What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-08-08 compared with 2024-05-09 · 256 added, 154 removed, 500 unchanged (45% of the section changed)

18 unchanged sentences

generally accepted accounting principles (U.S.

Adjusted EBITDA is used by management as the primary metric to measure each of its segments’ operating performance and allocate resources.

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.

12 unchanged sentences

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

At March 31, 2024, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

At June 30, 2024, 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.

7 unchanged sentences

“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 March 31, 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 March 31, 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.

The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended June 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.

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 March 31, 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 June 30, 2024 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 March 31, 2024 May 3, 2024

High Low Average June 30, 2024 August 2, 2024

Premium HCC (1)

13 unchanged sentences

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 three months ended March 31, 2024 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, coking coal prices retreated from a high base during the three months ended March 31, 2024.

Outside of India and China, metallurgical coal demand was hampered by thin steel margins.

In India robust economic output supported steel making profitability;

while in China steel demand was mixed but generally weaker, pressured by real estate sector performance, and domestic metallurgical coal prices declined in response.

Meanwhile, Australian high-quality coking coal showed signs of supply improvement after a period of extended production disruptions and relatively high segment prices.

This incremental volume of high-quality coking coal was reportedly placed in the seaborne market at progressively lower prices during the three months ended March 31, 2024.

In other metallurgical coal market segments, such as pulverized coal injection, prices also retreated during the period however not to the extent of high-quality coking coal given reduced steel making productivity targets under thin margin conditions had already been priced into these segments.

In the coming period, improving steel margins, economic stimulus measures and seasonal restocking patterns may lend support to metallurgical coal market pricing.

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

Within the seaborne thermal coal market, global thermal coal prices were rangebound during the three months ended March 31, 2024, finding support in Asian markets due to potential supply disruptions following new Russian sanctions.

In China, overall total generation demand has been elevated while domestic coal production has declined, which has driven stronger coal import demand year-over-year through the three months ended March 31, 2024.

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 six months ended June 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 six months ended June 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 India, steel production was disrupted due to election activities and more recently the onset of the monsoon season;

while in China, steel production was mixed with a weak property market slowing demand, partially offset by economic stimulus targeting the real estate sector.

Australian high-quality coking coal showed signs of supply improvement during the six months ended June 30, 2024 which has weighed on coking coal prices, however periodic price support has been observed via various supply side disruptions, including rail and port maintenance curtailing exports in Queensland, the restriction of U.S.

exports in Baltimore, Maryland and low domestic coal production in China.

The June 2024 incident at the Grosvenor Mine in Queensland, Australia has further limited global exports.

Despite these constraints, coking coal supply proved sufficient to meet demand during the period.

In the PCI segment, prices were initially under pressure early in the year from reduced steel making productivity targets under thin margin conditions, but have since found support from shifting of trade flows from Russian to Australian supply amidst newly announced sanctions.

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 were rangebound during the six months ended June 30, 2024, driven by healthy supply meeting elevated demand in Asian markets.

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

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In the U.S., overall electricity demand increased approximately 5% year-over-year.

Through the three months ended March 31, 2024, electricity generation from thermal coal has declined year-over-year due to low natural gas prices and stronger renewable generation, despite higher overall electricity demand.

Coal’s share of electricity generation has declined to approximately 15% for the three months ended March 31, 2024, while wind and solar’s combined generation share is at 17% and the share of natural gas generation has increased to 41%.

coal inventories declined in January, these levels have reversed and increased through March 31, 2024, resulting in stockpiles slightly above levels seen at the end of 2023.

During the three months ended March 31, 2024, utility consumption of PRB coal increased approximately 6% compared to the prior year period.

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

The acquisition was completed on April 16, 2024 for cash consideration of approximately $134 million and a contingent royalty of up to $200 million.

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

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

Through the six months ended June 30, 2024, electricity generation from thermal coal has increased slightly year-over-year driven by higher overall electricity demand and despite low natural gas prices and stronger renewable generation.

Coal’s share of electricity generation has declined to approximately 14% for the six months ended June 30, 2024, while wind and solar’s combined generation share is at 19% and the share of natural gas generation has decreased slightly to 40%.

coal inventories have declined through June 30, 2024, resulting in stockpiles slightly below levels seen at the end of 2023.

During the six months ended June 30, 2024, utility consumption of PRB coal was unchanged compared to the prior year period.

Centurion Mine

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

The first development coal was mined in June 2024, and a second continuous mine was commissioned in July 2024.

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

Approximately $200 million of the $489 million of capital expenditures to reach longwall production has been completed as of June 30, 2024.

The benchmark premium hard coking coal from Centurion is expected to receive a premium price relative to other metallurgical coals.

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 for the three and six months ended June 30, 2024.

Results of Operations

Three Months Ended March 31, 2024 Compared to the Three Months Ended March 31, 2023

The decrease in income from continuing operations, net of income taxes for the three months ended March 31, 2024 compared to the same period in the prior year ($238.4 million) was driven by lower revenue ($380.4 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.

Three and Six Months Ended June 30, 2024 Compared to the Three and Six Months Ended June 30, 2023

The increase in income from continuing operations, net of income taxes for the three months ended June 30, 2024 compared to the same period in the prior year ($6.7 million) was driven by the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($58.1 million), and lower year-over-year provisions for taxes ($34.8 million) and the losses at the NARM and Shoal Creek Mines ($31.8 million).

These favorable variances were offset by lower revenue ($226.8 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 ($97.9 million) and operating costs and expenses ($32.4 million).

Adjusted EBITDA for the three months ended March 31, 2024 reflected a year-over-year decrease of $230.1 million.

The decrease in income from continuing operations, net of income taxes for the six months ended June 30, 2024 compared to the same period in the prior year ($231.7 million) was driven by lower revenue ($607.2 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 ($132.7 million), the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($90.5 million) and lower year-over-year provision for losses at the NARM and Shoal Creek Mines ($30.0 million).

Adjusted EBITDA for the three and six months ended June 30, 2024 reflected year-over-year decreases of $48.5 million and $278.6 million, respectively.

The following table presents tons sold by operating segment:

Three Months Ended March 31, Increase (Decrease)

2024 2023 Tons %

(Tons in millions)

Three Months Ended June 30, Increase (Decrease)

to Volumes Six Months Ended June 30, Increase (Decrease)

2024 2023 Tons % 2024 2023 Tons %

(Tons in millions) (Tons in millions)

Seaborne Thermal 4.1 4.0 0.1 3 % 8.1 7.6 0.5 7 %

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The following table presents supplemental financial data by operating segment:

Three Months Ended March 31, (Decrease)

Three Months Ended June 30, (Decrease)

Increase Six Months Ended June 30, (Decrease)

2024 2023 $ % 2024 2023 $ %

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

insurance recoveries;

and certain other costs related to post-mining activities.

The following table presents revenue by reporting segment:

Three Months Ended March 31, Decrease to Revenue

Three Months Ended June 30, (Decrease) Increase to Revenue Six Months Ended June 30, Decrease to Revenue

2024 2023 $ % 2024 2023 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Seaborne Thermal $ 307.5 $ 399.5 $ (92.0) (23) % $ 591.4 $ 746.0 $ (154.6) (21) %

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Seaborne Thermal.

Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable realized prices ($94.9 million), partially offset by favorable export volumes ($32.3 million).

Segment revenue decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable realized prices ($117.4 million and $217.8 million, respectively), partially offset by favorable export volumes ($25.4 million and $63.2 million, respectively).

Seaborne Metallurgical.

Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable realized prices ($89.9 million), offset by favorable volumes ($48.5 million) driven by increased production at the Shoal Creek Mine.

Segment revenue decreased during the three months ended June 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($56.8 million) and mix variances ($21.4 million).

Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($181.1 million), offset by favorable volume and mix variances ($61.5 million) driven by increased production at the Shoal Creek Mine.

Powder River Basin.

Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year primarily due to unfavorable volumes ($48.0 million) resulting from decreased demand driven by low natural gas pricing and mild weather.

Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($67.2 million) resulting from decreased demand driven by low natural gas pricing and mild weather, partially offset by increased sales contract cancellation settlements ($12.4 million).

Segment revenue decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($38.2 million and $85.7 million, respectively) resulting from decreased demand driven by low natural gas pricing and mild weather.

Segment revenue increased during the three months ended June 30, 2024 compared to the same period in the prior year due to favorable realized prices ($3.2 million).

Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable volumes ($69.4 million) resulting from decreased demand driven by low natural gas pricing and mild weather, partially offset by increased sales contract cancellation settlements ($13.1 million).

Corporate and Other.

Segment revenue decreased during the three months ended March 31, 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 ($118.7 million) as all derivative contracts settled in 2023;

lower results from trading activities ($31.8 million);

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.

Segment revenue decreased during the three months ended June 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 ($40.3 million) as all derivative contracts settled in 2023;

offset by favorable results from trading activities ($19.0 million).

Segment revenue decreased during the six months ended June 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);

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;

and lower results from trading activities ($12.8 million).

Adjusted EBITDA

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

Three Months Ended March 31, Decrease to Segment Adjusted EBITDA

Three Months Ended June 30, (Decrease) Increase to Segment Adjusted EBITDA Six Months Ended June 30, Decrease to Segment Adjusted EBITDA

2024 2023 $ % 2024 2023 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Seaborne Thermal $ 104.4 $ 197.5 $ (93.1) (47) % $ 198.2 $ 361.5 $ (163.3) (45) %

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Seaborne Thermal.

Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($89.8 million), partially offset by favorable volume and mix variances ($21.1 million).

Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year as a result of lower realized prices net of sales price sensitive costs ($106.0 million and $200.8 million, respectively), partially offset by favorable volume and mix variances ($15.4 million and $39.2 million, respectively).

Seaborne Metallurgical.

Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($71.0 million) and unfavorable volumes ($22.0 million) and operational costs ($15.4 million) at the Australian operations primarily resulting from a longwall move at the Metropolitan Mine in the first quarter of 2024.

These decreases were offset by favorable volumes from the Shoal Creek Mine ($52.4 million) despite the outage at the Demopolis Lock in the first quarter of 2024.

Segment Adjusted EBITDA increased during the three months ended June 30, 2024 compared to the same period in the prior year due to the Shoal Creek insurance recovery ($80.8 million) further discussed in Note 15.

“Other Events” in the accompanying unaudited condensed consolidated financial statements and favorable mix variances ($15.4 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.

These increases were offset by lower realized prices net of sales price sensitive costs ($41.3 million) and unfavorable operational costs ($24.3 million).

Segment Adjusted EBITDA decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($151.0 million) and unfavorable operational costs ($47.7 million).

These decreases were offset by favorable volumes ($88.4 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).

Powder River Basin.

Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($24.1 million) and elevated overburden removal costs ($10.5 million), offset by lower costs for materials, services, repairs and labor ($11.0 million) and favorable commodity pricing ($6.9 million).

Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($39.5 million), offset by increased sales contract cancellation settlements ($12.4 million) and lower costs for materials, services, repairs and labor ($8.2 million).

Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($14.1 million and $44.9 million, respectively) and increased lease spend ($3.4 million and $5.4 million, respectively), offset by lower costs for materials, services, repairs and labor ($9.7 million and $22.3 million, respectively) and favorable commodity pricing ($1.4 million and $8.2 million, respectively).

Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($22.3 million and $59.7 million, respectively), offset by favorable mine sequencing ($2.4 million and $11.5 million, respectively) and increased sales contract cancellation settlements (six months, $13.1 million).

Corporate and Other Adjusted EBITDA.

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

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

Three Months Ended June 30, (Decrease) Increase to Adjusted EBITDA Six Months Ended June 30, (Decrease) Increase to Adjusted EBITDA

2024 2023 $ % 2024 2023 $ %

(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, costs associated with suspended operations including the Centurion Mine and expenses related to the Company’s other commercial activities.

Corporate and Other Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable trading results ($40.2 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, 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 June 30, 2024 compared to the same period in the prior year due to favorable trading results ($14.7 million) and the favorable net impact of foreign currency rate changes ($9.4 million).

Corporate and Other Adjusted EBITDA decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable trading results ($25.5 million);

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.

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

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

Three Months Ended June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income

2024 2023 $ % 2024 2023 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Adjusted EBITDA (1)

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Restructuring charges (0.1) (2.0) 1.9 95 % (0.2) (2.1) 1.9 90 %

Asset impairment — (2.0) 2.0 100 %

Provision for NARM loss (1.8) — (1.8) n.m.

Asset impairment — — — n.m.

— (2.0) 2.0 100 %

Provision for NARM and Shoal Creek losses (1.9) (33.7) 31.8 94 % (3.7) (33.7) 30.0 89 %

Shoal Creek insurance recovery - property damage 28.7 — 28.7 n.m.

28.7 — 28.7 n.m.

Changes in amortization of basis difference related to equity affiliates 0.3 0.4 (0.1) (25) % 0.7 0.7 — — %

Interest expense (14.7) (18.4) 3.7 20 %

Interest expense, net of capitalized interest (10.7) (13.3) 2.6 20 % (25.4) (31.7) 6.3 20 %

Net loss on early debt extinguishment — (2.0) 2.0 100 % — (8.8) 8.8 100 %

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— 40.3 (40.3) (100) % — 159.0 (159.0) (100) %

Unrealized losses on foreign currency option contracts (5.7) (2.2) (3.5) (159) %

Unrealized gains (losses) on foreign currency option contracts 2.4 2.8 (0.4) (14) % (3.3) 0.6 (3.9) (650) %

Take-or-pay contract-based intangible recognition 0.8 0.6 0.2 33 % 1.5 1.2 0.3 25 %

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

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

Three Months Ended June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income

2024 2023 $ % 2024 2023 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Seaborne Thermal $ (28.7) $ (27.6) $ (1.1) (4) % $ (56.3) $ (51.4) $ (4.9) (10) %

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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 March 31,

Three Months Ended June 30, Six Months Ended June 30,

2024 2023 2024 2023

Seaborne Thermal $ 2.08 $ 2.09 $ 2.09 $ 2.13

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The increases in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S.

Thermal segments during the three months ended March 31, 2024 compared to the same period in the prior year reflect the impact of volume and mix variances across the segments.

Thermal segments during the three and six months ended June 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 three and six months ended June 30, 2024.

Interest Expense, Net of Capitalized Interest.

The decrease in expense during the three and six months ended June 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.

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Interest Income.

The increase in interest income during the three months ended March 31, 2024 was primarily due to higher cash balances, including restricted cash balances on which the Company earns interest, and higher interest rates in the current year.

The decrease in interest income during the three months ended June 30, 2024 was primarily due to lower average cash balances, including restricted cash balances on which the Company earns interest, in the current year.

Unrealized Gains on Derivative Contracts Related to Forecasted Sales.

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Income Tax Provision.

The decrease in the income tax provision during the three months ended March 31, 2024 compared to the same period in the prior year was primarily due to lower pretax income.

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

Refer to Note 8.

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The following table presents net income attributable to common stockholders:

Three Months Ended March 31, (Decrease) Increase

Three Months Ended June 30, Increase (Decrease)

to Income Six Months Ended June 30, (Decrease) Increase

2024 2023 $ % 2024 2023 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Income from continuing operations, net of income taxes $ 210.8 $ 204.1 $ 6.7 3 % $ 256.5 $ 488.2 $ (231.7) (47) %

4 unchanged sentences

Net Income Attributable to Noncontrolling Interests.

The decrease in the results attributable to noncontrolling interests during the three months ended March 31, 2024 compared to the same period in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest.

The decrease in the results attributable to noncontrolling interests during the three and six months ended June 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 March 31, Decrease

Three Months Ended June 30, Increase

to EPS Six Months Ended June 30, Decrease

2024 2023 $ % 2024 2023 $ %

4 unchanged sentences

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 144.9 million and 161.4 million for the three months ended March 31, 2024 and 2023, respectively.

Diluted EPS reflects weighted average diluted common shares outstanding of 142.8 million and 159.0 million for the three months ended June 30, 2024 and 2023, respectively, and 143.8 million and 160.2 million for the six months ended June 30, 2024 and 2023, respectively.

Reconciliation of Non-GAAP Financial Measures

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

Three Months Ended March 31,

Three Months Ended June 30, Six Months Ended June 30,

2024 2023 2024 2023

(Dollars in millions)

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Depreciation, depletion and amortization

82.9 80.6 162.7 156.9

Asset retirement obligation expenses

12.9 15.5 25.8 30.9

Restructuring charges

0.1 2.0 0.2 2.1

Asset impairment

Provision for NARM loss 1.8 —

Provision for NARM and Shoal Creek losses 1.9 33.7 3.7 33.7

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

Changes in amortization of basis difference related to equity affiliates (0.3) (0.4) (0.7) (0.7)

Interest expense

Interest expense, net of capitalized interest 10.7 13.3 25.4 31.7

Net loss on early debt extinguishment — 2.0 — 8.8

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Unrealized gains on derivative contracts related to forecasted sales — (40.3) — (159.0)

Unrealized losses on foreign currency option contracts 5.7 2.2

Unrealized (gains) losses on foreign currency option contracts (2.4) (2.8) 3.3 (0.6)

Take-or-pay contract-based intangible recognition

(0.8) (0.6) (1.5) (1.2)

Income tax provision 39.4 74.2 59.5 192.2

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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 March 31,

Three Months Ended June 30, Six Months Ended June 30,

2024 2023 2024 2023

(Dollars in millions)

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$ 803.9 $ 862.0 $ 1,618.1 $ 1,708.6

Unrealized losses on foreign currency option contracts (5.7) (2.2)

Unrealized gains (losses) on foreign currency option contracts 2.4 2.8 (3.3) 0.6

Take-or-pay contract-based intangible recognition

0.8 0.6 1.5 1.2

Net periodic benefit credit, excluding service cost (10.2) (9.7) (20.3) (19.4)

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

Three Months Ended March 31,

Three Months Ended June 30, Six Months Ended June 30,

2024 2023 2024 2023

(Dollars in millions)

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Total Reporting Segment Costs $ 796.9 $ 855.7 $ 1,596.0 $ 1,691.0

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

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 March 31, 2024

Three Months Ended June 30, 2024

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

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Total Reporting Segment Costs 203.1 231.5 204.1 166.6

Adjusted EBITDA, excluding Shoal Creek insurance recovery $ 104.4 $ 62.8 $ 17.8 $ 35.4

Shoal Creek insurance recovery - business interruption — 80.8 — —

Adjusted EBITDA $ 104.4 $ 143.6 $ 17.8 $ 35.4

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Adjusted EBITDA Margin per Ton $ 25.29 $ 31.82 $ 1.13 $ 9.68

Three Months Ended March 31, 2023

Three Months Ended June 30, 2023

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

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Adjusted EBITDA Margin per Ton $ 49.71 $ 52.35 $ 1.38 $ 13.92

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

Six Months Ended June 30, 2024

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

(Amounts in millions, except per ton data)

Tons sold 8.1 3.4 34.5 6.9

Revenue $ 591.4 $ 541.3 $ 476.0 $ 393.6

Total Reporting Segment Costs 393.2 430.2 441.8 311.7

Adjusted EBITDA, excluding Shoal Creek insurance recovery $ 198.2 $ 111.1 $ 34.2 $ 81.9

Shoal Creek insurance recovery - business interruption — 80.8 — —

Adjusted EBITDA $ 198.2 $ 191.9 $ 34.2 $ 81.9

Revenue per Ton $ 72.86 $ 159.10 $ 13.80 $ 57.33

Costs per Ton 48.44 126.46 12.81 45.40

Adjusted EBITDA Margin per Ton $ 24.42 $ 32.64 $ 0.99 $ 11.93

Six Months Ended June 30, 2023

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

(Amounts in millions, except per ton data)

Tons sold 7.6 3.3 40.9 8.3

Revenue $ 746.0 $ 660.9 $ 565.0 $ 449.3

Total Reporting Segment Costs 384.5 467.6 503.0 333.2

Adjusted EBITDA $ 361.5 $ 193.3 $ 62.0 $ 116.1

Revenue per Ton $ 98.81 $ 202.33 $ 13.80 $ 54.23

Costs per Ton 50.94 143.14 12.28 40.22

Adjusted EBITDA Margin per Ton $ 47.87 $ 59.19 $ 1.52 $ 14.01

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.

Three Months Ended March 31, 2024

Six Months Ended June 30, 2024

(Dollars in millions)

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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, the EPA signed a final rule based on the 2023 proposed rule on April 24, 2024.

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 April 24, 2024, the EPA signed a pre-publication version of final rules for new, modified and reconstructed fossil fuel-fired EGUs.

This rule package consists of four elements:

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;

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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 rules, 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.

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.

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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 rules – whether fired by coal, oil 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 rules, 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.

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 rules include several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order maintain adequate electric generation resources and grid reliability.

Finally, as part of the final rules, 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, 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 rules, as implemented by the EPA and states, could have substantial impacts on the use of coal, oil and natural gas for the generation of electricity.

The Company is evaluating the impacts the final rules will have on its results of operations, cash flows and financial condition.

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

Court of Appeals for the Eighth Circuit (Eighth Circuit).

If the Eighth Circuit affirms the final rule, as 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.

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

On April 24, 2024, the EPA signed a pre-publication version of 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.

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 could influence fuel switching or additional coal generating unit retirements by the end of 2034.

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;

4 unchanged sentences

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 March 2026.

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 April 24, 2024, the EPA signed a pre-publication version of additional amendments to the 2015 CCR rule that further address aspects of the D.C.

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.

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

On December 20, 2023, the U.S.

Supreme Court issued an order for oral argument regarding applications for an emergency stay of the rule.

Supreme Court held oral argument on February 21, 2024.

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.

Regional Haze.

2 unchanged sentences

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 remains pending.

Federal Coal Leasing Moratorium .

2 unchanged sentences

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 the Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations.

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.

1 unchanged sentence

On appeal, the U.S.

Court of Appeals for the 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.

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.

2 unchanged sentences

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 the Interior and Commerce finalized five rules aiming to streamline and update the ESA.

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 issued pre-publication versions of three final revised rules on March 27, 2024.

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

SEC Climate-Related Disclosures .

3 unchanged sentences

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

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

Court of Appeals for the Eighth Circuit.

On April 4, 2024, the SEC voluntarily stayed implementation of the final rules.

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

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

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

Regulatory Matters - Australia

New South Wales Environmental .

In New South Wales (NSW), laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulations 2000, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Radiation Control Act 1990, Biodiversity Conservation Act 2016 (BC Act), Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Land Management Act 2016, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Forestry Act 2012, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks & Wildlife Act 1974.

Under the NSW EPA Act, environmental planning instruments must be considered when approving a mining project development application.

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 (NSW) 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.

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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 BC Act commenced in New South Wales 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.

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:

2 unchanged sentences

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

The New South Wales government is currently considering fifty-eight recommendations of a 2023 independent review of the BC Act.

Any changes to the BC Act have the potential to affect approval processes for future NSW mining projects.

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 by introducing a new statutory standard requiring mining proponents to demonstrate how they have genuinely avoided and minimized impacts to biodiversity and removing the option for major mining proponents to meet a credit obligation through a commitment to ecological mine site rehabilitation .

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

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.

Risks Related to Global Climate Change

9 unchanged sentences

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 March 31, 2024, the Company’s cash and cash equivalents balances totaled $855.7 million, including approximately $473 million held by Australian subsidiaries, approximately $366 million held by U.S.

subsidiaries and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S.

As of June 30, 2024, the Company’s cash and cash equivalents balances totaled $621.7 million, including approximately $388 million held by U.S.

subsidiaries, approximately $217 million held by Australian subsidiaries and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S.

A significant majority of the cash held by the Company’s foreign subsidiaries is denominated in U.S.

This cash is generally used to support non-U.S.

liquidity needs, including capital and operating expenditures in Australia.

From time to time, the Company may repatriate excess cash from its foreign subsidiaries to the U.S.

During the three months ended March 31, 2024, the Company did not repatriate any excess cash.

liquidity needs, including capital and operating expenditures in Australia and payment of the foreign subsidiaries’ share of certain U.S.

corporate expenditures.

From time to time, the Company may repatriate profits from its foreign subsidiaries to the U.S.

in the form of intercompany dividends.

During the six months ended June 30, 2024, 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 $1,157.4 million as of March 31, 2024 from $1,059.7 million as of December 31, 2023.

The Company’s available liquidity decreased from $1,059.7 million as of December 31, 2023 to $940.8 million as of June 30, 2024.

Available liquidity was comprised of the following:

March 31, 2024 December 31, 2023

June 30, 2024 December 31, 2023

(Dollars in millions)

4 unchanged sentences

Capital Returns to Shareholders

The Company repurchased approximately 3.2 million shares of its common stock for $80.5 million, including commission fees, and paid dividends of $9.7 million during the three months ended March 31, 2024.

The Company repurchased approximately 3.2 million shares of its common stock for $80.5 million, including commission fees, and paid dividends of $19.1 million during the six months ended June 30, 2024.

Surety Agreement Amendment and Collateral Requirements

4 unchanged sentences

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 $521.8 million at March 31, 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.

1 unchanged sentence

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 March 31, 2024.

The Company is in compliance with such requirements at June 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.

3 unchanged sentences

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

The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum.

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

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

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

At March 31, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 million.

At June 30, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 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 March 31, 2024, the bank guarantee facilities were backed by cash of $177.0 million.

At June 30, 2024, the bank guarantee facilities were backed by cash of $179.5 million.

Revolving Credit Facility

4 unchanged sentences

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

As of March 31, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $99.0 million outstanding as of March 31, 2024.

As of June 30, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $98.0 million outstanding as of June 30, 2024.

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

“Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $221.0 million at March 31, 2024.

“Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $222.0 million at June 30, 2024.

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.

1 unchanged sentence

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

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

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

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

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

(Dollars in millions)

4 unchanged sentences

Long-term debt $ 323.2 $ 320.7

The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at March 31, 2024, of approximately $19 million in 2024, $18 million in 2025, $16 million in 2026, $12 million in 2027 and $325 million in 2028.

Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $11.5 million and $19.1 million during the three months ended March 31, 2024 and 2023, respectively.

The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at June 30, 2024, of approximately $16 million in 2024, $18 million in 2025, $16 million in 2026, $13 million in 2027 and $326 million in 2028.

Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $24.1 million and $41.9 million during the six months ended June 30, 2024 and 2023, respectively.

2028 Convertible Notes

4 unchanged sentences

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 quarter 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 will not be convertible at the option of the holders during the second quarter of 2024.

During the first and second 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 quarter of 2024, and will not be similarly convertible during the third quarter of 2024.

Accounts Receivable Securitization Program

1 unchanged sentence

“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.

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

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 March 31, 2024, the Company had no outstanding borrowings and $53.1 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, 2024.

At June 30, 2024, the Company had no outstanding borrowings and $56.2 million of letters of credit outstanding under the program.

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

Covenant Compliance

The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2024.

The following table summarizes the Company’s cash flows for the three months ended March 31, 2024 and 2023, as reported in the accompanying unaudited condensed consolidated financial statements.

The Company was compliant with all relevant covenants under its debt and other finance agreements at June 30, 2024.

The following table summarizes the Company’s cash flows for the six months ended June 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.

Three Months Ended March 31,

Six Months Ended June 30,

(Dollars in millions)

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Operating Activities.

The decrease in net cash provided by operating activities for the three months ended March 31, 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 ($201.0 million);

The decrease in net cash provided by operating activities for the six months ended June 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 ($461.9 million), primarily attributable to income tax payments and accruals ($191.3 million), an increase in accounts receivable due to timing of sales and overall higher price per ton ($176.6 million) and Shoal Creek inventories build due to the Demopolis Lock outage that continued through May 2024 ($55.0 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, partially offset by a decrease in cash used for collateral requirements ($197.2 million).

and lower cash generated from mining operations.

These unfavorable variances were partially offset by a decrease in cash used for collateral requirements ($266.5 million).

Investing Activities.

The increase in net cash used in investing activities for the three months ended March 31, 2024 compared to the same period in the prior year was driven by higher capital expenditures and payments of capital accruals ($10.9 million) and higher net contributions to joint ventures ($5.4 million).

The increase in net cash used in investing activities for the six months ended June 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 and payments of capital accruals ($53.0 million).

Financing Activities.

The increase in net cash used by financing activities for the three months ended March 31, 2024 compared to the same period in the prior year was primarily driven by common stock repurchases and dividends paid in the current year ($83.1 million and $9.7 million, respectively).

The decrease in net cash used by financing activities for the six months ended June 30, 2024 compared to the same period in the prior year was primarily driven by a decrease in common stock repurchases ($89.9 million), partially offset by an increase in dividends paid ($8.3 million).

Off-Balance-Sheet Arrangements

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

March 31, 2024

June 30, 2024

Reclamation Support Other Support (1)

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

Not presented in the above table is $836.0 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at March 31, 2024, as described in Note 12.

Not presented in the above table is $825.1 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at June 30, 2024, as described in Note 12.

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

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

The restricted cash and collateral balance at March 31, 2024 decreased from $957.6 million at December 31, 2023 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 unfavorable impact of foreign currency rate changes.

At March 31, 2024, the Company had total asset retirement obligations of $703.2 million.

The restricted cash and collateral balance at June 30, 2024 decreased from $957.6 million at December 31, 2023 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 June 30, 2024, the Company had total asset retirement obligations of $699.9 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 three months ended March 31, 2024 primarily due to an approximate $85 million reduction in U.S.

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

reclamation bonding requirements.

The Company had an additional reduction in U.S.

reclamation bonding requirements of approximately $20 million during April 2024.

At March 31, 2024, the Company’s reclamation bonding requirements were supported by approximately $730 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 June 30, 2024, the Company’s reclamation bonding requirements were supported by approximately $720 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.

Critical Accounting Policies and Estimates

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Actual results may differ from these estimates.

At March 31, 2024, the Company identified certain assets with an aggregate carrying value of approximately $219 million in its Other U.S.

At June 30, 2024, the Company identified certain assets with an aggregate carrying value of approximately $214 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, 2023.

The Company’s critical accounting policies remain unchanged at March 31, 2024, and there have been no material changes in the Company’s critical accounting estimates.

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