What changed in this filing

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Item 1. Business

2022-02-18 compared with 2021-02-23 · 407 added, 431 removed, 468 unchanged (64% of the section changed)

We are a leading coal producer.

At December 31, 2020, we owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia.

Included in that count is our 50% equity interest in Middlemount Coal Pty Ltd.

(Middlemount), which owns the Middlemount Mine in Queensland, Australia.

In addition to our mining operations, we market and broker coal from other coal producers, both as principal and agent, and trade coal and freight-related contracts through trading and business offices in the U.S., Australia, China and the United Kingdom.

Throughout the year ended December 31, 2020, we idled nine individual mines for periods ranging from one week to multiple months.

Included in the count was our Shoal Creek Mine in Alabama, which was idled in October 2020 to reset the cost structure of the mine amid weak pricing and demand, and our Metropolitan Mine in New South Wales, Australia, which was idled in late December 2020.

As more fully described within “Liquidity and Capital Resources” of Part II, Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020 and the first quarter of 2021, we entered into a series of interrelated agreements with our surety bond providers, the revolving lenders under our credit agreement and certain holders of our senior secured notes to extend a significant portion of our near-term debt maturities to December 2024 and to stabilize collateral requirements for our existing surety bond portfolio.

In December 2019, after receiving the requisite regulatory and permitting approvals, we formed an unincorporated joint venture with Glencore plc (Glencore), in which we hold a 50% interest, to combine the existing operations of our Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine.

Both parties contributed mining tenements upon formation of the joint venture (United Wambo Joint Venture), and the combined operations commenced in December 2020.

As per the joint venture agreement, we fully owned and operated the Wambo Open-Cut Mine through the date combined operations commenced.

At that date, the parties contributed mining equipment and other assets, and certain additional construction and development activities are ongoing.

We proportionally consolidate the entity based upon our economic interest.

On April 13, 2016, Peabody and a majority of its wholly owned domestic subsidiaries, as well as one international subsidiary in Gibraltar (collectively with Peabody, the Debtors), filed voluntary petitions for reorganization under Chapter 11 of Title 11 of the U.S.

Code in the U.S.

Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court).

The Debtors’ Chapter 11 cases (collectively, the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al.

16-42529 (Bankr.

On March 17, 2017, the Bankruptcy Court entered an order, Docket No.

2763, confirming the Debtors’ Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan).

On April 3, 2017, (the Effective Date), the Debtors satisfied the conditions to effectiveness set forth in the Plan, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.

Peabody is a leading producer of metallurgical and thermal coal.

At December 31, 2021, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia, including a 50% equity interest in Middlemount Coal Pty Ltd.

(Middlemount).

In addition to its mining operations, the Company markets and brokers coal from other coal producers, both as principal and agent, and trades coal and freight-related contracts.

Segment and Geographic Information

As of December 31, 2020, we report our results of operations primarily through the following reportable segments:

As of December 31, 2021, Peabody reports its results of operations primarily through the following reportable segments:

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

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Refer to Part II, Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding our segments.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding the Company’s segments.

“Segment and Geographic Information” to the accompanying consolidated financial statements is incorporated herein by reference and also contains segment and geographic financial information.

Mining Locations

The maps that follow display our active mine locations as of December 31, 2020.

Also shown are the primary ports that we use for our coal exports and our corporate headquarters in St.

The maps that follow display Peabody’s active mine locations as of December 31, 2021.

Also shown are the primary ports that the Company uses for its coal exports and the Company’s corporate headquarters in St.

Louis, Missouri.

Peabody Energy Corporation 2021 Form 10-K

Peabody Energy Corporation 2020 Form 10-K

Australian Locations

Peabody Energy Corporation 2021 Form 10-K

The table below summarizes information regarding the operating characteristics of each of our mines that were active in 2020 in the U.S.

The table below summarizes information regarding the operating characteristics of each of the Company’s mines in the U.S.

and Australia.

The mines are listed within their respective mining segment in descending order, as determined by tons sold in 2020.

Segment/Mining Complex Location Mine

Method 2020 Tons Sold

(In millions)

Seaborne Thermal Mining

Wilpinjong New South Wales S D, T/S T R, EV 13.8

The mines are listed within their respective mining segment in descending order, as determined by tons produced in 2021.

Segment/Mining Complex Location Mine Type Mining Method Coal Type Primary Transport Method Processing

Plants Year Ended December 31,

2021 2020 2019

Seaborne Thermal Mining (Tons in millions)

Wilpinjong New South Wales S D, T/S T R, EV Yes 13.2 14.2 14.1

Wambo Open-Cut (1)

New South Wales S T/S T R, EV 4.0

New South Wales S T/S T R, EV Yes 2.4 4.0 3.4

Wambo Underground (2)

New South Wales U LW T, C R, EV 1.2

New South Wales U LW T, C R, EV Yes 1.4 1.5 2.2

Seaborne Metallurgical Mining

Coppabella (3)

Queensland S DL, D, T/S P R, EV 2.0

Queensland S DL, D, T/S P R, EV Yes 2.1 2.2 2.4

Queensland S D, T/S C, P, T R, EV Yes 1.3 1.2 1.7

Metropolitan (4)

New South Wales U LW C, P, T R, EV 1.4

Queensland S D, T/S C, P, T R, EV 1.0

New South Wales U LW C, P, T R, EV Yes 1.0 1.0 1.5

Shoal Creek (5)

Alabama U LW C B, EV 0.9

Alabama U LW C B, EV Yes 0.1 0.6 1.9

Millennium (6)

Queensland S HW C, P R, EV 0.3

Queensland S HW C, P R, EV No — 0.1 0.6

Middlemount (7)

Queensland S D, T/S C, P R, EV —

Queensland S D, T/S C, P R, EV Yes — — —

Powder River Basin Mining

North Antelope Rochelle Wyoming S D, DL, T/S T R 66.1

Caballo Wyoming S D, T/S T R 11.6

Rawhide Wyoming S D, T/S T R 9.5

North Antelope Rochelle Wyoming S DL, D, T/S T R No 62.8 66.1 85.3

Caballo Wyoming S D, T/S T R No 13.9 11.6 12.6

Rawhide Wyoming S D, T/S T R No 11.6 9.5 10.1

Thermal Mining

Bear Run Indiana S DL, D, T/S T Tr, R 5.7

El Segundo/Lee Ranch New Mexico S D, DL, T/S T R 4.6

Wild Boar Indiana S D, T/S, HW T Tr, R, R/B, T/B 2.0

Gateway North Illinois U CM T Tr, R, R/B, T/B 1.9

Francisco Underground Indiana U CM T R 1.8

Twentymile Colorado U LW T R, Tr 1.6

Bear Run Indiana S DL, D, T/S T Tr, R Yes 6.0 5.2 6.8

El Segundo/Lee Ranch New Mexico S DL, D, T/S T R No 3.7 4.6 5.5

Wild Boar Indiana S D, T/S, HW T Tr, R, R/B, T/B Yes 2.4 2.0 2.5

Gateway North Illinois U CM T Tr, R, R/B, T/B Yes 1.8 1.8 3.0

Twentymile Colorado U LW T R, Tr Yes 1.7 1.2 2.6

Francisco Underground Indiana U CM T R Yes 1.5 1.6 2.0

Somerville Central (6)

Indiana S DL, D, T/S T R, R/B, T/B, T/R 0.5

Wildcat Hills Underground (8)

Illinois U CM T T/B 0.2

Indiana S DL, D, T/S T R, R/B, T/B, T/R No — 0.4 1.2

Arizona S DL, T/S T R No — — 3.8

Wildcat Hills

Underground (8)

Illinois U CM T T/B No — — 1.4

Cottage Grove (8)

Illinois S D, T/S T T/B No — — 0.1

S Surface Mine B Barge

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R Rail P Pulverized Coal Injection

(1) In December 2020, the United Wambo Joint Venture began joint production.

The tons shown reflect our proportionate share throughout the year.

(1) In December 2020, the United Wambo Joint Venture, an unincorporated joint venture between Peabody and Glencore plc, began joint production.

The tons shown reflect Peabody’s proportionate share throughout the years.

The Company’s 50% joint venture interest is subject to an outside non-controlling ownership interest.

(2) Majority-owned mine in which there is an outside non-controlling ownership interest.

(3) We own a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines.

The tons shown reflect our share.

(4) Mine was idled during the fourth quarter of 2020.

(5) Mine ceased production in March 2020, with sales continuing throughout May 2020.

(6) We own a 50% equity interest in Middlemount, which owns the Middlemount Mine.

Because that entity is accounted for as an unconsolidated equity affiliate, 2020 tons sold from that mine, which totaled 3.2 million tons (on a 100% basis), have been excluded from the table above.

(7) Mine ceased production in December 2020, with sales continuing into January 2021.

(8) Mine ceased production in December 2019, with sales continuing throughout April 2020.

Refer to the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table within Part I, Item 2.

“Properties,” which is incorporated by reference herein, for additional information regarding coal reserves, product characteristics and production volume associated with each mine.

(3) Peabody owns a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines.

The tons shown reflect its share.

(4) The mine was idled in the fourth quarter of 2020.

The mine restarted production in the second quarter of 2021.

(5) The mine was idled in the fourth quarter of 2020.

The mine restarted production in November 2021.

(6) The mine ceased production during 2020.

(7) Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine.

Because Middlemount is accounted for as an unconsolidated equity affiliate, the table above excludes tons produced from that mine, which totaled 2.0 million, 1.6 million and 1.4 million tons, respectively (on a 50% basis).

(8) The mine ceased production in 2019.

Refer to the Reserves and Resources tables within Item 2.

“Properties,” which is incorporated by reference herein, for additional information regarding coal reserves and resources, and product characteristics associated with each mine.

Peabody Energy Corporation 2021 Form 10-K

Coal Supply Agreements

Our coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers.

Most of our sales from our mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions).

A smaller portion of our sales from our mining operations are made under contracts with terms of less than one year, including sales made on a spot basis.

Sales under long-term coal supply agreements comprised approximately 89%, 88% and 87% of our worldwide sales from our mining operations (by volume) for the years ended December 31, 2020, 2019 and 2018, respectively.

A recent trend has been for our customers under long-term coal supply agreements to seek contracts of shorter duration.

For the year ended December 31, 2020, we derived 32% of our revenues from coal supply agreements from our five largest customers.

Peabody’s coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers.

Most of the Company’s sales from its mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions).

A smaller portion of the Company’s sales from its mining operations are made under contracts with terms of less than one year, including sales made on a spot basis.

Sales under long-term coal supply agreements comprised approximately 84%, 89% and 88% of the Company’s worldwide sales from its mining operations (by volume) for the years ended December 31, 2021, 2020 and 2019, respectively.

For the year ended December 31, 2021, Peabody derived 26% of its revenues from coal supply agreements from its five largest customers.

Those five customers were supplied primarily from 17 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2022 to 2026.

Our largest customer in 2020 contributed revenue of approximately $264 million, or approximately 9% of our total revenues from coal supply agreements, and has contracts expiring at various times from 2021 to 2023.

Our sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 264 million and 327 million tons of coal as of January 1, 2021 and 2020, respectively.

Contracts in backlog have remaining terms ranging from one to six years and represent approximately two years of production based on our 2020 production volume of 128.8 million tons.

Approximately 62% of our backlog is expected to be filled beyond 2021.

Peabody’s largest customer in 2021 contributed revenue of approximately $258 million, or approximately 8% of Peabody’s total revenues from coal supply agreements, and has contracts expiring at various times from 2022 to 2025.

Peabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 283 million and 264 million tons of coal as of January 1, 2022 and 2021, respectively.

Contracts in backlog have remaining terms ranging from one to nine years and represent approximately two years of production based on the Company’s 2021 production volume of 126.9 million tons.

Approximately 57% of its backlog is expected to be filled beyond 2022.

Seaborne Mining Operations.

Revenues from our Seaborne Thermal Mining and Seaborne Metallurgical Mining segments represented approximately 42%, 45% and 48% of our total revenues from coal supply agreements for the years ended December 31, 2020, 2019 and 2018, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 19%, 17% and 16% of our sales volumes from mining operations.

Our production is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically.

Industry commercial practice, and our typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a quarterly, spot or index basis.

For our seaborne mining operations, the portion of sales volume under contracts with a duration of less than one year represented 39% in 2020.

Revenues from Peabody’s Seaborne Thermal Mining and Seaborne Metallurgical Mining segments represented approximately 50%, 42% and 45% of its total revenues from coal supply agreements for the years ended December 31, 2021, 2020 and 2019, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 18%, 19% and 17% of its sales volumes from mining operations.

The Company’s production is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically.

Industry commercial practice, and Peabody’s typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a bi-annual, quarterly, spot or index basis.

For its seaborne mining operations, the portion of sales volume under contracts with a duration of less than one year represented 45% in 2021.

Thermal Mining Operations.

Revenues from our Powder River Basin Mining and Other U.S.

Thermal Mining segments, in aggregate, represented approximately 58%, 55% and 52% of our revenues from coal supply agreements for the years ended December 31, 2020, 2019 and 2018, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 81%, 83% and 84% of our sales volumes from mining operations.

We expect to continue selling a significant portion of coal production from our U.S.

Revenues from Peabody’s Powder River Basin Mining and Other U.S.

Thermal Mining segments, in aggregate, represented approximately 50%, 58% and 55% of its revenues from coal supply agreements for the years ended December 31, 2021, 2020 and 2019, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 82%, 81% and 83% of its sales volumes from mining operations.

The Company expects to continue selling a significant portion of coal production from its U.S.

thermal mining segments under existing long-term supply agreements.

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The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers.

Consequently, the terms of those agreements may vary in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions.

Our approach is to selectively renew, or enter into new, long-term supply agreements when we can do so at prices and terms and conditions we believe are favorable.

However, recent trends indicate that customers may be less likely to enter into long-term supply agreements prospectively, driven by the reduced utilization of plants and plant retirements, sustained low natural gas pricing and the increased use of renewable energy sources.

Consequently, the terms of those agreements may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions.

Peabody’s approach is to selectively renew, or enter into new, long-term supply agreements when it can do so at prices and terms and conditions it believes are favorable.

However, recent trends indicate that customers may be less likely to enter into long-term supply agreements prospectively, driven by the reduced utilization of plants and plant retirements, fluidity of natural gas pricing and the increased use of renewable energy sources.

Transportation

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is usually sold at the mine with transportation costs borne by the purchaser.

Peabody’s U.S.

mine sites are typically adjacent to a rail loop;

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Title predominately passes to the purchaser at the rail or barge, as applicable.

Peabody’s U.S.

and Australian export coal is usually sold at the loading port, with purchasers paying ocean freight.

In each case, we usually pay transportation costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).

We believe we have good relationships with U.S.

and Australian rail carriers and port and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators.

In each case, the Company usually pays transportation costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).

The Company believes it has good relationships with U.S.

and Australian rail carriers and port and barge companies due, in part, to its modern coal-loading facilities and the experience of its transportation coordinators.

Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.

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Export Facilities.

We have generally secured our ability to transport coal in Australia through rail and port contracts and access to five east coast coal export terminals that are primarily funded through take-or-pay arrangements (refer to the “Liquidity and Capital Resources” section in Part II, Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on our take-or-pay obligations).

In Queensland, seaborne thermal and metallurgical coal from our mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by our joint venture Middlemount Mine.

In New South Wales, our primary ports for exporting thermal and metallurgical coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group.

We have secured our ability to transport coal from our Shoal Creek Mine under barge and port contracts;

the primary port is the McDuffie Terminal in Mobile, Alabama, which we utilize without a take-or-pay arrangement.

thermal mining operations exported less than 1% and approximately 1% of its annual tons sold during the years ended December 31, 2019 and 2018, respectively.

Peabody has generally secured its ability to transport coal in Australia through rail and port contracts and access to five east coast coal export terminals that are primarily funded through take-or-pay arrangements (refer to the “Liquidity and Capital Resources” section in Part II, Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on its take-or-pay obligations).

In Queensland, seaborne thermal and metallurgical coal from the Company’s mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by its joint venture Middlemount Mine.

In New South Wales, the Company’s primary ports for exporting thermal and metallurgical coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group.

Peabody has secured its ability to transport coal from its Shoal Creek Mine under barge and port contracts;

the primary port is the McDuffie Terminal in Mobile, Alabama, which the Company utilizes without a take-or-pay arrangement.

Peabody’s U.S.

thermal mining operations exported less than 1% of its annual tons sold during both the years ended December 31, 2021 and 2019.

No tons were exported during the year ended December 31, 2020.

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Mining Supplies and Equipment.

The principal goods we purchase in support of our mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (including roof control materials), lubricants and electricity.

We have many well-established, strategic relationships with our key suppliers of goods and do not believe that we are overly dependent on any of our individual suppliers.

In situations where we have elected to concentrate a large portion of our purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases, benefit from long-term pricing for parts and ensure security of supply.

Supplier concentration related to our mining equipment also allows us to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across our global platform, enhancing our flexibility to move equipment between mines and reduce working capital through inventory optimization.

Surface and underground mining equipment demand and lead times have remained steady in recent periods.

We consistently use our global leverage with major suppliers to ensure security of supply to meet the requirements of our active mines.

We also purchase services at our mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements.

We do not believe that we have undue operational or financial risk associated with our dependence on any individual service providers.

Demand for coal and the prices that we will be able to obtain for our coal are highly competitive and influenced by factors beyond our control, including but not limited to global economic conditions;

The principal goods Peabody purchases in support of its mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (including roof control materials), lubricants and electricity.

Peabody has many well-established, strategic relationships with its key suppliers of goods and does not believe that it is overly dependent on any of its individual suppliers.

In situations where Peabody has elected to concentrate a large portion of its purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases, benefit from long-term pricing for parts and ensure security of supply.

Supplier concentration related to the Company’s mining equipment also allows it to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across its global platform, enhancing its flexibility to move equipment between mines and reduce working capital through inventory optimization.

Surface and underground mining equipment demand and lead times have increased in recent periods.

Peabody consistently uses its global leverage with major suppliers and comprehensive planning processes to ensure security of supply to meet the requirements of its active mines.

Peabody also purchases services at its mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements.

Peabody does not believe that it has undue operational or financial risk associated with its dependence on any individual service providers.

Demand for coal and the prices that the Company will be able to obtain for its coal are highly competitive and influenced by factors beyond the Company’s control, including but not limited to global economic conditions;

the demand for electricity and steel;

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and foreign governments.

Demand for our thermal coal products is impacted by economic conditions;

Thermal Coal.

Demand for Peabody’s thermal coal products is impacted by economic conditions;

demand for electricity, which is impacted by energy efficient products;

and the cost of electricity generation from coal and alternative forms of generation.

Our products compete with producers of other forms of electricity generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use.

The use and price of thermal coal is heavily influenced by the availability and relative cost of alternative fuel sources and the generation of electricity utilizing alternative fuels, with customers focused on securing the lowest cost fuel supply in order to coordinate the most efficient utilization of generating resources in the economic dispatch of the power grid at the most competitive price.

Regulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption.

Peabody Energy Corporation 2020 Form 10-K

The Company’s products compete with producers of other forms of electricity generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use.

In the U.S., natural gas is highly competitive (along with other alternative fuel sources) with thermal coal for electricity generation.

The competitiveness of natural gas has been strengthened by accelerated growth in domestic natural gas production and new natural gas combined cycle generation capacity, as well as comparatively low natural gas prices (versus historic levels).

The competitiveness of natural gas has been strengthened by accelerated growth in domestic natural gas production and new natural gas combined cycle generation capacity.

The Henry Hub Natural Gas Prompt Price averaged $3.72 per mmBtu in 2021, versus $2.13 and $2.53 per mmBtu in 2020 and 2019, respectively.

The growth in domestic natural gas production and logistical constraints has led to discounts for regional gas prices versus the Henry Hub price, further driving lower natural gas price trends.

In addition, the competitiveness of other alternative fuel sources for electricity generation has been strengthened by the growth of low-cost and government subsidized generation fueled by other alternative fuel sources.

In addition, the competitiveness of other alternative fuel sources for electricity generation has been strengthened by the growth of government subsidized renewable energy generation.

These pressures, coupled with increasing regulatory burdens, have contributed to a significant number of coal plant retirements.

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coal power capacity was retired, and since 2010, U.S.

coal power capacity has fallen by more than thirty percent.

coal power capacity has fallen by approximately thirty-two percent.

Peabody Energy Corporation 2021 Form 10-K

Internationally, thermal coal also competes with alternative forms of electricity generation.

The competitiveness and availability of natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region.

The competitiveness and availability of natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region.

Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Russia, Colombia, the U.S.

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In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, among others.

In addition to our alternative fuel source competitors, our principal U.S.

direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners, American Consolidated Natural Resources, Inc., Arch Resources, Inc., CONSOL Energy, Eagle Specialty Materials LLC, Foresight Energy, Hallador Energy, Kiewit, and Navajo Transitional Energy Company LLC, among others.

Major international direct coal supply competitors (listed alphabetically) include Adaro Energy, Anglo American plc, BHP, Bumi Resources, China Shenhua Energy, Coal India Limited, Drummond Company, Glencore, South32, SUEK, Whitehaven Coal Limited and Yancoal Australia Ltd, among others.

In addition to its alternative fuel source competitors, Peabody’s principal U.S.

direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners;

American Consolidated Natural Resources, Inc.;

Arch Resources, Inc.;

CONSOL Energy;

Eagle Specialty Materials LLC;

Foresight Energy;

Hallador Energy;

and Navajo Transitional Energy Company LLC, among others.

Major international direct coal supply competitors (listed alphabetically) include Adaro Energy;

Anglo American plc;

Bumi Resources;

China Shenhua Energy;

Coal India Limited;

Drummond Company;

Whitehaven Coal Limited;

and Yancoal Australia Ltd, among others.

Metallurgical Coal.

Demand for our metallurgical coal products is impacted by economic conditions;

Demand for Peabody’s metallurgical coal products is impacted by economic conditions;

government policies;

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and competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces.

We compete on the basis of coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.

The Company competes on the basis of coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.

Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, and the competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others.

Major international direct competitors (listed alphabetically) include Anglo American, Arch Resources, Inc., BHP, Glencore, Jellinbah, KRU, Shanxi Coking Coal Group, Teck Resources, Warrior Met Coal, Whitehaven Coal Limited and Yancoal Australia Ltd, among others.

Major international direct competitors (listed alphabetically) include Anglo American;

Arch Resources, Inc.;

Teck Resources;

Warrior Met Coal;

Whitehaven Coal Limited;

and Yancoal Australia Ltd, among others.

Cybersecurity Risk Management

We use digital technology to conduct our business operations and engage with our customers, vendors and partners.

As we implement newer technologies such as cloud, analytics, automation and “internet of things,” the threats to our business operations from cyber intrusions, denial of service attacks, manipulation and other cyber misconduct increase.

To address the risk, we continue to evolve our risk management approach in an effort to continually assess and improve our cybersecurity risk detection, deterrence and recovery capabilities.

Our cybersecurity strategy emphasizes reduction of cyber risk exposure and continuous improvement of our cyber defense and resilience capabilities.

Peabody uses digital technology to conduct its business operations and engage with its customers, vendors and partners.

As the Company implements newer technologies such as cloud, analytics, automation and “internet of things,” the threats to its business operations from cyber intrusions, denial of service attacks, manipulation and other cyber misconduct affecting both the Company and its partners’ technologies increase.

To address the risk, the Company continues to evolve its risk management approach in an effort to continually assess and improve its cybersecurity risk detection, deterrence and recovery capabilities.

Peabody’s cybersecurity strategy emphasizes reduction of cyber risk exposure and continuous improvement of its cyber defense and resilience capabilities.

These include:

(i) proactive management of cyber risk to ensure compliance with contractual, legal and regulatory requirements, (ii) performing due diligence on third parties to ensure they have sound cybersecurity practices in place, (iii) ensuring essential business services remain available during a business disruption, (iv) implementing data policies and standards to protect sensitive company information and (v) exercising cyber incident response plans and risk mitigation strategies to address potential incidents should they occur.

For more information regarding the risks associated with these matters, see “Item 1A.

Risk Factors.”

Peabody Energy Corporation 2020 Form 10-K

During 2021, a software vendor that provides cloud services to the Company for its payroll function suffered a significant ransomware attack.

The Company’s mitigation actions were adequate to avoid significant operational disruptions or material financial losses.

Human Capital

We had approximately 4,600 employees as of December 31, 2020, including approximately 3,500 hourly employees.

Additional information on our employees and related labor relations matters is contained in Note 22.

Peabody had approximately 4,900 employees as of December 31, 2021, including approximately 3,900 hourly employees.

Additional information on its employees and related labor relations matters is contained in Note 21.

“Management — Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference.

During the year ended December 31, 2020, we reduced our global headcount by nearly 2,000 employees, in both operational and non-operational positions, representing approximately 30% of our workforce.

The reductions were made in connection with our cost repositioning efforts to appropriately align our cost structure and optimize our coal production relative to prevailing market conditions.

As of December 31, 2020, approximately 2,900 of our employees are located in the U.S., with the remainder primarily located in Australia.

About 92% of our team members work for mine operations in the U.S.

and Australia, while the remaining are employed at our global headquarters in St.

Peabody endeavors to engage with its organized workforce and foster strong relationships with those organizations built on trust and communication, which was evidenced in 2021 by successful labor negotiations at its Shoal Creek, Wambo and Metropolitan Mines.

As of December 31, 2021, approximately 3,300 of Peabody’s employees are located in the U.S., with the remainder primarily located in Australia.

About 94% of its team members work for mine operations in the U.S.

and Australia, while the remaining are employed at its global headquarters in St.

Louis or other business offices.

We strive to create a strong, united workforce with a commitment to safety as a way of life.

In 2020, we achieved a global safety incidence rate of 1.67 incidents per 200,000 hours worked, which was 43% better than the 2019 U.S.

Peabody Energy Corporation 2021 Form 10-K

Peabody strives to create a strong, united workforce with a commitment to safety as a way of life.

In 2021, the Company achieved a global safety incidence rate of 1.18 incidents per 200,000 hours worked, which was 56% better than the 2020 U.S.

industry average incidence rate of 2.69 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).

We offer an inclusive work environment and engage, recognize and develop employees.

We seek a workforce that is comprised of diverse backgrounds, thoughts and experiences.

Our company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities.

We believe in fostering an inclusive work environment built on mutual trust, respect and engagement.

We invest in our employees through health and wellness programs, competitive total rewards and development opportunities.

The typical Peabody employee has approximately nine years of experience with the company, and more than 60% of all Peabody employees remain employed with the company for more than five years.

We offer a variety of learning events, including mentoring and development programs to aid our employees in their career growth.

Peabody strives to offer an inclusive work environment and engages, recognizes and develops employees.

Peabody seeks a workforce that is comprised of diverse backgrounds, thoughts and experiences as a means to drive innovation and excellence within its business, and has formalized inclusion programs and training in policy and practice.

The Company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities.

Peabody believes in fostering an inclusive work environment built on mutual trust, respect and engagement.

Peabody invests in its employees through health and wellness programs, competitive total rewards and development opportunities.

Peabody actively seeks employees' feedback, including through surveys and focus groups on its employee value proposition.

The typical Peabody employee has approximately eight years of experience with the company, and more than 51% of all Peabody employees remain employed with the company for more than five years.

The Company offers a variety of learning events, including mentoring and development programs to aid its employees in their career growth.

During the past five years, approximately 32% of open positions and 72% of director and above positions have been filled by internal candidates through promotions and lateral career development opportunities.

Information About Our Executive Officers

Set forth below are the names, ages and positions of our executive officers.

Executive officers are appointed by, and hold office at the discretion of, our Board of Directors, subject to the terms of any employment agreements.

Kellow 53 President and Chief Executive Officer

Set forth below are the names, ages and positions of Peabody’s executive officers.

Executive officers are appointed by, and hold office at the discretion of, Peabody’s Board of Directors, subject to the terms of any employment agreements.

Grech 60 President and Chief Executive Officer

Spurbeck 48 Executive Vice President and Chief Financial Officer

Jarboe 47 Chief Legal Officer and Corporate Secretary

Jarboe 48 Chief Administrative Officer and Corporate Secretary

Yeates 61 Executive Vice President and Chief Operating Officer

Richard 61 Senior Vice President and Chief Human Resources Officer

Hathhorn 50 President - Australian Operations

Kemal Williamson 61 President - U.S.

Hathhorn 51 President - U.S.

Jamie Frankcombe 61 President - Australian Operations

Forkin III 63 Senior Vice President - Corporate Development and Strategy

(1) As of February 11, 2022.

Kellow was named our President and Chief Operating Officer in August 2013;

our President, Chief Executive Officer-elect and a director in January 2015;

and our President and Chief Executive Officer in May 2015.

Kellow’s career experience enables him to provide the Company with valuable insights from miner, competitor fuel and industrial customer perspectives.

From 1985 to 2013, he worked for BHP Ltd.

in the United States, Australia and South America.

Kellow has held chief executive leadership, operating and financial roles in global business in the coal, copper, nickel, aluminum, steel, oil and gas sectors.

He serves as a Vice Chairman of the U.S.

National Mining Association and a director and former Chairman of the World Coal Association.

Kellow is a graduate of the Advanced Management Program at the University of Pennsylvania’s Wharton School of Business and holds a Master of Business Administration Degree and a Bachelor’s Degree in Commerce from the University of Newcastle.

He also holds an honorary Doctor of Science degree from the South Dakota School of Mines and Technology.

Peabody Energy Corporation 2020 Form 10-K

Spurbeck was named our Executive Vice President and Chief Financial Officer in June 2020, after serving in an interim capacity from January 2020 through June 2020.

He oversees finance, treasury, tax, internal audit, financial reporting, financial planning, risk and mine finance, corporate accounting functions and investor relations and corporate communications.

Grech was named Peabody’s President and Chief Executive Officer in June 2021.

He has over 30 years of experience in the natural resources industry.

Grech served as Chief Executive Officer and a member of the Board of Directors of Wolverine Fuels, LLC, a thermal coal producer and marketer based in Sandy, Utah, from July 2018 until May 2021.

Prior to joining Wolverine Fuels, LLC, Mr.

Grech served as President of Nexus Gas Transmission from October 2016 to July 2018, and previously held the position of Chief Commercial Officer and Executive Vice President of Consol Energy.

Grech brings a strong operational, commercial and financial background in both mining and other energy business operations and has extensive utilities and capital markets experience.

He serves as a director of Blue Danube.

Grech holds a Bachelor of Science in Electrical Engineering from Lawrence Technological University and an MBA from the University of Michigan.

Spurbeck was named Peabody’s Executive Vice President and Chief Financial Officer in June 2020, after serving in an interim capacity from January 2020 through June 2020.

He oversees finance, treasury, tax, internal audit, financial reporting, financial planning, risk and mine finance, corporate accounting functions, investor relations and corporate communications, information technology and shared services.

Spurbeck has more than 25 years of accounting and financial experience, most recently serving as the Company’s Senior Vice President and Chief Accounting Officer from early 2018 to January 2020.

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Spurbeck is a Certified Public Accountant and holds a Bachelor’s Degree in Accounting from Hillsdale College.

Jarboe was named our Chief Legal Officer and Corporate Secretary in March 2020.

In this role, he has executive responsibility for providing comprehensive legal counsel for Peabody’s business activities and leads the Company’s global legal and compliance functions.

Jarboe was named Peabody’s Chief Administrative Officer and Corporate Secretary in November 2021 after serving as Chief Legal Officer and Corporate Secretary since March 2020.

He leads the Company’s global human resources, legal, government affairs, and ethics and compliance functions.

Jarboe joined Peabody in 2010 and has served in a variety of legal roles.

He most recently led the Litigation, Disputes and Labor & Employment activities for Peabody.

Prior to joining Peabody, Mr.

Previously, Mr.

Jarboe practiced law with Husch Blackwell LLP and Bryan Cave LLP.

Jarboe holds a Bachelor of Arts Degree from the University of Kansas, a Master’s Degree from the University of Missouri – Kansas City and a Juris Doctor degree from Washington University School of Law.

Yeates was named our Executive Vice President and Chief Operating Officer in October 2020.

Peabody Energy Corporation 2021 Form 10-K

Yeates was named Peabody’s Executive Vice President and Chief Operating Officer in October 2020.

He has executive responsibility for operations, sales and marketing and technical services.

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He has an Executive MBA from the Monash Mt Eliza Business School and is a Fellow of the Australian Institute of Company Directors.

Richard was named our Senior Vice President and Chief Human Resources Officer in November 2017.

He has executive responsibility for organizational and employee development, benefits, compensation, international human resources, security, travel and facilities management.

Richard has more than 30 years of human resources experience and has been instrumental in leading his prior organizations to achieve Great Place to Work and Top Training Organization designations.

From 2002 to May 2017, Mr.

Richard served as Vice President - Human Resources for Shaw Industries Group, Inc., a leading flooring materials producer and a subsidiary of Berkshire Hathaway, Inc.

Prior to that, he served as a human resources leader for 19 years at Ferro Corporation, a global supplier of technology-based manufacturing, including four years as Vice President - Human Resources.

Richard holds a Bachelor of Science Degree in Management and a Masters of Business Administration Degree from Louisiana Tech University.

Hathhorn was named our President - Australian Operations in August 2019.

He has executive responsibility for our Australian operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions.

Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America.

Hathhorn joined us in 2011 as our Senior Vice President - Midwest Operations, and subsequently served as our Group Executive - Americas Operations Support from 2013 to 2016, and Group Executive - Americas Operations from 2016 until assuming his current role.

Hathhorn was named Peabody’s President - U.S.

Operations in November 2021.

He has executive responsibility for the Company’s U.S.

operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions.

Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America and in Australia.

Hathhorn joined Peabody in 2011 as Senior Vice President - Midwest Operations, and subsequently served as Group Executive - Americas Operations Support from 2013 to 2016, Group Executive - Americas Operations from 2016 to 2019 and President - Australian Operations until assuming his current role.

Previously, Mr.

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Hathhorn holds a Bachelor of Science Degree in Mining Engineering from the University of Idaho, College of Mines.

Peabody Energy Corporation 2020 Form 10-K

Kemal Williamson was named our President - Americas in October 2012 and his title was updated to President - U.S.

Operations in June 2019.

He has executive responsibility for our U.S.

operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions.

Williamson has more than 30 years of experience in mining engineering and operations roles across North America and Australia.

He most recently served as Group Executive of Operations for the Peabody Energy Australia operations.

He also has held executive leadership roles across project development, as well as in positions overseeing our Powder River Basin and Other U.S.

Thermal operations.

Williamson joined us in 2000 as Director of Land Management.

Prior to that, he served for two years at Cyprus Australia Coal Corporation as Director of Operations and managed coal operations in Australia for half a decade.

He also has mining engineering, financial analysis and management experience across Colorado, Kentucky and Illinois.

Williamson holds a Bachelor of Science Degree in Mining Engineering from Pennsylvania State University as well as a Master of Business Administration Degree from the Kellogg School of Management, Northwestern University in Evanston, Illinois.

Jamie Frankcombe was named Peabody’s President - Australian Operations in November 2021.

He has executive responsibility for the Company’s Australian operating platform, which includes overseeing the areas of health and safety, environment, people, operational performance and product delivery.

He is a senior mining executive with 30 years of experience in developing and managing large-scale open cut and underground coal, iron ore, copper and gold mines in Australia, Indonesia, Asia and the Americas.

Prior to joining Peabody, Mr.

Frankcombe served as Deputy Managing Director for Phu Bia Mining in Laos managing the Phu Kham (copper & gold) and Ban Houayxai (gold & silver) operating assets from June 2021 to November 2021.

Prior to that, Mr.

Frankcombe served as Integration Team Lead with Aurelia Metals Ltd from November 2020 to April 2021 with the responsibility of integrating the Dargues Gold Mine project and operations into the Aurelia Metals Ltd portfolio.

Prior to that, he spent seven years as Chief Operating Officer for Whitehaven Coal Mining Ltd., overseeing operational and safety leadership of four open cut coal mines and one underground mine.

In addition, he served as a director of Coal Services Pty Ltd.

from September 2017 to July 2021.

Frankcombe holds an Honours Degree in Engineering (Mining) and a Masters in Business Administration (Technology).

Forkin III joined Peabody in 2010 and was named Senior Vice President - Corporate Development and Strategy in November 2017.

He has executive responsibility for mergers and acquisitions, portfolio management, global strategy, U.S.

thermal coal sales and renewable energy development.

Forkin has an extensive background in corporate finance, the energy industry, mergers and acquisitions and equity market research.

Prior to joining Peabody, Mr.

Forkin was in senior leadership roles at a U.S.

solar development company and investment banking firms specializing in renewable and conventional energy.

He spent the first nine years of his career at Deloitte LLP.

Forkin holds a Bachelor of Science degree in Accountancy from the University of Illinois at Urbana-Champaign and is a Certified Public Accountant (inactive).

Regulatory Matters — U.S.

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Numerous federal, state and local governmental permits and approvals are required for mining operations.

We believe that we have obtained all permits currently required to conduct our present mining operations.

We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations.

Peabody believes that it has obtained all permits currently required to conduct its present mining operations.

The Company endeavors to conduct its mining operations in compliance with all applicable federal, state and local laws and regulations.

However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry.

Peabody Energy Corporation 2021 Form 10-K

Mine Safety and Health

We are subject to health and safety standards both at the federal and state level.

Peabody is subject to health and safety standards both at the federal and state level.

The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.

The MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards.

MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards.

MSHA employs various enforcement measures for noncompliance, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine.

In Part I, Item 4.

“Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, we provide additional details on MSHA compliance.

“Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, the Company provides additional details on MSHA compliance.

Black Lung (Coal Workers’ Pneumoconiosis)

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however, the approval rate has increased following implementation of black lung provisions contained in the Affordable Care Act.

The Affordable Care Act included significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.

The trust fund has been funded by an excise tax on U.S.

In 2008, the excise tax rates were set through December 31, 2018 at $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

On January 1, 2019 the rate reverted back to $0.50 per ton of underground coal and $0.25 per ton of surface coal, not to exceed 2% of the gross sales price.

In December of 2019, legislation was passed that increased the rate for the year ending December 31, 2020.

The enacted legislation mandates the previous rates of $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

We recognized expense related to the tax of $53.3 million, $31.4 million and $78.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Peabody Energy Corporation 2020 Form 10-K

The Affordable Care Act includes significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.

These changes could have a material impact on our costs expended in association with the federal black lung program.

As a result of legislation enacted in December of 2020, the excise tax rates were set at 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal for the year ending December 31, 2021.

This enacted legislation expired on December 31, 2021 and the excise tax rates reverted back to 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal.

On December 2, 2021 the Government Accountability Office (GAO) published a report titled “Black Lung Benefits Program:

Continued Inaction on Coal Operator Self-Insurance Increases Financial Risk to Trust Fund.” This report notes that the Department of Labor (DOL) took some steps to improve its oversight of self-insured coal mine operators, but these efforts were complicated by the COVID-19 pandemic.

The GAO states in the report that the DOL has not taken necessary action to prevent additional benefit liabilities from being transferred to the trust fund and recommends that the DOL act on recommendations made in 2020.

Subsequently, the Office of Workers' Compensation Programs (OWCP) indicated that it plans to issue a Notice of Proposed Rulemaking in the upcoming months to update its regulations authorizing coal producers to self-insure and for determining appropriate security amounts, and that it plans to solicit public comments for that proposal.

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

OWCP recently requested the Company to refile its application for self-insurance.

Peabody recognized expense related to the tax of $51.5 million, $53.3 million and $31.4 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Environmental Laws and Regulations

We are subject to various federal, state, local and tribal environmental laws and regulations.

These laws and regulations place substantial requirements on our coal mining operations, and require regular inspection and monitoring of our mines and other facilities to ensure compliance.

We are also affected by various other federal, state, local and tribal environmental laws and regulations that impact our customers.

Temporary Enforcement Policy.

On March 26, 2020, the United States Environmental Protection Agency (EPA) announced a temporary policy regarding EPA enforcement of environmental legal obligations as a result of the COVID-19 pandemic.

(COVID-19 Implications for EPA’s Enforcement and Compliance Assurance Program).

Under the temporary policy, the EPA exercised enforcement discretion for certain noncompliance events that occurred during the period of time that the temporary policy was in effect and that resulted from the COVID-19 pandemic.

The EPA’s temporary policy did not provide leniency for intentional criminal violations of law and imposed conditions on any violation that may result in “acute risk or an imminent threat to human health or the environment.” The policy also did not apply to activities that were carried out under Superfund and Resource Conservation and Recovery Act (RCRA) Corrective Action enforcement instruments.

The EPA's temporary policy became effective on March 13, 2020 and remained in effect until August 31, 2020.

Peabody is subject to various federal, state, local and tribal environmental laws and regulations.

These laws and regulations place substantial requirements on its coal mining operations, and require regular inspection and monitoring of its mines and other facilities to ensure compliance.

The Company is also affected by various other federal, state, local and tribal environmental laws and regulations that impact its customers.

Surface Mining Control and Reclamation Act .

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Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority, with oversight from OSMRE.

States in which we have active mining operations have achieved primacy control of enforcement through federal authorization.

In Arizona, where we will be performing reclamation work on tribal lands, we are regulated by the OSMRE because the tribes do not have SMCRA authorization.

States in which Peabody has active mining operations have achieved primacy control of enforcement through federal authorization.

In Arizona, where Peabody will be performing reclamation work on tribal lands, the Company is regulated by the OSMRE because the tribes do not have SMCRA authorization.

Peabody Energy Corporation 2021 Form 10-K

SMCRA provides for three categories of bonds:

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A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.

Our total reclamation bonding requirements in the U.S.

The Company’s total reclamation bonding requirements in the U.S.

were $1,054.5 million as of December 31, 2021.

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The cost calculation for each bond must be completed according to the regulatory authority of each state or OSMRE.

Our asset retirement obligations calculated in accordance with generally accepted accounting principles for our U.S.

The Company’s asset retirement obligations calculated in accordance with generally accepted accounting principles for its U.S.

operations were $518.6 million as of December 31, 2021.

The bond requirement amount for our U.S.

The bond requirement amount for the Company’s U.S.

operations significantly exceeds the financial liability for final mine reclamation because the asset retirement obligation liability is discounted from the end of the mine’s economic life to the balance sheet date in recognition that the final reclamation cash outlay is projected to be a number of years away.

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Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation bonding requirements.

In situations where our coal resources are federally owned, the U.S.

In situations where the Company’s coal resources are federally owned, the U.S.

Bureau of Land Management oversees a substantive exploration and leasing process.

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Federal coal leases also require an approved federal mining permit under the signature of the Assistant Secretary of the Department of the Interior.

Peabody Energy Corporation 2020 Form 10-K

The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S.

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The fee amount can change periodically based on changes in federal legislation.

Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2012 through September 30, 2021, the fee is $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively.

We recognized expense related to the fees of $28.4 million, $36.5 million and $40.9 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2012 through September 30, 2021, the fee was $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively.

As a result of the Abandoned Mine Land Reclamation Amendments of 2021, which Congress enacted on November 15, 2021 as part of the Infrastructure Investment and Jobs Act, from October 1, 2021 through September 30, 2034, the fee is $0.224 and $0.096 per ton of surface-mined and underground-mine coal, respectively.

The Company recognized expense related to the fees of $27.0 million, $28.4 million and $36.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Clean Air Act (CAA) .

The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect our U.S.

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.

Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), nitrogen dioxide, ozone and sulfur dioxide (SO 2 ).

In recent years, the EPA has adopted more stringent national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO 2 .

It is possible that these modifications, as well as future modifications to NAAQS, could directly or indirectly impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle and/or engine emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.

In 2009, the EPA adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008.

The PM NAAQS was thereafter revised and made more stringent in 2012.

In 2015, the EPA issued a final rule setting the ozone NAAQS at 70 parts per billion (ppb).

The primary ozone standard was upheld by the United States Court of Appeals for the D.C.

National Ambient Air Quality Standards (NAAQS).

The 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.

Fifteen states and other petitioners have filed a petition for review of the rule in the United States Court of Appeals for the D.C.

Circuit (D.C.

Circuit) in Murray Energy v.

2019), Slip Op.

The court, however, remanded the secondary ozone NAAQS standard to the EPA and vacated a “grandfathering” provision concerning the use of the prior ozone NAAQS in certain permitting actions.

The Clean Air Act requires the EPA to review NAAQS every five years to determine whether revision to current standards are appropriate.

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

The EPA also proposed to retain the PM standards promulgated in 2012 (85 Fed.

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

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

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

On December 31, 2020, the EPA issued a final rule to retain the current primary and secondary ozone standards.

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

Circuit by several states and environmental organizations.

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

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 the implementation for other NAAQS for nitrogen oxide and SO 2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed.

9866) that retains, without revision, the existing NAAQS for SO 2 of 75 ppb averaged over an hour.

The CAA also indirectly, but significantly, affects the U.S.

coal industry by extensively regulating the air emissions of SO 2 , nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants, imposing more capital and operating costs on such facilities.

In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze.

The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule (CSAPR) and the CSAPR Update Rule, New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review.

In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions.

Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed.

At present, however, the EPA does not directly regulate such emissions.

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.

Peabody Energy Corporation 2021 Form 10-K

Final NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs) .

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

Peabody Energy Corporation 2020 Form 10-K

This rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb carbon dioxide per megawatt-hour gross output (CO 2 /MWh-gross).

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

On January 13, 2021, the EPA promulgated a final rule which did not address BSER, but rather finalized a pollutant-specific significant contribution determination for greenhouse gas emissions from EGUs of 3%.

Thus, the NSPS remains in effect.

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 EGUs under Section 111(d) of the CAA (80 Fed.

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).

Following Federal Register publication, 39 separate petitions for review of the CPP by approximately 157 entities were filed in the D.C.

The petitions reflected challenges by 27 states and governmental entities, as well as by utilities, industry groups, trade associations, coal companies and other entities.

The lawsuits were consolidated with the case filed by West Virginia and Texas (in which other states also joined) (D.C.

On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning states.

The motion was granted on January 11, 2016.

Numerous states and other entities also intervened in support of the EPA.

On February 9, 2016, the U.S.

Supreme Court granted a motion to stay implementation of the CPP until the legal challenges were resolved.

Thereafter, oral arguments in the case were heard in the D.C.

Circuit sitting en banc.

On April 28, 2017, the D.C.

Circuit granted the EPA’s motion to hold the case in abeyance while the agency reconsidered the rule.

In October 2017, the EPA proposed to repeal the CPP.

In August 2018, the EPA issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule.

44,746 (August 31, 2018)).

On June 19, 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE.

(Repeal of the Clean Power Plan;

Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units;

Revisions to Emission Guidelines Implementing Regulations, 84 Fed.

32,520 (July 8, 2019)).

The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the BSER.

The EPA’s final rule also revises the CAA Section 111(d) regulations to give the states greater flexibility on the content and timing of their state plans.

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 Peabody, filed a motion to dismiss, which the court granted in September 2019.

Peabody Energy Corporation 2020 Form 10-K

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 consolidated in American Lung Association v.

19-1140 (D.C.

This litigation has been fully briefed and oral argument before a 3-judge panel of the D.C.

Circuit was held on October 8, 2020.

The oral argument was organized around four issue areas concerning the EPA’s repeal of the CPP, the EPA’s authority to regulate power plants under the CAA, whether the ACE rule properly interpreted and applied the CAA and the treatment of biomass in the ACE Rule.

On January 19, 2021, the panel held that the ACE Rule and its repeal of the CPP were to be vacated and remanded to the EPA.

It also vacated amendments to the implementing regulations that extended the compliance timeline.

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 vacating the ACE rule and 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, issues pertaining to whether the EPA is limited to issuing standards for existing sources achievable through demonstrated technology and methods applied to such sources, or whether the EPA may also issue nationwide “performance standards” that can apply to the electric generation sector (such as cap and trade) which could effectively restructure the nation’s energy system.

The Company will continue to monitor the consolidated matters.

Peabody Energy Corporation 2021 Form 10-K

EPA’s Greenhouse Gas Permitting Regulations for Major Emission Sources .

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

On July 6, 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states.

Following litigation in the D.C.

Circuit and U.S.

Supreme Court, the first phase of the nitrogen oxide and SO 2 emissions reductions required by CSAPR commenced in January 2015;

further reductions of both pollutants in the second phase of CSAPR became effective in January 2017.

The EPA subsequently revised CSAPR requirements for the state of Texas to remove that state from second phase requirements regarding SO 2 (82 Fed.

45,481 (Sept.

On October 26, 2016, the EPA published the final CSAPR Update Rule to address implementation of the 2008 ozone NAAQS.

This rule imposed reductions in nitrogen oxides emissions beginning in 2017 in 22 states subject to CSAPR.

Several states and utilities, as well as agricultural and industry groups, filed petitions for review of the CSAPR Update Rule in the D.C.

On September 13, 2019, the D.C.

Circuit held that the CSAPR Update Rule did not comply with provisions of the Clean Air Act requiring upwind states to address air pollution which significantly interferes with the ability of a downwind state or states to attain NAAQS by relevant compliance dates.

The court thus remanded the CSAPR Update Rule to the EPA in order for the Agency to address the court’s decision.

In 2018, the EPA issued another determination that the existing CSAPR Update Rule fully addressed the CAA’s “good neighbor” requirements for 20 states with respect to the 2008 NAAQS for ground-level ozone.

This determination was also challenged in the D.C.

On October 1, 2019, the D.C.

Circuit issued a judgment vacating this rule on the basis of the court’s decision in Wisconsin v.

Additional litigation concerning the interstate transport of air pollution and the EPA’s response under the Clean Air Act continues.

In Maryland v.

18-1285), the D.C.

Circuit upheld EPA determinations that upwind states had not met their burden in seeking relief from transported air pollution under the same Clean Air Act provisions at issue in Wisconsin .

In New York v.

19-1231 (D.C.

Cir., July 14, 2020), the D.C.

Circuit vacated the EPA’s denial of a Clean Air Act section 126 petition requesting that the Agency find approximately 350 sources of nitrogen oxides in nine States were contributing significantly to nonattainment in the New York Metropolitan Area.

The court remanded the denial to the EPA for further proceedings consistent with the court’s opinion.

EPA has proposed a rule to address the court’s remand in Wisconsin as well as NOx emissions in 21 states targeted by the CSAPR Update Rule.

The proposed rule would find that 9 of the states identified do not significantly contribute to downwind nonattainment and/or maintenance issues and therefore do not need additional emission reductions.

For the 12 other states, EPA has proposed to adjust state NOx budgets downward and create a new emission trading program.

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

In 2016, the EPA published the final CSAPR Update Rule which imposed additional reductions in 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.

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.

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

Circuit and briefing in this litigation commenced in November 2021, but this does not stay the effectiveness of the rule.

Mercury and Air Toxic Standards (MATS) .

The EPA published the final MATS rule in the Federal Register on February 16, 2012.

The MATS rule revised the NSPS for nitrogen oxides, SO 2 and PM for new and modified coal-fueled electricity generating plants, and imposed MACT emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants.

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

The MATS rule revised the new source performance standards (NSPS) for NO x , SO 2 and PM for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants.

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

The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls.

Peabody Energy Corporation 2020 Form 10-K

Following issuance of the final rule, numerous petitions for review were filed.

Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on HAPs against all challenges on April 15, 2014, in a two-to-one decision.

Industry groups and a number of states filed and were granted review of the D.C.

Circuit decision in the U.S.

Supreme Court.

On June 29, 2015 the U.S.

Supreme Court held that the EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate HAPs from power plants.

The court reversed the D.C.

Circuit and remanded the case for further proceedings.

On December 1, 2015, in response to the court’s decision the EPA published a proposed supplemental finding in the Federal Register that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule.

On December 15, 2015, the D.C.

Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S.

Supreme Court decision.

On April 14, 2016, the EPA issued a final supplemental finding that largely tracked its proposed finding.

Several states, companies and industry groups challenged that supplemental finding in the D.C.

Circuit in separate petitions for review, which were subsequently consolidated (D.C.

Several states and environmental groups also filed as intervenors for the respondent EPA.

Although briefing in this litigation has concluded, the case remains in abeyance.

On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule that would revoke the determination that regulating HAPs from coal-fired power plants is “appropriate and necessary” under Section 112(n)(1)(A) of the CAA.

The proposed finding was based on an EPA assessment that health and environmental benefits from the MATS rule were not directly related to mercury pollution and should not be included in the benefit portion of the analysis.

A final rule reversing EPA’s 2016 Supplemental Finding and determining, in lieu, that it is not “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants was promulgated in May 2020.

31,286 (May 22, 2020).

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.

Both actions have been challenged in the D.C.

See American Academy of Pediatrics et al.

Wheeler , No.

20-1221 (D.C.

Cir.), Air Alliance Houston, et al v.

20-1268 (D.C.

Both actions were challenged in the D.C.

Circuit but this litigation was placed in abeyance.

In 2021 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 residual risk and technology review standards for coal- and oil-fired EGUs.

Regional Haze.

The Clean Air Act contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from manmade air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal.

States are required to revise plans every 10 years.

Federal Coal Leasing Moratorium .

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

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

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

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Environmental groups have since amended their complaint to challenge the Environmental Assessment and FONSI, and the litigation remains pending.

Peabody Energy Corporation 2021 Form 10-K

Clean Water Act (CWA) .

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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.

On June 1, 2020, the EPA issued a final rule intended to clarify the scope of the state or tribal regulators’ authority that could in effect limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances.

Peabody Energy Corporation 2020 Form 10-K

Although the EPA issued a final rule in 2020 that effectively could have in effect limited state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances, as a result of litigation developments this year, the 1971 certification rule is currently back in effect.

The EPA plans to issue another proposal in 2022 to update the 1971 rule.

New Source Review (NSR).

The Clean Air Act imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification.

These requirements are contained in the Clean Air Act’s PSD and Nonattainment New Source Review programs, generally referred to as NSR.

On March 25, 2020, the EPA released a draft guidance document that would allow power plants, refineries and other sources of emissions to begin certain construction activities while still awaiting a permit under the NSR program.

Under the EPA’s revised interpretation, a source owner or operator may, prior to obtaining a NSR permit, undertake physical on-site activities, including activities that may significantly alter the site and/or are permanent in nature, provided that those activities do not constitute physical construction on an emissions unit.

The comment period on the draft memo ended May 11, 2020.

These requirements are contained in the Clean Air Act’s prevention of significant deterioration (PSD) and Nonattainment New Source Review (NNSR) programs, generally referred to as NSR.

On August 4, 2020, the EPA released a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the New Source Review Regulations).

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CWA Definition of “Waters of the United States”.

A final rule defining the scope of waters protected under the CWA (commonly called the Waters of the United States, or WOTUS) (WOTUS Rule), was published by the EPA and the Corps in June 2015.

Several states and others subsequently filed lawsuits challenging the 2015 WOTUS Rule, and eventually that rule was preliminarily enjoined in over half of the country.

On October 22, 2019, the EPA and the Corps jointly published a final rule, which became effective on December 23, 2019, repealing the 2015 WOTUS Rule and recodifying the regulatory definitions of WOTUS that existed prior to the implementation of the WOTUS Rule.

On January 23, 2020, the EPA and the 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.

A federal district judge in Colorado preliminarily enjoined the Navigable Waters Protection Rule in the State of Colorado on June 19, 2020.

The new rule took effect in all other states on June 22, 2020, but the pre-2015 definitions apply in Colorado.

Litigation over both the 2019 repeal rule and the 2020 Navigable Waters Protection Rule remains pending in several federal district courts.

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.

On December 7, 2021, the agencies published the first of two rulemaking proceedings to formally repeal the Navigable Waters Protection Rule, codify the pre-2015 regulatory framework, and then build upon that framework.

The agencies plan to issue the second proposal in 2022, but the exact timing is unclear.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry.

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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 April 12, 2019, the U.S.

Court of Appeals for the Fifth Circuit agreed with environmental groups that the portions of the rule regulating legacy wastewater and residual combustion leachate are unlawful.

The Court vacated those portions of the rule.

The EPA has not yet determined how to address the vacated portions of the 2015 rule following the Fifth Circuit’s decision.

Separately, 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.

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.

Peabody Energy Corporation 2021 Form 10-K

National Environmental Policy Act (NEPA) .

NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement.

We must provide information to agencies when we propose actions that will be under the authority of the federal government.

Peabody must provide information to agencies when it proposes actions that will be under the authority of the federal government.

The NEPA process involves public participation and can involve lengthy timeframes.

The White House Council on Environmental Quality issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020.

The final rule seeks to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things.

That final rule sought to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things.

States and environmental groups have filed several lawsuits challenging the final rule.

On October 7, 2021, however, CEQ published a proposed rule announcing a two-phase rulemaking process to generally restore the pre-2020 NEPA regulations before more broadly revisiting the 2020 rule.

Resource Conservation and Recovery Act (RCRA) .

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Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.

Peabody Energy Corporation 2020 Form 10-K

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous.

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

The EPA expects to issue a final rule around May 2021.

Although EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around October 2022.

Separately, on August 28, 2020, the EPA finalized certain amendments to its 2015 CCR rule to partially address the D.C.

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

The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision, and the EPA expects to issue a proposed rule in the summer of 2021.

The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision.

Initially the EPA had planned to issue a proposal in mid-2021, but the EPA now expects to issue the proposal rule in September 2022.

Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous.

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

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

The Department of the Interior issued three proposed rules in 2018 aiming to streamline and update the ESA.

The three final rules became effective on September 26, 2019 and are currently the subject of a pending legal challenge filed in the U.S.

District Court for the Northern District of California by a coalition of 18 states.

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

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

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

Peabody Energy Corporation 2021 Form 10-K

Use of Explosives .

Our surface mining operations are subject to numerous regulations relating to blasting activities.

Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring.

Peabody’s surface mining operations are subject to numerous regulations relating to blasting activities.

Pursuant to these regulations, it incurs costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring.

The storage of explosives is subject to strict federal regulatory requirements.

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A Fifth National Climate Assessment is currently in development with an anticipated publication date in 2023.

Peabody Energy Corporation 2020 Form 10-K

Regulatory Matters — Australia

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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 returned or security released after satisfactory reclamation is completed.

Native Title and Cultural Heritage .

Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement.

These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established.

Native title rights do not extend to minerals;

however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements.

There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Government established a Senate Inquiry.

The Inquiry’s terms of reference include reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions;

and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites.

The Inquiry was due to finalize its report by December 9, 2020.

The reporting deadline for the final report has been extended to October 2021 and instead the Joint Standing Committee released its interim report in December 2020.

The interim report focused specifically on Western Australia but the next phase of the Inquiry will be expanded to encompass other Australian states and territories, both with a view to address particular issues and to develop a nationally consistent response to heritage protection.

The Inquiry’s findings and resultant legislation, if any, could potentially impact the Company’s mining permits or existing mine plans in an effort to mitigate against adverse impacts to such sites.

Mining Tenements and Environmental .

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Environmental approvals processes involve complex issues that, on occasion, require lengthy studies and documentation.

Peabody Energy Corporation 2020 Form 10-K

In February 2019, the New South Wales (NSW) Land and Environment Court (LEC) upheld the government’s denial of a planning approval for a non-Peabody coal mining project ( Gloucester Resources Limited v.

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Although the approval was refused for other reasons, the judge in that case discussed ‘Scope 3’ greenhouse gas emissions resulting from the consumption of coal to be mined under the proposed project.

Such emissions are often raised as a ground of objection to Australian mining projects, including our mining projects.

Such emissions are often raised as a ground of objection to Australian mining projects, including Peabody’s mining projects.

For example, in a subsequent LEC decision ( Australian Coal Alliance Incorporated v.

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In December 2020, the NSW Government finalized and published the Guideline for the Competitive Allocation of Coal, which details the process for considering areas for coal exploration and allocating them by public tender.

Peabody Energy Corporation 2021 Form 10-K

In Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 2008, Planning Act 2016, Coal Mining Safety and Health Act 1999, Minerals and Energy Resources (Common Provisions) Act 2014, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Biosecurity Act 2014, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959.

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

Peabody Energy Corporation 2020 Form 10-K

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

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

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.

Peabody Energy Corporation 2021 Form 10-K

Mining Rehabilitation (Reclamation).

Mine reclamation is regulated by state-specific legislation.

As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so.

As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding, or, in certain circumstances (see below in relation to the Mineral and Energy Resources (Financial Provisioning) Act 2018), make alternative financial contributions to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so.

Self-bonding is not permitted.

Our mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements.

This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under our credit facility and accounts receivable securitization program.

We operate in both the Queensland and New South Wales state jurisdictions.

Our reclamation bonding requirements in Australia were $312.6 million as of December 31, 2020.

The bond requirements represent the calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state.

Peabody’s mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements.

This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under the Company’s credit facility and accounts receivable securitization program.

The Company operates in both the Queensland and New South Wales state jurisdictions.

Peabody’s reclamation bonding requirements in Australia were $240.2 million as of December 31, 2021.

The bond requirements represent the states’ calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state.

The cost calculation for each bond must be completed according to the regulatory authority of each state.

The costs associated with our Australian asset retirement obligations are calculated in accordance with generally accepted accounting principles and were $225.4 million as of December 31, 2020.

The total bonding requirements for our Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is projected to be a number of years away, whereas the bonding amount represents the cost of reclamation if a mine ceases to operate immediately as well as different costs assumptions.

The costs associated with the Company’s Australian asset retirement obligations are calculated in accordance with U.S.

generally accepted accounting principles and were $201.2 million as of December 31, 2021.

The total bonding requirements for the Company’s Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is projected to be a number of years away, whereas the bonding amount represents the states’ calculated cost of reclamation if a mine ceases to operate immediately as well as different costs assumptions.

New South Wales Reclamation.

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The proposed rehabilitation management plan for the mining area which must be prepared for large mines is intended to replace the current approach of preparing a mining operation plan.

Peabody Energy Corporation 2020 Form 10-K

Queensland Reclamation.

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The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which no longer provides for discounting.

The commencement date for the new FA framework was April 1, 2019 and there is a transitional period during which we will move each of our mines in Queensland into the new FA framework.

The commencement date for the new FA framework was April 1, 2019 and there is a transitional period during which Peabody will move each of its mines in Queensland into the new FA framework.

Peabody Energy Corporation 2021 Form 10-K

The new progressive rehabilitation requirements commenced on November 1, 2019 and require each mine, within a three-year transitional period, to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation will require regulatory approval.

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Under the legislation, each current mine is exempt from the requirement to justify its NUMAs to the extent that its current approvals provide for such areas.

We are of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of our Queensland mines.

The Company is of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of its Queensland mines.

Residual Risks .

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It is unclear the extent to which the report will impact policy reform at a federal government level.

Native Title and Cultural Heritage .

These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established.

Native title rights do not extend to minerals;

There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Government established a Senate Inquiry.

The Inquiry’s terms of reference included reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions;

and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites.

Following an interim report released on December 9, 2020, the Joint Standing Committee on Northern Australia released its final report on October 18, 2021.

The final report sets out three key findings and eight recommendations, including that a new framework for cultural heritage protection be implemented at a national level by way of new legislated national minimum standards for State and Territory laws.

The recommendations also include that a review of the Native Title Act 1993 (Cth) be undertaken to address inequalities in the negotiating position of Aboriginal and Torres Strait Islander peoples in the future act regime, including the ‘right to negotiate’ process which is associated with the grant of certain mining tenements.

Any legislation passed as a result of the recommendations in the final report could potentially impact the Company’s current and future mining tenements and operations.

Occupational Health and Safety .

State legislation requires us to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision.

State legislation requires Peabody to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision.

In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry.

There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.

Peabody Energy Corporation 2021 Form 10-K

In September 2020, Safe Work Australia (SWA) published its revised Workplace Exposure Standards (WES) for coal dust and silica based on toxicological information and other monitoring data.

SWA have recommended exposure limits of 1.5 mg/m 3 for coal dust (to apply from October 2022) and 0.05 mg/m 3 for silica (to apply as soon as possible).

In Queensland, the new workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05 milligrams per cubic meter (mg/m 3 )) took effect from July 1, 2020.

In Queensland, a new workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05 milligrams per cubic meter (mg/m 3 )) took effect from July 1, 2020.

In New South Wales, the new respirable crystalline silica workplace exposure standard of 0.05 mg/m 3 commenced on July 1, 2020.

The respirable coal dust workplace exposure standard of 2.5 mg/m 3 will be reduced to 1.5 mg/m 3 commencing on February 1, 2021 and mines will need to report exceedances of the new exposure standard to the NSW Resources Regulator from this commencement date.

NSW will be the first mining jurisdiction in Australia to implement an exposure standard for diesel particulate matter with the exposure standard of 0.1 mg/m 3 to also commence on February 1, 2021

Peabody Energy Corporation 2020 Form 10-K

The respirable coal dust workplace exposure standard of 2.5 mg/m 3 was reduced to 1.5 mg/m 3 on February 1, 2021 and mines need to report exceedances of the new exposure standard to the NSW Resources Regulator from this date.

NSW is the first mining jurisdiction in Australia to implement an exposure standard for diesel particulate matter with the exposure standard of 0.1 mg/m 3 which became enforceable on February 1, 2021.

In addition, 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.

On July 1, 2020, the Resources Safety and Health Queensland Act 2020 became effective.

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The matters regulated under the national system include general employment conditions, unfair dismissal, enterprise bargaining, bullying claims, industrial action and resolution of workplace disputes.

Most of the hourly workers employed in our mines are also covered by the Black Coal Mining Industry Award and company specific enterprise agreements approved under the national system.

Most of the hourly workers employed in the Company’s mines are also covered by the Black Coal Mining Industry Award and company specific enterprise agreements approved under the national system.

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

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

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

The rule was amended in March 2019 with the effect that all current reported covered emissions baselines will expire on June 30, 2020, and there will be alternatives for setting new baselines, including by reference to default emissions intensity values.

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

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

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

Queensland Royalty .

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The Government contributes $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars.

Peabody’s contribution to the Fund was approximately $713,000 Australian dollars for the 2019-20 financial year and is expected to decrease in years two and three based on an expected reduction in production at our Queensland mines.

Peabody’s contribution to the Fund was approximately $522,000 Australian dollars for the 2020-21 financial year and $713,000 Australian dollars for the 2019-20 financial year.

Peabody’s contribution is expected to further decrease in year three based on an expected reduction in production at its Queensland mines.

Peabody Energy Corporation 2021 Form 10-K

New South Wales Royalty .

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Sydney Water Catchment Areas .

In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning, Industry and Environment (DPIE) on the impact of underground mining activities in Sydney’s water catchment areas, including at our Metropolitan Mine.

The Panel issued its final report in October 2019.

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and undertaking further research into mine closure planning to reduce potential long-term impacts.

Risks Related to Global Climate Change

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

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

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

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

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

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

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

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

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

Securities and Exchange Commission filings, its annual Environmental, Social and Governance 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.

Peabody Energy Corporation 2021 Form 10-K

Global Climate

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 below in the section “Regulations Related to Global Climate Change” within this Item 1.

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

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

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

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

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

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

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

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

Peabody Energy Corporation 2021 Form 10-K

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.

Regulations Related to Global Climate Change

In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no such legislation has been signed into law.

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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.

In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012.

RGGI 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.

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

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

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

Peabody Energy Corporation 2021 Form 10-K

Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and the Company regularly discloses information regarding its production-related emissions in its annual Environmental, Social and Governance Report.

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.

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The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices.

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 us 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.

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, we attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies.

Such analyses require that we 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 our operations, financial condition or cash flow.

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

Available Information

We file or furnish annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC.

These materials are available free of charge through our website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC.

Information included on our website does not constitute part of this document.

Peabody files or furnishes annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC.

These materials are available free of charge through the Company’s website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC.

Information included on the Company’s website does not constitute part of this document.

These materials may also be accessed through the SEC’s website (www.sec.gov).

In addition, copies of our filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at:

In addition, copies of the Company’s filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at:

Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St.

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Investor Relations.

Peabody Energy Corporation 2020 Form 10-K

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-K

Item 1. Business