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Item 2. Management’s Discussion and Analysis

2025-05-08 compared with 2024-11-08 · 309 added, 474 removed, 332 unchanged (70% of the section changed)

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Cautionary Notice Regarding Forward-Looking Statements

This report includes statements of Peabody’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections.

These statements relate to future events or Peabody’s future financial performance.

The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to Peabody’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report.

These forward-looking statements are based on numerous assumptions that Peabody believes are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements.

This report includes statements of the Company’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections.

These statements relate to future events or the Company’s future financial performance.

The Company uses words such as “anticipate,” “believe,” “expect,” “intend,” “may,” “forecast,” “project,” “should,” “estimate,” “goal,” “plan,” “outlook,” “target,” “likely,” “could,” “will,” “would,” “to be” or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to the Company’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report.

These forward-looking statements are based on numerous assumptions and expectations that the Company believes in good faith to be reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements.

These factors are difficult to accurately predict and may be beyond the Company’s control.

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 June 30, 2024 filed with the SEC on August 8, 2024 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 the Company’s results of operations includes references to and analysis of Adjusted EBITDA and Total Reporting Segment Costs, which are financial measures not recognized in accordance with U.S.

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 as the primary metric to measure each of the segments’ operating performance and allocate resources.

Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments’ operating performance.

Also included in the following discussion of the Company’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment.

These metrics are used by management to measure each of its reporting segments’ operating performance.

Adjusted EBITDA is used by the chief operating decision maker, defined as Peabody’s President and Chief Executive Officer, as the primary financial metric to measure each segment’s operating performance against expected results and to allocate resources, including capital investment in mining operations and potential expansions.

Total Segment Costs is also used by management as a component of a metric to measure each segment’s operating performance.

Also included in the following discussion of Peabody’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment.

These metrics are used by management to measure each reporting segment’s operating performance.

Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting segment level.

The Company considers all measures reported on a per ton basis to be operating/statistical measures;

however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2.

In its discussion of liquidity and capital resources, the Company includes references to Available Free Cash Flow (AFCF) which is also a non-GAAP financial measure.

AFCF is used by management as a measure of its ability to generate excess cash flow from its business operations.

The Company believes non-GAAP performance measures are used by investors to measure its operating performance.

however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2.

Peabody believes non-GAAP measures are used by investors to measure its operating performance.

These measures are not intended to serve as alternatives to U.S.

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Peabody is a leading producer of metallurgical and thermal coal.

In 2023, the Company produced and sold 126.7 million and 126.2 million tons of coal, respectively, from continuing operations.

At September 30, 2024, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

In 2024, Peabody produced and sold 118.1 million and 118.0 million tons of coal, respectively, from continuing operations.

At March 31, 2025, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia.

In addition to its mining operations, the Company markets and brokers coal from other coal producers;

trades coal and freight-related contracts;

and since 2022, is partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage.

The Company reports its results of operations primarily through the following reportable segments:

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Refer to Note 15.

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

Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 index thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended September 30, 2024 is set forth in the table below.

The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended September 30, 2024 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized.

“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 segment.

The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended March 31, 2025 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized.

The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.

In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended September 30, 2024 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 below is also not necessarily indicative of the pricing the Company realized during the three months ended March 31, 2025 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors.

Such long-term contracts in the U.S.

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Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company’s realized pricing.

High Low Average September 30, 2024 November 4, 2024

High Low Average March 31, 2025 May 2, 2025

Premium HCC (1)

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(2) Prices expressed per short ton.

Within the global coal industry, supply and demand for its products and the supplies used for mining continue to be impacted by the ongoing Russian-Ukrainian conflict.

As future developments related to the Russian-Ukrainian conflict and geopolitical instability in key energy producing regions are unknown, the global coal industry data for the nine months ended September 30, 2024 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, coking coal prices have retreated from a high base during the nine months ended September 30, 2024.

Parts of the global steel market have reported tepid demand and thin profit margins during this period, restricting demand growth for metallurgical coal.

In China, continued weakness in the property sector has contributed to lower domestic steel demand and steel production in 2024 and has also supported increased steel exports.

The increased availability of competitively priced Chinese imports has pressured steel margins for steel producers in other countries, although India has recorded year-over-year production growth due to its increased domestic consumption.

Meanwhile, global supply of coking coal has been relatively stable during the nine months ended September 30, 2024, and has met global demand despite various disruption events, such as a fire at the Grosvenor Mine in Australia and shipping interruptions at the U.S.’s Baltimore, Maryland port.

In the PCI segment, prices were initially under pressure early in the year with a wide discount to coking coal caused in part by reduced steel making productivity targets under thin margin conditions.

PCI relativities to coking coal have since improved.

In September 2024, increased government stimulus activity in China has supported an uptick in Chinese ferrous futures prices, which has in turn contributed to improved spot pricing for seaborne metallurgical coal.

In the coming period, seasonal restocking patterns and ongoing economic stimulus may lend support to metallurgical coal pricing.

Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of exports from Australia and economic performance in China, India and elsewhere.

Within the seaborne thermal coal market, global thermal coal prices continued to remain stable during the nine months ended September 30, 2024, driven by healthy supply meeting elevated demand in Asian markets.

In China, overall total generation demand has been elevated while domestic coal production has remained relatively flat, which has driven stronger coal import demand year-over-year through the nine months ended September 30, 2024.

In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production.

Looking ahead, global thermal coal markets remain turbulent amid tighter supply ahead of winter restocking requirements in the Northern Hemisphere, as well as volatile global natural gas markets.

In the U.S., overall electricity demand increased approximately 3% year-over-year.

Through the nine months ended September 30, 2024, electricity generation from thermal coal has decreased year-over-year driven by continued low natural gas prices and stronger renewable generation.

Coal’s share of electricity generation has declined to approximately 15% for the nine months ended September 30, 2024, while wind and solar’s combined generation share is at 17% and the share of natural gas generation has remained level at 43%.

coal inventories have declined through September 30, 2024, resulting in stockpiles declining more than 10 million tons below levels seen at the end of 2023.

During the nine months ended September 30, 2024, utility consumption of PRB coal has declined compared to the prior year period.

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 tariff 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 three months ended March 31, 2025 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, metallurgical coal prices softened during the three months ended March 31, 2025.

Seasonal steelmaking weakness in China and mixed steelmaking profit margins in other regions generally weighed on metallurgical coal demand.

In China, ongoing challenges in the property sector contributed to softer domestic steel demand and to strong rates of steel exports.

During the period, Chinese metallurgical coal stocks were reported to be relatively high and Chinese domestic coal prices generally remained below international seaborne prices.

Outside of China, Japan experienced falling steel production and metallurgical coal imports due to sluggish domestic demand and weakening exports, while in contrast India’s increased steelmaking capacity supported higher metallurgical coal imports relative to the same period in 2024.

Meanwhile, metallurgical coal supply was generally ample to meet spot demand during the period, despite notable wet season disruptions to Australian mining and logistics, as well as lower rates of U.S.

and Russian seaborne exports.

PCI relativity to coking coal was fairly stable during the three months ended March 31, 2025.

Looking forward, the end of the typical Australian wet season may support additional coal supply to global markets, although this effect may be softened by a number of ongoing operational disruptions at prominent metallurgical coal mines globally.

Meanwhile, metallurgical coal buyers may take a cautious approach to procurement in the near-term given an increasingly complex international trade environment.

Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of exports from Australia and Canada, evolving bilateral trade policies and the economic performance in China, India and elsewhere.

Within the seaborne thermal coal market, global thermal coal prices softened during the three months ended March 31, 2025, driven by weakening demand conditions and oversupply as seen by higher stockpiles in Asian markets.

In China, overall total generation demand has remained relatively flat to start the year, while domestic coal production has been stronger.

Combining stronger domestic coal production and relatively stable coal import demand against weaker demand has led to an increase in coal stockpiles in China through the three months ended March 31, 2025.

In India, elevated domestic coal production, lower import demand and relatively flat coal generation has led to elevated coal stockpiles.

Looking ahead, global thermal coal markets should begin to see stronger demand as summer restocking requirements in the Northern Hemisphere start;

in addition, volatile global natural gas markets can impact global thermal coal markets.

In the U.S., overall electricity demand increased over 3% year-over-year.

Through the three months ended March 31, 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 17% for the three months ended March 31, 2025, while wind and solar’s combined generation share is at 19% and the share of natural gas generation has declined to approximately 38%.

coal inventories have declined through March 31, 2025, resulting in stockpiles declining more than 15 million tons below levels seen at the end of 2024.

Centurion Mine

Peabody’s redevelopment of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, continues to advance as planned.

Through September 30, 2024, two continuous miners units have been commissioned, the first development coal was produced and the first coal was washed.

The first coal shipment from the Centurion Mine is expected in the fourth quarter of 2024, and the Company is targeting the commencement of longwall production in the first quarter of 2026.

Approximately $250 million of the $489 million of capital expenditures to reach longwall production has been completed as of September 30, 2024.

Wards Well Acquisition.

The Company entered into a definitive agreement dated October 26, 2023, to acquire the southern part of the Wards Well tenements (Wards Well) which are adjacent to the Company’s Centurion Mine in Queensland, Australia.

The acquisition was completed on April 16, 2024 for total consideration of $153.4 million, consisting of cash consideration of $134.4 million, cash transaction costs of $9.4 million and the non-cash settlement of existing receivables with the acquiree of $9.6 million.

The agreement also includes an initial contingent royalty of up to $200 million.

The royalty will only be payable once the Company has recovered its investment and development costs of Wards Well and if the average sales price achieved exceeds certain thresholds.

No royalty is payable if the Company does not commence mining Wards Well.

Shoal Creek Insurance Recovery.

On March 29, 2023, the Company’s Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine.

On June 20, 2023, the Company announced that the Shoal Creek Mine, in coordination with the Mine Safety and Health Administration, had safely completed localized sealing of the affected area of the mine.

In October 2023, the Company filed an insurance claim against applicable insurance policies with combined business interruption and property loss limits of $125 million above a $50 million deductible.

During June 2024, the Company reached a settlement with its insurers and various re-insurers and recognized a $109.5 million insurance recovery which the Company included in its results of operations during the nine months ended September 30, 2024.

Peabody’s development of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, continues to advance as planned.

Centurion continues to make progress toward full-scale longwall production in the first quarter of 2026.

At March 31, 2025, the mine had four continuous miner units in coal production and had shipped its second delivery of development coal.

Peabody expects to begin producing continuous miner coal from Centurion North early in the third quarter of 2025, and targets combined production of 500 thousand tons for 2025.

Planned Acquisition

On November 25, 2024, Peabody entered into definitive agreements (the Purchase Agreements) with Anglo American plc (Anglo), to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia, including Anglo’s interests in the Moranbah North and Grosvenor mines, the Moranbah South development project, the Capcoal complex, the Roper Creek mine and the Dawson complex (comprising the Dawson Main/Central operating mine, the Dawson South operating mine, the Dawson South Exploration project and the Theodore South exploration project, collectively, the Dawson Assets).

The Company has agreed to, following the prospective closing of the Anglo acquisition, sell the Dawson Assets to Pt Bukit Makmur Mandiri Utama or one of its subsidiaries (BUMA).

The Purchase Agreements required Peabody to acquire the balance, or a portion thereof, of the remaining interest in the Moranbah North and Grosvenor mines upon receipt of a tag-along notice from any joint venture participant (the Tag-Along Notice).

On January 15, 2025, Peabody received a Tag-Along Notice pursuant to which Peabody acquired an additional 0.5% interest in the Moranbah North and Grosvenor mines.

Peabody has secured a bridge facility commitment to finance the acquisition.

The Company intends to replace the bridge facility with permanent financing, including debt capacity, additional investment by existing joint venture partners and other financing to supplement as warranted.

On May 5, 2025, Peabody announced that it had notified Anglo and BUMA of a Material Adverse Change (MAC) impacting Peabody’s planned acquisition.

The MAC relates to issues involving the Moranbah North Mine, which remains inactive following what was described as a gas ignition event on March 31, 2025.

If the MAC is not resolved to Peabody’s satisfaction in the limited timeframe specified under the Purchase Agreements, Peabody may elect to terminate the Purchase Agreements.

“Long-term Debt” and Note 11.

“Other Events” for further information.

Results of Operations

Three and Nine Months Ended September 30, 2024 Compared to the Three and Nine Months Ended September 30, 2023

The decrease in income from continuing operations, net of income taxes for the three months ended September 30, 2024 compared to the same period in the prior year ($16.3 million) was driven by higher operating costs and expenses ($42.1 million), partially offset by a lower year-over-year provision for taxes ($20.8 million) and higher revenue ($9.1 million) due to higher seaborne thermal coal pricing.

The decrease in income from continuing operations, net of income taxes for the nine months ended September 30, 2024 compared to the same period in the prior year ($248.0 million) was driven by lower revenue ($598.1 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S.

thermal segments.

This unfavorable variance was partially offset by a lower tax provision ($153.5 million), the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($48.4 million) and a lower year-over-year provision for losses at the NARM and Shoal Creek Mines ($33.3 million).

Adjusted EBITDA for the three and nine months ended September 30, 2024 reflected year-over-year decreases of $45.2 million and $323.8 million, respectively.

Three Months Ended March 31, 2025 Compared to the Three Months Ended March 31, 2024

The decrease in income from continuing operations, net of income taxes for the three months ended March 31, 2025 compared to the same period in the prior year ($7.4 million) was driven by lower revenue primarily due to lower seaborne coal pricing ($46.6 million) and higher depreciation, depletion and amortization expense ($12.3 million).

This unfavorable variance was partially offset by lower operating costs and expenses ($44.0 million) and a lower year-over-year provision for taxes ($15.2 million).

Adjusted EBITDA for the three months ended March 31, 2025 reflected a year-over-year decrease of $16.5 million.

The following table presents tons sold by operating segment:

Three Months Ended September 30, (Decrease) Increase

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

2024 2023 Tons % 2024 2023 Tons %

(Tons in millions) (Tons in millions)

Three Months Ended March 31, Increase (Decrease)

2025 2024 Tons %

(Tons in millions)

Seaborne Thermal 4.4 4.0 0.4 10 %

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Total tons sold from operating segments 28.9 27.3 1.6 6 %

Corporate and Other — — — n.m.

0.1 0.3 (0.2) (67) %

Corporate and Other — 0.1 (0.1) (100) %

Total tons sold 28.9 27.4 1.5 5 %

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The following table presents supplemental financial data by operating segment:

Three Months Ended September 30, Increase

(Decrease) Nine Months Ended September 30, (Decrease)

Three Months Ended March 31, (Decrease)

2025 2024 $ %

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The following table presents revenue by reporting segment:

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

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

2025 2024 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 265.1 $ 283.9 $ (18.8) (7) %

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Seaborne Thermal.

Segment revenue increased during the three months ended September 30, 2024 compared to the same period in the prior year due to favorable mix variances.

Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($214.2 million), partially offset by favorable export volume ($75.4 million).

Segment revenue decreased during the three months ended March 31, 2025 compared to the same period in the prior year due to unfavorable realized prices ($80.6 million), offset by favorable volume and mix variances ($61.8 million).

Seaborne Metallurgical.

Segment revenue decreased during the three and nine months ended September 30, 2024 compared to the same periods in the prior year due to unfavorable realized prices ($28.1 million and $195.1 million, respectively), partially offset by favorable volume and mix variances ($23.6 million and $71.0 million, respectively).

Segment revenue decreased during the three months ended March 31, 2025 compared to the same period in the prior year due to unfavorable realized prices ($75.2 million), offset by favorable volume ($48.3 million).

Powder River Basin.

Segment revenue decreased during the three months ended September 30, 2024 compared to the same period in the prior year due to unfavorable volume.

Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to unfavorable volume ($91.5 million) resulting from decreased demand driven by low natural gas pricing and mild weather and unfavorable realized prices ($6.7 million), partially offset by increased revenue from sales contract cancellation settlements.

Segment revenue decreased during the three months ended September 30, 2024 compared to the same period in the prior year primarily due to unfavorable realized prices ($10.9 million) due in part to mix variances.

Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to unfavorable volume ($71.9 million) resulting from decreased demand driven by low natural gas pricing and mild weather and unfavorable realized prices ($10.0 million), partially offset by increased revenue from sales contract cancellation settlements ($14.7 million).

Segment revenue increased during the three months ended March 31, 2025 compared to the same period in the prior year due to favorable volume ($17.7 million) and favorable realized prices ($3.8 million).

Segment revenue decreased during the three months ended March 31, 2025 compared to the same period in the prior year primarily due to decreased revenue from sales contract cancellation settlements ($13.5 million), unfavorable realized prices ($6.5 million) and unfavorable volume ($2.9 million).

Corporate and Other.

Segment revenue increased during the three months ended September 30, 2024 compared to the same period in the prior year due to favorable results from trading activities ($16.4 million).

Segment revenue decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($159.0 million) as all derivative contracts settled in 2023 and prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15.

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

Segment revenue for the three months ended March 31, 2025 was comparable to the same period in the prior year.

Segment Costs

The following table presents costs by reporting segment:

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

2025 2024 $ %

(Dollars in millions)

Seaborne Thermal $ 180.9 $ 190.1 $ (9.2) (5) %

Seaborne Metallurgical 206.9 198.7 8.2 4 %

Powder River Basin 239.3 237.7 1.6 1 %

Thermal 135.8 145.1 (9.3) (6) %

Corporate and Other 4.4 27.5 (23.1) (84) %

Total Segment Costs (1)

$ 767.3 $ 799.1 $ (31.8) (4) %

(1) This is a financial measure not recognized in accordance with U.S.

Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S.

Seaborne Thermal.

Segment Costs decreased during the three months ended March 31, 2025 compared to the same period in the prior year due to lower costs for labor, repairs and outside services resulting from timing of maintenance and operational improvements ($19.9 million) and favorable commodity pricing ($4.8 million).

These decreases were offset by higher variable expense ($19.1 million) due to higher volume (0.4 million tons).

Seaborne Metallurgical.

Segment Costs increased during the three months ended March 31, 2025 compared to the same period in the prior year due to higher variable operational and sales related costs driven by increased volume (0.4 million tons).

Powder River Basin.

Segment Costs increased during the three months ended March 31, 2025 compared to the same period in the prior year primarily due to higher sales related costs ($5.5 million) driven by favorable volume (0.9 million tons) and higher leasing costs ($2.8 million).

These increases were offset by lower costs for labor, repairs and outside services ($6.2 million) due to mining in areas with less overburden.

The decrease in Segment Costs during the three months ended March 31, 2025 compared to the same period in the prior year was driven by lower volume (0.1 million tons).

Corporate and Other.

Segment Costs decreased during the three months ended March 31, 2025 compared to the same period in the prior year primarily due to favorable foreign currency rate changes.

Adjusted EBITDA

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

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

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

2025 2024 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 84.2 $ 93.8 $ (9.6) (10) %

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Seaborne Thermal.

Segment Adjusted EBITDA increased during the three months ended September 30, 2024 compared to the same period in the prior year due to favorable mix variances, partially offset by lower realized prices net of sales price sensitive costs.

Segment Adjusted EBITDA decreased during the nine months ended September 30, 2024 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($203.3 million), partially offset by favorable volume and mix variances ($39.3 million).

Segment Adjusted EBITDA decreased during the three months ended March 31, 2025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($78.6 million), offset by favorable operational costs ($32.2 million) and favorable volume and mix variances ($28.7 million).

Seaborne Metallurgical.

Segment Adjusted EBITDA decreased during the three months ended September 30, 2024 compared to the same period in the prior year due to unfavorable operational costs ($42.2 million) and lower realized prices net of sales price sensitive costs ($26.4 million).

These decreases were offset by favorable volume ($20.9 million).

Segment Adjusted EBITDA decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($164.5 million) and unfavorable operational costs ($92.7 million).

These decreases were offset by favorable volume ($104.0 million) driven by increased production from the Shoal Creek Mine following the fire in the first quarter of 2023, despite the lock outages during 2024;

and the Shoal Creek insurance recovery ($80.8 million) further discussed in Note 15.

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

Segment Adjusted EBITDA decreased during the three months ended March 31, 2025 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($63.6 million), offset by favorable operational costs ($35.8 million).

Powder River Basin.

Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2024 compared to the same periods in the prior year due to increased lease spend ($4.6 million and $10.0 million, respectively), unfavorable volume ($4.0 million and $49.3 million, respectively) and increased overburden removal costs ($3.6 million and $10.9 million, respectively).

These decreases were offset by favorable commodity pricing ($7.7 million and $15.6 million, respectively) and lower costs for materials, services, repairs and labor ($6.3 million and $28.5 million, respectively).

Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2024 compared to the same periods in the prior year due to unfavorable volume ($12.2 million and $52.4 million, respectively), lower realized prices net of sales price sensitive costs ($10.5 million and $11.1 million, respectively) and higher costs for materials, services, repairs and labor ($3.7 million and $10.2 million, respectively).

These decreases were offset by favorable mine sequencing ($3.5 million and $16.0 million, respectively) and increased sales contract cancellation settlements ($1.6 million and $14.7 million, respectively).

Segment Adjusted EBITDA increased during the three months ended March 31, 2025 compared to the same period in the prior year due to favorable volume ($7.5 million), decreased overburden removal costs ($5.6 million) and lower costs for materials, services, repairs and labor ($4.2 million).

Segment Adjusted EBITDA decreased during the three months ended March 31, 2025 compared to the same period in the prior year primarily due to decreased sales contract cancellation settlements ($13.5 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, (Decrease) Increase to Adjusted EBITDA

2025 2024 $ %

(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 R3 Renewables LLC, costs associated with suspended operations including the Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities.

Corporate and Other Adjusted EBITDA increased during the three months ended September 30, 2024 compared to the same period in the prior year due to the favorable net impact of foreign currency rate changes ($17.1 million) and favorable trading results ($14.4 million), partially offset by unfavorable variances in Middlemount’s results driven by lower sales volume and pricing.

Corporate and Other Adjusted EBITDA decreased during the nine months ended September 30, 2024 compared to the same period in the prior year due to prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15.

“Other Events” to the accompanying unaudited condensed consolidated financial statements;

unfavorable trading results ($11.1 million);

and unfavorable variances in Middlemount’s results driven by lower sales volume and pricing.

These decreases were partially offset by the favorable net impact of foreign currency rate changes ($11.6 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 equity method investment in renewable energy joint ventures, costs associated with suspended operations including the Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities.

Corporate and Other Adjusted EBITDA increased during the three months ended March 31, 2025 compared to the same period in the prior year primarily due to the favorable impact of foreign currency rate changes ($20.2 million) and lower costs at closed and suspended operations ($7.6 million).

These favorable impacts were partially offset by unfavorable variances in Middlemount’s results driven by lower sales pricing and unfavorable production costs.

Income From Continuing Operations, Net of Income Taxes

The following table presents 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

2025 2024 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Adjusted EBITDA (1)

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Restructuring charges (1.7) (0.1) (1.6) (1,600) %

Asset impairment — — — n.m.

— (2.0) 2.0 100 %

Provision for NARM and Shoal Creek losses — (3.3) 3.3 100 % (3.7) (37.0) 33.3 90 %

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

28.7 — 28.7 n.m.

Transaction costs related to business combinations (2.4) — (2.4) n.m.

Provision for NARM loss — (1.8) 1.8 100 %

Changes in amortization of basis difference related to equity affiliates 0.6 0.4 0.2 50 %

Interest expense, net of capitalized interest (11.5) (14.7) 3.2 22 %

Net loss on early debt extinguishment — — — n.m.

— (8.8) 8.8 100 %

Interest income 15.4 19.2 (3.8) (20) %

Unrealized gains on derivative contracts related to forecasted sales

— 159.0 (159.0) (100) %

Unrealized gains (losses) on foreign currency option contracts 4.3 (5.7) 10.0 175 %

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

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

2025 2024 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ (33.4) $ (27.6) $ (5.8) (21) %

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

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

2024 2023 2024 2023

Three Months Ended March 31,

Seaborne Thermal $ 2.00 $ 2.10

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Thermal 1.82 1.55

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, 2024 compared to the same periods in the prior year reflect the impact of volume and mix variances across the segments.

Provision for NARM and Shoal Creek Losses.

The provision recorded during the prior year periods was for losses related to the events at the NARM and Shoal Creek Mines, as discussed in Note 15.

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

Incremental repair costs related to the tornado damage at NARM were recorded during the current year.

Shoal Creek Insurance Recovery - Property Damage.

During June 2024, the Company reached a settlement with its insurers and various re-insurers related to the Shoal Creek losses and recorded a $109.5 million insurance recovery, as discussed in Note 15.

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

Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery, which consisted of $28.7 million recognized during the year ended December 31, 2023.

The remaining $80.8 million, applicable to incremental costs and business interruption recoveries, is included in Adjusted EBITDA for the nine months ended September 30, 2024.

Depreciation, depletion and amortization expense increased during the three months ended March 31, 2025 compared to the same period in the prior year primarily due to increased depreciation resulting from asset additions and shortened mine lives.

The changes in the weighted-average depletion rate per ton for both the Powder River Basin and the Other U.S.

Thermal segments during the three months ended March 31, 2025 compared to the same period in the prior year reflect the impact of volume and mix variances across the segments.

Transaction Costs Related to Business Combinations.

The charges recorded during the current year period relate to the planned acquisition of multiple metallurgical coal mines from Anglo which was announced during the fourth quarter of 2024.

Refer to Note 11.

“Other Events” in the accompanying unaudited condensed consolidated financial statements for further information regarding the planned Anglo acquisition.

Interest Expense, Net of Capitalized Interest.

The decrease in expense during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was driven by lower interest and fees for financial assurance instruments and the capitalization of interest related to the redevelopment of the Centurion Mine.

Net Loss on Early Debt Extinguishment.

The loss recognized during the prior year was primarily related to the Company’s terminated letter of credit facility as further discussed in Note 12.

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

Unrealized Gains on Derivative Contracts Related to Forecasted Sales.

The prior year unrealized gains primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales.

As further described in Note 6.

"Derivatives and Fair Value Measurements" to the Annual Report on Form 10-K for the year ended December 31, 2023, all derivative contracts related to forecasted coal sales settled in 2023.

The decrease in expense during the three months ended March 31, 2025 compared to the same period in the prior year was driven by lower interest and fees for financial assurance instruments and the capitalization of interest related to the development of the Centurion Mine.

Interest Income.

The decrease in income during the three months ended March 31, 2025 compared to the same period in the prior year was driven by lower average cash balances during the current period.

Unrealized Gains (Losses) on Foreign Currency Option Contracts.

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

For additional information, refer to Note 6.

“Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.

Income Tax Provision.

The decrease in the income tax provision during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was primarily due to lower pretax income.

The decrease in the income tax provision during the three months ended March 31, 2025 compared to the same period in the prior year was primarily due to lower expected pretax income.

Refer to Note 8.

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The following table presents net income attributable to common stockholders:

Three Months Ended September 30, Decrease

to Income Nine Months Ended September 30, Decrease

Three Months Ended March 31, (Decrease) Increase

2025 2024 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Income from continuing operations, net of income taxes $ 38.3 $ 45.7 $ (7.4) (16) %

(Loss) income from discontinued operations, net of income taxes (1.0) 2.5 (3.5) (140) % (3.3) (0.1) (3.2) (3,200) %

Loss from discontinued operations, net of income taxes (0.3) (0.7) 0.4 57 %

Net income 38.0 45.0 (7.0) (16) %

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Net income attributable to common stockholders $ 34.4 $ 39.6 $ (5.2) (13) %

(Loss) Income from Discontinued Operations, Net of Income Taxes.

The decrease in the results from discontinued operations, net of income taxes during the three and nine months ended September 30, 2024 compared to the same periods in the prior year was primarily due to the prior year gain recognized on the settlement of the Patriot federal black lung liabilities.

Net Income Attributable to Noncontrolling Interests.

The decrease in the results attributable to noncontrolling interests during the three and nine months ended September 30, 2024 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.

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

Three Months Ended March 31, (Decrease) Increase

2025 2024 $ %

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Income from continuing operations $ 0.27 $ 0.30 $ (0.03) (10) %

(Loss) income from discontinued operations — 0.02 (0.02) (100) % (0.03) — (0.03) n.m.

Loss from discontinued operations — (0.01) 0.01 100 %

Net income attributable to common stockholders $ 0.27 $ 0.29 $ (0.02) (7) %

Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period.

Diluted EPS reflects weighted average diluted common shares outstanding of 141.6 million and 149.9 million for the three months ended September 30, 2024 and 2023, respectively, and 143.1 million and 156.7 million for the nine months ended September 30, 2024 and 2023, respectively.

Diluted EPS reflects weighted average diluted common shares outstanding of 138.7 million and 144.9 million for the three months ended March 31, 2025 and 2024, respectively.

Reconciliation of Non-GAAP Financial Measures

Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization.

Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below.

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

2024 2023 2024 2023

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

Three Months Ended March 31,

(Dollars in millions)

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Depreciation, depletion and amortization

84.7 82.3 247.4 239.2

Asset retirement obligation expenses

12.9 15.4 38.7 46.3

Restructuring charges

1.9 0.9 2.1 3.0

Asset impairment

Provision for NARM and Shoal Creek losses — 3.3 3.7 37.0

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

Transaction costs related to business combinations 2.4 —

Provision for NARM loss — 1.8

Changes in amortization of basis difference related to equity affiliates (0.6) (0.4)

Interest expense, net of capitalized interest 11.5 14.7

Net loss on early debt extinguishment — — — 8.8

Interest income

(15.4) (19.2)

Unrealized gains on derivative contracts related to forecasted sales — — — (159.0)

Unrealized (gains) losses on foreign currency option contracts (4.3) 5.7

Take-or-pay contract-based intangible recognition

(0.8) (0.7) (2.3) (1.9)

Income tax provision 4.9 20.1

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$ 144.0 $ 160.5

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

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

2024 2023 2024 2023

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

Three Months Ended March 31,

(Dollars in millions)

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Take-or-pay contract-based intangible recognition

0.8 0.7 2.3 1.9

Net periodic benefit credit, excluding service cost (7.4) (10.1)

Total Reporting Segment Costs $ 840.2 $ 793.9 $ 2,436.2 $ 2,484.9

The following table presents Total Reporting Segment Costs by reporting segment:

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

2024 2023 2024 2023

Total Segment Costs $ 767.3 $ 799.1

The following table presents Total Segment Costs by reporting segment:

Three Months Ended March 31,

(Dollars in millions)

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Corporate and Other 4.4 27.5

Total Reporting Segment Costs $ 840.2 $ 793.9 $ 2,436.2 $ 2,484.9

Total Segment Costs $ 767.3 $ 799.1

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

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

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

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 Reporting 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

Three Months Ended September 30, 2023

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

(Amounts in millions, except per ton data)

Tons sold 4.2 1.5 22.7 4.2

Revenue $ 297.4 $ 247.0 $ 313.0 $ 228.2

Total Reporting Segment Costs 181.9 168.4 258.9 179.1

Adjusted EBITDA $ 115.5 $ 78.6 $ 54.1 $ 49.1

Revenue per Ton $ 71.38 $ 162.02 $ 13.79 $ 53.89

Costs per Ton 43.68 110.38 11.41 42.28

Adjusted EBITDA Margin per Ton $ 27.70 $ 51.64 $ 2.38 $ 11.61

Nine Months Ended September 30, 2024

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

Three Months Ended March 31, 2025

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

2 unchanged sentences

Revenue $ 265.1 $ 220.1 $ 275.6 $ 168.7

Total Reporting Segment Costs 586.4 644.9 695.4 500.0

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

Shoal Creek insurance recovery - business interruption — 80.8 — —

Total Segment Costs 180.9 206.9 239.3 135.8

Adjusted EBITDA $ 84.2 $ 13.2 $ 36.3 $ 32.9

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Adjusted EBITDA Margin per Ton $ 19.27 $ 7.49 $ 1.84 $ 10.61

Nine Months Ended September 30, 2023

Three Months Ended March 31, 2024

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

2 unchanged sentences

Revenue $ 283.9 $ 247.0 $ 254.1 $ 191.6

Total Reporting Segment Costs 566.4 636.0 761.9 512.3

Total Segment Costs 190.1 198.7 237.7 145.1

Adjusted EBITDA $ 93.8 $ 48.3 $ 16.4 $ 46.5

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Adjusted EBITDA Margin per Ton $ 23.53 $ 33.77 $ 0.88 $ 14.50

Available Free Cash Flow is defined as operating cash flow less investing cash flow and distributions to noncontrolling interests;

plus/minus changes to restricted cash and collateral and other anticipated expenditures.

See the table below for a reconciliation of Available Free Cash Flow to its most comparable measure under U.S.

Nine Months Ended September 30, 2024

(Dollars in millions)

Net cash provided by operating activities $ 486.7

- Net cash used in investing activities (389.6)

- Distributions to noncontrolling interests (34.8)

+/- Changes to restricted cash and collateral (24.7)

- Anticipated expenditures or other requirements —

Available Free Cash Flow $ 37.6

Regulatory Update

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Regulatory Matters - U.S.

National Ambient Air Quality Standards (NAAQS) .

The Clean Air Act (CAA) requires the U.S.

Environmental Protection Agency (EPA) to review national ambient air quality standards every five years to determine whether revisions to current standards are appropriate.

On March 6, 2024, the EPA revised the level of the primary standard for fine particulate matter (PM 2.5), lowering the annual standard from 12.0 ug /m 3 to 9.0 ug /m 3 .

States are now required to take several actions to implement the standards which could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies or operate in a different manner.

Such actions could potentially increase the cost of utilizing fossil fuels for electric generation and industrial uses.

The EPA is also in the process of reviewing the current ozone NAAQS.

The level of the ozone NAAQS can also affect requirements to install new or improved emission control technologies at fossil fuel-fired EGUs and non-EGU industrial sources.

Final New Source Performance Standards (NSPS) for Fossil Fuel-Fired EGUs .

The EPA promulgated a final rule to limit carbon dioxide (CO 2 ) from new, modified and reconstructed fossil fuel-fired EGUs under Section 111(b) of the CAA on August 3, 2015, and published it in the Federal Register on October 23, 2015.

The rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for CO 2 (known as the Best System of Emission Reduction (BSER)) which is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS).

Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance.

Reconstructed EGUs must implement the most efficient generating technology based on the size of the unit.

Numerous legal challenges to the final rule were filed in the U.S.

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

Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups.

The cases were consolidated under the case filed by North Dakota (D.C.

Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources:

Electric Generating Units;

Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports.

On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards.

In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices.

The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology.

On May 23, 2023, however, the EPA published a notice of proposed rulemaking addressing NSPS from new, modified and reconstructed fossil-fuel steam EGUs.

In contrast to the 2018 proposed rule, the 2023 proposed rule did not propose to amend the 2015 NSPS for coal-fired EGUs.

Status reports filed with the D.C.

Circuit in North Dakota v.

EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule and the 2023 proposed rule.

As indicated in the following section, on May 9, 2024, the EPA published the final rule in the Federal Register based on the 2023 proposed rule.

This final rule did not amend the 2015 NSPS for coal-fired EGUs, but indicated that the EPA will continue to consider whether or not to make revisions to that rule in the future.

EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs .

On May 9, 2024, the EPA published a final rule for new, modified and reconstructed fossil fuel-fired EGUs in the Federal Register.

The final rule consists of four elements:

(1) revised NSPS for controlling CO 2 emissions from new and reconstructed stationary combustion turbines;

(2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification;

(3) emission guidelines for existing fossil fuel-fired steam EGUs;

and (4) repeal of the Affordable Clean Energy rule promulgated in 2019.

With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions.

Pursuant to the final rule, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO 2 emission rate based on CCS with 90% capture by January 1, 2032.

Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO 2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030.

(This translates into a 16% reduction in CO 2 emissions determined from a unit-specific baseline).

Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements.

All requirements related to existing affected units in the final rule – whether fired by coal or natural gas – will be imposed through state plans that are permitted to take into account the remaining useful life of a generating unit when determining appropriate controls.

Under the final rule, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations.

States are also permitted to impose more stringent standards.

In addition, the final rule includes several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order to maintain adequate electric generation resources and grid reliability.

Finally, as part of the final rule, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO 2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU.

In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032.

Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015.

The final rule is subject to numerous legal challenges that have been consolidated in the D.C.

Petitioners filed an emergency application for a stay of the rule with the U.S.

Supreme Court which was denied in an order issued by the U.S.

Supreme Court on October 16, 2024.

In a statement respecting this denial, Justices Kavanaugh and Gorsuch expressed the view that the petitioners “have shown a strong likelihood of success on the merits as to at least some of their challenges” but because efforts to comply would not need to be initiated until June 2025, they would be “unlikely to suffer irreparable harm before the Court of Appeals for the D.C.

Circuit decides the merits” of the pending litigation.

Justice Thomas would have granted the application for a stay;

the views of other Justices regarding the merits of the litigation are unknown.

If the rule is ultimately affirmed and implemented by the EPA and states, it could have a substantial impact on the use of coal and natural gas for the generation of electricity.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry.

In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs.

In 2020, the EPA finalized revisions to certain requirements in the 2015 rule.

On May 9, 2024, the EPA published a final rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments.

The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants.

In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim.

The final rule is subject to numerous legal challenges that have been consolidated in the Eighth Circuit.

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

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

Federal CCR Permit Program and Revisions to Closure Requirements.

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

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

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

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

Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around October 2024.

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

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

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

Circuit’s 2018 decision.

Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units.

Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule .

The CSAPR and related updates require numerous U.S.

states and the District of Columbia to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine PM pollution in other states.

On March 15, 2023, the EPA issued a final rule to address regional ozone transport by imposing new federal ozone season emission budgets for nitrogen oxide (NO x ) in 23 states, including California, Nevada, Oklahoma and Texas, as well as some Indian reservations.

The rule includes state emission budgets for NO x affecting fossil fuel-fired power plants and a “backstop daily emissions rate” for large coal-fired power plants if they exceed specified limits.

The rule also sets first-time limits on certain industrial sources that will apply starting with the 2026 ozone season in 20 states.

The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million.

These emission limitations would apply in addition to requirements contained in state implementation plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations.

When implemented, this rule could influence the closure of some coal generating units that have not installed selective catalytic reduction technologies.

Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S.

Courts of Appeal, resulting in different court opinions and in requirements being implemented in some states, but stayed in others.

On June 27, 2024, the U.S.

Supreme Court issued a stay of the rule in 11 states pending the disposition of a petition for review of the rule in the D.C.

Circuit and any subsequent timely petition for certiorari filed with and granted by the U.S.

Supreme Court.

The EPA subsequently issued a policy memorandum on August 5, 2024, that provides an administrative stay of the rule;

Circuit thereafter issued a partial remand of the rule to allow the EPA to respond to comments regarding the severability of the rule’s provisions.

Mercury and Air Toxic Standards (MATS) .

In 2012, the EPA published the final MATS rule, which revised the NSPS for NO x , sulfur dioxide and PM for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants.

MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs.

On March 6, 2023, the EPA issued a final rule which reaffirmed its determination to regulate coal- and oil-fired EGUs under CAA section 112, including the regulation of HAPs from EGUs after considering cost.

On April 24, 2023, the EPA proposed to amend the 2012 MATS rule and require an additional two-thirds reduction in the filterable PM emission of non-mercury HAP metals from existing coal-fired power plants and to reduce the mercury standard for lignite plants by 70%.

On April 25, 2024, the EPA issued its final MATS rule which significantly tightens the filterable particulate matter (fPM) emissions limit for existing coal-fired EGU’s, lowering the standard from 0.030 lb/MMBtu to 0.010 lb/MMBtu.

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.

On March 29, 2024, the EPA published a proposed consent decree under which deadlines 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 judgement in the U.S.

District Court for the District of Columbia which was granted.

Federal Coal Leasing Moratorium .

The Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking.

Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium.

Environmental groups took the issue to court (District of Montana) and in April 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review.

On May 22, 2020, the court held that the Department of Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations.

Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI.

On August 12, 2022, the court invalidated the Environmental Assessment and FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis.

On appeal, the U.S.

Court of Appeals for the Ninth Circuit (Ninth Circuit) reversed the district court on February 21, 2024, explaining that the lawsuit was mooted by the Department of Interior’s April 2021 order revoking Order 3349.

The Ninth Circuit directed the district court to dismiss the case as moot.

Endangered Species Act (ESA) .

The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened.

Changes in listings or requirements under these regulations could have a material adverse effect on Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans.

During the Trump Administration, the Departments of Interior and Commerce finalized five rules aiming to streamline and update the ESA.

But in June 2021, the agencies announced their plan to revise, rescind or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives.

The agencies issued proposed rules on June 22, 2023, and they published three final revised rules on April 5, 2024.

Black Lung Benefits Act Self-Insurance Requirements .

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

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

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

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

The Trump Administration recently 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 emissions from new and existing fossil fuel-fired electric generating units (EGUs), commonly known as “Clean Power Plan 2.0,” which could also impact the final 2015 New Source Performance Standards for fossil fuel-fired EGUs;

• National Ambient Air Quality Standards for fine particulate matter;

• Cross State Air Pollution Rule;

• Mercury and Air Toxic Standards;

• 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.

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.

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.

SEC Climate-Related Disclosures .

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

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

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 greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider;

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

The Company is assessing the potential impact of the final rules.

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

Regulatory Matters - Australia

Coal Mine Subsidence Compensation Amendment Act 2024 (NSW).

On August 15, 2024, the Coal Mine Subsidence Compensation Amendment Act 2024 No.

48 (NSW) was passed into law.

The amendment act amends the Coal Mine Subsidence Compensation Act 2017 No.

37 (NSW), implementing all nine recommendations of the 2023 statutory review.

The amendments are designed to strengthen the compensation framework to ensure people affected by coal mine subsidence in New South Wales (NSW) can access compensation and support.

The key amendments include extension of the chief executive’s powers to evacuate people from land they reasonably believe has been damaged as a result of subsidence and that may cause danger to a member of the public;

make payment from the fund for temporary accommodation for people who have been evacuated;

requirement of the Subsidence Advisory to assess claims as soon as reasonably practicable after receiving a compensation claim;

limitation on claims if pre-mining inspection was required and refused by the claimant and addition of powers to direct pre-mining inspections;

requiring information and documents from coalmine operators;

and clarifying the roles of Subsidence Advisory and mine operators in the assessment and determination of claims.

Work Health and Safety Act 2011 (NSW) .

On June 4, 2024, the Work Health and Safety Amendment (Industrial Manslaughter) Bill 2024 (Bill) was introduced to the NSW Parliament.

The Bill subsequently passed the NSW Parliament on June 20, 2024.

The Bill amends the Work Health and Safety Act 2011 (NSW) (NSW WHS Act) to include the offense of industrial manslaughter.

The offense will apply to a person conducting a business or undertaking (PCBU) or an officer of a PCBU who engages in conduct that constitutes a failure to comply with the person’s health and safety duty and causes the death of a worker or another individual to whom the duty is owed;

and the person engages in conduct with gross negligence.

The maximum penalty is $20 million Australian dollars for a body corporate or 25 years imprisonment for an individual.

The Bill also provides for an alternative finding of guilt.

That is, where a person is charged with industrial manslaughter, and on trial the court or jury is not satisfied that the person is guilty but is satisfied that the person is guilty of an offense against section 31 (Gross negligence or reckless conduct— Category 1) of the NSW WHS Act, the person may be found guilty and liable to punishment for that offense.

Environmental Protection (Powers and Penalties) and Other Legislation Amendment Act 2024 (QLD) (Powers and Penalties Act).

On June 18, 2024, the Environmental Protection (Powers and Penalties) and Other Legislation Amendment Act 2024 (QLD) (Powers and Penalties Act) received assent.

The Powers and Penalties Act amends the powers and penalties provisions of the Environmental Protection Act 1994 (EP Act), facilitates a more proactive approach to environmental risk management and ensures timely and effective regulatory responses to environmental harm.

The key changes include the general environmental duty becoming an offense provision, an increase in maximum penalties and the consolidation of the various enforcement instruments presently available under the EP Act into a single Environmental Enforcement Order.

National Greenhouse and Energy Reporting Act 2007 (NGER Act).

The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system.

The Clean Energy Regulator administers the NGER Act.

The federal Department of Environment and Energy is responsible for NGER Act-related policy developments and review.

In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015.

The reforms commenced on July 1, 2023 and introduced site specific baseline emissions for heavy emitting facilities as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030.

Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions.

Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO 2 in 2023-24, increasing with the Consumer Price Index plus 2% each year.

In June 2024 amendments to the NGER Act came into effect requiring open-cut mines covered by the Safeguard Mechanism that currently report fugitive methane emissions using a basic method with minimal data inputs (Method 1) to transition over a two-year period to a more complex method requiring site-level sampling and analysis (Methods 2 or 3).

This change in reporting methods is expected to increase the Safeguard Mechanism liability position of open-cut mining operations in Queensland.

The impacts of this change are currently being assessed.

New South Wales Environmental .

Under the NSW Environmental Planning and Assessment Act 1979 (EPA Act), environmental planning instruments must be considered when approving a mining project development application.

Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation.

Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales.

The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act.

As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified.

If a new development approval is required then this could take additional time to achieve.

On April 3, 2024, the Environment Protection Legislation Amendment (Stronger Regulation and Penalties) Bill 2024 was assented to by the Parliament of New South Wales.

The bill increases the NSW Environment Protection Agency’s (NSW EPA) powers across a range of environmental legislation including increasing the NSW EPA’s maximum penalties for serious environmental offenses;

increasing the NSW EPA’s on-the-spot maximum fines;

providing the NSW EPA the power to issue what will be known as ‘Preliminary Investigation Notices’ which permit the NSW EPA to force a person to help the NSW EPA compile a criminal case against the person or against another person;

extending the monetary benefits order so that it can apply to any ‘related entity’ as defined in the Corporations Act 2001;

providing the NSW EPA the power to issue what will be known as ‘Recall Notices’ which order responsible entities to recall contaminated substances suspected of causing harm to the community and environment;

and providing the NSW EPA the power to issue what will be known as ‘name and shame’ public warnings to call out poor and repeat environmental performers for the protection of communities.

The reform also creates a new power in Australia for the NSW Land and Environment Court that empowers the court to ban offenders, upon the NSW EPA’s application, with a poor compliance history from seeking and obtaining environmental protection licenses.

On August 25, 2017, the Biodiversity Conservation Act 2016 (BC Act) commenced in NSW and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project.

The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means:

securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation.

The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts.

The proposed development can only proceed once the biodiversity offset obligations have been satisfied.

On July 18, 2024, following an independent review of the BC Act, the NSW government announced it would amend the BC Act to reform the biodiversity offsets scheme.

On August 13, 2024, the Biodiversity Conservation Amendment (Biodiversity Offsets Scheme) Bill 2024 was introduced into NSW Parliament and, if passed into law, will require mining proponents to demonstrate they have genuinely avoided, minimized and offset impacts to biodiversity.

The bill reinforces the current government’s intent that biodiversity offsets are a last resort.

Additionally, the bill proposes to replace the current ‘no net loss’ standard for biodiversity with the requirement for proponents to achieve ‘net positive’ biodiversity outcomes.

If enacted, these and other proposed changes have the potential to affect approval processes for future NSW mining projects.

NSW Parliament is expected to pass the bill by late November 2024.

New South Wales Coal Directions .

The State of New South Wales enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers).

On December 22, 2022, the State Premier declared such an emergency, intended to control coal and electricity pricing.

Subsequently, directions were issued to Peabody Energy Australia Pty Ltd and other coal producers with operations in NSW, which were amended at various dates.

The most recent directions required Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and imposed additional reporting obligations to demonstrate compliance.

The Australian Energy Regulator has confirmed that the directions have ended, and the last report was submitted on July 12, 2024.

Aboriginal and Torres Strait Islander Heritage Protection Act 1984.

On August 16, 2024, Australia’s Minister for the Environment and Water made a declaration under Section 10 of the Aboriginal and Torres Strait Islander Heritage Protection Act 1984 over a riverine area in NSW that is a proposed tailings dam site for a gold mining project.

The declaration prohibits any mining or related development activity in the area despite the project having previously obtained all necessary environmental and planning approvals under state and federal government laws.

The project proponent has indicated that the decision renders the mine project as no longer financially viable given the time required to develop and receive approvals for an alternative tailings dam site.

The decision has the potential to affect future mining approvals in Australia.

The proponent has until early November to apply for a judicial review of the minister’s decision.

Risks Related to Global Climate Change

There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2023.

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.

In December 2022, the federal government passed The Fair Work Legislation Amendment (Secure Jobs, Better Pay) Act 2022, which amends the Fair Work Act.

The legislation introduced several changes to workplace laws in Australia including changes to enterprise agreement making and termination;

when industrial action can be taken;

and access to multi-employer bargaining or single interest employer authorizations.

Following this amendment, the Wambo Underground Mine and four other mines in New South Wales (NSW) were served with an application for a single interest employer authorization which was granted by the Fair Work Commission against three employers including Peabody.

The three employers appealed the authorization in a hearing held in March 2025.

A decision on the appeal is expected in the second quarter of 2025.

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 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 Fair Work 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 Fair Work Commission is satisfied that it is not fair and reasonable to do so.

These orders do not apply to contactor 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 Australia’s Fair Work Commission.

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

Additionally an application for a regulated labor hire arrangement order has been made at the Metropolitan Mine in relation to a labor hire employer which is currently progressing through the determination process.

The Australian Parliament has passed various other pieces of legislation changing the Australian industrial and employment landscape.

This includes the Fair Work Legislation Amendment (Closing Loopholes No.

2) Bill 2023 which was passed on February 12, 2024 and made many changes, including to the definition of who is a casual employee and the definition of who is a contractor versus employee.

The change to the casual employment definition was introduced to move away from a decision of the High Court of Australia in which an employee in the Australian coal mining industry who was rostered to work full-time hours on a 12-month roster was found to be employed on a casual basis pursuant to the terms of his contract of employment and therefore not entitled to receive the benefits that permanent employees receive (e.g.

paid annual leave).

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 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 on its operations.

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

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 federal 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.

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

The first hearing is scheduled for the second quarter of 2025.

Metropolitan Mine Stormwater Discharge.

Significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site resulted in stormwater being discharged from the mine site on several occasions in 2021 and 2022.

On September 6, 2023, the New South Wales Environment Protection Authority commenced a prosecution for five breaches of the Protection of the Environment Operations Act 1997 (the Act) relating to the stormwater discharges.

On March 15, 2024, the Metropolitan Collieries Pty Ltd (MCPL) pled guilty to two of the charges related to water pollution and two charges related to a failure to adequately maintain plant and equipment were consolidated into one charge to which the MCPL also pled guilty.

The remaining charge was discontinued.

A sentencing hearing was held in November 2024 and the judgment was handed down in March 2025.

MCPL was convicted of three separate offenses under the Act and fined a total monetary penalty of $0.1 million.

MCPL was also ordered to pay costs in the amount of $0.2 million.

There are also various publication orders that MCPL must comply with under the judgement.

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.

Refer to Part I, Item 1.

“Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 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 ends in 2020 (the Paris Agreement).

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

On January 20, 2021, the U.S.

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

On January 20, 2025, 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, collateral and margining requirements, dividends, share repurchases and selling and administrative expenses.

The Company has also used cash for early debt retirements.

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.

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, 2024, the Company’s cash and cash equivalents balances totaled $772.9 million, including approximately $420 million held by U.S.

As of March 31, 2025, the Company’s cash and cash equivalents balances totaled $696.5 million, including approximately $389 million held by U.S.

subsidiaries, approximately $296 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, 2024, no profits from foreign subsidiaries were repatriated.

During the three months ended March 31, 2025, no profits from foreign subsidiaries were repatriated.

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

The Company’s available liquidity increased to $1,089.9 million as of September 30, 2024 from $1,059.7 million as of December 31, 2023.

The Company’s available liquidity increased to $1,087.0 million as of March 31, 2025 from $1,072.5 million as of December 31, 2024.

Available liquidity was comprised of the following:

September 30, 2024 December 31, 2023

March 31, 2025 December 31, 2024

(Dollars in millions)

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Capital Returns to Shareholders

The Company repurchased approximately 7.7 million shares of its common stock for $180.5 million, including commission fees, and paid dividends of $28.5 million during the nine months ended September 30, 2024.

The Company paid dividends of $9.1 million during the three months ended March 31, 2025.

Surety Agreement Amendment and Collateral Requirements

In April 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020.

Under the April 2023 amendment, the Company and its surety providers agreed to a maximum aggregate collateral amount of $721.8 million based upon bonding levels at the effective date of the amendment.

This maximum collateral amount will vary prospectively as bonding levels increase or decrease.

The amendment extended the agreement through December 31, 2026.

Under the April 2023 amendment, the Company and its surety providers agreed to a maximum aggregate collateral amount based upon bonding levels which will vary prospectively as bonding levels increase or decrease.

The amendment also extended the agreement through December 31, 2026.

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

The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers, which was $507.3 million at September 30, 2024.

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

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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, 2024.

To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 31, 2023.

The remainder was comprised of $140.5 million of existing cash-collateralized letters of credit and $15.0 million already held on behalf of a surety provider.

The amendment became effective on April 14, 2023, when the Company terminated a then-existing credit agreement.

The Company is in compliance with such requirements at March 31, 2025.

At March 31, 2025, the Company’s maximum aggregate collateral amount was $525.0 million, which was comprised of $398.0 million in trust accounts and letters of credit of $127.0 million held for the benefit of certain surety providers.

Credit Support Facilities

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The agreement has an initial expiration date of December 31, 2025.

At September 30, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 million.

At March 31, 2025, letters of credit of $115.6 million were outstanding under the agreement, which were collateralized by cash of $119.1 million.

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, 2024, the bank guarantee facilities were backed by cash of $187.9 million.

At March 31, 2025, the bank guarantee facilities were backed by cash of $170.2 million.

Revolving Credit Facility

The Company established a new revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto.

The Company established a revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto.

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

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

As of September 30, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $98.6 million outstanding as of September 30, 2024.

On November 25, 2024, the Company amended the 2024 Credit Agreement to, among other things, permit (i) Peabody’s planned acquisition of multiple coal mines from Anglo as further discussed in Note 11.

“Other Events,” (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 of March 31, 2025, the 2024 Credit Agreement had only been utilized for letters of credit, including $49.3 million outstanding as of March 31, 2025.

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 13.

“Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $221.4 million at September 30, 2024.

“Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $270.7 million at March 31, 2025.

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 increased its targeted capital expenditures for 2024 from approximately $375 million to $425 million.

The increase is primarily driven by the acceleration of the planned capital spend at the Centurion Mine as development rates have advanced ahead of projected timelines and timing of spend at the Wambo Open-Cut Mine.

The Company’s total indebtedness as of September 30, 2024 and December 31, 2023 is presented in the table below.

Debt Instrument (defined below, as applicable) September 30, 2024 December 31, 2023

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

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

(Dollars in millions)

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

BUMA Loan Note 9.5 9.3

Finance lease obligations 23.5 25.1

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Long-term debt $ 331.2 $ 332.3

The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at September 30, 2024, of approximately $8 million in 2024, $20 million in 2025, $17 million in 2026, $13 million in 2027 and $326 million in 2028.

Cash paid for interest, net of capitalized interest related to the Company’s indebtedness and financial assurance instruments amounted to $32.6 million and $56.7 million during the nine months ended September 30, 2024 and 2023, respectively.

The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at March 31, 2025, of approximately $19 million in 2025, $18 million in 2026, $13 million in 2027, $326 million in 2028, less than $1 million in 2029 and $10 million thereafter.

Cash paid for interest, net of capitalized interest related to the Company’s indebtedness and financial assurance instruments amounted to $9.9 million and $11.5 million during the three months ended March 31, 2025 and 2024, respectively.

2028 Convertible Notes

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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 first three quarters of 2024, the Company’s reported common stock prices did not prompt the conversion feature of the 2028 Convertible Notes.

As a result, the 2028 Convertible Notes were not convertible at the option of the holders during the second or third quarters of 2024, and will not be similarly convertible during the fourth quarter of 2024.

During the first 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 second quarter of 2025.

Bridge Loan Facility

Concurrently with its entry into definitive agreements to acquire the Anglo assets, the Company entered into a bridge loan facility commitment letter (the Bridge Commitment Letter and, the senior secured 364-day bridge facility provided for therein, the Bridge Facility), pursuant to which the lenders, agreed to provide the Bridge Facility to the Company in the amount of up to $2.075 billion in order to finance the planned acquisition in part.

The Company expects to replace the Bridge Facility with permanent financing prior to the closing date, but there can be no assurance such financing will occur and any such expectation is subject to market conditions.

To the extent borrowings are made under the Bridge Facility, any loans would bear interest at a SOFR plus an applicable margin of 8.00% or a base rate plus an applicable margin of 7.00%, at the Company’s option.

Such applicable margin would increase by an additional 0.75% on the date that is 90 days following the closing date of the planned acquisition.

Any borrowings under the Bridge Facility would mature 364 days from the initial funding date, which would be on or around the closing date of the planned acquisition.

The availability of borrowings under the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of this type.

Any definitive financing documentation for the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of this type.

Upon execution of any definitive financing documentation for the Bridge Facility, the Bridge Facility will be guaranteed by substantially all U.S.

subsidiaries of the Company and secured by substantially all assets of the Company, its U.S.

subsidiaries and, subject to certain conditions, certain of the Company’s Australian subsidiaries.

Accounts Receivable Securitization Program

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“Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017.

The securitization program was amended in February 2023 to increase the available funding capacity from $175.0 million to $225.0 million and adjust the relevant interest rate for borrowings to a SOFR plus an applicable margin.

Funding capacity is limited to the availability of eligible receivables and is accounted for as a secured borrowing.

The securitization program provides up to $225.0 million of funding capacity which is accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of collateral and the trade receivables underlying program.

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, 2024, the Company had no outstanding borrowings and $60.4 million of letters of credit outstanding under the program.

The Company was not required to post cash collateral under the securitization program at September 30, 2024.

At March 31, 2025, the Company had no outstanding borrowings and $60.4 million of letters of credit outstanding under the program.

The Company was not required to post cash collateral under the securitization program at March 31, 2025.

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, 2024.

The following table summarizes the Company’s cash flows for the nine months ended September 30, 2024 and 2023, as reported in the accompanying unaudited condensed consolidated financial statements.

Available Free Cash Flow is a financial measure not recognized in accordance with U.S.

Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S.

Nine Months Ended September 30,

The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2025.

The following table summarizes the Company’s cash flows for the three months ended March 31, 2025 and 2024, as reported in the accompanying unaudited condensed consolidated financial statements.

Three Months Ended March 31,

(Dollars in millions)

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Cash, cash equivalents and restricted cash at end of period $ 1,383.8 $ 1,566.3

Available Free Cash Flow $ 37.6

Operating Activities.

The decrease in net cash provided by operating activities for the nine months ended September 30, 2024 compared to the same period in the prior year was driven by a year-over-year decrease in operating cash flow from working capital ($260.9 million), primarily attributable to income tax payments and accruals ($218.8 million) and Shoal Creek inventories build due to the lock outages during 2024 ($61.1 million);

the prior year receipt of cash related to variation margin requirements associated with derivative financial instruments ($198.0 million);

and lower cash generated from mining operations.

These unfavorable variances were partially offset by decreases in cash used for collateral requirements ($289.2 million) and discontinued operations ($74.9 million) primarily related to the prior year use of cash to settle disputed black lung claims.

Net cash provided by operating activities for the three months ended March 31, 2025 was comparable to the same period in the prior year and primarily driven by a year-over-year increase in operating cash flow from working capital ($169.3 million), offset by a decrease in cash from collateral arrangements resulting from prior year collateral releases ($151.7 million) and lower cash generated from mining operations.

Investing Activities.

The increase in net cash used in investing activities for the nine months ended September 30, 2024 compared to the same period in the prior year was driven by the acquisition of Wards Well ($143.8 million) and higher capital expenditures ($75.3 million).

The increase in net cash used in investing activities for the three months ended March 31, 2025 compared to the same period in the prior year was driven higher capital expenditures and payments of capital accruals ($40.8 million).

These variances were partially offset by higher net distribution from joint ventures ($22.1 million).

Financing Activities.

The decrease in net cash used by financing activities for the nine months ended September 30, 2024 compared to the same period in the prior year was primarily driven by decreases in common stock repurchases ($80.9 million) and distributions to noncontrolling interest ($24.1 million), partially offset by an increase in payment of debt issuance and other deferred financing costs ($10.8 million).

The decrease in net cash used by financing activities for the three months ended March 31, 2025 compared to the same period in the prior year was primarily driven by decreases in common stock repurchases ($83.1 million) and payment of debt issuance and other deferred financing costs ($9.1 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, 2024

March 31, 2025

Reclamation Support Other Support (1)

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Obligations supported, net $ 931.8 $ 146.6 $ 1,078.4

(1) Instruments support obligations related to pension and health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities.

(1) Instruments support obligations related to leases, health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities.

(2) Amounts do not include cash-collateralized letters of credit.

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

Not presented in the above table is $839.0 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at September 30, 2024, as described in Note 12.

Not presented in the above table is $815.3 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at March 31, 2025, as described in Note 13.

“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 decreased $118.6 million during the nine months ended September 30, 2024 due to collateral releases related to reductions in reclamation bonding requirements, replacement of cash-collateralized letters of credit with letters of credit under the new revolving credit facility and the impact of foreign currency rate changes.

At September 30, 2024, the Company had total asset retirement obligations of $701.4 million.

The restricted cash and collateral balance increased $5.5 million during the three months ended March 31, 2025 due to an increase in bonding requirements and the impact of foreign currency rate changes.

At March 31, 2025, the Company had total asset retirement obligations of $725.4 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.

As noted above, the Company’s reclamation bonding requirements decreased during the nine months ended September 30, 2024, primarily due to an approximate $110 million reduction in U.S.

reclamation bonding requirements.

At September 30, 2024, the Company’s reclamation bonding requirements were supported by approximately $725 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, 2025, the Company’s reclamation bonding requirements were supported by approximately $710 million of restricted cash and other balances serving as collateral, which substantially supports the financial liability for final mine reclamation as calculated in accordance with U.S.

Critical Accounting Policies and Estimates

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Actual results may differ from these estimates.

At September 30, 2024, the Company identified certain assets with an aggregate carrying value of approximately $207 million in its Other U.S.

At March 31, 2025, the Company identified certain assets with an aggregate carrying value of approximately $75 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, 2024.

The Company’s critical accounting policies remain unchanged at September 30, 2024, 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, 2025, 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