What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2024-05-09 compared with 2023-11-03 · 288 added, 344 removed, 366 unchanged (63% of the section changed)

11 unchanged sentences

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

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

“Risk Factors” of Part II of its Quarterly Report on Form 10-Q for the quarter ended March 31, 2023 filed with the SEC on May 4, 2023 and Item 1A.

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

“Risk Factors” and Item 3.

11 unchanged sentences

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 measure.

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.

5 unchanged sentences

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

At September 30, 2023, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

At March 31, 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.

1 unchanged sentence

trades coal and freight-related contracts;

and during 2022, 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.

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:

3 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 September 30, 2023 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, 2023 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 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 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, 2023 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, 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.

1 unchanged sentence

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, 2023 October 27, 2023

High Low Average March 31, 2024 May 3, 2024

Premium HCC (1)

12 unchanged sentences

(2) Prices expressed per short ton.

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

Furthermore, inflationary pressures and supply chain constraints have contributed to rising costs and may continue to impact future periods.

As future developments related to the Russian-Ukrainian conflict and rising inflation are unknown, the global coal industry data for the nine months ended September 30, 2023 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, the volatility which characterized the first half of 2023 has continued during the three months ended September 30, 2023 as global macroeconomic turbulence combined with demand and supply fluctuations.

The steel sector showed positive signs in early 2023, however ongoing economic uncertainty, inflating feed-stock prices and multi-year high steel exports from China have reportedly dampened steel margins and slowed steel production.

India is an exception where steel output has grown year-over-year reflecting strong economic growth.

Overall, metallurgical coal prices improved in the latter part of the three months ended September 30, 2023, supported by exports from some key metallurgical coal producing regions tracking historical lows.

However, the impact of the diverging steel market outlook has further bifurcated metallurgical coal market outcomes.

Supply and demand fundamentals for prime hard coking coals are supporting stronger price outcomes for this grade.

In other metallurgical coal market segments, such as pulverized coal injection coal, reduced steel making productivity targets and a greater breadth of supply options have contributed to more conservative price increases.

The seaborne metallurgical coal market is expected to remain volatile for the balance of the year, influenced by the rate of recovery of export from Australia and economic performance in China, India and elsewhere.

Within the seaborne thermal coal market, global thermal coal prices remained volatile during the three months ended September 30, 2023.

China has ended its unofficial ban of Australian coal imports, providing additional demand for Australian thermal coal through the nine months ended September 30, 2023.

In China, domestic coal production and renewable generation have been strong through the nine months ended September 30, 2023;

however, import demand has been higher year-over-year, as overall coal demand has been strong.

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.

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

Overall, global thermal coal markets remain turbulent amid ample supply and seasonal demand requirements in the Northern Hemisphere, as well as volatile global natural gas markets.

In the United States, overall electricity demand decreased approximately 2% year-over-year, negatively impacted by weather in the first half of the year.

Through the nine months ended September 30 2023, electricity generation from thermal coal has declined year-over-year due to low natural gas prices and stronger renewable generation despite lower overall electricity demand.

Coal’s share of electricity generation has declined to approximately 16% for the nine months ended September 30, 2023, while wind and solar’s combined generation share has increased to 16% and the share of natural gas generation has increased to 43%.

While coal inventories have slightly recovered over the summer, they remain approximately 35% higher than the levels at the end of 2022.

During the nine months ended September 30, 2023, utility consumption of PRB coal declined approximately 20% compared to the prior year period.

Department of Labor Settlement

On August 8, 2023, the Company entered into a settlement agreement with the U.S.

Department of Labor to resolve a liability dispute regarding the federal black lung claims of the Company’s previously divested legacy operations of Patriot Coal Corporation and certain of its wholly-owned subsidiaries (Patriot).

In accordance with the settlement agreement, the Company paid $72.0 million to settle the Patriot federal black lung claims, with the exception of approximately $4.2 million of certain claims for attorney’s fees and additional compensation due to claimants not paid during appeal.

As a result of the settlement, the Company recognized a $3.9 million gain within “Income (loss) from discontinued operations, net of income taxes” during the three and nine months ended September 30, 2023.

Surety Agreement Amendment and Shareholder Return Program

On April 14, 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020.

Under the agreement, the Company was required to post collateral on a periodic basis.

Pursuant to the amendment, the Company and its surety bond providers agreed to (i) establish a combined maximum collateral cap, (ii) remove the restrictions on shareholder returns contained in the original agreement, subject to a minimum liquidity threshold, and (iii) extend the expiration date of the existing agreement from December 31, 2025 to December 31, 2026.

Peabody also terminated the letter of credit facility which was previously used primarily for surety collateral, further reducing interest costs and increasing financial flexibility.

On April 17, 2023, the Company announced that its Board of Directors (Board) approved a new shareholder return framework which includes a share repurchase plan, a fixed quarterly cash dividend and a variable quarterly cash dividend component.

The Board also approved a new share repurchase program authorizing repurchases up to $1.0 billion of the Company’s common stock.

Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of the surety agreement amendment.

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.

Development coal production has been resumed in a new area of the mine.

During the nine months ended September 30, 2023, the Company recorded a provision for loss of $28.7 million related to the fire.

The provision includes $17.8 million related to longwall development and other costs and $10.9 million for equipment deemed inoperable within the affected area of the mine.

In October, 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.

On June 23, 2023, the Company’s North Antelope Rochelle Mine (NARM) sustained damage from a tornado which led to a temporary suspension of operations.

The mine resumed operations on June 25, 2023.

During the three and nine months ended September 30, 2023, the Company recorded a provision for loss of $3.3 million and $8.3 million, respectively, related to the tornado damage.

The combined provision includes $4.0 million for materials and supplies inventories, $1.0 million for buildings and equipment and $3.3 million for incremental repair costs.

The Company anticipates that incremental repair costs will continue to be recorded in future periods.

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

The acquisition terms include cash consideration of $136 million and a contingent royalty of up to $200 million.

In the U.S., overall electricity demand increased approximately 4% 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.

Completion of the transaction is subject to the satisfaction of certain conditions, including regulatory approvals.

Results of Operations

Three and Nine Months Ended September 30, 2023 Compared to the Three and Nine Months Ended September 30, 2022

The decrease in income from continuing operations, net of income taxes for the three months ended September 30, 2023 compared to the same period in the prior year ($255.6 million), was driven by lower revenue ($263.6 million) primarily due to decreases in net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales and seaborne coal pricing;

a higher tax provision ($35.8 million);

and decreased results from equity affiliates ($21.9 million).

These unfavorable variances were partially offset by lower net interest expense ($44.1 million) and operating costs and expenses ($34.7 million).

The decrease in income from continuing operations, net of income taxes for the nine months ended September 30, 2023 compared to the same period in the prior year ($58.9 million), was primarily driven by a higher income tax provision ($217.7 million);

higher operating costs and expenses ($149.3 million), which reflect increased sales price sensitive costs and inflationary pressures for materials, services, repairs and labor;

decreased results from equity affiliates ($111.2 million);

and a provision of $37.0 million related to the losses at NARM and Shoal Creek.

These unfavorable variances were offset by higher revenue ($355.9 million) due to net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales and lower net interest expense ($141.2 million).

Adjusted EBITDA for the three and nine months ended September 30, 2023 reflected year-over-year decreases of $168.9 million and $325.4 million, respectively.

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.

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 following table presents tons sold by operating segment:

Three Months Ended September 30, Increase (Decrease)

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

2023 2022 Tons % 2023 2022 Tons %

(Tons in millions) (Tons in millions)

Three Months Ended March 31, Increase (Decrease)

2024 2023 Tons %

(Tons in millions)

Seaborne Thermal 4.0 3.6 0.4 11 %

7 unchanged sentences

The following table presents supplemental financial data by operating segment:

Three Months Ended September 30, (Decrease)

Increase Nine Months Ended September 30, Increase

Three Months Ended March 31, (Decrease)

2024 2023 $ %

25 unchanged sentences

The following table presents revenue by reporting segment:

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

Three Months Ended March 31, Decrease to Revenue

2024 2023 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 283.9 $ 346.5 $ (62.6) (18) %

5 unchanged sentences

Seaborne Thermal.

Segment revenue decreased during the three months ended September 30, 2023 compared to the same period in the prior year due to unfavorable realized prices ($241.9 million), offset by favorable mix variances ($186.1 million).

Segment revenue increased during the nine months ended September 30, 2023 compared to the same period in the prior year due to favorable mix variances ($234.5 million), offset by unfavorable realized prices ($150.4 million).

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).

Seaborne Metallurgical.

Segment revenue decreased during the three months ended September 30, 2023 compared to the same period in the prior year due to unfavorable realized prices ($32.9 million) and unfavorable volumes ($30.8 million).

Segment revenue decreased during the nine months ended September 30, 2023 compared to the same period in the prior year due to unfavorable realized prices ($249.2 million) and unfavorable volumes from the Shoal Creek Mine resulting from the fire in the first quarter of 2023 ($106.0 million), partially offset by favorable volumes from the Australian operations ($97.3 million).

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.

Powder River Basin.

Segment revenue increased during the three and nine months ended September 30, 2023 compared to the same periods in the prior year due to favorable realized prices ($12.8 million and $79.6 million, respectively) and favorable volumes ($9.7 million and $27.0 million, respectively) resulting from improved rail performance.

Segment revenue decreased during the three and nine months ended September 30, 2023 compared to the same periods in the prior year due to unfavorable volumes ($34.4 million and $55.6 million, respectively) resulting from decreased demand, offset by favorable realized prices ($1.2 million and $43.7 million, respectively).

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).

Corporate and Other.

Segment revenue decreased during the three months ended September 30, 2023 compared to the same period in the prior year due to decreased net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales ($90.4 million) as all derivative contracts have settled in the current year and lower results from trading activities ($44.1 million).

Segment revenue increased during the nine months ended September 30, 2023 compared to the same period in the prior year due to net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales in the current year compared to net unrealized mark-to-market losses in the prior year ($394.1 million);

higher results from trading activities ($19.8 million);

and 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 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.

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

1 unchanged sentence

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

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

Three Months Ended March 31, Decrease to Segment Adjusted EBITDA

2024 2023 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ 93.8 $ 164.0 $ (70.2) (43) %

8 unchanged sentences

Seaborne Thermal.

Segment Adjusted EBITDA decreased during the three months ended September 30, 2023 compared to the same period in the prior year as a result of lower realized prices net of sales sensitive costs ($221.8 million), offset by favorable mix variances ($165.3 million).

Segment Adjusted EBITDA increased during the nine months ended September 30, 2023 compared to the same period in the prior year as a result of favorable mix variances ($200.4 million), offset by lower realized prices net of sales sensitive costs ($137.2 million) and unfavorable operational costs ($25.5 million) resulting from higher costs for repairs, maintenance and labor.

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).

Seaborne Metallurgical.

Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2023 compared to the same periods in the prior year due to lower realized prices net of sales sensitive costs ($21.5 million and $239.0 million, respectively);

unfavorable volume and mix variances ($19.1 million and $43.3 million, respectively);

and unfavorable operational costs (nine months, $40.1 million) resulting from the fire at the Shoal Creek Mine in the first quarter of 2023 and increased repair and maintenance spend at the Australian metallurgical operations.

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.

Powder River Basin.

Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2023 compared to the same periods in the prior year due to favorable commodity pricing and usage ($11.3 million and $23.9 million, respectively);

decreased overburden removal costs ($3.6 million and $13.3 million, respectively);

higher realized prices net of sales sensitive costs ($2.3 million and $36.4 million, respectively);

and favorable volumes ($1.9 million and $11.0 million, respectively).

The increases were partially offset by higher costs for materials, services, repairs and labor ($3.0 million and $13.2 million, respectively) due in part to timing, increased repairs for an aging equipment fleet and inflationary pressures on materials and services.

Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2023 compared to the same periods in the prior year due to unfavorable volumes ($29.0 million and $31.4 million, respectively) and higher costs for materials, services, repairs and labor (nine months, $34.1 million) due in part to timing, increased repairs for an aging equipment fleet and inflationary pressures on materials and services.

These decreases were offset by favorable commodity pricing ($4.4 million and $15.1 million, respectively) and higher realized prices net of sales sensitive costs (nine months, $33.4 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 ($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).

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

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

2024 2023 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Middlemount (1)

9 unchanged sentences

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

Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $5.2 million and $12.9 million during the three months ended September 30, 2023 and 2022, respectively, and $11.1 million and $56.4 million during the nine months ended September 30, 2023 and 2022, respectively.

(2) Includes gains (losses) on certain surplus coal reserve, 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 North Goonyella Mine and expenses related to the Company’s other commercial activities.

Corporate and Other Adjusted EBITDA decreased during the three months ended September 30, 2023 compared to the same period in the prior year due to unfavorable trading results ($40.1 million) and unfavorable variances in Middlemount’s results driven by a 38% decrease in sales pricing and lower sales volumes.

Corporate and Other Adjusted EBITDA decreased during the nine months ended September 30, 2023 compared to the same period in the prior year due to unfavorable variances in Middlemount’s results driven by a 33% decrease in sales pricing and lower sales volumes, offset by favorable trading results ($28.4 million) and revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15.

(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);

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 the unfavorable net impact of foreign currency rate changes ($15.0 million).

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

2024 2023 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Adjusted EBITDA (1)

4 unchanged sentences

Asset impairment — (2.0) 2.0 100 %

Provision for NARM and Shoal Creek loss (3.3) — (3.3) n.m.

(37.0) — (37.0) n.m.

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

Changes in amortization of basis difference related to equity affiliates 0.4 0.3 0.1 33 %

2 unchanged sentences

Interest income 19.2 13.1 6.1 47 %

Unrealized gains (losses) on derivative contracts related to forecasted sales

Unrealized gains on derivative contracts related to forecasted sales

— 118.7 (118.7) (100) %

Unrealized (losses) gains on foreign currency option contracts (0.5) (1.4) 0.9 64 % 0.1 (4.4) 4.5 102 %

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

Take-or-pay contract-based intangible recognition 0.7 0.6 0.1 17 %

5 unchanged sentences

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

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

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

2024 2023 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal $ (27.6) $ (23.8) $ (3.8) (16) %

6 unchanged sentences

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

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

2023 2022 2023 2022

Three Months Ended March 31,

Seaborne Thermal $ 2.10 $ 2.17

2 unchanged sentences

Thermal 1.55 1.21

The decrease in the weighted-average depletion rate per ton for the Seaborne Thermal segment during the three and nine months ended September 30, 2023 compared to the same periods in the prior year reflects the impact of volume and mix variances across the segment.

The changes in the weighted-average depletion rate per ton for the Seaborne Metallurgical segment during the three and nine months ended September 30, 2023 compared to the same periods in the prior year reflect the impact of volume and mix variances across the segment.

Provision for NARM and Shoal Creek Loss.

Provisions of $3.3 million and $37.0 million, respectively, were recorded during the three and nine months ended September 30, 2023 for losses and ongoing incremental repair costs related to the events at NARM and the Shoal Creek Mine, as discussed in Note 15.

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

Interest Expense.

The decrease in interest expense during the three and nine months ended September 30, 2023 primarily reflects the impacts of debt retirements completed by the Company during 2022 as further described in Note 9.

“Long-term Debt” to the accompanying unaudited condensed consolidated financial statements and Note 10.

“Long-term Debt” to the Annual Report on Form 10-K for the year ended December 31, 2022.

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.

Net Loss on Early Debt Extinguishment.

The losses recognized during the nine months ended September 30, 2023 were primarily related to the Company’s terminated letter of credit facility as further discussed in Note 12.

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.

The losses recognized during the prior year periods were primarily related to the redemption of existing notes during the periods as further described in Note 9.

“Long-term Debt” to the accompanying unaudited condensed consolidated financial statements and Note 10.

“Long-term Debt” to the Annual Report on Form 10-K for the year ended December 31, 2022.

Interest Income.

The increase in interest income during the three and nine months ended September 30, 2023 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.

Based upon projected cash balances and interest rates, the Company anticipates significantly higher interest income throughout 2023 as compared to the prior year.

Unrealized Gains (Losses) on Derivative Contracts Related to Forecasted Sales.

Unrealized gains (losses) primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales.

For additional information, refer to Note 6.

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

Unrealized (Losses) Gains on Foreign Currency Option Contracts.

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

For additional information, refer to Note 6.

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

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.

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.

Income Tax Provision.

The increase in the income tax provision during the three months ended September 30, 2023 compared to the same period in the prior year was primarily due to the release of a valuation allowance related to Australian net operating losses during the fourth quarter of 2022, partially offset by lower pretax income.

The increase in the income tax provision during the nine months ended September 30, 2023 compared to the same period in the prior year was primarily due to an increase in pretax income and the release of a valuation allowance related to Australian net operating losses during the fourth quarter of 2022.

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.

Refer to Note 8.

2 unchanged sentences

The following table presents net income attributable to common stockholders:

Three Months Ended September 30, (Decrease) Increase

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

Three Months Ended March 31, (Decrease) Increase

2024 2023 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Income from continuing operations, net of income taxes $ 45.7 $ 284.1 $ (238.4) (84) %

Income (loss) from discontinued operations, net of income taxes 2.5 (0.8) 3.3 413 % (0.1) (2.3) 2.2 96 %

Loss from discontinued operations, net of income taxes (0.7) (1.3) 0.6 46 %

Net income 45.0 282.8 (237.8) (84) %

1 unchanged sentence

Net income attributable to common stockholders $ 39.6 $ 268.5 $ (228.9) (85) %

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

The increase in the results from discontinued operations, net of income taxes during the three and nine months ended September 30, 2023 compared to the same periods in the prior year was primarily due to the gain recognized on the settlement of the Patriot federal black lung liabilities, as discussed in Note 13.

“Commitments and Contingencies” in the accompanying unaudited condensed consolidated financial statements.

Net Income Attributable to Noncontrolling Interests.

The increase in the results attributable to noncontrolling interests during the three and nine months ended September 30, 2023 compared to the same periods in the prior year was primarily due to stronger 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 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.

Diluted Earnings per Share (EPS)

The following table presents diluted EPS:

Three Months Ended September 30, (Decrease) Increase

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

Three Months Ended March 31, Decrease

2024 2023 $ %

1 unchanged sentence

Income from continuing operations $ 0.30 $ 1.69 $ (1.39) (82) %

Income (loss) from discontinued operations 0.02 (0.01) 0.03 300 % — (0.02) 0.02 100 %

Loss from discontinued operations (0.01) (0.01) — — %

Net income attributable to common stockholders $ 0.29 $ 1.68 $ (1.39) (83) %

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 149.9 million and 161.9 million for the three months ended September 30, 2023 and 2022, respectively, and 156.7 million and 155.6 million for the nine months ended September 30, 2023 and 2022, respectively.

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.

Reconciliation of Non-GAAP Financial Measures

1 unchanged sentence

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,

2023 2022 2023 2022

Three Months Ended March 31,

(Dollars in millions)

1 unchanged sentence

Depreciation, depletion and amortization

82.3 80.7 239.2 227.4

Asset retirement obligation expenses

15.4 13.1 46.3 40.8

Restructuring charges

0.9 1.0 3.0 2.8

Asset impairment

— 1.7 2.0 1.7

Provision for NARM and Shoal Creek loss 3.3 — 37.0 —

Provision for NARM loss 1.8 —

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

Interest expense

13.8 33.8 45.5 110.8

Net loss on early debt extinguishment — 6.8

1 unchanged sentence

(19.2) (13.1)

Unrealized (gains) losses on derivative contracts related to forecasted sales — (90.4) (159.0) 235.1

Unrealized losses (gains) on foreign currency option contracts 0.5 1.4 (0.1) 4.4

Unrealized gains on derivative contracts related to forecasted sales — (118.7)

Unrealized losses on foreign currency option contracts 5.7 2.2

Take-or-pay contract-based intangible recognition

(0.7) (0.8) (1.9) (2.2)

Income tax provision 20.1 118.0

2 unchanged sentences

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,

2023 2022 2023 2022

Three Months Ended March 31,

(Dollars in millions)

1 unchanged sentence

$ 814.2 $ 846.6

Unrealized (losses) gains on foreign currency option contracts (0.5) (1.4) 0.1 (4.4)

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

Take-or-pay contract-based intangible recognition

0.7 0.8 1.9 2.2

Net periodic benefit credit, excluding service cost (10.1) (9.7)

1 unchanged sentence

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

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

2023 2022 2023 2022

Three Months Ended March 31,

(Dollars in millions)

8 unchanged sentences

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

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

Three Months Ended September 30, 2022

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

(Amounts in millions, except per ton data)

Tons sold 3.7 1.8 22.3 4.8

Revenue $ 353.2 $ 310.7 $ 290.5 $ 261.4

Total Reporting Segment Costs 182.0 197.5 252.6 188.7

Adjusted EBITDA $ 171.2 $ 113.2 $ 37.9 $ 72.7

Revenue per Ton $ 95.54 $ 179.77 $ 12.99 $ 54.58

Costs per Ton 49.22 114.32 11.29 39.40

Adjusted EBITDA Margin per Ton $ 46.32 $ 65.45 $ 1.70 $ 15.18

Nine Months Ended September 30, 2023

Three Months Ended March 31, 2024

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

7 unchanged sentences

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

Nine Months Ended September 30, 2022

Three Months Ended March 31, 2023

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

8 unchanged sentences

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

plus/minus changes to restricted cash and collateral (excluding one-time effects of the recent surety agreement amendment) and other anticipated expenditures.

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, 2023

Three Months Ended March 31, 2024

(Dollars in millions)

11 unchanged sentences

National Ambient Air Quality Standards (NAAQS) .

The Clean Air Act (CAA) requires the United States Environmental Protection Agency (EPA) to review national ambient air quality standards every five years to determine whether revision to current standards are appropriate.

On January 6, 2023, the EPA proposed to lower the level of the primary standard for particulate matter (PM).

If enacted as proposed, this rule could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies, thereby increasing the cost of utilizing fossil fuels for electric generation and industrial uses.

On August 18, 2023, the EPA announced that it was no longer engaging in a reconsideration of the 2020 ozone NAAQS that it had initiated on October 28, 2021, but rather will “wrap the EPA’s reconsideration process” into a new five-year periodic review of the ozone NAAQS.

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

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 D.C.

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

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:

(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 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.

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 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.

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, 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.

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 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.

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.

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 March 2026.

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.

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 .

7 unchanged sentences

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

The rule has been challenged in several U.S.

Courts of Appeal, including the U.

Court of Appeals for the D.C.

Circuit (D.C.

EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired Electricity Utility Generating Units (EGUs) .

On May 23, 2023, the EPA proposed a rule that includes five separate actions regarding the control of greenhouse gas (GHG) emissions from fossil fuel-fired power plants.

The EPA proposed to revise New Source Performance Standards (NSPS) to address carbon dioxide (CO 2 ) emissions from both new fossil fuel-fired steam generating units and new fossil fuel-fired stationary combustion turbines.

The EPA also proposed emission guidelines for existing coal- and oil/gas-fired steam generating units and for existing stationary combustion turbines.

Finally, in the same proposed rule, the EPA proposed to repeal the Affordable Clean Energy Rule, promulgated by the EPA in 2019 and vacated by the D.C.

Circuit in 2021.

If finalized in the form proposed, the regulations would require existing fossil fuel-fired steam generating units (primarily coal units) to use carbon capture and sequestration (CCS) with 90% capture of CO 2 if they plan to operate after December 31, 2039.

These units, however, may also pursue a different compliance pathway that is based on making a commitment to cease operations.

The proposed rule also would require existing stationary combustion turbines over 300 megawatts with a capacity factor greater than 50% (primarily units using natural gas) to either utilize CCS by 2035 or pursue a pathway that would require co-firing with 30% low-GHG hydrogen by 2032, followed by co-firing with 96% low-GHG hydrogen by 2038.

The EPA is also taking comments with regard to imposing standards for stationary combustion turbines under 300 megawatts.

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

The EPA, however, proposes that such plans generally be no less stringent than the emission reductions that would be obtained under the EPA’s guidelines.

Existing steam generating units must start complying with the EPA’s proposed standards by January 1, 2030 and existing stationary combustion turbines by either January 1, 2032 or January 1, 2035 depending on what option for compliance is chosen.

Finally, as part of the proposed rule, any newly constructed steam electric generating unit or newly constructed stationary combustion turbine would be subject to GHG standards as of May 23, 2023, the date of the proposed rule.

In addition, as proposed, any new fossil-fuel steam generating unit will need to comply with partial CCS upon startup as well as a requirement for 90% CO 2 reduction through CCS by 2040.

Any new or reconstructed stationary combustion turbine will be subject to different standards based on whether it is considered low load, intermediate load or a base load unit.

If finalized as proposed, the GHG NSPS could have substantial impacts on the use of coal, oil and natural gas for the generation of electricity.

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%.

The EPA is also proposing to require the use of continuous emissions monitoring systems, and to revise other requirements such as those applicable to the startup of generating units.

Under the proposed rule, the EPA estimated that approximately 500 megawatts of coal-fired capacity would retire by 2028.

The public comment period on the proposals ended on June 23, 2023.

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.

On March 29, 2023, the EPA proposed a rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate.

If the proposed rule is finalized in substantially the same form, the revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants.

Concurrently, the EPA issued a direct final rule which extended the deadline through June 2023 for steam electric power plants to commit to the permanent cessation of coal combustion by December 31, 2028 in exchange for less stringent wastewater discharge requirements during the interim.

The direct final rule could influence fuel switching or additional coal generating unit retirements by the end of 2028.

Clean Water Act (CWA) Definition of “Waters of the United States”.

On January 18, 2023, the EPA and the U.S.

Army Corp of Engineers finalized a revised definition of “Waters of the United States” to clarify the scope of federal regulatory authority under the CWA.

Several courts preliminarily enjoined that rule in 27 states.

In addition, on May 25, 2023, the Supreme Court of the United States issued its decision in Sackett v.

21-454, which significantly narrowed the scope of federal regulatory authority over wetlands and non-navigable waters.

The agencies finalized a rule on September 8, 2023, to conform key aspects of the regulatory definition to the Sackett decision.

Pending litigation over the January 2023 definition is set to resume, as the September 2023 final rule did not address many of the claims at issue in those cases.

CWA Water Quality Certification Rule .

Through the CWA Section 401 certification program, state and tribal regulators have approval authority over federal permits or licenses that might result in a discharge to their waters.

State and tribal regulators consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.

The EPA issued a final rule in 2020 that could limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances.

On September 27, 2023, the EPA finalized a superseding rule that would expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements.

That rule takes effect on November 27, 2023.

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 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.

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).

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 the 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 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 the 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.

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;

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

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

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

Court of Appeals for the Eighth Circuit.

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

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

Regulatory Matters - Australia

New South Wales Coal Directions.

The State of New South Wales (NSW) 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 have been amended at various dates.

The most recent directions require 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 impose additional reporting obligations to demonstrate compliance.

While these directions are currently not anticipated to significantly impact the Wambo Mines or the Wilpinjong Mine, the nature and extent of those obligations and associated reporting requirements may continue to evolve if further directions are issued.

Industrial Relations .

A national industrial relations system, the Fair Work Act and National Employment Standards, administered by the federal government applies to all employers and employees.

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.

On October 27, 2022, the Fair Work Legislation Amendment (Secure Jobs, Better Pay) Bill 2022 was tabled in the Australian Federal Parliament.

The bill proposed a number of changes relating to gender equity, flexible working arrangements, job security and bargaining amongst other matters.

The Australian Federal Parliament passed the bill amending the Fair Work Act.

The legislation introduced several changes to workplace laws in Australia including changes to enterprise agreement making and termination, to when industrial action can be taken and to access to multi-employer bargaining.

In addition, employers will no longer be able to employ individuals on a fixed-term contract for more than two years, and access to flexible working arrangements for employees has been expanded.

A number of measures aimed at addressing the gender pay gap have also been introduced.

In early September 2023, the Fair Work Legislation Amendment (Closing Loopholes) Bill 2023 was presented to the Australian Federal Parliament.

The bill contemplates amendments to the Fair Work Act 2009 in relation to casual employment;

regulated labor hire arrangement orders;

workplace delegates’ rights exemptions to waive entry requirements for suspected underpayment and increasing maximum penalties for underpayments;

introduction of a criminal offense for wage theft;

and increased powers for unions.

The bill is currently being considered by a Senate Committee for Education and Employment for inquiry and report by February 1, 2024.

If these amendments pass it is likely to result in increased labor and compliance costs.

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.

On March 27, 2023, the Australian Federal Government announced several additional measures in the Safeguard Mechanism (Crediting) Amendments Bill 2023 which was introduced and passed both Houses of Parliament on March 30, 2023.

The legislation introduces a cap on overall net emissions from facilities covered by the scheme through 2030.

The legislation also sets a cap of net zero tonnes carbon dioxide equivalent for any financial year beginning after June 30, 2049.

In addition, if the Minister for Environment and Water grants an approval under the Environment Protection and Biodiversity Conservation Act 1999 (Cth) (EPBC Act) to a new or expanded facility covered by the scheme, the Minister will be required to give an estimate of the facility's Scope 1 emissions to the Minister for Climate Change, the Climate Change Secretary and the Climate Change Authority for assessment against scheme targets.

The legislation went into effect on July 1, 2023.

The potential impact of these reforms to Peabody’s Australian operations is under review.

New South Wales Royalty .

In New South Wales, the royalty applicable to coal is charged as a percentage of the value of production (total revenue less allowable deductions).

This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines.

As part of its 2023/24 state budget the newly elected New South Wales government announced that from July 1, 2024 it would be increasing each of these rates by 2.6% to 8.8% for deep underground mines, 9.8% for underground mines and 10.8% for open-cut mines.

The future impacts of this royalty rate rise on Peabody’s NSW mining operations is being assessed.

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.

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 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.

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.

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.

Risks Related to Global Climate Change

4 unchanged sentences

The Company’s primary source of cash is proceeds from the sale of its coal production to customers.

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

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.

2 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 September 30, 2023, the Company’s cash balances totaled $988.5 million, including approximately $505.6 million held by Australian subsidiaries, $466.3 million held by U.S.

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.

3 unchanged sentences

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

During the nine months ended September 30, 2023, the Company repatriated approximately $250 million through intercompany dividends.

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

The Company’s available liquidity decreased from $1,317.8 million as of December 31, 2022 to $1,068.3 million as of September 30, 2023.

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

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.

Available liquidity was comprised of the following:

September 30, 2023 December 31, 2022

March 31, 2024 December 31, 2023

(Dollars in millions)

Cash and cash equivalents $ 855.7 $ 969.3

Credit facility availability — 3.5

Revolving credit facility availability 221.0 —

Accounts receivable securitization program availability 80.7 90.4

1 unchanged sentence

Capital Returns to Shareholders

The Company repurchased approximately 12.6 million shares of its common stock for $266.6 million and paid dividends of $20.7 million during the nine months ended September 30, 2023.

From October 1, 2023 through October 27, 2023, the Company repurchased an additional 1.1 million shares for $27.3 million.

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.

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 agreement, the Company was required to post collateral on a periodic basis through December 31, 2025.

Prior to the April 2023 amendment, the Company had posted cumulative collateral of $557.8 million, primarily in the form of letters of credit.

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 represented a negotiated increase from the uncapped cumulative collateral amount prior to the amendment and will vary prospectively as bonding levels increase or decrease.

The amendment also removed restrictions on the payment of dividends and share repurchases, and extended the agreement through December 31, 2026.

In order to maintain the new maximum collateral standstill, 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 $586.1 million at September 30, 2023.

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

The amendment 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 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, which commenced for the second quarter of 2023.

The Company granted second liens on $200.0 million of mining equipment under the original agreement, which remain in force under the April 2023 amendment.

The Company is in compliance with such requirements at March 31, 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 credit agreement which, as amended, provided for $237.2 million of capacity for irrevocable standby letters of credit (LC Facility).

The $223.8 million of letters of credit that were outstanding under the LC Facility at March 31, 2023 were cancelled upon its termination and, in certain cases, replaced by cash-collateralized letters of credit or letters of credit issued under the Company’s accounts receivable securitization program.

Collateralized Letter of Credit Agreement

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

Credit Support Facilities

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

2 unchanged sentences

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

At September 30, 2023, letters of credit of $167.0 million were outstanding under the agreement, which were collateralized by cash of $172.0 million.

Margin Requirements

From time to time, the Company enters into hedging arrangements, including economic hedging arrangements, to manage various risks, including coal price volatility.

Most hedging arrangements require the Company to post margin with its clearing broker based on the value of the related instruments and other credit factors.

If the fair value of its exchange-cleared hedge portfolio moves significantly, the Company could be required to post additional margin, which could negatively impact its liquidity.

During the nine months ended September 30, 2023, the Company’s coal derivative contracts with margin requirements were settled and margin postings declined from $255.5 million at December 31, 2022 to zero at September 30, 2023.

The Company’s total indebtedness as of September 30, 2023 and December 31, 2022 is presented in the table below.

Debt Instrument (defined below, as applicable) September 30, 2023 December 31, 2022

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.

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.

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

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

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

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

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.

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.

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.

The 2024 Credit Agreement is secured by substantially all assets of the Company and its U.S.

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

(Dollars in millions)

4 unchanged sentences

Long-term debt $ 323.3 $ 320.7

During 2022, the Company utilized various methods allowable or required under its then-existing debt agreements to retire all of its senior secured long-term debt, leaving only the 2028 Convertible Notes, which are further described below, and various finance lease obligations outstanding at December 31, 2022.

The Company’s remaining indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at September 30, 2023, of approximately $5 million in 2023, $23 million in 2024, $16 million in 2025, $13 million in 2026, $12 million in 2027 and $325 million thereafter.

Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $56.7 million and $104.2 million during the nine months ended September 30, 2023 and 2022, respectively.

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.

2028 Convertible Notes

1 unchanged sentence

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

The Company used the proceeds of the offering of the 2028 Convertible Notes and available cash to redeem $62.6 million of senior secured notes maturing in 2024 and $257.4 million of senior secured notes maturing in 2025, and to pay related premiums, fees and expenses relating to the offering and redemptions.

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

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

The 2028 Convertible Notes bore interest from March 1, 2022 at a rate of 3.250% per year payable semi-annually in arrears on March 1 and September 1 of each year, beginning on September 1, 2022.

During the first three quarters of 2023, 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 2023, and will not be similarly convertible during the fourth quarter of 2023.

The now-terminated LC Facility had an original capacity of $324.0 million and was subsequently amended at various dates to reduce its capacity and effect certain other changes, including in February 2023 to reduce capacity by $65.0 million, accelerate the expiration date to December 31, 2023 from December 31, 2024, and eliminate the prepayment premium due upon any reduction of commitments thereunder prior to July 29, 2023.

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.

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 secured overnight financing rate.

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 September 30, 2023, the Company had no outstanding borrowings and $107.4 million of letters of credit outstanding under the program, which were primarily in support of portions of the Company’s reclamation obligations.

The Company was not required to post cash collateral under the securitization program at September 30, 2023.

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.

Covenant Compliance

The Company was compliant with all relevant covenants under its debt and other finance agreements at September 30, 2023.

The April 2023 termination of the Company’s credit agreement and related letter of credit facility, as described in Note 12.

“Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, eliminated the related compliance requirements as of March 31, 2023 and prospectively.

The following table summarizes the Company’s cash flows for the nine months ended September 30, 2023 and 2022, 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 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.

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,

Three Months Ended March 31,

(Dollars in millions)

Net cash provided by operating activities $ 119.0 $ 386.3

Net cash (used in) provided by investing activities (174.6) 61.1

Net cash used in investing activities (75.2) (58.5)

Net cash used in financing activities (127.7) (39.0)

4 unchanged sentences

Operating Activities.

The increase in net cash provided by operating activities for the nine months ended September 30, 2023 compared to the same period in the prior year was primarily driven by the receipt of cash in the current year and posting of cash in the prior year related to variation margin requirements associated with derivative financial instruments ($484.0 million) and the year-over-year increase in operating cash flow from working capital fluctuations ($296.4 million), partially offset by an increase in cash used for collateral requirements ($109.1 million) and cash used to settle disputed black lung claims ($72.0 million) with the remaining variance primarily due to lower cash generated from mining operations.

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 prior year receipt of cash related to variation margin requirements associated with derivative financial instruments ($149.2 million);

and lower cash generated from mining operations, partially offset by a decrease in cash used for collateral requirements ($197.2 million).

Investing Activities.

The increase in net cash used in investing activities for the nine months ended September 30, 2023 compared to the same period in the prior year was driven by lower cash receipts from Middlemount ($152.3 million), higher capital expenditures and the payment of capital accruals ($82.7 million) including capital expenditures for the redevelopment of the North Goonyella Mine ($58.8 million), and lower cash receipts from the disposal of assets ($16.7 million).

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).

Financing Activities.

The increase in net cash used by financing activities for the nine months ended September 30, 2023 compared to the same period in the prior year was driven by the cash proceeds from common stock and debt issuances in the prior year ($222.0 million and $545.0 million, respectively) and common stock repurchases and dividends paid in the current year ($264.0 million and $20.7 million, respectively), partially offset by lower repayments of long-term debt ($839.4 million) in the current year.

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).

Off-Balance-Sheet Arrangements

4 unchanged sentences

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

September 30, 2023 December 31, 2022

March 31, 2024

Reclamation Support Other Support (1)

Total Reclamation Support Other Support (1)

(Dollars in millions)

3 unchanged sentences

1,015.7 206.7 1,222.4

Letters of credit in support of surety

Letters of credit in support of surety bonds (3)

(53.6) (14.4) (68.0)

3 unchanged sentences

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

At September 30, 2023, the Company had total asset retirement obligations of $753.9 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.

Not presented in the above table is approximately $866.1 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at September 30, 2023, as described in Note 12.

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.

“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, mandatory repurchases of credit facility capacity and amounts held directly with beneficiaries which are not supported by surety bonds.

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.

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.

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.

Critical Accounting Policies and Estimates

5 unchanged sentences

Actual results may differ from these estimates.

At September 30, 2023, the Company identified certain assets with an aggregate carrying value of approximately $388 million in its Powder River Basin and Other U.S.

Thermal segments whose recoverability is most sensitive to customer demand and customer concentration risk.

The Company conducted a review of those assets as of September 30, 2023 and determined that no impairment charges were necessary as of that date.

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

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

The Company’s critical accounting policies and estimates are discussed in Part II, Item 7.

“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 September 30, 2023, 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, 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

1 unchanged sentence

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