What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-08-03 compared with 2023-05-04 · 309 added, 303 removed, 346 unchanged (64% 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, and 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” and Item 3.

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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.

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

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

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In 2022, the Company produced and sold 122.9 million and 123.7 million tons of coal, respectively, from continuing operations.

At March 31, 2023, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

At June 30, 2023, 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.

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

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

Thermal Mining and Corporate and Other.

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

Thermal and Corporate and Other.

Refer to Note 13.

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

Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 index thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended March 31, 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 March 31, 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 June 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 Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.

In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended March 31, 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 June 30, 2023 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors.

Such long-term contracts in the U.S.

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

High Low Average March 31, 2023 April 28, 2023

High Low Average June 30, 2023 July 28, 2023

Premium HCC (1)

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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 three months ended March 31, 2023 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, the three months ended March 31, 2023 were characterized by ongoing volatility as global macroeconomic turbulence counteracted improving demand and further weather-induced supply disruptions in Australia.

Several steelmakers announced blast furnace capacity restarts in the three months ended March 31, 2023, as growth in forward orders drives improvements to steel prices and margins.

This is supportive for seaborne metallurgical coal demand in the coming period.

Furthermore, China has ended its unofficial ban of Australian coal imports providing increased market depth for Australian products, especially for Premium HCC.

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

Within the seaborne metallurgical coal market, the six months ended June 30, 2023 were characterized by ongoing volatility as global macroeconomic turbulence combined with seasonal demand and supply fluctuations.

The steel sector showed positive signs in early 2023 with several steelmakers announcing blast furnace capacity restarts;

however ongoing economic uncertainty and multi-year high steel exports from China have dampened the revival and impacted metallurgical coal demand in key markets.

Russian coal remains banned in the European Union, Japan and elsewhere, disrupting natural trade flows and resulting in low priced Russian products being made available to countries, such as China and India, which can continue procurement.

The PCI market remained exceedingly tight during the three months ended March 31, 2023, especially in Europe, where Russia traditionally held dominant market share.

The Company believes energy shortages and the global inflationary environment present a risk to industrial activity in some markets, but the underlying market fundamentals remain constructive with continuing themes of supply tightness, resilient demand and further economic stimulus in China and elsewhere.

Within the seaborne thermal coal market, global thermal coal prices stabilized in March and recently showed improvement amid supply distributions in Colombia and Australia and ongoing robust demand from India and China.

China has ended its unofficial ban of Australian coal imports, providing additional demand for Australian thermal coal.

In China, domestic coal production and renewable generation have been strong to start the year, however, import demand has been higher year-over-year, as overall coal demand has been strong.

Combined with abundant domestic and Mongolian supply, this is further enabling China to readily compete in the international steel market.

Further economic stimulus in China, India and elsewhere, combined with seasonal demand growth is fueling positive sentiment in the market outlook to the end of the year.

Within the seaborne thermal coal market, global thermal coal prices have remained volatile during the quarter ended June 30, 2023 with prices declining from the first quarter.

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

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

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

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

Overall, global thermal coal markets remain turbulent as supply has been disrupted due to logistics and weather issues and lower global natural gas prices.

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

In the United States, overall electricity demand decreased nearly 4% year-over-year, negatively impacted by weather.

Through the three months ended March 31, 2023, electricity generation from thermal coal has declined year-over-year due to low gas prices, and stronger gas and renewable generation despite lower overall electricity demand.

Coal’s share of electricity generation has declined to approximately 15% for the three months ended March 31, 2023, while wind and solar’s combined generation share has increased to 17% and the share of gas generation has increased to 39%.

Coal inventories have increased during the three months ended March 31, 2023, with an increase of approximately 25% or 22 million tons.

During the three months ended March 31, 2023, utility consumption of PRB coal declined approximately 25% compared to the prior year period.

Surety Agreement Amendment

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

Coal’s share of electricity generation has declined to approximately 15% for the six months ended June 30, 2023, while wind and solar’s combined generation share has increased to 17% and the share of natural gas generation has increased to 40%.

Coal inventories have increased during the six months ended June 30, 2023, with an increase of approximately 50%.

During the six months ended June 30, 2023, utility consumption of PRB coal declined approximately 25% compared to the prior year period.

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.

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

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

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 and Part II, Item 2.

“Unregistered Sales of Equity Securities and Use of Proceeds” 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.

All mine personnel were safely evacuated from the mine.

The Mine Safety and Health Administration (MSHA) has allowed mine rescue-equipped personnel into the mine at various times to assess the situation.

On April 26, 2023, MSHA approved a temporary sealing program which was completed on April 28, 2023, and the Company continues to monitor air quality in the affected underground area.

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 three and six months ended June 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.

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 six months ended June 30, 2023, the Company recorded a provision for loss of $5.0 million related to the tornado damage.

The provision includes $4.0 million for materials and supplies inventories and $1.0 million for buildings and equipment.

This provision represents the best estimate of potential loss based on the assessments made to date.

The Company continues to assess the loss and anticipates that incremental repair costs will be recorded in future periods.

Results of Operations

Three Months Ended March 31, 2023 Compared to the Three Months Ended March 31, 2022

The increase in results from continuing operations, net of income taxes for the three months ended March 31, 2023 compared to the same period in the prior year ($403.9 million), was primarily driven by higher revenue ($672.6 million) due to higher realized prices and volumes.

This favorable variance was partially offset by higher operating costs and expenses ($147.6 million), which reflect increased sales price sensitive costs and inflationary pressures for commodities, materials, services, repairs and labor;

and a higher income tax provision ($119.0 million).

Adjusted EBITDA for the three months ended March 31, 2023 reflected a year-over-year increase of $63.1 million.

Three and Six Months Ended June 30, 2023 Compared to the Three and Six Months Ended June 30, 2022

The decrease in income from continuing operations, net of income taxes for the three months ended June 30, 2023 compared to the same period in the prior year ($207.2 million), was driven by a higher tax provision ($62.9 million);

lower revenue ($53.1 million) primarily due to a 42% decrease in metallurgical pricing;

decreased results from equity affiliates ($46.4 million);

higher operating costs and expenses ($36.4 million);

and a provision of $33.7 million related to the losses at NARM and Shoal Creek.

This unfavorable variance was partially offset by lower net interest expense ($46.8 million).

The increase in income from continuing operations, net of income taxes for the six months ended June 30, 2023 compared to the same period in the prior year ($196.7 million), was primarily driven by higher revenue ($619.5 million) due to net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales and lower net interest expense ($97.1 million).

This favorable variance was partially offset by higher operating costs and expenses ($184.0 million), which reflect increased sales price sensitive costs and inflationary pressures for materials, services, repairs and labor;

a higher income tax provision ($181.9 million);

decreased results from equity affiliates ($89.3 million);

and a provision of $33.7 million related to the losses at NARM and Shoal Creek.

Adjusted EBITDA for the three and six months ended June 30, 2023 reflected year-over-year decreases of $219.6 million and $156.5 million, respectively.

The following table presents tons sold by operating segment:

Three Months Ended March 31, (Decrease) Increase

2023 2022 Tons %

(Tons in millions)

Seaborne Thermal Mining 3.6 3.8 (0.2) (5) %

Seaborne Metallurgical Mining

1.3 1.2 0.1 8 %

Powder River Basin Mining 22.0 20.6 1.4 7 %

Thermal Mining 4.5 4.2 0.3 7 %

Three Months Ended June 30, Increase (Decrease)

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

2023 2022 Tons % 2023 2022 Tons %

(Tons in millions) (Tons in millions)

Seaborne Thermal 4.0 4.0 — — % 7.6 7.8 (0.2) (3) %

Seaborne Metallurgical 2.0 1.6 0.4 25 % 3.3 2.8 0.5 18 %

Powder River Basin 18.9 18.5 0.4 2 % 40.9 39.1 1.8 5 %

Thermal 3.8 4.4 (0.6) (14) % 8.3 8.6 (0.3) (3) %

Total tons sold from operating segments 28.7 28.5 0.2 1 % 60.1 58.3 1.8 3 %

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The following table presents supplemental financial data by operating segment:

Three Months Ended March 31, Increase

Three Months Ended June 30, Increase

(Decrease) Six Months Ended June 30, Increase

2023 2022 $ % 2023 2022 $ %

Revenue per Ton - Mining Operations (1)

Revenue per Ton (1)

Seaborne Thermal $ 100.59 $ 87.37 $ 13.22 15 % $ 98.81 $ 77.52 $ 21.29 27 %

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Thermal 53.63 51.40 2.23 4 % 54.23 49.96 4.27 9 %

Costs per Ton - Mining Operations (1)(2)

Costs per Ton (1)(2)

Seaborne Thermal $ 50.88 $ 43.85 $ 7.03 16 % $ 50.94 $ 43.33 $ 7.61 18 %

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Thermal 39.71 37.25 2.46 7 % 40.22 36.90 3.32 9 %

Adjusted EBITDA Margin per Ton - Mining Operations (1)(2)

Adjusted EBITDA Margin per Ton (1)(2)

Seaborne Thermal $ 49.71 $ 43.52 $ 6.19 14 % $ 47.87 $ 34.19 $ 13.68 40 %

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The following table presents revenue by reporting segment:

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

2023 2022 $ %

(Dollars in millions)

Seaborne Thermal Mining $ 346.5 $ 251.2 $ 95.3 38 %

Seaborne Metallurgical Mining

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

2023 2022 $ % 2023 2022 $ %

Powder River Basin Mining 305.3 251.2 54.1 22 %

Thermal Mining 249.4 203.1 46.3 23 %

(Dollars in millions) (Dollars in millions)

Seaborne Thermal $ 399.5 $ 354.9 $ 44.6 13 % $ 746.0 $ 606.1 $ 139.9 23 %

Seaborne Metallurgical 372.5 533.8 (161.3) (30) % 660.9 855.1 (194.2) (23) %

Powder River Basin 259.7 229.7 30.0 13 % 565.0 480.9 84.1 17 %

Thermal 199.9 224.9 (25.0) (11) % 449.3 428.0 21.3 5 %

Corporate and Other 37.2 (21.4) 58.6 274 % 211.6 (356.8) 568.4 159 %

Revenue $ 1,268.8 $ 1,321.9 $ (53.1) (4) % $ 2,632.8 $ 2,013.3 $ 619.5 31 %

Seaborne Thermal Mining.

Segment revenue increased during the three months ended March 31, 2023 compared to the same period in the prior year due to favorable realized prices ($68.7 million) and favorable mix variances ($26.6 million) which offset unfavorable volumes.

Seaborne Metallurgical Mining.

Segment revenue decreased during the three months ended March 31, 2023 compared to the same period in the prior year due to unfavorable realized prices ($39.8 million), partially offset by favorable volumes ($6.9 million).

Powder River Basin Mining.

Segment revenue increased during the three months ended March 31, 2023 compared to the same period in the prior year due to favorable realized prices ($33.3 million) and favorable volumes ($20.8 million) resulting from improved rail performance.

Thermal Mining.

Segment revenue increased during the three months ended March 31, 2023 compared to the same period in the prior year due to favorable realized prices ($28.4 million) and favorable volumes ($17.9 million).

Seaborne Thermal.

Segment revenue increased during the three and six months ended June 30, 2023 compared to the same periods in the prior year due to favorable mix variances ($35.5 million and $66.3 million, respectively) which offset unfavorable volumes and favorable realized prices ($9.1 million and $73.6 million, respectively).

Seaborne Metallurgical.

Segment revenue decreased during the three and six months ended June 30, 2023 compared to the same periods in the prior year due to unfavorable realized prices ($204.0 million and $226.8 million, respectively) and unfavorable volumes from the Shoal Creek Mine resulting from the fire in the first quarter of 2023 ($121.3 million and $124.6 million, respectively), offset by favorable volumes from the Australian operations ($164.0 million and $157.2 million, respectively).

Powder River Basin.

Segment revenue increased during the three and six months ended June 30, 2023 compared to the same periods in the prior year due to favorable realized prices ($25.9 million and $65.2 million, respectively) and favorable volumes ($4.1 million and $18.9 million, respectively) resulting from improved rail performance.

Segment revenue decreased during the three months ended June 30, 2023 compared to the same period in the prior year due to unfavorable volumes ($41.4 million) resulting from decreased demand, offset by favorable realized prices ($16.4 million).

Segment revenue increased during the six months ended June 30, 2023 compared to the same period in the prior year due to favorable realized prices ($43.5 million), offset by unfavorable volumes ($22.2 million) resulting from decreased demand.

Corporate and Other.

Segment revenue increased during the three months ended March 31, 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 ($419.7 million);

higher results from trading activities ($72.7 million) due to higher margins recognized on the physical sale of coal and lower net realized losses on derivative contracts related to forecasted coal sales;

Segment revenue increased during the three months ended June 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 ($64.8 million), partially offset by lower results from trading activities ($6.6 million).

Segment revenue increased during the six months ended June 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 ($484.5 million);

higher results from trading activities ($63.9 million) primarily due to lower net realized losses on derivative contracts related to forecasted coal sales;

and revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 14.

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

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

2023 2022 $ %

(Dollars in millions)

Seaborne Thermal Mining

$ 164.0 $ 90.5 $ 73.5 81 %

Seaborne Metallurgical Mining

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

2023 2022 $ % 2023 2022 $ %

Powder River Basin Mining 35.8 7.6 28.2 371 %

Thermal Mining 64.2 50.0 14.2 28 %

(Dollars in millions) (Dollars in millions)

Seaborne Thermal $ 197.5 $ 176.8 $ 20.7 12 % $ 361.5 $ 267.3 $ 94.2 35 %

Seaborne Metallurgical 102.5 299.7 (197.2) (66) % 193.3 480.7 (287.4) (60) %

Powder River Basin 26.2 (2.0) 28.2 1,410 % 62.0 5.6 56.4 1,007 %

Thermal 51.9 61.9 (10.0) (16) % 116.1 111.9 4.2 4 %

Corporate and Other (19.9) 41.4 (61.3) (148) % 15.9 39.8 (23.9) (60) %

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

Seaborne Thermal Mining.

Segment Adjusted EBITDA increased during the three months ended March 31, 2023 compared to the same period in the prior year as a result of higher realized prices net of sales sensitive costs ($64.1 million) and favorable mix variances ($26.6 million), partially offset by higher commodity pricing ($8.9 million) and higher port and demurrage costs ($7.1 million).

Seaborne Metallurgical Mining.

Segment Adjusted EBITDA decreased during the three months ended March 31, 2023 compared to the same period in the prior year due to unfavorable operational costs ($50.4 million) resulting from wet weather impacts at the Coppabella and Moorvale Mines and geological conditions at the Shoal Creek Mine and lower realized prices net of sales sensitive costs ($43.8million).

Powder River Basin Mining.

Segment Adjusted EBITDA increased during the three months ended March 31, 2023 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($22.1 million);

decreased overburden removal costs ($11.0 million);

and favorable volumes ($7.3 million) resulting from improved rail performance.

The increases were partially offset by higher costs for materials, services, repairs and labor ($9.7 million) due in part to timing, increased repairs for an aging equipment fleet and inflationary pressures on materials and services.

Thermal Mining.

These increases were offset by higher costs for materials, services, repairs and labor ($16.9 million) due in part to increased equipment repairs and headcount resulting from increasing volume demands and inflationary pressures on materials and services.

Seaborne Thermal.

Segment Adjusted EBITDA increased during the three and six months ended June 30, 2023 compared to the same periods in the prior year as a result of favorable mix variances ($23.8 million and $53.6 million, respectively) and higher realized prices net of sales sensitive costs ($8.6 million and $68.8 million, respectively), partially offset by unfavorable operational costs ($11.5 million and $19.8 million, respectively) resulting from higher costs for repairs, maintenance and labor.

Seaborne Metallurgical.

Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2023 compared to the same periods in the prior year due to lower realized prices net of sales sensitive costs ($199.8 million and $229.7 million, respectively) and unfavorable operational costs ($87.6 million and $137.4 million, respectively) 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, partially offset by favorable volumes ($92.0 million and $87.8 million, respectively).

Powder River Basin.

Segment Adjusted EBITDA increased during the three and six months ended June 30, 2023 compared to the same periods in the prior year due to favorable commodity pricing ($13.3 million and $11.3 million, respectively);

higher realized prices net of sales sensitive costs ($13.2 million and $34.8 million, respectively);

and decreased overburden removal costs (six months, $14.4 million).

The increases were partially offset by higher costs for materials, services, repairs and labor ($0.5 million and $10.0 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 months ended June 30, 2023 compared to the same period in the prior year due to higher costs for materials, services, repairs and labor ($17.0 million) due in part to timing, increased repairs for an aging equipment fleet and inflationary pressures on materials and services and unfavorable volumes ($16.1 million).

These decreases were offset by higher realized prices net of sales sensitive costs ($14.3 million) and favorable commodity pricing ($10.5 million).

Segment Adjusted EBITDA increased during the six months ended June 30, 2023 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($37.1 million) and favorable commodity pricing ($10.6 million), offset by higher costs for materials, services, repairs and labor ($32.6 million) due in part to increased equipment repairs and headcount and inflationary pressures on materials and services and unfavorable volumes ($7.1 million).

Corporate and Other Adjusted EBITDA.

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

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

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

2023 2022 $ % 2023 2022 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Middlemount (1)

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(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 $2.6 million and $20.2 million during the three months ended March 31, 2023 and 2022, respectively.

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 $3.3 million and $23.3 million during the three months ended June 30, 2023 and 2022, respectively, and $5.9 million and $43.5 million during the six months ended June 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 benefited during the three months ended March 31, 2023 compared to the same period in the prior year from favorable trading results ($69.7 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 14.

Corporate and Other Adjusted EBITDA decreased during the three months ended June 30, 2023 compared to the same period in the prior year primarily due to unfavorable variances in Middlemount’s results driven by a 40% decrease in sales pricing and lower sales volumes.

Corporate and Other Adjusted EBITDA decreased during the six months ended June 30, 2023 compared to the same period in the prior year due to unfavorable variances in Middlemount’s results driven by a 29% decrease in sales pricing and lower sales volumes, offset by favorable trading results ($68.6 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 14.

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

This benefit was offset by unfavorable variances in Middlemount’s results due to lower sales pricing and sales volumes.

Income (Loss) From Continuing Operations, Net of Income Taxes

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

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

Income From Continuing Operations, Net of Income Taxes

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

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

2023 2022 $ % 2023 2022 $ %

(Dollars in millions)

(Dollars in millions) (Dollars in millions)

Adjusted EBITDA (1)

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Asset impairment — — — n.m.

(2.0) — (2.0) n.m.

Provision for NARM and Shoal Creek loss (33.7) — (33.7) n.m.

(33.7) — (33.7) n.m.

Changes in amortization of basis difference related to equity affiliates 0.4 0.6 (0.2) (33) % 0.7 1.2 (0.5) (42) %

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40.3 (24.5) 64.8 264 % 159.0 (325.5) 484.5 149 %

Unrealized (losses) gains on foreign currency option contracts (2.2) 3.3 (5.5) (167) %

Unrealized gains (losses) on foreign currency option contracts 2.8 (6.3) 9.1 144 % 0.6 (3.0) 3.6 120 %

Take-or-pay contract-based intangible recognition 0.6 0.7 (0.1) (14) % 1.2 1.4 (0.2) (14) %

Income tax (provision) benefit (118.0) 1.0 (119.0) (11,900) %

Income (loss) from continuing operations, net of income taxes $ 284.1 $ (119.8) $ 403.9 337 %

Income tax provision (74.2) (11.3) (62.9) (557) % (192.2) (10.3) (181.9) (1,766) %

Income from continuing operations, net of income taxes $ 204.1 $ 411.3 $ (207.2) (50) % $ 488.2 $ 291.5 $ 196.7 67 %

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

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

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

2023 2022 $ %

(Dollars in millions)

Seaborne Thermal Mining

$ (23.8) $ (24.0) $ 0.2 1 %

Seaborne Metallurgical Mining

(21.1) (19.9) (1.2) (6) %

Powder River Basin Mining

(11.7) (10.5) (1.2) (11) %

Thermal Mining

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

2023 2022 $ % 2023 2022 $ %

(Dollars in millions) (Dollars in millions)

Seaborne Thermal $ (27.6) $ (26.2) $ (1.4) (5) % $ (51.4) $ (50.2) $ (1.2) (2) %

Seaborne Metallurgical (22.9) (22.0) (0.9) (4) % (44.0) (41.9) (2.1) (5) %

Powder River Basin (10.6) (9.3) (1.3) (14) % (22.3) (19.8) (2.5) (13) %

Thermal (17.1) (13.7) (3.4) (25) % (34.8) (29.4) (5.4) (18) %

Corporate and Other

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

Three Months Ended March 31,

Seaborne Thermal Mining $ 2.17 $ 2.48

Seaborne Metallurgical Mining

Powder River Basin Mining 0.31 0.33

Thermal Mining

The decrease in the weighted-average depletion rate per ton for the Seaborne Thermal Mining segment during the three months ended March 31, 2023 compared to the same period in the prior year reflects the impact of volume and mix variances across the segment.

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

2023 2022 2023 2022

Seaborne Thermal $ 2.09 $ 2.46 $ 2.13 $ 2.47

Seaborne Metallurgical 1.82 3.42 1.96 2.85

Powder River Basin 0.30 0.32 0.30 0.32

Thermal 1.33 1.24 1.26 1.21

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

The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical segment during the three and six months ended June 30, 2023 compared to the same periods in the prior year reflects the impact of the fire at the Shoal Creek Mine.

Provision for NARM and Shoal Creek Loss.

A provision of $33.7 million million was recorded during the three and six months ended June 30, 2023 for losses related to the events at NARM and the Shoal Creek Mine, as discussed in Note 14.

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

The current period provision represents the best estimate of potential loss associated with these events based on assessments made to date.

Interest Expense.

The decrease in interest expense during the three months ended March 31, 2023 primarily reflects the impacts of debt retirements completed by the Company during 2022 as further described in Note 8.

The decrease in interest expense during the three and six months ended June 30, 2023 primarily reflects the impacts of debt retirements completed by the Company during 2022 as further described in Note 8.

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

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Net Loss on Early Debt Extinguishment.

The losses recognized during the three months ended March 31, 2023 were primarily related to the amendment of the Company’s now-terminated letter of credit facility as further discussed in Note 11.

The losses recognized during the three and six months ended June 30, 2023 were primarily related to the Company’s terminated letter of credit facility as further discussed in Note 11.

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

The losses recognized during the prior year period were primarily related to the redemption of existing notes during the period as further described in Note 8.

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 8.

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

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Interest Income.

The increase in interest income during the three months ended March 31, 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.

The increase in interest income during the three and six months ended June 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.

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“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.

Unrealized Gains (Losses) on Foreign Currency Option Contracts.

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

For additional information, refer to Note 5.

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

Income Tax (Provision) Benefit.

The increase in the income tax provision during the three months ended March 31, 2023 compared to the same period in the prior year was primarily due to an increase in pretax income and the release of valuation allowance related to Australian net operating losses during the fourth quarter of 2022.

Income Tax Provision.

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

Refer to Note 7.

“Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information.

Net Income (Loss) Attributable to Common Stockholders

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

Three Months Ended March 31, Increase (Decrease)

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders:

Three Months Ended June 30, (Decrease) Increase

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

2023 2022 $ % 2023 2022 $ %

(Dollars in millions)

Income (loss) from continuing operations, net of income taxes $ 284.1 $ (119.8) $ 403.9 337 %

(Dollars in millions) (Dollars in millions)

Income from continuing operations, net of income taxes $ 204.1 $ 411.3 $ (207.2) (50) % $ 488.2 $ 291.5 $ 196.7 67 %

Loss from discontinued operations, net of income taxes (1.3) (0.7) (0.6) (86) % (2.6) (1.5) (1.1) (73) %

Net income (loss) 282.8 (120.6) 403.4 334 %

Net income (loss) attributable to noncontrolling interests 14.3 (1.1) 15.4 1,400 %

Net income (loss) attributable to common stockholders $ 268.5 $ (119.5) $ 388.0 325 %

Net Income (Loss) Attributable to Noncontrolling Interests.

The increase in the results attributable to noncontrolling interests during the three months ended March 31, 2023 compared to the same period 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.

Net income 202.8 410.6 (207.8) (51) % 485.6 290.0 195.6 67 %

Net income attributable to noncontrolling interests 23.6 1.1 22.5 2,045 % 37.9 — 37.9 n.m.

Net income attributable to common stockholders $ 179.2 $ 409.5 $ (230.3) (56) % $ 447.7 $ 290.0 $ 157.7 54 %

Net Income Attributable to Noncontrolling Interests.

The increase in the results attributable to noncontrolling interests during the three and six months ended June 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.

Diluted Earnings per Share (EPS)

The following table presents diluted EPS:

Three Months Ended March 31, Increase

Three Months Ended June 30, Decrease

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

2023 2022 $ % 2023 2022 $ %

Diluted EPS attributable to common stockholders:

Income (loss) from continuing operations $ 1.69 $ (0.87) $ 2.56 294 %

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

Net income (loss) attributable to common stockholders $ 1.68 $ (0.88) $ 2.56 291 %

Income from continuing operations $ 1.16 $ 2.55 $ (1.39) (55) % $ 2.85 $ 1.93 $ 0.92 48 %

Loss from discontinued operations (0.01) (0.01) — — % (0.02) — (0.02) n.m.

Net income attributable to common stockholders $ 1.15 $ 2.54 $ (1.39) (55) % $ 2.83 $ 1.93 $ 0.90 47 %

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 161.4 million and 136.2 million for the three months ended March 31, 2023 and 2022, respectively.

Diluted EPS reflects weighted average diluted common shares outstanding of 159.0 million and 161.9 million for the three months ended June 30, 2023 and 2022, respectively, and 160.2 million and 152.5 million for the six months ended June 30, 2023 and 2022, respectively.

Reconciliation of Non-GAAP Financial Measures

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

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

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

Three Months Ended March 31,

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

2023 2022 2023 2022

(Dollars in millions)

Income (loss) from continuing operations, net of income taxes $ 284.1 $ (119.8)

Income from continuing operations, net of income taxes $ 204.1 $ 411.3 $ 488.2 $ 291.5

Depreciation, depletion and amortization

80.6 73.8 156.9 146.7

Asset retirement obligation expenses

15.5 12.7 30.9 27.7

Restructuring charges

2.0 0.2 2.1 1.8

Asset impairment

Provision for NARM and Shoal Creek loss 33.7 — 33.7 —

Changes in amortization of basis difference related to equity affiliates (0.4) (0.6) (0.7) (1.2)

Interest expense

13.3 37.6 31.7 77.0

Net loss on early debt extinguishment 2.0 2.3 8.8 25.8

Interest income

(23.1) (0.9) (36.2) (1.4)

Unrealized (gains) losses on derivative contracts related to forecasted sales (40.3) 24.5 (159.0) 325.5

Unrealized losses (gains) on foreign currency option contracts 2.2 (3.3)

Unrealized (gains) losses on foreign currency option contracts (2.8) 6.3 (0.6) 3.0

Take-or-pay contract-based intangible recognition

Income tax provision (benefit) 118.0 (1.0)

(0.6) (0.7) (1.2) (1.4)

Income tax provision 74.2 11.3 192.2 10.3

Total Adjusted EBITDA

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

Three Months Ended March 31,

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

2023 2022 2023 2022

(Dollars in millions)

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$ 862.0 $ 825.6 $ 1,708.6 $ 1,524.6

Unrealized (losses) gains on foreign currency option contracts (2.2) 3.3

Unrealized gains (losses) on foreign currency option contracts 2.8 (6.3) 0.6 (3.0)

Take-or-pay contract-based intangible recognition

0.6 0.7 1.2 1.4

Net periodic benefit credit, excluding service cost (9.7) (12.3) (19.4) (24.5)

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

Three Months Ended March 31,

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

2023 2022 2023 2022

(Dollars in millions)

Seaborne Thermal Mining $ 182.5 $ 160.7

Seaborne Metallurgical Mining 197.6 140.3

Powder River Basin Mining 269.5 243.6

Thermal Mining 185.2 153.1

Seaborne Thermal $ 202.0 $ 178.1 $ 384.5 $ 338.8

Seaborne Metallurgical 270.0 234.1 467.6 374.4

Powder River Basin 233.5 231.7 503.0 475.3

Thermal 148.0 163.0 333.2 316.1

Corporate and Other 2.2 0.8 2.7 (6.1)

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

Three Months Ended March 31, 2023

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

Thermal Mining

Three Months Ended June 30, 2023

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

(Amounts in millions, except per ton data)

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

Three Months Ended March 31, 2022

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

Thermal Mining

Three Months Ended June 30, 2022

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

(Amounts in millions, except per ton data)

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Adjusted EBITDA Margin per Ton $ 43.52 $ 185.65 $ (0.11) $ 14.15

Six Months Ended June 30, 2023

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

(Amounts in millions, except per ton data)

Tons sold 7.6 3.3 40.9 8.3

Revenue $ 746.0 $ 660.9 $ 565.0 $ 449.3

Total Reporting Segment Costs 384.5 467.6 503.0 333.2

Adjusted EBITDA $ 361.5 $ 193.3 $ 62.0 $ 116.1

Revenue per Ton $ 98.81 $ 202.33 $ 13.80 $ 54.23

Costs per Ton 50.94 143.14 12.28 40.22

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

Six Months Ended June 30, 2022

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

(Amounts in millions, except per ton data)

Tons sold 7.8 2.8 39.1 8.6

Revenue $ 606.1 $ 855.1 $ 480.9 $ 428.0

Total Reporting Segment Costs 338.8 374.4 475.3 316.1

Adjusted EBITDA $ 267.3 $ 480.7 $ 5.6 $ 111.9

Revenue per Ton $ 77.52 $ 299.82 $ 12.30 $ 49.96

Costs per Ton 43.33 131.26 12.16 36.90

Adjusted EBITDA Margin per Ton $ 34.19 $ 168.56 $ 0.14 $ 13.06

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.

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

Six Months Ended June 30, 2023

(Dollars in millions)

Net cash provided by operating activities $ 739.7

- Net cash used in investing activities (120.0)

- Distributions to noncontrolling interests (22.8)

+/- Changes to restricted cash and collateral 39.7

- Anticipated expenditures or other requirements —

Available Free Cash Flow $ 636.6

Regulatory Update

Other than as described in the following section, there were no significant changes to the Company’s regulatory matters subsequent to December 31, 2022.

Information regarding the Company’s regulatory matters is outlined in Part I, Item 1.

Other than as described in the following section, there were no significant changes to the Company’s regulatory or global climate matters subsequent to December 31, 2022.

This section should be considered in connection with the Company’s regulatory and global climate matters as outlined in Part I, Item 1.

“Business” in its Annual Report on Form 10-K for the year ended December 31, 2022.

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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.

As part of this recurring review process, the EPA in 2020 proposed to retain the ozone NAAQS promulgated in 2015, including both the primary (public health) and secondary (public welfare) standards.

The EPA subsequently promulgated final standards to this effect.

In 2021, fifteen states and other petitioners filed a petition for review of the rule in the United States Court of Appeals for the D.C.

Circuit (D.C.

The litigation is currently in abeyance following a motion filed by the EPA to allow for review of the standards.

The EPA also proposed in 2020 to retain the particulate matter (PM) NAAQS last revised in 2012.

On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM 2.5 ) and the primary 24-hour standard for coarse particulate matter (PM 10 ) and secondary PM 10 standards.

This rule has also been challenged in the D.C.

Circuit by several states and environmental organizations.

The case is currently in abeyance following a motion filed by the EPA to allow for review of the standards.

On January 6, 2023, the EPA proposed to lower the level of the annual PM 2.5 NAAQS from 12.0 ug /m 3 to within the range of 9.0 to 10.0 ug /m 3.

On January 6, 2023, the EPA proposed to lower the allowable level of average annual primary particulate matter (PM).

If enacted as proposed, this rule would require fossil fuel generating units to install additional nitrogen oxide (NO x ) reducing technologies, ultimately increasing the cost of fossil fuel generated energy or causing potential unit retirements.

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

In 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states.

In 2016, the EPA published the final CSAPR Update Rule which imposed additional reductions in NO x beginning in 2017 in 22 states subject to CSAPR.

This rule was subsequently remanded back to the EPA.

EPA , 938 F.3d 303.

In April 2021, the EPA published a final rule in the Federal Register to address the D.C.

Circuit remand.

This rule imposed further reductions of NO x emissions in 12 states that were subject to the original 2016 rule, which was based on the 2008 ozone NAAQS.

In the same rule, the EPA determined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions.

The EPA subsequently issued Federal Implementation Plans to lower state ozone season NO x budgets in 2021 to 2024 in the affected states.

A petition for review challenging the 2021 rule was filed in the D.C.

Briefing is completed and oral arguments were held September 28, 2022, but this does not stay the effectiveness of the rule.

On March 15, 2023, the EPA Administrator signed a final rule to address regional ozone transport for the 2015 ozone NAAQS by imposing new federal ozone season emission budgets for NO x in 23 states, including California, Nevada, Oklahoma and Texas, as well as some areas in Indian country.

The CSAPR and related updates require numerous U.S.

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

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

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

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

The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million, depending on the discount rate applied.

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

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

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

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 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.

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) .

The EPA published the final MATS rule in the Federal Register in 2012.

The MATS rule revised the New Source Performance Standards 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.

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.

In 2020, the EPA issued a final rule reversing a prior finding and determined that it is not “appropriate and necessary” under the CAA to regulate HAP emissions from coal- and oil-fired power plants.

This rule also finalized residual risk and technology review standards for the coal- and oil-fired electricity utility generating units source category.

Both actions were challenged in the D.C.

Circuit but this litigation was placed in abeyance.

On February 9, 2022 the EPA proposed a rule to revoke the 2020 finding and to reaffirm the agency’s 2016 finding that it remained “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants under Section 112 of the CAA.

In the same proposal, the EPA solicited comments on the performance and cost of new or improved technologies to control HAPs from these power plants as part of the agency’s review of related residual risk and technology review standards.

The EPA finalized the 2022 proposed rule on March 6, 2023, revoking the 2020 finding and concluding that it is appropriate and necessary to regulate coal- and oil-fired electric steam generating units under CAA Section 112.

If enacted, this rule could influence closure of additional coal generating units.

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 3, 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 as well as the usage of continuous emissions monitoring systems, among other proposals.

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.

On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants.

The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams.

On October 13, 2020, the EPA issued a final rule revising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water.

However, on March 8, 2023, the EPA released the pre-publication versions of two actions to further revise certain discharge limits applicable to steam electric power plants.

The first action is a proposed 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-fired steam electric power plants.

The second action is a direct final rule that extends the deadline for steam electric power plants to opt in to the 2028 early retirement provision that was part of the 2020 rule.

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 have indicated that they are implementing the CWA consistent with the Sackett decision, and they may issue additional guidance or initiate another rulemaking proceeding to revise the 2023 rule.

Regulatory Matters - Australia

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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 a coal market price emergency on the basis that the declaration was necessary to reduce the risk that increases in coal prices could contribute to an increase in electricity prices.

On December 23, 2022, directions were issued to Peabody Energy Australia Pty Ltd and a number of other coal producers with operations in NSW.

Those directions were amended on January 31, 2023 and February 16, 2023.

The most recent directions require Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and by 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 with the directions.

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.

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

The Clean Energy Regulator administers the NGER Act.

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

On July 1, 2016, amendments to the NGER Act implemented the Emissions Reduction Fund Safeguard Mechanism.

From that date, large designated facilities such as coal mines were issued with a baseline for their covered emissions and must take steps to keep their emissions at or below the baseline or face penalties.

The National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 outlines key elements of a responsible emitter’s duty to avoid an excess emissions situation and provides detail on how it can meet that requirement.

The rule was amended between 2019 and 2021 to transition responsible emitters to new baseline setting arrangements.

From the start of the 2020-21 compliance year, baselines must use prescribed production variables (an example being run of mine coal) and default emissions intensity values (being values set by the government to represent the industry average emissions intensity of production over five years) unless specific exemptions apply (such as a facility having site-specific values set).

On January 10, 2023, the Australian federal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime.

The reforms will commence on July 1, 2023 utilizing site specific baseline emissions as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030.

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

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

On March 27, 2023, the Australian Federal Government announced a number of 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 to 2030.

The legislation also sets a cap of net zero tonnes CO 2-e for any financial year beginning after June 30, 2049.

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 is now awaiting assent and is expected to commence on July 1, 2023.

The legislation went into effect on July 1, 2023.

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

Risks Related to Global Climate Change

Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to greenhouse gas (GHG) emissions.

The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3).

To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2).

Peabody’s board of directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future.

Peabody views technology as vital to advancing global climate change solutions, and the Company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal.

The board of directors has ultimate oversight for climate-related risk and opportunity assessments, and has delegated certain aspects of these assessments to subject matter committees of the board.

In addition, the board and its committees are provided regular updates on major risks and changes, including climate-related matters.

The senior management team champions the strategic objectives set forth by the board of directors and Peabody’s global workforce turns those objectives into meaningful actions.

Management believes that the Company’s external communications, including environmental regulatory filings and public notices, U.S.

Securities and Exchange Commission filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress.

All such communications are subject to oversight and review protocols established by Peabody’s board of directors and executive leadership team.

The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change.

Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements.

The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the ESG-related policies of financial institutions and other private companies.

The Company has experienced, or may in the future experience, negative effects on its results of operations due to the following specific risks as a result of such factors:

• Reduced utilization or closure of existing coal-fired electricity generating plants;

• Electricity generators switching from coal to alternative fuels, when feasible;

• Increased costs associated with regulatory compliance;

• Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;

• Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes;

• Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions;

• Disruption to operations or markets due to anti-coal activism and litigation;

• Reputational damage associated with involvement in GHG emissions.

With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks:

• Disruption to water supplies vital to mining operations;

• Disruption to transportation and other supply chain activities;

• Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions;

• Electrical grid failures and power outages.

While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:

• Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and carbon capture, use and storage (CCUS) technologies;

• Increased steel demand related to construction and other infrastructure projects related to climate change concerns;

• The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.

Global climate issues continue to attract public and scientific attention.

Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues.

In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants.

There have been significant developments in federal and state legislation and regulation and international accords regarding climate change.

Such developments are described within Part I, Item 1.

“Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022.

The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources.

Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future.

The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source.

That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal.

Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use.

Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement.

The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources.

In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.

From time to time, the Company’s board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies.

Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows.

Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.

There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2022.

Refer to Part I, Item 1.

“Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 for information regarding the Company’s global climate matters.

Liquidity and Capital Resources

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

The Company has also used cash for early debt retirements, dividends, and share repurchases.

As described below, the Company recently amended its existing agreement with the providers of its surety bond portfolio, which included lifting the previous restrictions on capital returns to shareholders.

In connection with the amendment, the Company announced a new shareholder return plan, as discussed in Part II, Item 2.

“Unregistered Sales of Equity Securities and Use of Proceeds.” Any future determinations to return capital to stockholders, such as dividends or share repurchases will depend on a variety of factors, including its net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results.

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

The Company has also used cash for early debt retirements.

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

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

As of March 31, 2023, the Company’s cash balances totaled $892.2 million, including approximately $563.6 million held by Australian subsidiaries, $301.8 million held by U.S.

As of June 30, 2023, the Company’s cash balances totaled $1,080.5 million, including approximately $676.4 million held by Australian subsidiaries, $380.9 million held by U.S.

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

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

During the three months ended March 31, 2023, the Company repatriated approximately $100 million through intercompany dividends.

During the six months ended June 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 $907.5 million as of March 31, 2023.

The Company’s available liquidity decreased from $1,317.8 million as of December 31, 2022 to $1,115.3 million as of June 30, 2023.

Available liquidity was comprised of the following:

March 31, 2023 December 31, 2022

June 30, 2023 December 31, 2022

(Dollars in millions)

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Total liquidity $ 1,115.3 $ 1,317.8

Capital Returns to Shareholders

The Company repurchased approximately 8.9 million shares of its common stock for $184.2 million and paid dividends of $10.8 million during the three months ended June 30, 2023.

Subsequent to June 30, 2023, the Company repurchased an additional 3.1 million shares for $67.0 million.

Surety Agreement Amendment and Collateral Requirements

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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.

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

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

Such compliance requirements will commence for the second quarter of 2023.

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.

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

At March 31, 2023, letters of credit of $245.3 million were outstanding under the agreement, which were collateralized by cash of approximately $250 million.

At March 31, 2023, letters of credit of $168.2 million were outstanding under the agreement, which were collateralized by cash of $173.2 million.

Margin Requirements

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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.

At March 31, 2023, the Company was party to coal derivative contracts related to 0.3 million metric tons of production, all of which are expected to settle during the second quarter of 2023.

At March 31, 2023 and December 31, 2022, the Company had margin posted of $59.8 million and $255.5 million, respectively, related to its coal derivative contracts.

For additional information regarding the Company’s coal derivative contracts, refer to Part I, Item 3.

“Quantitative and Qualitative Disclosures About Market Risk” of this Quarterly Report.

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

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

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

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

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

(Dollars in millions)

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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 3.250% Convertible Senior Notes due 2028 (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 March 31, 2023, of approximately $12 million in 2023, $23 million in 2024, $16 million in 2025, $13 million in 2026, $12 million in 2027 and $322 million thereafter.

Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $19.1 million and $37.2 million during the three months ended March 31, 2023 and 2022, respectively.

The Company’s remaining indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at June 30, 2023, of approximately $10 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 $40.6 million and $77.8 million during the six months ended June 30, 2023 and 2022, respectively.

2028 Convertible Notes

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The 2028 Convertible Notes will bear 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 quarter 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 are not convertible at the option of the holders during the second quarter of 2023.

During the first and second 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 quarter of 2023, and will not be similarly convertible during the third 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.

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

At March 31, 2023, the Company had no outstanding borrowings and $190.7 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 March 31, 2023.

By April 14, 2023, $101.3 million of letters of credit outstanding under the securitization program were cancelled in connection with the surety agreement amendment and related trust accounts described above.

At June 30, 2023, the Company had no outstanding borrowings and $117.8 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 June 30, 2023.

Covenant Compliance

The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2023.

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

The April 2023 termination of the Company’s credit agreement and related letter of credit facility eliminated the related compliance requirements as of March 31, 2023 and prospectively.

The following table summarizes the Company’s cash flows for the three months ended March 31, 2023 and 2022, as reported in the accompanying unaudited condensed consolidated financial statements.

Three Months Ended March 31,

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

Six Months Ended June 30,

(Dollars in millions)

Net cash provided by (used in) operating activities $ 386.3 $ (273.7)

Net cash provided by operating activities $ 739.7 $ 9.4

Net cash (used in) provided by investing activities (120.0) 94.5

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Cash, cash equivalents and restricted cash at end of period $ 1,811.9 $ 1,133.3

Available Free Cash Flow $ 636.6

Operating Activities.

The increase in net cash provided by operating activities for the three months ended March 31, 2023 compared to the same period in the prior year was driven by lower cash utilization with respect to the margin requirements associated with derivative financial instruments ($547.4 million) and the year-over-year increase in operating cash flow from Company’s mining operations ($112.6 million).

The increase in net cash provided by operating activities for the six months ended June 30, 2023 compared to the same period in the prior year was driven by the year-over-year increase in operating cash flow from working capital fluctuations ($450.7 million), including the return of margin associated with derivative financial instruments ($255.5 million), and from the Company’s mining operations ($279.6 million).

Investing Activities.

The increase in net cash used in investing activities for the three months ended March 31, 2023 compared to the same period in the prior year was driven by lower cash receipts from Middlemount ($47.2 million), higher net contributions to joint ventures and related parties ($25.7 million), and higher capital expenditures and the payment of capital accruals ($20.6 million).

The increase in net cash used in investing activities for the six months ended June 30, 2023 compared to the same period in the prior year was driven by lower cash receipts from Middlemount ($142.2 million), higher capital expenditures and the payment of capital accruals ($54.9 million), and lower cash receipts from the disposal of assets ($11.4 million).

Financing Activities.

The decrease in net cash provided by financing activities for the three months ended March 31, 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), partially offset by lower repayments of long-term debt ($597.2 million) in the current year.

The increase in net cash used by financing activities for the six months ended June 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 ($173.0 million and $10.8 million, respectively), partially offset by lower repayments of long-term debt ($650.0 million) in the current year.

Off-Balance-Sheet Arrangements

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

March 31, 2023 December 31, 2022

June 30, 2023 December 31, 2022

Reclamation Support Other Support (1)

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1,142.8 207.1 1,349.9 1,687.9 258.5 1,946.4

1,258.8 219.1 1,477.9 1,687.9 258.5 1,946.4

Letters of credit in support of surety

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

(2) March 31, 2023 balances exclude $223.8 million of letters of credit outstanding under the LC Facility and $101.3 million of letters of credit outstanding under the Company’s accounts receivable securitization program that were cancelled by April 14, 2023.

The collateral obligations related to such letters of credit were met by the March 31, 2023 funding of collateral trust accounts in connection with the surety agreement amendment described above.

Amounts do not include cash collateralized letters of credit.

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

At March 31, 2023, the Company had total asset retirement obligations of $752.5 million.

At June 30, 2023, the Company had total asset retirement obligations of $753.5 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 $936.7 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at March 31, 2023, as described in Note 11.

Not presented in the above table is approximately $925.4 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at June 30, 2023, as described in Note 11.

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

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“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in its Annual Report on Form 10-K for the year ended December 31, 2022.

The Company’s critical accounting policies remain unchanged at March 31, 2023, and there have been no material changes in the Company’s critical accounting estimates.

The Company’s critical accounting policies remain unchanged at June 30, 2023, and there have been no material changes in the Company’s critical accounting estimates.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis