What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-05-05 compared with 2021-11-05 · 329 added, 456 removed, 368 unchanged (68% of the section changed)

17 unchanged sentences

generally accepted accounting principles (U.S.

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

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

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

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

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

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Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S.

Peabody is a leading coal producer.

Peabody is a leading producer of metallurgical and thermal coal.

In 2021, the Company produced and sold 126.9 million and 130.1 million tons of coal, respectively, from continuing operations.

At September 30, 2021, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

At March 31, 2022, 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.

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“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 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended September 30, 2021 is set forth in the table below.

The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended September 30, 2021 due to quality differentials and the majority 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.

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

In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended September 30, 2021 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors.

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, 2022 due to quality differentials and the majority 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.

The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a bi-annual, 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, 2022 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors.

Such long-term contracts in the U.S.

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

High Low Average September 30, 2021

High Low Average March 31, 2022 April 29, 2022

Premium HCC (1)

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(2) Prices expressed per short ton.

Within the global coal industry, supply and demand disruptions were widespread as the coronavirus (COVID-19) pandemic forced country-wide lockdowns and regional restrictions.

Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19.

The global coal industry data for the nine months ended September 30, 2021 presented herein may not be indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration.

Within the seaborne metallurgical coal market, a combination of robust steel production, decade-high steel margins and tight coal availability have driven Australian spot prices to record levels.

China’s unofficial ban on Australian coal remains in place and continues to support delivered China prices well above those of all other markets as domestic, Mongolian and seaborne coal supply from other sources continues to lag overall demand.

The high prices being paid by China are incentivizing producers in Russia, the U.S.

and Canada to supply China with incremental volumes, providing opportunities for Australia to supply customers typically serviced by these countries.

The supply response to the record prices remains muted sending metallurgical coal prices higher.

Within the global coal industry, supply and demand for its products and the supplies used for mining have been impacted by the recent Russian-Ukrainian conflict and the coronavirus (COVID-19) pandemic.

Furthermore, inflationary pressures have contributed to rising costs.

As future developments related to the Russian-Ukrainian conflict, the COVID-19 pandemic and rising inflation are unknown, the global coal industry data for the three months ended March 31, 2022 presented herein may not be indicative of their ultimate impacts.

Within the seaborne metallurgical coal market, the three months ended March 31, 2022 were characterized by significant volatility, primarily driven by sanctions and trade redistribution efforts following the onset of the Russian-Ukrainian conflict.

Buyers in Atlantic markets are seeking to mitigate exposure to Russian coal imports, causing an upswell in demand for supply from other regions such as Australia, the U.S.

Market prices rose approximately $300 per metric tonne from January to mid-March, far exceeding prior records, before falling a similar quantum through the end of March and start of April amid scant market liquidity.

Prices have once more begun increasing in April, following the European Union and Japan firming their stance and announcing total bans on Russian coal imports.

This will have a particular impact on the PCI market, where Russia accounts for approximately 35% of global traded volumes.

China’s unofficial ban on Australian coal remains in place and continues to disrupt traditional trade flows.

Global supply remains tight and this dynamic is only intensifying with the sanctions imposed on Russian imports.

The Company believes energy shortages in some markets present a risk to industrial activity but the underlying market fundamentals remain constructive.

Within the seaborne thermal coal market, a combination of tight supplies and elevated demand have driven Newcastle thermal coal pricing to record levels.

China’s domestic thermal coal supply remains hampered by heightened safety inspections and mine suspensions, as well as flooding.

Thermal electricity generation in China has been strong year-to-date, and the relaxation of China’s import controls combined with tight domestic supply has pushed import demand higher.

Both India and China are experiencing rolling power outages, as multi-year low stockpile levels and high coal prices are pushing power plants into load shedding.

In Europe, gas supply constraints and low wind generation have pushed standby coal plants to resume operation to help supply strong electricity demand.

Despite the strong demand, the supply response has been muted, sending thermal coal prices higher.

Heavy rains in Indonesia, rail issues in Russia, production issues in Colombia and hampered domestic supply in China have all combined to pressure the global thermal market.

In the United States, overall electricity demand increased 3% year-over-year, positively impacted by weather and the prior year economic impacts of the COVID-19 pandemic.

Electricity generation from thermal coal has notably improved year-over-year as a result of higher natural gas prices and stronger overall electricity demand.

This has positively impacted coal’s share of electricity generation, with a rise to approximately 23% for the nine months ended September 30, 2021, while causing natural gas’s share to decline to approximately 37%.

Stronger coal use and a limited supply response in coal production has contributed to decreasing coal stockpile levels.

Since December 2020, coal inventories have fallen by approximately 54 million tons, a 40% decline.

Through the nine months ended September 30, 2021, utility consumption of PRB coal rose approximately 30% compared to the prior year period.

Financing and Surety Transactions

During the fourth quarter of 2020 and the first quarter of 2021, the Company entered into a series of interrelated agreements with its surety bond providers, the revolving lenders under its credit agreement and certain holders of its senior secured notes to extend a significant portion of its near-term debt maturities to December 2024 and to stabilize collateral requirements for its existing surety bond portfolio.

During the second and third quarters of 2021, and continuing into the fourth quarter of 2021, the Company completed a series of additional financing transactions intended to improve its capital structure.

These transactions included at-the-market common stock issuances for cash proceeds, common stock issuances for the retirement of long-term debt and the retirement of long-term debt primarily through open market purchases.

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

During July 2021, the Company executed transactions to sell its closed Millennium and Wilkie Creek Mines, which reduced its closed mine reclamation liabilities and associated costs.

Both mines were sold for minimal cash consideration and gains of $26.1 million and $24.6 million, respectively, were recorded in connection with the sales.

In September 2021, the Company reached a new collective bargaining agreement with the UMWA on behalf of the hourly workforce of its Shoal Creek Mine.

The Company idled the mine in the fourth quarter of 2020 due to market conditions.

During the idle period the Company undertook activities, including a preparation plant upgrade project, to increase productivity, lower costs and improve yields from the operation in the future.

The Company expects to begin production at Shoal Creek Mine in the second half of the fourth quarter of 2021, with ramp up through the first quarter of 2022.

The full workforce of the Metropolitan Mine, which was idled in December 2020, returned to the mine in May 2021.

Development work at the mine has been ongoing and longwall production restarted late in the second quarter of 2021, with a ramp up to planned production levels in the fourth quarter of 2021.

The underground workforce enterprise agreement expired in January 2021 and was renegotiated in October 2021.

In October 2021, the Company announced changes to its postretirement health care benefit plan for certain represented retirees.

Effective January 1, 2022, the Company will not provide medical coverage to certain existing retirees but will continue to offer a life insurance benefit to eligible retirees.

As of September 30, 2021, the health care benefit obligation attributed to these certain existing retirees is approximately $160.0 million.

The impact of the changes will reduce the Company’s postretirement benefit obligation during the fourth quarter of 2021.

Within the seaborne thermal coal market, the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries has driven global thermal coal prices to record levels and high volatility during the three months ended March 31, 2022.

Prior to the Russian-Ukrainian conflict, thermal coal supply was already tight due to an export ban in Indonesia in January as well as heavy rains and COVID-19 restrictions in Australia.

During the three months ended March 31, 2022, Newcastle thermal coal pricing hit record levels due to concerns over a severe supply shock following the onset of the Russian-Ukrainian conflict, but pricing subsided slightly to end the quarter in the $200 per metric tonne range.

In China, domestic coal production has been strong during the three months ended March 31, 2022, which has lowered import demand to start the year.

In India, coal production has been elevated as well, allowing coal buyers to wait for lower thermal seaborne prices and limit imports;

however stockpile levels have fallen recently.

Overall, global thermal coal markets remain turbulent as supply remains tight and European coal importers look to replace Russian coal.

In the United States, overall electricity demand increased more than 3% year-over-year, positively impacted by weather.

Through the three months ended March 31, 2022, electricity generation from thermal coal has declined year-over-year due to strong year-over-year comparatives in February 2021, as well as record renewable generation.

Coal’s share of electricity generation has declined slightly to approximately 22% for the three months ended March 31, 2022, while wind generation’s share has increased to 11%.

Coal inventories have continued to decline since December 2021, with a decline of approximately 5% or 5 million tons.

During the three months ended March 31, 2022, utility consumption of PRB coal rose approximately 1% compared to the prior year period.

Financing and Liquidity Transactions

During the first quarter of 2022, Peabody issued convertible senior unsecured notes and used the proceeds of the offering to retire nearer term higher cost senior secured debt.

This both lowered the Company’s borrowing rates and extended debt maturities to 2028.

High demand and tight supply for coal globally has resulted in a substantial rise in seaborne thermal coal prices, which has been amplified by the Russian-Ukrainian conflict, resulting in unprecedented upward volatility in Newcastle coal pricing since late February.

As a result, Peabody posted additional cash margin of $351.6 million during the three months ended March 31, 2022 to satisfy the margin requirements for its derivative contracts.

During the quarter, the Company put in place a revolving financing facility to support near-term liquidity requirements, particularly with respect to these cash margin requirements which fluctuate depending upon the underlying market coal prices.

The Company received proceeds under the revolving financing facility which were repaid in full with proceeds from the sale of shares under the at-the-market offering program.

Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of these financing and liquidity transactions.

In March 2022, the Company entered into a joint venture with unrelated partners to form R3 Renewables LLC (R3).

R3 was formed with the intent of developing various sites, including certain non-mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage.

The Company’s interest in R3 is accounted for as an equity method investment.

The Company contributed $2.0 million to R3 and recorded an equity loss of $1.0 million from its operations during the three months ended March 31, 2022.

In March 2022, Peabody Investments Corp., a wholly owned subsidiary of the Company, entered into a commitment agreement relating to one of its qualified pension plans (the Plan) with an insurer.

Under the commitment agreement, the Plan purchased a group annuity contract for approximately $500 million and the insurer will reimburse the Plan for future benefit payments to be made to the Plan’s participants.

Under the terms of this transaction, the Plan will continue to administer and pay the retirement benefits of Plan participants but will be reimbursed by the insurer for the payment of all benefits covered by the group annuity contract.

Refer to Note 12.

“Pension and Postretirement Benefit Costs” to the accompanying unaudited condensed consolidated financial statements for a further discussion of this transaction.

Results of Operations

Three and Nine Months Ended September 30, 2021 Compared to the Three and Nine Months Ended September 30, 2020

The Company’s revenues for the three months ended September 30, 2021 increased compared to the same period in 2020 ($8.0 million) due to the impacts of higher seaborne thermal and metallurgical pricing and higher seaborne metallurgical volumes, offset by net unrealized mark-to-market losses on derivative contracts related to forecasted sales and other financial trading ($222.3 million).

Revenues for the nine months ended September 30, 2021 decreased compared to the same period in 2020 ($90.2 million) primarily due to the net unrealized mark-to-market losses on derivative contracts related to forecasted sales and other financial trading ($249.5 million) and lower sales volumes, partially offset by higher seaborne thermal and metallurgical pricing.

Results from continuing operations, net of income taxes for the three months ended September 30, 2021 increased compared to the same period in the prior year ($5.2 million) primarily due to improved results from equity affiliates ($26.4 million), net gains from asset disposals in the current year ($23.3 million) driven by the sale of the Millennium Mine, net gains on early debt extinguishments in the current year ($16.0 million), net mark-to-market losses on actuarially determined liabilities recorded in the prior year period ($13.0 million) and lower postretirement health care costs ($11.4 million).

These favorable variances were offset by higher operating costs and expenses ($98.5 million).

Results from continuing operations, net of income taxes for the nine months ended September 30, 2021 increased compared to the same period in the prior year ($1,579.1 million) primarily due to the asset impairment charges recorded in the prior year period ($ 1,418.1 million), lower operating costs and expenses driven by the sales volume decline as well as production efficiencies and other cost improvements ($43.3 million), lower depreciation, depletion and amortization ($43.2 million), improved results from equity affiliates ($37.1 million), lower postretirement health care costs ($34.3 million) and net gains on early debt extinguishments in the current year ($31.3 million).

These favorable variances were offset by the unfavorable revenue variance described above and increased interest expense ($41.0 million) primarily resulting from fees and higher borrowing rates related to new debt arrangements entered into during the first quarter of 2021.

Adjusted EBITDA for the three and nine months ended September 30, 2021 reflected a year-over-year increase of $193.7 million and $316.7 million, respectively.

As of September 30, 2021, the Company’s available liquidity was approximately $615 million.

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021

The Company’s revenue for the three months ended March 31, 2022 increased compared to the same period in 2021 ($40.1 million) primarily due to the impacts of higher pricing, offset by net unrealized mark-to-market losses on derivative contracts related to forecasted sales and other financial trading activity ($ 290.2 million).

Results from continuing operations, net of income taxes for the three months ended March 31, 2022 decreased compared to the same period in the prior year ($42.1 million), primarily due to higher operating costs and expenses ($116.4 million) which reflected inflationary pressures and increased costs for materials, services, repairs and labor related to the Company’s efforts to ramp up the operations to meet current and anticipated volumes.

The results were further impacted by net losses on early debt extinguishments in the current year ($27.0 million).

These unfavorable variances were offset by improved results from equity affiliates ($45.6 million), a favorable revenue variance due to higher pricing exceeding the net unrealized mark-to-market losses as described above ($40.1 million);

and decreased interest expense ($13.0 million).

Adjusted EBITDA for the three months ended March 31, 2022 reflected a year-over-year increase of $266.4 million.

As of March 31, 2022, the Company’s available liquidity was approximately $842 million.

Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting the Company’s available liquidity.

The following table presents tons sold by operating segment:

Three Months Ended September 30, (Decrease ) Increase

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

2021 2020 Tons % 2021 2020 Tons %

(Tons in millions) (Tons in millions)

Three Months Ended March 31, (Decrease ) Increase

2022 2021 Tons %

(Tons in millions)

Seaborne Thermal Mining 3.8 4.1 (0.3) (7) %

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The following table presents supplemental financial data by operating segment:

Three Months Ended September 30, Increase

(Decrease) Nine Months Ended September 30, Increase

Three Months Ended March 31, Increase

2022 2021 $ %

Revenues per Ton - Mining Operations (1)

Revenue per Ton - Mining Operations (1)

Seaborne Thermal $ 66.86 $ 43.36 $ 23.50 54 %

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and certain other costs related to post-mining activities.

The following table presents revenues by reporting segment:

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

The following table presents revenue by reporting segment:

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

2022 2021 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal Mining $ 251.2 $ 176.4 $ 74.8 42 %

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Corporate and Other (335.4) 9.7 (345.1) (3,558) %

Revenues $ 679.0 $ 671.0 $ 8.0 1 % $ 2,053.7 $ 2,143.9 $ (90.2) (4) %

Revenue $ 691.4 $ 651.3 $ 40.1 6 %

Seaborne Thermal Mining.

Segment revenues increased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year due to favorable realized coal pricing (three months, $105.5 million;

nine months, $144.8 million), offset by unfavorable volume and mix variances (three months, $7.8 million;

nine months, $39.7 million).

Segment revenue increased during the three months ended March 31, 2022 compared to the same period in the prior year primarily due to favorable realized coal pricing ($110.9 million), offset by unfavorable volumes ($36.1 million) which were impacted by a longwall move at the Wambo Underground Mine, wet weather and COVID-19-related staffing shortages.

Seaborne Metallurgical Mining.

Segment revenues increased during the three months ended September 30, 2021 compared to the same period in the prior year due to favorable realized coal pricing ($67.0 million) and favorable volume and mix variances ($33.7 million).

Segment revenues increased during the nine months ended September 30, 2021 compared to the same period in the prior year due to favorable realized coal pricing ($52.3 million), partially offset by unfavorable volume and mix variances ($27.9 million).

The unfavorable volume variances resulted from the Shoal Creek Mine being idled through the first nine months of 2021, the Metropolitan Mine being idled through the first quarter of 2021 and the closure of the Millennium Mine during the second quarter of 2020.

These unfavorable volume variances were partially offset by improved demand at the Coppabella and Moorvale Mines.

Segment revenue increased during the three months ended March 31, 2022 compared to the same period in the prior year due to favorable realized coal pricing ($190.2 million) and favorable volume and mix variances ($43.6 million).

Powder River Basin Mining.

Segment revenues decreased during the three months ended September 30, 2021 compared to the same period in the prior year primarily due to decreased production ($9.7 million) and unfavorable realized coal pricing ($8.0 million).

Segment revenues decreased during the nine months ended September 30, 2021 compared to the same period in the prior year primarily due to unfavorable realized coal pricing ($19.3 million), partially offset by increased demand ($6.2 million).

Segment revenue increased during the three months ended March 31, 2022 compared to the same period in the prior year primarily due to favorable realized coal pricing ($27.2 million), partially offset by unfavorable volumes ($4.4 million).

Thermal Mining.

Segment revenues increased during the three months ended September 30, 2021 compared to the same period in the prior year due to favorable realized pricing ($18.9 million), offset by lower volumes attributable to decreased production and rail performance issues ($14.1 million).

Segment revenues decreased during the nine months ended September 30, 2021 compared to the same period in the prior year primarily due to lower volumes attributable to decreased production and rail performance issues ($52.0 million), partially offset by favorable realized pricing ($23.9 million).

Segment revenue increased during the three months ended March 31, 2022 compared to the same period in the prior year due to favorable realized pricing ($40.0 million) and favorable volumes ($13.8 million).

Corporate and Other.

Segment revenues decreased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year primarily due to net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales and other financial trading (three months, $222.3 million;

nine months, $249.5 million), partially offset by higher results from trading activities.

Segment revenue decreased during the three months ended March 31, 2022 compared to the same period in the prior year primarily due to net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales and other financial trading activity ($285.3 million) and lower results from trading activities ($61.8 million).

Adjusted EBITDA

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

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

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

2022 2021 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal Mining

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Seaborne Thermal Mining.

Segment Adjusted EBITDA increased during the three months ended September 30, 2021 compared to the same period in the prior year as a result of higher realized net coal pricing ($97.5 million), partially offset by unfavorable mine sequencing impacts ($14.7 million), unfavorable sales volume variances ($5.1 million) and higher commodity pricing ($4.0 million).

Segment Adjusted EBITDA increased during the nine months ended September 30, 2021 compared to the same period in the prior year as a result of higher realized net coal pricing ($133.2 million) and cost improvements across the operations and product mix ($21.3 million).

The increases were partially offset by unfavorable volume variances ($29.1 million) and unfavorable foreign currency impacts ($28.7 million).

Segment Adjusted EBITDA increased during the three months ended March 31, 2022 compared to the same period in the prior year as a result of higher realized net coal pricing ($102.3 million), partially offset by unfavorable operational costs ($40.5 million) resulting from the longwall move at the Wambo Underground Mine, the impacts of wet weather, COVID-19-related staffing shortages and inflationary pressures.

Seaborne Metallurgical Mining.

Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year due to higher realized net coal pricing (three months, $62.3 million;

nine months, $48.8 million), cost improvements at certain mines (three months, $23.1 million;

nine months, $71.9 million) and favorable volume variances (three months, $3.5 million;

nine months, $19.8 million), offset by unfavorable foreign currency impacts (three months, $2.2 million;

nine months, $41.9 million).

Segment Adjusted EBITDA increased during the three months ended March 31, 2022 compared to the same period in the prior year due to higher realized net coal pricing ($176.3 million) and cost improvements at certain mines ($23.4 million).

Powder River Basin Mining.

Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year due to lower realized net coal pricing (three months, $12.6 million;

nine months, $17.7 million), higher costs for materials, services, repairs and labor (three months, $12.6 million;

nine months, $16.7 million) and the unfavorable impacts of higher commodity pricing (three months, $8.1 million;

nine months, $18.1 million).

The decreases were offset by favorable mine sequencing impacts (nine months, $16.5 million).

Segment Adjusted EBITDA decreased during the three months ended March 31, 2022 compared to the same period in the prior year due to higher costs for materials, services, repairs and labor ($29.5 million) related to efforts to ramp up the operations to meet current and anticipated volumes and the unfavorable impacts of higher commodity pricing ($14.7 million), both of which were also impacted by inflationary pressures.

These decreases were partially offset by higher realized net coal pricing ($27.3 million).

Thermal Mining.

Segment Adjusted EBITDA decreased during the three months ended September 30, 2021 compared to the same period in the prior year due to higher costs for materials, services, repairs and labor ($12.9 million) and the unfavorable impacts of higher commodity pricing ($7.0 million), offset by higher realized net coal pricing ($17.9 million).

Segment Adjusted EBITDA increased during the nine months ended September 30, 2021 compared to the same period in the prior year due to higher realized net coal pricing ($21.2 million) and favorable mine sequencing impacts ($16.9 million), offset by the unfavorable impacts of higher commodity pricing ($13.6 million).

Segment Adjusted EBITDA increased during the three months ended March 31, 2022 compared to the same period in the prior year due to higher realized net coal pricing ($41.6 million) and favorable volumes ($6.7 million).

These increases were offset by higher costs for materials, services, repairs and labor ($24.4 million) related to efforts to ramp up the operations to meet current and anticipated volumes and the unfavorable impacts of higher commodity pricing ($10.0 million), both of which were also impacted by inflationary pressures.

Corporate and Other Adjusted EBITDA.

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

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

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

2022 2021 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Middlemount (1)

$ 45.1 $ (2.3) $ 47.4 2,061 %

Resource management

activities (2)

Resource management activities (2)

3.5 0.4 3.1 775 %

6 unchanged sentences

(1) Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and 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 $17.9 million and $8.6 million during the three months ended September 30, 2021 and 2020, respectively, and $40.7 million and $21.8 million during the nine months ended September 30, 2021 and 2020, respectively.

(2) Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.

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 $45.0 million and $11.7 million during the three months ended March 31, 2022 and 2021, respectively.

(2) Includes gains (losses) on certain surplus coal reserve 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.

The increase in Corporate and Other Adjusted EBITDA during the three and nine months ended September 30, 2021 compared to the same periods in the prior year was driven by favorable trading results (three months, $27.4 million;

nine months, $39.1 million);

the gain recognized in the current year on the sale of the Company’s Millennium Mine (three and nine months, $26.1 million) as discussed in Note 14.

“Other Events”;

a favorable variance in Middlemount’s results due to the combined impacts of higher sales pricing, improved production and cost improvements;

lower postretirement health care costs (three months, $11.2 million;

nine months, $33.6 million) primarily due to changes made to one of the Company’s postretirement health care benefit plans announced in 2020;

and lower containment and holding costs for the Company’s North Goonyella Mine (nine months, $15.4 million).

Corporate and Other Adjusted EBITDA benefited during the three months ended March 31, 2022 compared to the same period in the prior year from a favorable variance in Middlemount’s results ($47.4 million) due to the impact of higher sales pricing.

This benefit was largely offset by unfavorable trading results ($41.9 million).

Loss From Continuing Operations, Net of Income Taxes

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

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

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

2022 2021 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Adjusted EBITDA (1)

3 unchanged sentences

Restructuring charges (1.6) (2.1) 0.5 24 %

Transaction costs related to joint ventures — (6.0) 6.0 100 % — (23.1) 23.1 100 %

Asset impairment — — — n.m.

— (1,418.1) 1,418.1 100 %

Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 0.6 1.5 (0.9) (60) %

Interest expense (39.4) (52.4) 13.0 25 %

Net gain on early debt extinguishment 16.0 — 16.0 n.m.

31.3 — 31.3 n.m.

Net (loss) gain on early debt extinguishment (23.5) 3.5 (27.0) (771) %

Interest income 0.5 1.5 (1.0) (67) %

Net mark-to-market adjustment on actuarially determined liabilities — (13.0) 13.0 100 % — (13.0) 13.0 100 %

Unrealized losses on derivative contracts related to forecasted sales

2 unchanged sentences

Take-or-pay contract-based intangible recognition 0.7 1.1 (0.4) (36) %

Income tax benefit (provision) 3.7 0.1 3.6 3,600 % 10.3 (2.7) 13.0 481 %

Income tax benefit 1.0 1.8 (0.8) (44) %

Loss from continuing operations, net of income taxes $ (119.8) $ (77.7) $ (42.1) (54) %

3 unchanged sentences

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

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

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

2022 2021 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Seaborne Thermal Mining

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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 mining segments:

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

2021 2020 2021 2020

Three Months Ended March 31,

Seaborne Thermal Mining $ 2.48 $ 1.87

Seaborne Metallurgical Mining

1.14 1.83 1.06 2.24

Powder River Basin Mining 0.33 0.23

Thermal Mining

1.18 1.11 1.16 1.05

Depreciation, depletion and amortization expense decreased during the nine months ended September 30, 2021 compared to the same period in the prior year primarily due to the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 (nine months, $45.3 million).

The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the three and nine months ended September 30, 2021 compared to the same periods in the prior year reflects the volume and mix variances which impacted the Company’s revenues as described above.

The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the nine months ended September 30, 2021 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020.

Restructuring Charges.

Restructuring charges decreased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year as the result of workforce reductions made across the organization during the prior year.

Transaction Costs Related to Joint Ventures.

The charges recorded during the prior year period related to the proposed PRB Colorado joint venture with Arch Resources, Inc.

which was terminated during the third quarter of 2020.

Asset Impairment.

During the nine months ended September 30, 2020, the Company recognized $1,418.1 million in aggregate asset impairment charges related to the fair value of its North Antelope Rochelle Mine in its Powder River Basin Mining segment as discussed in Note 8.

“Property, Plant, Equipment and Mine Development” to the accompanying unaudited condensed consolidated financial statements.

Depreciation, depletion and amortization expense increased during the three months ended March 31, 2022 compared to the same period in the prior year primarily due to increased depletion.

The increase in the weighted-average depletion rate per ton for the Seaborne Thermal Mining segment during the three months ended March 31, 2022 compared to the same period in the prior year reflects the impact of the transition to the United Wambo Joint Venture.

The increase in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the three months ended March 31, 2022 compared to the same period in the prior year reflects the volume and mix variances which impacted the Company’s revenue as described above.

Interest Expense.

Interest expense increased during the three and nine months ended September 30, 2021 compared to the same periods in the prior year as the result of a series of refinancing transactions completed by the Company during the first quarter of 2021 as described in Note 11.

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

Net Gain on Early Debt Extinguishment.

The gain recognized during the three and nine months ended September 30, 2021 was primarily related to debt retirements made through various open market purchases during the second and third quarters of 2021 and the senior notes exchange completed during the first quarter of 2021 as further discussed in Note 11.

The decrease in interest expense during the three months ended March 31, 2022 was primarily driven by prior year fees related to a series of refinancing transactions completed by the Company ($10.6 million) as further described in Note 11.

“Long-term Debt” to the Annual Report on Form 10-K for the year ended December 31, 2021.

Net (Loss) Gain on Early Debt Extinguishment.

The loss recognized during the three months ended March 31, 2022 was primarily related to the redemption of existing notes during the period as further discussed in Note 11.

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

Net Mark-to-Market Adjustment on Actuarially Determined Liabilities.

The expense recorded during the three and nine months ended September 30, 2020 related to changes made to one of the Company’s postretirement health care benefit plans which triggered a remeasurement event.

Unrealized Losses on Derivative Contracts Related to Forecasted Sales.

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

Income Tax Benefit (Provision) .

The increase in the income tax benefit for the three and nine months ended September 30, 2021 compared to the same periods in the prior year was primarily due to differences in forecasted taxable income and an increase in the benefit related to the remeasurement of foreign income tax accounts.

Refer to Note 10.

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

Net Loss Attributable to Common Stockholders

The following table presents net loss attributable to common stockholders:

Three Months Ended September 30, Increase

to Income Nine Months Ended September 30, Increase

Three Months Ended March 31, (Decrease) Increase

2022 2021 $ %

(Dollars in millions) (Dollars in millions)

(Dollars in millions)

Loss from continuing operations, net of income taxes $ (119.8) $ (77.7) $ (42.1) (54) %

Income (loss) from discontinued operations, net of income taxes 24.3 (2.3) 26.6 1,157 % 20.0 (6.8) 26.8 394 %

Loss from discontinued operations, net of income taxes (0.8) (2.0) 1.2 60 %

Net loss (120.6) (79.7) (40.9) (51) %

Net income (loss) attributable to noncontrolling interests 8.9 0.1 8.8 8,800 % 12.6 (5.1) 17.7 347 %

Net (loss) income attributable to noncontrolling interests (1.1) 0.4 (1.5) (375) %

Net loss attributable to common stockholders $ (119.5) $ (80.1) $ (39.4) (49) %

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

The increase in the results from discontinued operations for the three and nine months ended September 30, 2021 compared to the same periods in the prior year was primarily due to the gain of $24.6 million recognized on the sale of the Wilkie Creek Mine.

Refer to Note 14.

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

Diluted Earnings per Share (EPS)

The following table presents diluted EPS:

Three Months Ended September 30, Increase

to EPS Nine Months Ended September 30, Increase

Three Months Ended March 31, (Decrease) Increase

2022 2021 $ %

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Loss from continuing operations $ (0.87) $ (0.79) $ (0.08) (10) %

Income (loss) from discontinued operations 0.22 (0.03) 0.25 833 % 0.19 (0.07) 0.26 371 %

Loss from discontinued operations (0.01) (0.02) 0.01 50 %

Net loss attributable to common stockholders $ (0.88) $ (0.81) $ (0.07) (9) %

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 114.9 million and 97.9 million for the three months ended September 30, 2021 and 2020, respectively, and 104.9 million and 97.6 million for the nine months ended September 30, 2021 and 2020, respectively.

Diluted EPS reflects weighted average diluted common shares outstanding of 136.2 million and 98.4 million for the three months ended March 31, 2022 and 2021, respectively.

Reconciliation of Non-GAAP Financial Measures

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

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

2021 2020 2021 2020

Three Months Ended March 31,

(Dollars in millions)

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Depreciation, depletion and amortization

77.9 72.2 223.3 266.5

Asset retirement obligation expenses

14.3 14.3 45.3 46.0

Restructuring charges

1.7 8.1 5.9 31.1

Transaction costs related to joint ventures

Asset impairment

— — — 1,418.1

Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates

(6.4) (0.5) (8.4) (1.6)

Interest expense

45.5 34.9 143.3 102.3

Net gain on early debt extinguishment (16.0) — (31.3) —

Net loss (gain) on early debt extinguishment 23.5 (3.5)

Interest income

(1.4) (1.6) (4.2) (7.1)

Net mark-to-market adjustment on actuarially determined liabilities — 13.0 — 13.0

Unrealized losses on derivative contracts related to forecasted sales 301.0 1.9

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Take-or-pay contract-based intangible recognition

(1.0) (1.5) (3.2) (6.8)

Income tax (benefit) provision

(3.7) (0.1) (10.3) 2.7

Income tax benefit (1.0) (1.8)

Total Adjusted EBITDA

$ 327.5 $ 61.1

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

Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:

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

2021 2020 2021 2020

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

Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:

Three Months Ended March 31,

(Dollars in millions)

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Take-or-pay contract-based intangible recognition

1.0 1.5 3.2 6.8

Net periodic benefit (credit) costs, excluding service cost (8.6) 2.8 (26.0) 8.3

Net periodic benefit credit, excluding service cost (12.2) (8.7)

Total Reporting Segment Costs

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The following table presents Reporting Segment Costs by reporting segment:

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

2021 2020 2021 2020

Three Months Ended March 31,

(Dollars in millions)

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Total Reporting Segment Costs $ 690.8 $ 567.4

The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment:

Three Months Ended September 30, 2021

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

Thermal Mining

(Amounts in millions, except per ton data)

Tons sold 4.5 1.5 22.7 4.5

Revenues $ 260.7 $ 179.5 $ 247.1 $ 184.6

Reporting Segment Costs 156.3 122.1 210.1 139.5

Adjusted EBITDA $ 104.4 $ 57.4 $ 37.0 $ 45.1

Revenues per Ton $ 58.53 $ 119.98 $ 10.88 $ 40.99

Costs per Ton 35.09 81.61 9.25 30.99

Adjusted EBITDA Margin per Ton $ 23.44 $ 38.37 $ 1.63 $ 10.00

Three Months Ended September 30, 2020

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

Thermal Mining

(Amounts in millions, except per ton data)

Tons sold 4.6 1.1 23.6 4.8

Revenues $ 163.0 $ 78.8 $ 264.8 $ 179.8

Reporting Segment Costs 127.7 106.1 186.5 128.2

Adjusted EBITDA $ 35.3 $ (27.3) $ 78.3 $ 51.6

Revenues per Ton $ 35.28 $ 71.88 $ 11.26 $ 37.20

Costs per Ton 27.59 96.87 7.93 26.52

Adjusted EBITDA Margin per Ton $ 7.69 $ (24.99) $ 3.33 $ 10.68

Nine Months Ended September 30, 2021

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

Three Months Ended March 31, 2022

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

2 unchanged sentences

Tons sold 3.8 1.2 20.6 4.2

Revenues $ 631.2 $ 388.0 $ 724.1 $ 496.0

Revenue $ 251.2 $ 321.3 $ 251.2 $ 203.1

Reporting Segment Costs 160.7 140.3 243.6 153.1

Adjusted EBITDA $ 90.5 $ 181.0 $ 7.6 $ 50.0

Revenues per Ton $ 49.86 $ 99.18 $ 10.99 $ 40.20

Revenue per Ton $ 66.86 $ 258.43 $ 12.18 $ 48.46

Costs per Ton 42.77 112.87 11.81 36.54

Adjusted EBITDA Margin per Ton $ 24.09 $ 145.56 $ 0.37 $ 11.92

Nine Months Ended September 30, 2020

Three Months Ended March 31, 2021

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

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Tons sold 4.1 1.0 20.7 3.9

Revenues $ 526.1 $ 363.6 $ 737.2 $ 524.1

Revenue $ 176.4 $ 87.5 $ 228.4 $ 149.3

Reporting Segment Costs 147.9 109.9 198.3 113.1

Adjusted EBITDA $ 28.5 $ (22.4) $ 30.1 $ 36.2

Revenues per Ton $ 38.14 $ 87.16 $ 11.35 $ 38.67

Revenue per Ton $ 43.36 $ 87.47 $ 11.01 $ 38.76

Costs per Ton 36.36 109.89 9.56 29.37

Adjusted EBITDA Margin per Ton $ 7.00 $ (22.42) $ 1.45 $ 9.39

Free Cash Flow is defined as net cash used in operating activities less net cash used in investing activities and excludes cash outflows related to business combinations.

Free Cash Flow is defined as net cash (used in) provided by operating activities less net cash provided by (used in) investing activities and excludes cash outflows related to business combinations.

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

Nine Months Ended September 30,

Three Months Ended March 31,

(Dollars in millions)

Net cash used in operating activities $ (18.4) $ (32.1)

Net cash used in investing activities (119.7) (159.4)

Net cash (used in) provided by operating activities $ (273.7) $ 71.0

Net cash provided by (used in) investing activities 35.2 (93.2)

Free Cash Flow $ (238.5) $ (22.2)

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Regulatory Matters - U.S.

Clean Air Act (CAA).

The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect the Company’s U.S.

coal mining operations both directly and indirectly.

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

National Ambient Air Quality Standards (NAAQS) .

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

As part of this recurring review process, the EPA in 2020 proposed to retain the ozone standards promulgated in 2015, including current secondary standards, and subsequently promulgated final standards to this effect.

7 unchanged sentences

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

On March 11, 2022, the EPA announced their Clean Air Act ‘good neighbor’ proposed rule.

The rule would double the number of covered states, set first-time limits on certain industrial source plant boilers and require daily limits on emissions from large coal-fired power plants.

The EPA estimates that by 2026 the compliance cost will be $1.1 billion.

More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts.

This could also be the case with respect to other NAAQS for nitrogen dioxide (NO 2 ) and sulfur dioxide (SO 2 ), although these standards are not subject to a statutorily-required review until 2023 for NO 2 and 2024 for SO 2 .

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

On October 23, 2015, the EPA published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired electric generation units (EGUs) under Section 111(d) of the CAA (80 Fed.

The rule (known as the Clean Power Plan or CPP) established emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs.

The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).

The EPA subsequently proposed to repeal the CPP and in August 2018 issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule.

In June 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE.

The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the Best System of Emission Reduction (BSER).

The EPA’s final rule also revises certain regulations to give the states greater flexibility on the content and timing of their state plans.

Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C.

Circuit matter seeking review of CPP, including the Company, filed a motion to dismiss, which the court granted in September 2019.

Numerous petitions for review challenging the ACE Rule were filed in the D.C.

Circuit and subsequently consolidated.

In January 2021, a 3-judge panel of the D.C.

Circuit vacated and remanded the ACE Rule to the EPA, including its repeal of the CPP and amendments to the implementing regulations that extended the compliance timeline.

On October 29, 2021, the Supreme Court granted certiorari in four matters seeking review of the D.C.

Circuit’s opinion invalidating the repeal of the CPP.

In granting certiorari, the Supreme Court consolidated the cases to consider the breadth of the EPA’s scope pursuant to 42 U.S.C.

Section 7411(d) of the CAA, specifically, whether it is limited to issuing standards for existing sources achievable through demonstrated technology and methods, or if it may also issue industry wide systems (such as cap and trade) which effectively seek to shift energy generation.

The Company will continue to monitor the consolidated matters.

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

1 unchanged sentence

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

In October 2020, the EPA proposed a rule to address a previous D.C.

Circuit remand of the CSAPR Update Rule and in April 2021, the EPA published a final rule in the Federal Register which imposed further reductions of NO x emissions in 12 states that were subject to the original 2016 rule.

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 standard.

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.

In order to implement reductions in the 12 identified states, the EPA issued Federal Implementation Plans to lower state ozone season NO x budgets in 2021 to 2024, although limited emission trading can be used for compliance and states have the ability to replace federal plans with revised state plans that are no less stringent.

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

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

Circuit, but this does not stay the effectiveness of the rule.

Circuit and briefing in this litigation has been completed, but this does not stay the effectiveness of the rule.

In addition, on February 28, 2022, the EPA released a proposed rule for additional FIPs to address interstate air pollution from fossil-fuel power plants in 25 states and certain industrial sources in 23 states.

This rule is based on the more stringent 2015 ozone NAAQS and would, if finalized, affect some of the states covered by previous rules, but also include several new states, including states in the western United States.

Mercury and Air Toxic Standards (MATS) .

3 unchanged sentences

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 EGU source category.

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.

In August 2020, the EPA sent a draft rule to the Office of Management and Budget for review regarding reconsideration of the “appropriate and necessary” finding as well as standards for coal- and oil-fired EGUs.

CWA Definition of “Waters of the United States ”.

In January 2020 the EPA and the Army Corps of Engineers (Corps) finalized the Navigable Waters Protection Rule to revise the definition of “Waters of the United States” and thereby establish the scope of federal regulatory authority under the CWA.

On August 30, 2021, a federal court in Arizona vacated the Navigable Waters Protection Rule, and on September 3, 2021, the EPA and the Corps announced that they had “halted implementation” of the rule nationwide and that they are interpreting “Waters of the United States” consistent with the pre-2015 regulatory framework.

The agencies reaffirmed that they are moving forward on two rulemaking proceedings to formally repeal the Navigable Waters Protection Rule and then to build upon the pre-2015 regulatory framework.

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 August 3, 2021, the EPA announced it is undertaking a supplemental rulemaking to “strengthen certain discharge limits” applicable to steam electric power plants.

As finalized, the revised effluent limitations guidelines could significantly increase costs for many coal-fired steam electric power plants.

On February 9, 2022 the EPA proposed a rule to revoke the 2020 finding and to reaffirm the agency’s 2016 finding that it remains “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired powerplants under Clean Air Act section 112.

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

Clean Water Act (CWA).

The CWA of 1972 directly impacts U.S.

coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES).

Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.

Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands.

Section 404 of the CWA requires mining companies to obtain permits from the Corps to place material in or mine through jurisdictional waters of the U.S.

States are empowered to develop and apply water quality standards.

These standards are subject to change and must be approved by the EPA.

Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances.

Standards vary from state to state.

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

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

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

That rule was temporarily vacated by a district court, but a Supreme Court order on April 7, 2022, effectively reinstated the rule.

The EPA, however, plans to issue another proposal in 2022 that would supersede the 2020 rule.

Regulatory Matters - Australia

The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues.

The Australian federal government retains control over the level of foreign investment and export approvals.

Industrial relations are regulated under both federal and state laws.

Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being incrementally returned or security released after satisfactory reclamation is progressively completed.

Safe Work Australia (SWA).

As part of a broader review of workplace exposure standards, SWA is currently considering a proposal to reduce the time weighted average (TWA) Workplace Exposure Standard (WES) for carbon dioxide (CO 2 ) in Australian coal mines from 12,500 ppm to 5,000 ppm.

Currently there is a separate TWA for CO 2 in coal mines however SWA proposes to remove this to align with a general industry standard.

If implemented, the change has the potential to affect underground mines operating in CO 2 rich coal seams, including the primary coal seam of the Company’s Metropolitan Mine.

Importantly, a minimum three-year transition period applies for any change to standards.

Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021.

On February 25, 2021 the Commonwealth Government introduced the Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021 into Parliament, which proposes amendments to the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) following the release of the Final Report of the Independent Review of the Act undertaken by Professor Graeme Samuel (the Samuel Review) that made 38 recommendations for short and long-term reforms, and ultimately calls for a complete overhaul of the existing legislative framework by 2022, to be undertaken in several tranches, with a strong focus on the setting of National Environmental Standards, assurance and compliance, data availability and management, and indigenous engagement.

The bill responds to some of the recommendations for immediate reform made in the Samuel Review, and seeks to:

establish a framework for the making, varying, revoking and application of National Environmental Standards;

apply the National Environmental Standards to bilateral agreements with States and Territories;

and establish an Environment Assurance Commissioner to monitor and audit bilateral agreements and other processes under the EPBC Act.

The bill passed the Australian Parliament’s House of Representatives in June 2021 and is now under consideration by the Australian Senate.

Native Title and Cultural Heritage.

On February 3, 2021 the Native Title Act 1993 was amended, largely directed at improving the efficiency of the native title system for all parties.

The amendments confirm the validity of most section 31 right to negotiate agreements which might be invalid because of non-execution by any of the persons comprising the registered native title claimant following the Full Federal Court's decision in McGlade v Registrar National Native Title Tribunal.

Other significant amendments include that:

during the right to negotiate process the parties to section 31 agreements are now required to notify the National Native Title Tribunal of the existence of any ancillary agreements;

new section 47C allows historical extinguishment to be disregarded on park areas including extinguishment by public works;

and new section 24MD(6B)(f) creates a new 8 month objection period for the creation of a right to mine for the purpose of an infrastructure facility associated with mining and to some compulsory acquisitions of native title.

Global Climate

In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no legislation directly affecting fossil fuel-fired powerplants has been signed into law.

Congress did include climate legislation, the American Innovation and Manufacturing Act of 2020, within a large appropriations bill for the 2021 fiscal year.

This legislation was enacted in December 2020, and final regulations were promulgated in September 2021.

The law requires the phasedown of the production and use of hydrofluorocarbons (HFCs) in the United States.

While it is possible that the U.S.

will adopt broader legislation in the future, the timing and specific requirements of any such legislation are uncertain.

Congress is considering several measures to address climate issues and greenhouse gas emissions as part of the U.S.

budgetary process, including reconciliation legislation that could create financial incentives and penalties as part of a “clean electricity standard” applying to electric generation.

In the absence of new U.S.

federal legislation, the EPA has taken steps to regulate greenhouse gas emissions pursuant to the CAA.

In response to the U.S.

Supreme Court ruling in Massachusetts v.

EPA, 549 U.S.

497 (2007) the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” As described above, however, the EPA’s rules affecting existing fossil-fuel fired power plants (i.e.

the ACE Rule and the EPA’s repeal of the CPP) were vacated and remanded back to the EPA by the D.C.

Greenhouse gas requirements for new, reconstructed and modified fossil fuel fired power plants remain in effect.

Several changes in the New Source Review (NSR) program, a permitting plan under the CAA for new source construction and major modifications, have also been issued through guidance and rulemaking as described under “Regulatory Matters – U.S.” in the Company’s Annual Report on Form 10-K.

The NSR program provides for the pre-construction review of new, reconstructed and modified stationary sources and results in determinations concerning the emission control technology that must be installed and operated at a source.

NSPS generally serve as a “floor” level of control for sources subject to NSR review;

the final level of control is determined through the permitting process.

In certain cases, performance standards or controls regarding greenhouse gas emissions may be required through the NSR process.

Because NSR review is undertaken both pursuant to applicable regulations and guidance and performed on a “case-by-case” basis, requirements imposed through this permitting process are subject to variation.

At the same time, a number of states in the U.S.

have adopted programs to regulate greenhouse gas emissions.

For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants.

Six mid-western states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets.

It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it.

Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions.

However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members.

Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating.

Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities in ways not limited to cap-and-trade programs.

Separately, California has committed through Executive Order B-55-18 and SB 100 to 100 percent “clean energy” by 2045 and the state of Washington has passed legislation to commit to carbon neutrality by 2050.

Several other U.S.

states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements.

In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources.

Some states have initiated public utility proceedings that may establish values for carbon emissions.

Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies.

This has had adverse impacts on the liquidity and operations of coal producers.

Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and Peabody regularly discloses in its annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by the Company in the U.S.

The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal.

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

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

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

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

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

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

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

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

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

In January 2021, the U.S.

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

In April 2021, the U.S.

announced its own Nationally Determined Contribution (NDC) with respect to the Paris Agreement.

The NDC is voluntary and would aim to cut carbon dioxide output by 50% to 52% compared with 2005 levels by 2030.

Recently, the U.S.

has announced the goal of a completely emissions-free power grid by 2035, but has not provided additional, more specific information with regard to how the goal will be achieved.

The Company anticipates a series of executive actions and/or orders from the current presidential administration aimed at curbing emission levels as well as associated rulemaking using the CAA and potentially other statutory and/or spending authorities.

In October 2017, the Australian Federal Government released a plan aimed at delivering an affordable and reliable energy system that meets Australia’s international commitments to emissions reduction.

The plan was referred to as the National Energy Guarantee (NEG) and was aimed at changing the National Electricity Market and associated legislative framework.

The NEG was abandoned by the Australian government in September 2018.

Following the outcome of the federal election in May 2019, the federal government confirmed it will not revive the former NEG policy.

Instead, the government will pursue a new energy and climate change policy, which includes a $2 billion Australian dollars investment in projects to bring down Australia's greenhouse gas emissions.

The Climate Solutions Fund is an extension of the former Emissions Reduction Fund.

The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but has not formally committed to net zero emissions by 2050 with the focus of energy policy on the use of technology to accelerate the development and commercialization of low and zero emissions technologies and driving down electricity prices.

The outcome of Australia’s federal election on May 21, 2022 has the potential to impact federal environmental, taxation, labor market and other legislation governing Australian mining operations.

On March 15, 2022, the Full Court of the Federal Court of Australia overturned the decision in Sharma v Minister for the Environment [2021] FCA 560 (Sharma), a case which found in 2021 that the Federal Minister for the Environment had a duty to avoid causing personal injury or death to children in Australia as a result of carbon emissions when deciding an application to approve a coal mine expansion.

In light of this decision, the Minister no longer must consider the effects of carbon emissions when assessing referrals under the Environment Protection and Biodiversity Conservation Act 1999.

However, an application by Sharma for special leave to appeal to the High Court of Australia remains probable, and the duty could be reinstated.

As part of the Queensland Government’s 2019-20 Budget, it committed to freeze royalty rates on coal and minerals for three years provided companies voluntarily contribute to the Resources Community Infrastructure Fund.

The royalty freeze is due to end in June 2022 and the Queensland Government has not established a replacement rate.

The New South Wales Mining and Geoscience Department will be undertaking consultation with respect to the manner for calculating mining royalties in New South Wales between April and June 2022 as part of a proposed redraft of the Mining Royalties (COAL) – Ministerial Determination under Section 283(5) of the Mining Act 1992.

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, SEC 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, 2021.

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 the Company 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 carbon capture, utilization and storage (CCUS) technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal.

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.

From time to time, Peabody attempts to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies.

Such analyses require that Peabody make 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 its operations, financial condition or cash flow.

The Company does not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on its results of operations, financial condition or cash flows.

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.

On March 21, 2022, the SEC proposed rules that would require public companies to disclose extensive climate-related information in certain SEC filings.

Specifically, the proposed rules would add new Subpart 1500 to Regulation S-K and new Article 14 to Regulation S-X to require disclosure of climate-related risks that are reasonably likely to have a material impact on a public company’s business, results of operations, or financial condition;

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

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

The Company is currently assessing the potential impact of the proposed rules.

The proposal is open for public comment through at least May 21, 2022.

Liquidity and Capital Resources

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

As of September 30, 2021, the Company’s cash balances totaled $587.0 million, including approximately $265 million held by U.S.

As of March 31, 2022, the Company’s cash balances totaled $823.3 million, including approximately $331 million held by U.S.

subsidiaries, $473 million held by Australian subsidiaries, and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S.

The subsidiaries that conduct the operations of the Wilpinjong Mine held cash of approximately $145 million at September 30, 2021.

The Australian subsidiaries that conduct the operations of the Wilpinjong Mine held cash of approximately $213 million at March 31, 2022.

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

1 unchanged sentence

liquidity needs, including capital and operating expenditures in Australia.

The Company’s available liquidity declined from $728.7 million as of December 31, 2020 to $615.4 million as of September 30, 2021.

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

During the first quarter of 2022, the Company repatriated approximately $200 million.

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 declined from $995.9 million as of December 31, 2021 to $841.5 million as of March 31, 2022.

Available liquidity was comprised of the following:

September 30, 2021 December 31, 2020

March 31, 2022 December 31, 2021

(Dollars in millions)

3 unchanged sentences

Total liquidity $ 841.5 $ 995.9

The Company’s total funded indebtedness (Indebtedness) as of September 30, 2021 and December 31, 2020 is presented in the table below.

Debt Instrument (defined below, as applicable) September 30, 2021 December 31, 2020

Subsequent to March 31, 2022, the Company executed an amendment to its credit facility to reduce its capacity by approximately $17 million and to make allowable certain previously restricted payments for joint venture investments.

The amendment creates an investment basket which allows payments of $30.0 million per year specifically limited to investment in renewable energy-related projects.

Unused portions of the basket carryover from year-to-year, and the total amount of investment will further reduce the credit facility capacity by a like amount, or a minimum of $10.0 million per year, through the maturity of the credit facility.

The Company has no contractual commitment for such joint venture investment.

Margin Requirements

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

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

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

At March 4, 2022, the Company held coal derivative contracts in aggregate of 2.3 million metric tons.

The majority of these contracts were entered into in the first half of 2021 and related to 1.9 million metric tons of production at the Wambo Underground Mine in the Company’s Seaborne Thermal Mining segment, which were expected to be mined and settled at a rate of 1.2 million metric tons in 2022 and 0.7 million metric tons in 2023.

These hedge contracts were put in place to support the profitability of the mine, securing anticipated average prices of $84 per metric ton through mid-2023.

The remaining hedges relate to brokered coal transactions and other blending and optimization activities, which will settle throughout 2022.

High demand and tight supply for coal globally has resulted in a substantial rise in seaborne thermal coal prices, which has been amplified by the Russian-Ukrainian conflict resulting in unprecedented upward volatility in Newcastle coal pricing since late February.

The Newcastle financial price for March closed at $419.50 per metric ton on March 4, 2022, which was 148% above the closing index price of $169.17 per metric ton on December 31, 2021.

As a result, the Company’s total initial and variation margin requirements reached approximately $750 million during March 2022, and were $481.7 million at March 31, 2022.

Margin is returned to the Company upon reductions in the underlying market coal price or, absent such reductions, cash is recovered as the Company delivers coal into the market at spot prices.

Of the Company's total expected 2022 export sales from its Seaborne Thermal Mining segment, approximately 6% is hedged and approximately 53% is unpriced.

The unpriced volume will benefit if the current pricing environment persists.

On March 7, 2022, the Company entered into a credit agreement, by and among the Company, as borrower, Goldman Sachs Lending Partners LLC, as administrative agent, and the lenders party thereto (the Credit Agreement).

The Credit Agreement provides for a $150 million unsecured revolving credit facility (the Revolving Facility), which will mature on April 1, 2025 and bears interest at a rate of 10.0% per annum on drawn amounts.

The Revolving Facility is intended to support the Company’s near-term liquidity requirements, particularly with respect to the cash margin requirements associated with the Company’s coal derivative contracts.

Concurrently with the Credit Agreement, the Company entered into an agreement with Goldman Sachs & Company LLC to act as sales agent for at-the-market equity offerings of up to $225.0 million of the Company’s common stock.

During the three months ended March 31, 2022, the Company borrowed and repaid $225.0 million under the Revolving Facility using net proceeds of $222.0 million from at-the-market issuances of 10.1 million shares of common stock and available cash.

The equity offering agreement limit was reached as a result of these issuances and may not be further utilized without amendment and approval by the sales agent.

The Company had no outstanding borrowings and no availability under the Revolving Facility at March 31, 2022.

To reduce exposure to additional margin requirements, subsequent to March 31, 2022, the Company converted 0.8 million metric tons of financial hedges into fixed price physical sales over the next 12 months.

With these transactions, 1.4 million metric tons remain outstanding with 0.9 million metric tons projected to settle over the remainder of 2022.

On April 29, 2022, the Company had $535.9 million of margin posted.

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

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

The Company’s total funded indebtedness (Indebtedness) as of March 31, 2022 and December 31, 2021 is presented in the table below.

Debt Instrument (defined below, as applicable) March 31, 2022 December 31, 2021

(Dollars in millions)

6.000% Senior Secured Notes due March 2022 (2022 Notes)

$ 23.1 $ 459.0

8.500% Senior Secured Notes due December 2024 (2024 Peabody Notes)

10.000% Senior Secured Notes due December 2024 (2024 Co-Issuer Notes)

6.375% Senior Secured Notes due March 2025 (2025 Notes)

Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) 188.8 206.0

6.375% Senior Secured Notes due March 2025 (2025 Notes)

Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) 321.8 322.8

Revolving credit facility — 216.0

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

Finance lease obligations 27.6 29.3

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Long-term debt $ 1,079.0 $ 1,078.2

The Company’s Indebtedness was significantly impacted subsequent to December 31, 2020 as a result of various agreements and transactions described below.

Refinancing and Related Transactions

Such agreements and related activities are described below.

Organizational Realignment

In July and August 2020, the Company effected certain changes to its corporate structure in contemplation of a debt-for-debt exchange, which included, among other steps, the formation of certain wholly-owned subsidiaries (the Co-Issuers).

In connection with the change in structure, the Company’s subsidiary which owns and operates its Wilpinjong Mine in Australia became a subsidiary of the Co-Issuers.

The Co-Issuers and the Wilpinjong subsidiary were designated as unrestricted subsidiaries under the Company’s credit agreement (Credit Agreement) and its senior notes’ indenture (the Existing Indenture).

In connection with these actions, the Company contributed $100.0 million to the Co-Issuers to provide the Wilpinjong Mine with operating liquidity and address its near-term capital needs.

Surety Agreement

In November 2020, the Company entered into a surety transaction support agreement (Surety Agreement) with the providers of 99% of its surety bond portfolio (Participating Sureties) to resolve previous collateral demands made by the Participating Sureties.

In accordance with the Surety Agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit.

Upon completion of the Refinancing Transactions, as defined below, other provisions of the Surety Agreement became effective.

In particular, the Company granted second liens on $200.0 million of certain mining equipment and will post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the Participating Sureties.

The collateral postings may also further increase to the extent the Company generates more than $100.0 million of free cash flow (as defined in the Surety Agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement.

Further, the Participating Sureties have agreed to a standstill through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025), during which time, the Participating Sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves or cancel any existing surety bond.

The Company will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties.

Refinancing Transactions

On January 29, 2021 (the Settlement Date), the Company completed a series of transactions (collectively, the Refinancing Transactions) to, among other things, provide it with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity and financial flexibility.

The Refinancing Transactions included a senior notes exchange and related consent solicitation, a revolving credit facility exchange and various amendments to its existing debt agreements, as summarized below.

Exchange Offer

On the Settlement Date, the Company settled an exchange offer (Exchange Offer) pursuant to which $398.7 million aggregate principal amount of its 6.000% Senior Secured Notes due March 2022 (2022 Notes) were validly tendered, accepted by the Company and exchanged for aggregate consideration consisting of (a) $193.9 million aggregate principal amount of new 10.000% Senior Secured Notes due 2024 issued by the Co-Issuers (Co-Issuer Notes), (b) $195.1 million aggregate principal amount of new 8.500% Senior Secured Notes due 2024 issued by Peabody (Peabody Notes), and (c) a cash payment of approximately $9.4 million.

In connection with the settlement of the Exchange Offer, the Company also paid early tender premiums totaling $4.0 million in cash.

Refer to Note 11.

“Long-term Debt” for additional information associated with the Co-Issuer Notes and the Peabody Notes.

As required under the Exchange Offer, the Company purchased $22.4 million of the Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest, during the first quarter of 2021 and recognized a related net gain on extinguishment of $3.5 million.

Consent Solicitation

Concurrently with the Exchange Offer, the Company solicited consents from holders of the 2022 Notes to certain proposed amendments to the Existing Indenture to (i) eliminate substantially all of the restrictive covenants, certain events of default applicable to the 2022 Notes and certain other provisions contained in the Existing Indenture and (ii) release the collateral securing the 2022 Notes and eliminate certain other related provisions contained in the Existing Indenture.

The Company received the requisite consents from holders of the 2022 Notes and entered into a supplemental indenture to the Existing Indenture, which became operative on January 29, 2021.

Revolver Transactions

In connection with the Refinancing Transactions, the Company restructured the revolving loans under the Credit Agreement by (i) making a pay down of revolving loans thereunder in the aggregate amount of $10.0 million, (ii) the Co-Issuers incurring $206.0 million of term loans under a credit agreement, dated as of the Settlement Date (Co-Issuer Term Loans, Co-Issuer Term Loan Agreement), (iii) Peabody entering into a letter of credit facility (the Company LC Agreement), and (iv) amending the Credit Agreement (collectively, the Revolver Transactions).

The Co-Issuer Term Loans mature on December 31, 2024 and bear interest at a rate of 10.00% per annum.

On the Settlement Date, the Company entered into the Company LC Agreement with the revolving lenders party to the Credit Agreement, pursuant to which the Company obtained a $324.0 million letter of credit facility under which its existing letters of credit under the Credit Agreement were deemed to be issued.

The commitments under the Company LC Agreement mature on December 31, 2024.

Undrawn letters of credit under the Company LC Agreement bear interest at 6.00% per annum and unused commitments are subject to a 0.50% per annum commitment fee.

In connection with the Revolver Transactions, the Company amended the Credit Agreement to make certain changes in consideration of the Company LC Agreement.

After giving effect to the Revolver Transactions, there remain no revolving commitments or revolving loans under the Credit Agreement and the first lien net leverage ratio covenant was eliminated.

The Company LC Agreement requires that the Company’s restricted subsidiaries maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2024.

As such, liquidity attributable to the Co-Issuers, its subsidiaries and other unrestricted subsidiaries is excluded from the calculation.

Liquidity calculated in this manner amounted to $452.2 million at September 30, 2021.

The indenture which governs the Peabody Notes and the Company LC Agreement allow the Company to make open market debt repurchases, subject to certain limitations, including, but not limited to:

(i) the Company’s unrestricted subsidiaries’ liquidity must be greater than or equal to $200.0 million after giving effect to such repurchases and (ii) for every $4 of principal repurchased in any fiscal quarter, the Company must make an offer on a pro rata basis to purchase $1 of principal amount of debt from holders of the Peabody Notes and the priority lien obligations under the Company LC Agreement within 30 days of the end of such fiscal quarter at a price equal to the weighted average repurchase price paid over that quarter (Mandatory Repurchase Offer).

Other Debt Financing

The Refinancing Transactions did not significantly impact the Company’s existing senior secured term loan under the Credit Facility (Senior Secured Term Loan), or its $500.0 million of 6.375% senior secured notes due March 2025 (2025 Notes), but these debt instruments were impacted by subsequent financing transactions described below.

The term loan requires quarterly principal payments of $1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, through December 2024 with the remaining balance due in March 2025.

The senior secured notes require semi-annual interest payments each March 31 and September 30 until maturity.

The Company’s debt agreements impose various restrictions and limits on certain categories of payments that the Company may make, such as those for dividends, investments, and stock repurchases.

The Company is also subject to customary affirmative and negative covenants.

The Company was compliant with all covenants under its debt agreements including the minimum liquidity covenant under the Company LC Agreement at September 30, 2021.

Subsequent Financing Transactions

Subsequent to the Refinancing Transactions, the Company completed a series of financing transactions intended to improve its capital structure.

In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its common stock.

During September 2021, the Company announced that it could offer and sell up to an additional 12.5 million shares, for a total of 25.0 million shares authorized through the at-the-market offering program.

Through September 30, 2021, the Company sold approximately 17.1 million shares for net cash proceeds of $177.2 million.

Between October 1, 2021 and November 2, 2021, the Company settled sales of an additional 3.2 million shares for net proceeds of $43.4 million.

Through September 30, 2021, the Company retired $40.1 million of Peabody Notes, $19.7 million of 2025 Notes and $56.7 million of its Senior Secured Term Loan primarily through various open market purchases at an aggregate cost of $85.9 million.

During the nine months ended September 30, 2021, the Company recorded net gains on early debt extinguishment of $26.9 million related to these retirements.

Subsequent to September 30, 2021, the Company retired an additional $5.0 million of its Senior Secured Term Loan through similar open market purchases for an aggregate cost of $3.3 million.

Through September 30, 2021, the Company also completed multiple bilateral transactions with holders of the 2022 Notes, the 2025 Notes and the Peabody Notes in which the Company issued an aggregate 6.7 million shares of its common stock in exchange for $37.3 million aggregate principal amount of the 2022 Notes, $17.9 million aggregate principal amount of the 2025 Notes and $5.5 million aggregate principal amount of the Peabody Notes.

Between October 1, 2021 and November 2, 2021, the Company issued an additional 1.9 million shares of its common stock in exchange for $31.0 million aggregate principal amount of a combination of Peabody Notes and 2025 Notes.

As a result of the Company’s open market purchases of its debt during the three months ended September 30, 2021, on October 22, 2021, the Company announced a Mandatory Repurchase Offer of up to $15.8 million of Peabody Notes, at 73.590% of their aggregate accreted value, plus accrued and unpaid interest, and a concurrent repurchase offer of priority lien obligations under the Company LC Agreement.

The offers expire on November 22, 2021, unless extended by the Company.

Considering the Refinancing Transactions and the subsequent financing transactions described above, the Company expects to incur approximately $190 million of interest expense, including approximately $45 million of non-cash interest expense, during the year ended December 31, 2021.

Refer to Note 11.

“Long-term Debt” of the accompanying unaudited condensed consolidated financial statements for additional information related to the subsequent financing transactions described above.

The Company’s Indebtedness will require estimated principal and interest payments, assuming interest rates in effect at March 31, 2022, of approximately $60 million during the nine months ending December 31, 2022, and approximately $70 million in 2023, $455 million in 2024, $405 million in 2025, and $355 million thereafter.

Cash payments for interest related to the Company’s Indebtedness and financial assurance instruments amounted to $37.2 million and $56.3 million during the three months ended March 31, 2022 and 2021, respectively.

2021 Financing Activity

During the first quarter of 2021, the Company completed a series of transactions to, among other things, provide the Company with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity and financial flexibility.

These transactions included a senior notes exchange and related consent solicitation, a revolving credit facility exchange, various amendments to the Company’s existing debt agreements, and completion of a related surety transaction support agreement with the Company’s surety bond providers.

Subsequent to these transactions in the first quarter of 2021, the Company completed additional financing transactions during 2021 intended to improve its capital structure.

Such transactions included the implementation of an at-the-market equity offering program pursuant to which the Company sold approximately 24.8 million shares of common stock for net cash proceeds of $269.8 million, the retirement of $270.9 million principal amount of existing debt through various open market purchases at an aggregate cost of $232.4 million, and the issuance of an aggregate 10.0 million shares of common stock in exchange for an additional $106.1 million principal amount of existing debt through multiple bilateral transactions with debt holders.

In the event of allowable open market purchases of its debt, the terms of the 2024 Peabody Notes and the letter of credit facility entered into by the Company in connection with the 2021 financing activity (Company LC Agreement) require the Company to make a mandatory repurchase offer to those debt and lien holders.

In general, the repurchase offers equate to 25% of the principal amount of priority lien debt repurchased in the preceding quarter at a price equal to the weighted average repurchase price paid over that quarter.

The open market debt repurchases completed during the three months ended December 31, 2021 necessitated a mandatory repurchase offer of up to $38.6 million of 2024 Peabody Notes, at 94.940% of their aggregate accreted value, plus accrued and unpaid interest, and a concurrent repurchase offer of priority lien obligations under the Company LC Agreement.

The offer resulted in the valid tender and purchase of $0.1 million aggregate accreted value of 2024 Peabody Notes and $30.0 million aggregate principal and commitment amounts under the Company LC Agreement during the three months ended March 31, 2022.

The Company’s purchase of the principal and commitment amounts under the Company LC Agreement was effected by the posting of $28.5 million of collateral with the administrative agent and did not reduce the availability under the facility.

During the three months ended March 31, 2022, the Company made no other open market purchases of its debt.

The 2024 Co-Issuer Notes and the Co-Issuer Term Loans are also subject to mandatory prepayment offers at the end of each six-month period, beginning with June 30, 2021, whereby the Excess Cash Flow (as defined in the 2024 Co-Issuer Notes indenture) generated by the Wilpinjong Mine during each such period will be applied to the principal of such notes and loans on a pro rata basis, provided that the liquidity attributable to the Wilpinjong Mine would not fall below $60.0 million.

Such prepayments may be accepted or declined at the option of the debt holders.

Based upon the Wilpinjong Mine’s results for the six-month period ended December 31, 2021, a required offer to prepay $105.6 million of total principal resulted in the prepayment of $17.2 million of Co-Issuer Term Loans principal, $0.3 million of 2024 Co-Issuer Notes principal, and a related loss on early debt extinguishment of $0.5 million during the three months ended March 31, 2022.

The 2021 financing activity and related agreements are more fully described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021, as filed with the U.S.

Securities and Exchange Commission on February 18, 2022.

Retirement of 2022 Notes

On March 31, 2022, the Company retired the remaining principal balance of 2022 Notes upon maturity for $23.1 million.

3.250% Convertible Senior Notes due 2028

On March 1, 2022, through a private offering, the Company issued $320.0 million in aggregate principal amount of 3.250% Convertible Senior Notes due 2028 (the 2028 Convertible Notes).

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

The Company used the proceeds of the offering of the 2028 Convertible Notes to redeem the remaining $62.6 million of its outstanding 2024 Peabody Notes and, together with available cash, approximately $257.4 million of its outstanding 2025 Notes, and to pay related premiums, fees and expenses relating to the offering of the 2028 Convertible Notes and the redemptions.

The redemption of existing notes was deemed a debt extinguishment for accounting purposes.

The Company capitalized $11.2 million of debt issuance costs related to the offering and recognized a loss on early debt extinguishment of $23.0 million during the three months ended March 31, 2022.

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

The 2028 Convertible Notes 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 three months ended March 31, 2022, the Company incurred interest expense of $1.0 million related to the 2028 Convertible Notes.

The 2028 Convertible Notes will be convertible at the option of the holders only in the following circumstances:

(1) during any calendar quarter commencing after the calendar quarter ending on June 30, 2022, if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price for each of at least 20 trading days during the 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter;

(2) during the five consecutive business days immediately after any five consecutive trading day period (such five consecutive trading day period, the Measurement Period) in which the trading price per $1,000 principal amount of 2028 Convertible Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price per share of the Company’s common stock on such trading day and the conversion rate on such trading day;

(3) upon the occurrence of certain corporate events or distributions on the Company’s common stock;

(4) if the Company calls any 2028 Convertible Notes for redemption;

and (5) at any time from, and including, September 1, 2027 until the close of business on the second scheduled trading day immediately before the maturity date.

Upon conversion, the Company may satisfy its conversion obligation by paying or delivering, as applicable, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the indenture.

The initial conversion rate for the 2028 Convertible Notes will be 50.3816 shares of the Company’s common stock per $1,000 principal amount of 2028 Convertible Notes, which represents an initial conversion price of approximately $19.85 per share of the Company’s common stock.

The initial conversion price represents a premium of approximately 32.5% to the $14.98 per share closing price of the Company’s common stock on February 24, 2022.

The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture.

If certain corporate events described in the indenture occur prior to the maturity date, or the Company delivers a notice of redemption (as described below), the conversion rate will be increased for a holder who elects to convert its 2028 Convertible Notes in connection with such corporate event or notice of redemption, as the case may be, in certain circumstances.

The Company may not redeem the 2028 Convertible Notes prior to March 1, 2025.

The Company may redeem for cash all or any portion of the 2028 Convertible Notes, at its option, on or after March 1, 2025 and on or before the 40th scheduled trading day immediately before the maturity date, at a cash redemption price equal to 100% of the principal amount of the 2028 Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, but only if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price on (1) each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice;

and (2) the trading day immediately before the date the Company sends such notice.

However, the Company may not redeem less than all of the outstanding 2028 Convertible Notes unless at least $75 million aggregate principal amount of 2028 Convertible Notes are outstanding and not called for redemption as of the time the Company sends the related redemption notice.

No sinking fund is provided for the 2028 Convertible Notes.

If the Company undergoes a fundamental change (as defined in the indenture), noteholders may require the Company to repurchase their 2028 Convertible Notes at a cash repurchase price equal to 100% of the principal amount of the 2028 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date.

Covenant Compliance

The Company was compliant with all relevant covenants under its debt agreements at March 31, 2022, including the minimum aggregate liquidity requirement under the Company LC Agreement which requires the Company’s restricted subsidiaries to maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2024.

The Company’s restricted subsidiaries’ relevant liquidity amounted to $610.0 million at March 31, 2022.

Accounts Receivable Securitization Program

As described in Note 15.

“Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017 which currently matures in 2022.

The Company is in discussions to renew the facility prior to maturity.

The program provides for up to $250.0 million in funding, limited to the availability of eligible receivables, accounted for as a secured borrowing.

The securitization program was amended in January 2022 to extend its maturity to January 2025 and reduce the available funding capacity from $250.0 million to $175.0 million, which better aligns with the current average borrowing base.

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

Funding capacity under the program may also be utilized for letters of credit in support of other obligations.

At September 30, 2021, the Company h a d no outstanding borrowings and $133.6 million of letters of credit issued under the program, which were primarily in support of portions of the Company’s reclamation obligations.

The Company was not required to post cash collateral under the Securitization Program at September 30, 2021.

Capital Requirements

For 2021, the Company is targeting capital expenditures of approximately $200 million, which includes approximately $100 million for ongoing extension projects primarily related to its Seaborne Thermal Mining segment.

The Company has no substantial future payment requirements under U.S.

federal coal reserve leases.

Contractual Obligations

There were no material changes to the Company’s contractual obligations from the information previously provided in Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

At March 31, 2022, the Company had no outstanding borrowings and $161.8 million of letters of credit issued under the program, which were primarily in support of portions of the Company’s reclamation obligations.

The Company was required to post $24.7 million of cash collateral under the Securitization Program at March 31, 2022.

Cash Flows and Free Cash Flow

The following table summarizes the Company’s cash flows for the nine months ended September 30, 2021 and 2020, as reported in the accompanying unaudited condensed consolidated financial statements.

The following table summarizes the Company’s cash flows for the three months ended March 31, 2022 and 2021, as reported in the accompanying unaudited condensed consolidated financial statements.

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

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

Nine Months Ended September 30,

Three Months Ended March 31,

(Dollars in millions)

Net cash used in operating activities $ (18.4) $ (32.1)

Net cash used in investing activities (119.7) (159.4)

Net cash provided by financing activities 15.9 273.9

Net cash (used in) provided by operating activities $ (273.7) $ 71.0

Net cash provided by (used in) investing activities 35.2 (93.2)

Net cash provided by (used in) financing activities 132.2 (63.3)

Net change in cash, cash equivalents and restricted cash (106.3) (85.5)

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Cash, cash equivalents and restricted cash at end of period $ 848.0 $ 623.7

Net cash used in operating activities $ (18.4) $ (32.1)

Net cash used in investing activities (119.7) (159.4)

Net cash (used in) provided by operating activities $ (273.7) $ 71.0

Net cash provided by (used in) investing activities 35.2 (93.2)

Free Cash Flow $ (238.5) $ (22.2)

Operating Activities.

The decrease in net cash used in operating activities for the nine months ended September 30, 2021 compared to the same period in the prior year was driven by a year-over-year increase in operating cash flow, primarily from the Company’s mining operations ($237.7 million), partially offset by increased cash utilized to satisfy the margin requirements associated with derivative financial instruments ($224.0 million).

The increase in net cash used in operating activities for the three months ended March 31, 2022 compared to the same period in the prior year was driven by a year-over-year increase in cash utilized to satisfy the margin requirements associated with derivative financial instruments ($351.6 million).

Investing Activities.

The decrease in net cash used in investing activities for the nine months ended September 30, 2021 compared to the same period in the prior year was driven by lower capital expenditures ($19.9 million) and lower advances to related parties and joint ventures, on a net basis ($13.4 million).

The increase in net cash provided by investing activities for the three months ended March 31, 2022 compared to the same period in the prior year was driven by higher distributions from related parties and joint ventures, on a net basis ($55.2 million), higher cash receipts from the Company’s equity method investments ($44.9 million), and lower capital expenditures and payments of capital accruals ($25.0 million).

Financing Activities.

The decrease in net cash provided by financing activities for the nine months ended September 30, 2021 compared to the same period in the prior year was driven by $360.0 million of revolving loan and securitization borrowings in the prior year, higher repayments of debt principal ($52.6 million) and payments for deferred financing costs ($22.5 million) in the current year, partially offset by $177.2 million proceeds from the issuance of common stock in the current year.

The increase in net cash provided by financing activities for the three months ended March 31, 2022 compared to the same period in the prior year was driven by cash proceeds from long-term debt and common stock issuances ($545.0 million and $222.0 million, respectively), partially offset by higher repayments of debt principal ($559.7 million) and higher distributions to non-controlling interests ($13.7 million).

Off-Balance-Sheet Arrangements

In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets.

At September 30, 2021, such instruments inc lude d $1,462.4 million of surety bonds and $443.2 million o f letters of credit.

At March 31, 2022, such instruments inc lude d $1,484.9 million of surety bonds and $469.1 million o f letters of credit.

Such financial instruments provide support for its reclamation bonding requirements, lease obligations, insu rance policies and various other performance guarantees.

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The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in its condensed consolidated balance sheets.

As of September 30, 2021, the Company was party to financial instruments with off-balance-sheet risk in support of the following obligations:

As of March 31, 2022, the Company was party to financial instruments with off-balance-sheet risk in support of the following obligations:

Reclamation Health and welfare (1)

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Letters of credit outstanding under accounts receivable securitization program 134.0 17.7 10.1 — — 161.8

Other letters of credit — 1.4 — — — 1.4

1,652.1 149.0 98.8 35.9 18.2 1,954.0

17 unchanged sentences

This change in practice has had an unfavorable impact on its liquidity due to increased collateral requirements and surety and related fees.

At September 30, 2021, the Company had total asset retirement obligations of $710.2 million which were backed by a combination of surety bonds, bank guarantees and letters of credit.

At March 31, 2022, the Company had total asset retirement obligations of $724.5 million which were backed by a combination of surety bonds, bank guarantees and letters of credit.

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.

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The Company is also required under U.S.

GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities.

GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosure of contingent assets and liabilities.

On an ongoing basis, the Company evaluates its estimates.

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Actual results may differ from these estimates.

At September 30, 2021, the Company identified certain assets with an aggregate carrying value of approximately $1.1 billion in its Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S.

Thermal Mining and Corporate and Other segments whose recoverability is most sensitive to coal pricing, cost pressures, customer demand, customer concentration risk and future economic viability.

The Company conducted a review of those assets as of September 30, 2021 and determined that no impairment charges were necessary as of that date.

The Company’s critical accounting policies are discussed in Item 7.

At March 31, 2022, the Company identified certain assets with an aggregate carrying value of approximately $0.5 billion in its Other U.S.

Thermal Mining and Corporate and Other segments whose recoverability is most sensitive to customer demand, customer concentration risk and future economic viability.

The Company conducted a review of those assets as of March 31, 2022 and determined that no impairment charges were necessary as of that date.

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

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in its Annual Report on Form 10-K for the year ended December 31, 2021.

The Company’s critical accounting policies remain unchanged at September 30, 2021.

The Company’s critical accounting policies remain unchanged at March 31, 2022, and there have been no material changes in the Company’s critical accounting estimates.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

1 unchanged sentence

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis