case.

One Big Beautiful Bill Act of 2025 .

The OBBBA was signed into law on July 4, 2025.

Several provisions of the legislation could materially affect the Company’s operations, financial condition or cash flows, including a reduction to the federal royalty rate on coal production and the addition of metallurgical coal which is suitable for use in the production of steel to the list of critical minerals eligible for the Section 45X tax credit through 2029 at a rate of 2.5% of production costs.

Peabody realized benefits of approximately $9 million during the third quarter of 2025 related to the federal royalty reduction provisions of the legislation and estimates similar benefits for the fourth quarter of 2025.

The Company will continue to evaluate the applicability and effect of the OBBBA as more guidance is issued.

If the Eighth Circuit affirms the final rule, it could influence fuel switching or additional coal generating unit retirements by the end of 2034.

On December 31, 2025, the EPA published a final Deadline Extensions Rule that extends seven compliance deadlines in the 2024 rule.

The EPA is allowing EGUs six additional years (until December 31, 2031) to determine whether to submit a notice of planned participation for the permanent cessation of coal combustion.

The EPA further extended the deadlines by five years (to December 31, 2034) for direct discharging EGUs to comply with zero-discharge limitations for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate.

Finally, the EPA is allowing EGUs that discharge to wastewater treatment plants an additional year-and-a-half to seven-and-a-half years to comply with zero-discharge limitations for those same wastestreams.

The EPA also issued a No Action Assurance memorandum announcing it will not pursue enforcement actions for certain permit violations by EGUs not yet in compliance with permit requirements related to the 2020 and 2024 rules, if those EGUs satisfy certain conditions.

In parallel, the EPA announced that it plans to propose a Reconsideration Rule in 2026 to revise some of the limitations and standards in the 2024 rule.

Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities;

Federal CCR Permit Program and Revisions to Closure Requirements.

On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills.

Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval.

The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements.

The comment period for the EPA’s proposal ended on April 20, 2020.

The EPA has not yet issued a final rule, but it has indicated that it plans to reopen the comment period for that proposal in a future action.

Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C.

Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective.

On November 28, 2025, the EPA proposed to extend, by three years, the compliance deadline in the 2020 amendments for owners and operators to complete closure of unlined impoundments larger than 40 acres.

On May 8, 2024, the EPA published a final rule containing additional amendments to the 2015 CCR rule that further address aspects of the D.C.

Circuit’s 2018 decision.

On February 10, 2026, the EPA published a final rule that provides additional time to meet certain requirements in the May 2024 Rule.

Finally, on April 9, 2026, the EPA published a proposed rule to amend several provisions governing the disposal of CCR in landfills and surface impoundments and the benefit use for CCR.

Regulatory Matters - Australia

Industrial Relations Laws.

A national industrial relations system, the Fair Work Act and National Employment Standards, applies to all private sector employers and employees where the employer is a corporation.

The matters regulated under the national system include general employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes.

Most of the hourly workers employed in the Company’s mines are also covered by the Black Coal Mining Industry Award and company specific enterprise agreements approved under the national system.

Under the current Commonwealth Labor Party administration, there continues to be an increased legislative focus on enhanced employee entitlements including Flexible Work Arrangements and Right to Disconnect laws.

On December 7, 2023, the Fair Work Legislation Amendment (Closing Loopholes) Bill 2023 was passed by the Australian Federal Parliament.

The legislation allows unions, employees and/or hosts to make application to the Fair Work Commission (the Commission) for a ‘regulated labour hire arrangement order’ that, if successful, requires labor hire employers to provide similar wages and conditions to regulated workers as those provided to employees of the host.

The Commission must make the order requested if it is satisfied that (1) the employer supplies (or will supply) employee(s) to a regulated host to perform work for the host;

(2) the regulated host has 15 employees or more;

and (3) the regulated host has an enterprise agreement that would apply to the regulated employees if they were directly employed by the host, unless the Commission is satisfied that it is not fair and reasonable to do so.

These orders do not apply to contractor arrangements, only labor hire.

Various union applications for regulated labor hire arrangement orders to apply at Australian coal mining operations have been successfully made, and are currently being considered by the Commission.

Orders have been made in relation to labor hire employers who provide labor to Peabody Energy Australia PCI Mine Management Pty Ltd (now a regulated host) at its Coppabella Mine and to Helensburgh Coal Pty Ltd (now a regulated host) at the Metropolitan Mine.

Native Title and Cultural Heritage Laws.

Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement.

These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established.

Native title rights do not extend to minerals;

however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements.

There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Both New South Wales (NSW) and Queensland have additional state specific legislation in place that enables Aboriginal people to claim freehold title to available land currently owned by the state government.

If and when title to any claimable land is transferred to the relevant Aboriginal people, then ongoing consultation and compensation arrangements will need to be in place with the new landowner.

There is claimable land within proximity to all Company operations in NSW and Queensland and accordingly, as and when any claims are processed by the respective state government, the Company will need to progress consultation and compensation arrangements to ensure that its access rights are maintained.

The Company continues to monitor the progress of any claims that have the potential to impact its operations.

Aboriginal and Torres Strait Islander Heritage Protection Act 1984 (ATSIHP).

The purpose of the ATSIHP Act is to ensure the preservation and protection from harm or desecration of areas and objects in Australia and in Australian waters, that are of particular significance to Aboriginal people.

Under the ATSIHP Act, the Commonwealth Minister for Indigenous Australians can make declarations in relation to areas or objects for the purposes of protecting Aboriginal and Torres Strait Islander heritage.

Declarations are made in response to applications made by an Aboriginal person or group showing that the area or object is significant with respect to Aboriginal culture and is under threat of injury or desecration.

Such a declaration may prevent any development being carried out on the relevant area of land.

In 2024, the Commonwealth Minister made a declaration under the ATSIHP Act over an area that had been approved under state and federal environmental and planning laws for a gold mining project in NSW.

The project proponent has indicated that the decision renders the mine project unviable and has initiated Federal Court proceedings seeking a judicial review of the decision-making process.

Hearings into the matter are expected to occur in December 2025.

The Company will monitor any legal precedents set in this case that have the potential to impact its operations.

New South Wales (NSW) Strategic Statement on Coal Exploration and Mining.

The NSW Government released a new NSW Coal Industry 2026-50 policy (the Policy) in March 2026 (replacing the Strategic Statement on Coal Exploration and Mining) that provided a high level framework for the government's policy approach to the future of the coal sector.

The Policy’s key features include:

no new standalone greenfield coal mines;

no further government investment in coal exploration, although exploration will continue to be permitted near existing mine sites;

extensions to existing operations will continue to be considered;

and strengthened emissions regulation requirements for coal mine emissions.

Risks and Regulations Related to Global Climate Change

Other than as described in the following section, there have been no significant changes to the Company’s global climate matters subsequent to December 31, 2024.

There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2025.

Refer to Part I, Item 1.

“Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 for information regarding the Company’s global climate matters.

Regulations Related to Global Climate Change

The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of GHG emission targets for developed nations.

signed the Kyoto Protocol but it has never been ratified by the U.S.

Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008.

There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015).

At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties.

At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020.

In December 2012, Australia signed on to the second commitment period.

During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reduction contributions after the second commitment period ended in 2020 (the Paris Agreement).

The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global GHG emissions.

On January 20, 2021, the U.S.

reentered the Paris Agreement by accepting the agreement and all of its articles and clauses, after having announced its withdrawal from the agreement in November 2019.

On January 20, 2025, pursuant to the Executive Order on Putting America First In International Environmental Agreements, President Trump directed the U.S.

Ambassador to the United Nations to submit a formal notification withdrawing the United States from the Paris Agreement.

Liquidity and Capital Resources

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The Company has also generated cash from the sale of non-strategic assets, including coal reserves, coal resources and surface lands, and, from time to time, borrowings under its credit facilities and the issuance of securities.

The Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, finance and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, dividends, share repurchases and selling and administrative expenses.

The Company has also used cash for early debt retirements and acquisitions.

The Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, finance and operating lease payments, early debt retirements, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral requirements, dividends, share repurchases and selling and administrative expenses.

Any future determinations to return capital to stockholders, such as dividends or share repurchases, will depend on a variety of factors, including the Company’s net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results.

The Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on its future financial performance, which in turn depends on the successful implementation of its strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to its industry, many of which are beyond the Company’s control.

As of September 30, 2025, the Company’s cash and cash equivalents balances totaled $603.3 million, including approximately $377 million held by U.S.

As of March 31, 2026, the Company’s cash and cash equivalents balances totaled $492.5 million, including approximately $353 million held by U.S.

subsidiaries, approximately $129 million held by Australian subsidiaries and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S.

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in the form of intercompany dividends.

During the nine months ended September 30, 2025, no profits from foreign subsidiaries were repatriated.

During the three months ended March 31, 2026, no profits from foreign subsidiaries were repatriated.

If foreign-held cash is repatriated in the future, the Company does not expect restrictions or potential taxes will have a material effect to its near-term liquidity.

The Company’s available liquidity decreased from $1,072.5 million as of December 31, 2024 to $951.2 million as of September 30, 2025.

The Company’s available liquidity decreased from $942.1 million as of December 31, 2025 to $868.2 million as of March 31, 2026.

Available liquidity was comprised of the following:

September 30, 2025 December 31, 2024

March 31, 2026 December 31, 2025

(Dollars in millions)

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Capital Returns to Shareholders

The Company paid dividends of $27.5 million during the nine months ended September 30, 2025.

The Company paid dividends of $9.2 million during the three months ended March 31, 2026.

Surety Agreement Amendment and Collateral Requirements

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In order to maintain the maximum collateral agreement, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter.

The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers, which was $493.9 million at September 30, 2025.

The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds included within the surety bond portfolio and the amount of collateral posted in favor of surety providers, which was $479.0 million at March 31, 2026.

The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months.

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The Company’s ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test.

The Company is in compliance with such requirements at September 30, 2025.

At September 30, 2025, the Company’s maximum aggregate collateral amount was $519.2 million, which was comprised of $392.8 million in trust accounts and letters of credit of $126.4 million held for the benefit of certain surety providers.

The Company is in compliance with such requirements at March 31, 2026.

At March 31, 2026, the Company’s maximum aggregate collateral amount was $504.1 million, which was comprised of $377.7 million in trust accounts and letters of credit of $126.4 million held for the benefit of certain surety providers.

Credit Support Facilities

In February 2022, the Company entered into an agreement which provides up to $250.0 million of capacity for irrevocable standby letters of credit, primarily to support reclamation bonding requirements.

The initial agreement required the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization).

Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum.

The Company receives a variable deposit rate on the amount of cash collateral posted in support of letters of credit.

At September 30, 2025, letters of credit of $115.6 million were outstanding under the agreement, which were collateralized by cash of $119.1 million.

The agreement was amended on November 3, 2025, to (i) extend the expiration date to December 31, 2030 and (ii) change the required minimum cash collateral amount to 102% of the aggregate amount of letters of credit outstanding under the agreement, provided that in the event the Company’s credit rating falls below certain thresholds, the minimum collateral amount shall increase to 103%.

The agreement was amended on November 3, 2025, to (i) extend the expiration date to December 31, 2030 and (ii) reduce the required minimum cash collateral amount to 102% of the aggregate amount of letters of credit outstanding under the agreement, provided that in the event the Company’s credit rating falls below certain thresholds, the minimum collateral amount shall increase to 103%.

At March 31, 2026, letters of credit of $78.1 million were outstanding under the agreement.

In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements.

The Company receives a variable deposit rate on the amount of cash collateral posted in support of the bank guarantee facilities, which mature at various dates between 2026 and 2029.

At September 30, 2025, the bank guarantee facilities were backed by cash of $205.9 million.

At March 31, 2026, guarantees of $218.5 million were issued for which the Company receives a variable deposit rate on the amount of cash collateral posted in support of the facilities, which mature at various dates between 2026 and 2030.

Revolving Credit Facility

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The revolving commitments and any related loans, if applicable (any such loans, the Revolving Loans), established by the 2024 Credit Agreement terminate or mature, as applicable, on January 18, 2028, subject to certain conditions relating to the Company’s outstanding 2028 Convertible Notes.

The Revolving Loans bear interest at a secured overnight financing rate (SOFR) plus an applicable margin ranging from 3.50% to 4.25%, depending on the Company’s total net leverage ratio (as defined under the 2024 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option.

The Revolving Loans bear interest at a secured overnight financing rate plus an applicable margin ranging from 3.50% to 4.25%, depending on the Company’s total net leverage ratio (as defined under the 2024 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option.

Letters of credit issued under the 2024 Credit Agreement incur a combined fee equal to an applicable margin ranging from 3.50% to 4.25% plus a fronting fee equal to 0.125% per annum.

Unused capacity under the 2024 Credit Agreement bears a commitment fee of 0.50% per annum.

On November 25, 2024, the Company amended the 2024 Credit Agreement to, among other things, permit (i) Peabody’s then-planned acquisition of multiple coal mines from Anglo, (ii) the related bridge loan facility and (iii) the incurrence of additional indebtedness to finance the acquisition, subject to compliance with certain pro forma financial covenants.

As further discussed in Note 14.

“Commitments and Contingencies,” Peabody terminated the acquisition with Anglo on August 19, 2025.

As of September 30, 2025, the 2024 Credit Agreement had only been utilized for letters of credit, including $49.3 million outstanding as of September 30, 2025.

As of March 31, 2026, the 2024 Credit Agreement had only been utilized for letters of credit, including $49.2 million outstanding as of March 31, 2026.

These letters of credit support the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees as further described in Note 12.

“Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $270.7 million at September 30, 2025.

“Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $270.8 million at March 31, 2026.

The 2024 Credit Agreement contains customary covenants that, among other things and subject to certain exceptions (including compliance with financial ratios), may limit the Company and its subsidiaries’ ability to incur additional indebtedness, make certain restricted payments or investments, sell or otherwise dispose of assets, enter into transactions with affiliates, create or incur liens, and merge, consolidate or sell all or substantially all of their assets.

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subsidiaries, as well as a pledge of two Australian subsidiaries.

Capital Expenditures

The Company expects 2025 capital expenditures of approximately $420 million.

The Company’s total indebtedness as of September 30, 2025 and December 31, 2024 is presented in the table below.

Debt Instrument (defined below, as applicable) September 30, 2025 December 31, 2024

The Company’s total indebtedness as of March 31, 2026 and December 31, 2025 is presented in the table below.

Debt Instrument (defined below, as applicable) March 31, 2026 December 31, 2025

(Dollars in millions)

3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) $ 320.0 $ 320.0

BUMA Loan Note — 9.3

Finance lease obligations 19.1 20.8

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Long-term debt $ 320.9 $ 321.2

The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at September 30, 2025, of approximately $8 million in 2025, $20 million in 2026, $15 million in 2027, $327 million in 2028, and less than $1 million in 2029 and thereafter.

Cash paid for interest, net of capitalized interest related to the Company’s indebtedness and financial assurance instruments amounted to $35.0 million and $32.6 million during the nine months ended September 30, 2025 and 2024, respectively.

The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at March 31, 2026, of approximately $18 million in 2026, $16 million in 2027, $327 million in 2028, and less than $1 million in 2029 and thereafter.

The Company paid cash of $9.9 million during both the three months ended March 31, 2026 and 2025, for interest, net of capitalized interest, related to the Company’s indebtedness and financial assurance instruments.

2028 Convertible Notes

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The 2028 Convertible Notes are senior unsecured obligations of the Company and are governed under an indenture.

The Company used the proceeds of the offering of the 2028 Convertible Notes and available cash to redeem its then-existing senior secured notes and to pay related premiums, fees and expenses relating to the offering and redemptions.

The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms.

The 2028 Convertible Notes bear interest at a rate of 3.250% per year, payable semi-annually in arrears on March 1 and September 1 of each year.

During the third quarter of 2025, the Company’s reported common stock prices did not prompt the conversion feature of the 2028 Convertible Notes.

As a result, the 2028 Convertible Notes will not be convertible during the fourth quarter of 2025.

Bridge Loan Facility

Concurrently with its entry into definitive agreements to acquire the Anglo assets, the Company entered into a bridge loan facility commitment letter (the Bridge Commitment Letter, and the senior secured 364-day bridge facility provided for therein, the Bridge Facility), pursuant to which the lenders agreed to provide the Bridge Facility to the Company in order to finance the then-planned acquisition in part.

The Bridge Facility was terminated on August 19, 2025.

During the three and nine months ended September 30, 2025, the Company paid commitment and duration fees on the Bridge Facility of $36.3 million and $46.7 million, respectively, which are included in “Costs related to terminated acquisition” in the unaudited condensed consolidated statements of operations.

During both the fourth quarter of 2025 and the first quarter of 2026, the Company’s reported common stock prices prompted the conversion feature of the 2028 Convertible Notes.

As a result, the 2028 Convertible Notes were convertible at the option of the holders during the first quarter of 2026, for which no conversion requests were received, and remain convertible during the second quarter of 2026.

It is the Company’s current intent to settle any conversions of the 2028 Convertible Notes through shares of its common stock.

As such, the 2028 Convertible Notes are not classified as a current obligation in the accompanying condensed consolidated balance sheets.

Through May 4, 2026, the Company has not received any conversion requests and does not anticipate receiving any conversion requests in the near term as the market value of the 2028 Convertible Notes exceeds their conversion value.

Accounts Receivable Securitization Program

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Funding capacity under the program may also be utilized for letters of credit in support of other obligations, which has been the Company’s primary utilization.

At September 30, 2025, the Company had no outstanding borrowings and $62.5 million of letters of credit outstanding under the program.

The Company was not required to post cash collateral under the securitization program at September 30, 2025.

At March 31, 2026, the Company had no outstanding borrowings and $66.0 million of letters of credit outstanding under the program.

The Company was not required to post cash collateral under the securitization program at March 31, 2026.

The accounts receivable securitization program was amended in January 2025 to extend its maturity to January 2028.

Covenant Compliance

The Company was compliant with all relevant covenants under its debt and other finance agreements at September 30, 2025.

The following table summarizes the Company’s cash flows for the nine months ended September 30, 2025 and 2024, as reported in the accompanying unaudited condensed consolidated financial statements.

Nine Months Ended September 30,

The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2026.

The following table summarizes the Company’s cash flows for the three months ended March 31, 2026 and 2025, as reported in the accompanying unaudited condensed consolidated financial statements.

Three Months Ended March 31,

(Dollars in millions)

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Operating Activities.

The decrease in net cash provided by operating activities for the nine months ended September 30, 2025 compared to the same period in the prior year was primarily driven by a year-over-year decrease in cash from collateral arrangements resulting from prior year collateral releases ($148.9 million), costs related to the terminated Anglo acquisition ($75.2 million) and lower cash from mining operations.

These decreases were partially offset by a year-over-year increase in operating cash flow from working capital ($288.4 million), primarily attributable to changes in accounts payable and accrued expenses ($198.0 million) driven by prior year income tax payments and Shoal Creek inventory primarily due to the prior year lock outage ($87.1 million).

The decrease in net cash provided by operating activities for the three months ended March 31, 2026 compared to the prior year was driven by lower cash generated from mining operations and a year-over-year decrease in operating cash flow from working capital ($33.8 million).

Investing Activities.

The decrease in net cash used in investing activities for the nine months ended September 30, 2025 compared to the same period in the prior year was driven by a decrease due to the prior period Wards Well acquisition ($143.8 million), receipt of Anglo acquisition deposit ($29.0 million), and higher net distribution from joint ventures ($19.1 million).

These variances were partially offset by changes in accrued expenses related to capital accruals ($28.1 million), higher capital expenditures ($15.1 million), and the prior year cash receipt for Shoal Creek insurance recovery ($10.9 million).

The increase in net cash used in investing activities for the three months ended March 31, 2026 compared to the prior year was driven by higher net contributions to joint ventures ($17.9 million) and higher capital expenditures ($15.0 million).

Financing Activities.

The decrease in net cash used by financing activities for the nine months ended September 30, 2025 compared to the same period in the prior year was primarily driven by decreases in common stock repurchases ($183.1 million).

The decrease in net cash used in financing activities for the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by decreases in distributions to noncontrolling interests ($7.0 million).

Off-Balance-Sheet Arrangements

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The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk.

September 30, 2025

March 31, 2026

Reclamation Support Other Support (1)

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(3) Certain letters of credit serve as collateral for surety bonds at the request of surety bond providers.

Not presented in the above table is $851.0 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at September 30, 2025, as described in Note 13.

Not presented in the above table is $811.3 million of restricted cash and collateral which are included in the accompanying condensed consolidated balance sheets at March 31, 2026, as described in Note 12.

“Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements.

Such collateral is primarily in support of the financial instruments noted above, including in relation to the Company’s surety bond portfolio, its collateralized letter of credit agreement, its bank guarantee facilities and amounts held directly with beneficiaries which are not supported by surety bonds.

The restricted cash and collateral balance increased $41.2 million during the nine months ended September 30, 2025 due to an increase in bonding requirements and the impact of foreign currency rate changes.

At September 30, 2025, the Company had total asset retirement obligations of $730.3 million.

The restricted cash and collateral balance decreased $32.8 million during the three months ended March 31, 2026 due to a change in the mix of financial instruments used to support the Company’s obligations, partially offset by the impact of foreign currency rate changes.

At March 31, 2026, the Company had total asset retirement obligations of $756.3 million.

Bonding requirement amounts may differ significantly from the re lated asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.

At September 30, 2025, the Company’s reclamation bonding requirements were supported by approximately $743 million of restricted cash and other balances serving as collateral, which exceeds the financial liability for final mine reclamation as calculated in accordance with U.S.

At March 31, 2026, the Company’s reclamation bonding requirements were supported by approximately $705 million of restricted cash and other balances serving as collateral.

Critical Accounting Policies and Estimates

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Actual results may differ from these estimates.

At September 30, 2025, the Company identified certain assets with an aggregate carrying value of approximately $68 million in its Other U.S.

At March 31, 2026, the Company identified certain assets with an aggregate carrying value of approximately $60 million in its Other U.S.

Thermal segment whose recoverability is most sensitive to customer concentration risk.

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“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in its Annual Report on Form 10-K for the year ended December 31, 2025.

The Company’s critical accounting policies remain unchanged at September 30, 2025, and there have been no material changes in the Company’s critical accounting estimates.

The Company’s critical accounting policies remain unchanged at March 31, 2026, and there have been no material changes in the Company’s critical accounting estimates.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis