What changed in this filing

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Item 1. Business

2025-02-20 compared with 2024-02-23 · 339 added, 331 removed, 548 unchanged (55% of the section changed)

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(Middlemount).

In addition to its mining operations, the Company markets and brokers coal from other coal producers;

trades coal and freight-related contracts;

and, since 2022, is partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage.

During 2023, Peabody advanced the redevelopment of its North Goonyella Mine in Australia.

During the fourth quarter, the mine was renamed to Centurion Mine to reflect the next stage of redevelopment and the Company’s agreement to acquire an adjacent coal deposit.

The first development coal from the Centurion Mine is anticipated in the second quarter of 2024.

On November 21, 2024, Peabody entered into a partnership with RWE, a renewable energy company, to advance renewable energy projects by repurposing reclaimed land previously used for mining, including certain reclaimed mining land held by the Company.

On November 25, 2024, Peabody entered into definitive agreements with Anglo American plc, a United Kingdom public limited company (Anglo), to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia.

The acquisition is expected to close in the second quarter of 2025, subject to regulatory approvals, completion of preemptive rights processes and satisfaction of other customary closing conditions.

During 2024, Peabody continued to advance the development of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, as planned.

Development coal was produced and sold during the year, and commencement of longwall production is targeted for the first quarter of 2026.

Segment and Geographic Information

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Peabody Energy Corporation 2024 Form 10-K

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Peabody Energy Corporation 2024 Form 10-K

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Australian Locations

Peabody Energy Corporation 2024 Form 10-K

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

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Seaborne Metallurgical

Metropolitan (3)

New South Wales U LW C, P, T R, EV Yes 2.2 1.8 1.0

Shoal Creek (3)

Alabama U LW C B, EV Yes 2.1 0.6 0.8

Metropolitan New South Wales U LW C, P, T R, EV Yes 1.8 2.2 1.8

Coppabella (4)

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Queensland S D, T/S C, P, T R, EV Yes 1.5 2.2 1.5

Shoal Creek (5)

Alabama U LW C B, EV Yes 0.6 0.8 0.1

Centurion (5)

Queensland U LW C R, EV Yes 0.2 — —

Middlemount (6)

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Gateway North Illinois U CM T Tr, R, R/B, T/B, EV Yes 2.1 2.5 2.4

Francisco Underground Indiana U CM T R Yes 2.0 1.8 1.5

Wild Boar Indiana S HW, DL, D, T/S T Tr, R, R/B, T/B Yes 1.8 1.9 2.3

Francisco Underground Indiana U CM T R Yes 1.6 2.0 1.8

Twentymile Colorado U LW T R, Tr, EV Yes 1.0 1.3 1.5

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

(3) The mine restarted production in the second quarter of 2021 after being idled in the fourth quarter of 2020.

(3) The mine experienced a fire in March 2023 and restarted production in June 2023.

(4) 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.

(5) The mine experienced a fire in March 2023 and restarted production in June 2023.

In November 2021 the mine restarted production after being idled in the fourth quarter of 2020.

(5) The mine has been undergoing development since 2023.

The first development coal was produced in June 2024.

Longwall mining is expected to commence in the first quarter of 2026.

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

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Peabody Energy Corporation 2024 Form 10-K

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Coal Supply Agreements

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Peabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 153 million and 221 million tons of coal as of January 1, 2025 and 2024, respectively.

Contracts in backlog have remaining terms ranging from one to eight years and represent approximately two years of production based on the Company’s 2023 production volume of 126.7 million tons.

Contracts in backlog have remaining terms ranging from one to seven years and represent slightly more than one year of production based on the Company’s 2024 production volume of 118.1 million tons.

Approximately 42% of its backlog is expected to be filled beyond 2025.

Seaborne Operations.

Revenue from Peabody’s Seaborne Thermal and Seaborne Metallurgical segments represented approximately 56%, 59% and 50% of the Company’s total revenue from coal supply agreements for the years ended December 31, 2023, 2022 and 2021, respectively, during which all three periods the coal mining activities of those segments contributed approximately 18% of the Company’s sales volumes from mining operations.

Production from these segments 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, with spot, index and quarterly sales arrangements also utilized.

Revenue from Peabody’s Seaborne Thermal and Seaborne Metallurgical segments represented approximately 55%, 56% and 59% of the Company’s total revenue from coal supply agreements for the years ended December 31, 2024, 2023 and 2022, respectively, during which periods the coal mining activities of those segments contributed approximately 20%, 18% and 18% of the Company’s sales volumes from mining operations, respectively.

Production from these segments is primarily sold into the seaborne thermal and metallurgical markets.

A majority of the sales in these segments are executed through annual and multi-year international coal supply agreements which primarily contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized.

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 quarterly, spot or index basis.

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

Thermal segments, in aggregate, represented approximately 44%, 41% and 50% of the Company’s revenue from coal supply agreements for the years ended December 31, 2023, 2022 and 2021, respectively, during which all three periods the coal mining activities of those segments contributed approximately 82% of the Company’s sales volumes from mining operations.

Thermal segments, in aggregate, represented approximately 45%, 44% and 41% of the Company’s revenue from coal supply agreements for the years ended December 31, 2024, 2023 and 2022, respectively, during which periods the coal mining activities of those segments contributed approximately 80%, 82% and 82% of the Company’s sales volumes from mining operations, respectively.

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

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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.

Over the last few years, Peabody’s customers have shifted to long-term supply agreements with shorter durations, 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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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).

Peabody Energy Corporation 2023 Form 10-K

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.

Beginning in 2022, rail service constraints due, in part, to labor shortages and weather conditions experienced by Peabody’s rail service providers, negatively impacted U.S.

thermal shipment volumes.

The constraints began to lessen in 2023, resulting in improved rail performance compared to the prior year.

During 2024, lock outages along the Black Warrior River in Alabama, U.S.A.

negatively impacted Peabody’s sales volume and transportation costs at the Shoal Creek Mine.

The lock outages have largely been resolved during the second half of 2024, and Peabody anticipates improved sales volume and lower transportation costs at the Shoal Creek Mine in 2025.

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

Peabody Energy Corporation 2024 Form 10-K

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Export Facilities.

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Peabody’s U.S.

thermal operations exported less than 1% of their annual tons sold during the years ended December 31, 2022 and 2021.

No tons were exported during the year ended December 31, 2023.

thermal operations exported less than 1% of their annual tons sold during the year ended December 31, 2022.

No tons were exported during the years ended December 31, 2024 and 2023.

The primary port used for U.S.

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Mining Supplies and Equipment .

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 for parts and components stabilized throughout 2023.

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.

Throughout 2022 and 2023, inflationary pressures and supply chain constraints contributed to rising costs for mining equipment, supplies and services.

While supply chain constraints eased and inflation somewhat moderated in 2023, future periods could continue to be impacted.

Peabody relies on various goods to support its mining operations, including mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (such as roof control materials), lubricants and electricity.

The Company has established strong, strategic relationships with key suppliers and does not consider itself overly dependent on any single supplier.

When Peabody has chosen to concentrate a significant portion of its purchases with one supplier, it has been to leverage cost savings from bulk purchases, secure long-term pricing for parts and ensure a reliable supply chain.

This approach also enables fleet standardization for mining equipment, improving asset utilization, streamlining maintenance practices across global operations and optimizing inventory management, which reduces working capital.

In 2024, lead times for parts and components required for surface and underground mining equipment showed notable improvement.

Peabody continues to leverage its global purchasing power and comprehensive planning strategies to maintain a reliable supply chain that effectively supports the needs of its active mines.

In addition to goods, Peabody also contracts services for its mine sites, such as maintenance for mining equipment, construction, temporary labor, explosives use and other requirements.

The Company does not perceive any undue operational or financial risk from reliance on individual service providers.

In 2024, inflationary pressures stabilized, returning to more normal levels, and supply chain constraints eased.

This resulted in improved access to materials and supplies necessary to support mining operations.

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;

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and foreign governments.

Peabody Energy Corporation 2023 Form 10-K

Thermal Coal.

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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.

Peabody Energy Corporation 2024 Form 10-K

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

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

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

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

During 2024, approximately 6 gigawatts of U.S.

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

coal power capacity has fallen by approximately forty-one percent.

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

Conversely, emerging technologies, including data centers, artificial intelligence and cryptocurrency, are expected to drive U.S.

electricity demand in coming years.

As a result, U.S.

coal consumption is expected to increase in 2025 which has led to deferrals of planned coal plant retirements.

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

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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.

China’s unofficial ban on Australian coal concluded in January 2023, enabling the reestablishment of some traditional trade flows.

Global thermal coal markets were turbulent during 2022 and 2023, due in part to the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries.

Economic sanctions have continued to influence trade flows of thermal coal in 2024.

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

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American Consolidated Natural Resources, Inc.;

Arch Resources, Inc.;

CONSOL Energy;

Core Natural Resources, Inc.;

Eagle Specialty Materials LLC;

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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.

Trade flow disruptions occurred during 2022 and 2023 related to China’s unofficial ban on Australian coal and sanctions imposed on Russian coal imports.

Trade flow disruptions occurred during 2022 and 2023 related to sanctions imposed on Russian coal imports.

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

Arch Resources, Inc.;

Teck Resources;

Core Natural Resources, Inc.;

Oak Grove Mine;

Warrior Met Coal;

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Louis or its business offices in Brisbane and Beijing.

Peabody Energy Corporation 2023 Form 10-K

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

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industry average incidence rate of 2.98 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).

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.

Peabody Energy Corporation 2024 Form 10-K

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Peabody strives to offer a work environment that 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.

Such diversity may also serve to mitigate risks to the business in the current tight labor market.

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 believes in fostering a 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 seven years of experience with the company, and approximately 47% of all Peabody employees remain employed with the company for more than five years.

The typical Peabody employee has approximately seven and a half years of experience with the Company, and approximately 46% 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.

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Jarboe 51 Chief Administrative Officer and Corporate Secretary

Hathhorn 53 President - U.S.

Jamie Frankcombe 63 President - Australian Operations

Forkin III 66 Chief Development Officer

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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.

He has over 30 years of experience in the coal and 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.

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Peabody Energy Corporation 2024 Form 10-K

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

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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.

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 leadership of health, safety and environment, people, operational performance and product delivery.

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.

Hathhorn held various leadership positions with Drummond LTD in South America, including Mine Operations Superintendent, Port Manager, and Vice President - Mining Operations.

Prior to joining Drummond LTD, Mr.

Hathhorn held various engineering and supervisory positions with Newmont Mining Corporation.

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

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 leadership of health, safety and 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 a Bachelor of Engineering (Mining) from University of Wollongong and a Master of Business Administration (Technology) from Deakin University.

Forkin III was named Chief Development Officer in July 2022 after serving as Senior Vice President - Corporate Development and Strategy since November 2017.

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

Peabody Energy Corporation 2023 Form 10-K

Malcolm Roberts was named Chief Marketing Officer in May 2023.

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

The Company continually monitors the laws and regulations for changes resulting from updated legislation, judicial decisions and changes in governmental administrations.

Peabody Energy Corporation 2024 Form 10-K

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Mine Safety and Health

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

As a result of legislation enacted in December 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.

Effective October 1, 2022, the excise tax rates reverted back to 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 due to the enactment of the Inflation Reduction Act of 2022.

From January 1, 2022 through September 30, 2022 the excise tax rates were set at 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal.

Effective October 1, 2022, 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 due to the enactment of the Inflation Reduction Act of 2022.

Peabody recognized expense related to the tax of $52.2 million, $57.4 million and $32.4 million for the years ended December 31, 2024, 2023 and 2022, respectively.

Peabody Energy Corporation 2023 Form 10-K

Black Lung Benefits Act Self-Insurance Requirements .

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The Department of Labor’s (DOL) Office of Workers’ Compensation Programs (OWCP) is responsible for authorizing coal mine operators to self-insure and for setting the security amounts.

As part of its ongoing efforts to reform the self-insurance program to ensure that operators are adequately securing their liabilities, the OWCP proposed a rule in January 2023 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts.

The public comment period for the proposed rule ended April 19, 2023.

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.

As part of its ongoing efforts to reform the self-insurance program to ensure that operators are adequately securing their liabilities, the OWCP finalized a rule on December 12, 2024 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts.

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

Environmental Laws and Regulations

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

Peabody Energy Corporation 2024 Form 10-K

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SMCRA provides for three categories of bonds:

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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 2023 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 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.

Pursuant to 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 $20.4 million, $22.2 million and $21.7 million for the years ended December 31, 2024, 2023 and 2022, respectively.

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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.

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

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

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

On March 6, 2024, the EPA revised the level of the primary standard for fine particulate matter (PM 2.5), lowering the annual standard from 12.0 µg/m 3 to 9.0 µg/m 3 .

States are now required to take several actions to implement the standards which could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies or operate in a different manner.

Such actions could potentially increase the cost of utilizing fossil fuels for electric generation and industrial uses.

The revised PM 2.5 standard has been challenged in the U.S.

Court of Appeals for the District of Columbia Circuit (D.C.

Circuit) in Kentucky v.

The EPA is also in the process of reviewing the current ozone NAAQS.

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

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

Final 2015 New Source Performance Standards (NSPS) for Fossil Fuel-Fired EGUs .

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

Peabody Energy Corporation 2024 Form 10-K

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The rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for CO 2 (known as the Best System of Emission Reduction (BSER)) which is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS).

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Reconstructed EGUs must implement the most efficient generating technology based on the size of the unit.

Numerous legal challenges to the final rule were filed in the United States Court of Appeals for the D.C.

Circuit (D.C.

Numerous legal challenges to the final rule were filed in the D.C.

Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups.

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Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports.

On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards.

In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices.

The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology.

Status reports filed with the D.C.

Circuit in North Dakota v.

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

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

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

The EPA proposed to revise NSPS to address CO 2 emissions from both new fossil fuel-fired steam generating units and new fossil fuel-fired stationary combustion turbines.

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

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

Circuit in 2021.

Peabody Energy Corporation 2023 Form 10-K

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

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

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

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

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

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

Under the proposed rule, existing steam generating units would need to comply with the standards by January 1, 2030 and existing stationary combustion turbines would be required to comply by either January 1, 2032 or January 1, 2035, depending on what option for compliance is chosen.

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

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

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

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

On May 9, 2024, the EPA published a final rule for new, modified and reconstructed fossil fuel-fired EGUs in the Federal Register.

The final rule consists of four elements:

(1) revised NSPS for controlling CO 2 emissions from new and reconstructed stationary combustion turbines;

(2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification;

(3) emission guidelines for existing fossil fuel-fired steam EGUs;

and (4) repeal of the Affordable Clean Energy rule promulgated in 2019.

With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions.

Pursuant to the final rule, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO 2 emission rate based on CCS with 90% capture by January 1, 2032.

Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO 2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030.

(This translates into a 16% reduction in CO 2 emissions determined from a unit-specific baseline).

Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements.

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

Under the final rule, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations.

States are also permitted to impose more stringent standards.

In addition, the final rule includes several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order to maintain adequate electric generation resources and grid reliability.

Finally, as part of the final rule, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO 2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU.

In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032.

Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015.

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

Circuit in West Virginia v.

Petitioners filed an emergency application for a stay of the rule with the U.S.

Supreme Court which was denied in an order issued by the U.S.

Supreme Court on October 16, 2024.

If the rule is ultimately affirmed and implemented by the EPA and states, it could have a substantial impact on the use of coal and natural gas for the generation of electricity.

A companion rule that addresses how states may implement CO 2 emission limits for existing power plants has also been challenged in West Virginia v.

EPA’s Permitting Regulations for Major Emission Sources .

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In general, most permits are issued by state environmental agencies that either implement EPA permitting programs or have an EPA-approved state program.

Peabody Energy Corporation 2024 Form 10-K

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

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

The rule has been challenged in several U.S.

Courts of Appeal, including the D.C.

On December 20, 2023, the U.S.

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

Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S.

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

On June 27, 2024, the U.S.

Supreme Court issued a stay of the rule in 11 states pending the disposition of a petition for review of the rule in the D.C.

Circuit and any subsequent timely petition for certiorari filed with and granted by the U.S.

Supreme Court.

The EPA subsequently issued a policy memorandum on August 5, 2024, that provides an administrative stay of the rule;

Circuit thereafter issued a partial remand of the rule to allow the EPA to respond to comments regarding the severability of the rule’s provisions, which the EPA subsequently did on December 10, 2024.

Mercury and Air Toxic Standards (MATS) .

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On April 24, 2023, the EPA proposed to amend the 2012 MATS rule and require an additional two-thirds reduction in the filterable PM emission of non-mercury HAP metals from existing coal-fired power plants and to reduce the mercury standard for lignite plants by 70%.

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

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

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

Peabody Energy Corporation 2023 Form 10-K

On May 7, 2024, the EPA finalized a MATS rule which significantly tightens the filterable particulate matter (fPM) emissions limit for existing coal-fired EGU’s, lowering the standard from 0.030 lb/MMBtu to 0.010 lb/MMBtu for all coal-fired power plants.

This rule was challenged in the D.C.

Circuit in North Dakota v.

Regional Haze.

The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from 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.

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

States are required to revise plans every 10 years, but these statutory deadlines have not been met.

On March 29, 2024, the EPA published a proposed consent decree under which deadlines (for the second 10-year regional haze implementation period) would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026).

The EPA subsequently filed a motion to approve the consent judgment in the U.S.

District Court for the District of Columbia which was granted.

On December 31, 2024, EPA proposed to revise the due date for plans (for the third regional haze implementation period) from July 31, 2028 to July 31, 2031.

New Source Review (NSR).

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These rules and guidance may affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis.

Peabody Energy Corporation 2024 Form 10-K

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Federal Coal Leasing Moratorium .

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

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

Environmental groups took the issue to court (District of Montana) and in April 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review.

On May 22, 2020, the court held that the Department of the Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations.

Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI.

On August 12, 2022, the court invalidated the Environmental Assessment and FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis.

The August 2022 decision is currently on appeal to the U.S.

Court of Appeals for the Ninth Circuit.

Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium, but the Department of Interior revoked Order 3349 in April 2021, which mooted litigation related to Order 3349.

In November 2024, the Bureau of Land Management issued amended resource management plans for lands in Wyoming and Montana, which state that no federal coal will be available for future leasing in the Powder River Basin.

Montana and Wyoming challenged those decisions in a federal district court on December 11, 2024.

Clean Water Act (CWA) .

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

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

Pending litigation over the January 2023 definition has resumed and is ongoing, as the September 2023 final rule did not address many of the claims at issue in those cases.

CWA Water Quality Certification Rule .

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That rule took effect on November 27, 2023.

Peabody Energy Corporation 2023 Form 10-K

Challenges to the 2023 rule remain pending in the U.S.

District Court for the Western District of Louisiana.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry.

In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs.

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

If the proposed rule, expected in April 2024, is finalized in substantially the same form, the revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants.

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

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

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

On May 9, 2024, the EPA published a final rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments.

The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants.

In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim.

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

If the Eighth Circuit affirms the final rule, it could influence fuel switching or additional coal generating unit retirements by the end of 2034.

Peabody Energy Corporation 2024 Form 10-K

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National Environmental Policy Act .

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On April 20, 2022, however, the CEQ published the final Phase 1 rule that partially amended the 2020 rule by restoring key provisions of the pre-2020 NEPA regulations.

The CEQ proposed a Phase 2 rule on July 31, 2023 that makes broader changes to the 2020 rule, and it expects to finalize those changes in April 2024.

The CEQ proposed a Phase 2 rule on July 31, 2023 that makes broader changes to the 2020 rule, and it finalized the Phase 2 rule on May 1, 2024.

Separately, the CEQ published NEPA Guidance on Consideration of Greenhouse Gas Emissions and Climate Change on January 9, 2023.

The interim guidance was effective immediately, though the agency accepted comments on the guidance and expects to issue final guidance in April 2024.

The interim guidance was effective immediately, though the agency accepted comments on the guidance.

CEQ expected to issue final guidance in April 2024, but it withdrew the guidance from the regulatory review process on November 19, 2024.

Finally, on November 12, 2024, a divided panel of the D.C.

Circuit held that the CEQ lacks authority to issue legally binding regulations implementing NEPA in Marin Audubon Society v.

Federal Aviation Administration , No.

Although the federal government and environmental groups have sought rehearing of that decision, litigants in other pending NEPA cases are citing it for the holding that CEQ regulations are not binding.

Resource Conservation and Recovery Act (RCRA) .

4 unchanged sentences

While coal combustion residuals (CCR or coal ash) are exempted from regulation as hazardous waste, there are various EPA-imposed requirements regarding CCR management.

Proposed Rule for Disposal of CCR from Electric Utilities;

Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities;

Federal CCR Permit Program and Revisions to Closure Requirements.

3 unchanged sentences

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

Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around March 2026.

Although the EPA had planned to finalize this rule in 2021, the EPA postponed the expected issuance date for a final rule until December 2024 and it has not yet issued a final rule.

Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C.

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

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

The EPA expects to issue two final rules addressing the remainder of that decision in April and October 2024.

On May 8, 2024, the EPA published a final rule containing additional amendments to the 2015 CCR rule that further address aspects of the D.C.

Circuit’s 2018 decision.

Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA).

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

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

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

The agencies issued proposed rules on June 22, 2023, and they expect to finalize revised rules in April 2024.

Peabody Energy Corporation 2023 Form 10-K

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

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

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

Use of Explosives .

4 unchanged sentences

In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule.

Peabody Energy Corporation 2024 Form 10-K

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Federal Report on Climate Change .

4 unchanged sentences

SEC Climate-Related Disclosures .

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

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

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

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

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

The public comment period on the proposed rules has concluded and final rules are expected in April 2024.

Inflation Reduction Act of 2022 .

The Inflation Reduction Act of 2022 was signed into law on August 16, 2022.

Among its many provisions are programs that provide grants and other forms of direct and indirect financial assistance for the deployment of zero emission technologies as well as other actions that could affect energy markets and the future use of coal.

On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings.

Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition;

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

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

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

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

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

State Climate Change Legislation.

On May 30, 2024, Vermont’s S259, referred to as the Climate Superfund Act, became law and on December 26, 2024, the governor of New York signed S02129, known as the Climate Change Superfund Act (collectively, the Climate Change Laws).

The Climate Change Laws aim to require payments from entities deemed “responsible parties” to fund infrastructure projects meant to address climate change in New York.

The New York law defines a “responsible party” as an entity that “engaged in the trade or business of extracting fossil fuel or refining crude oil” from January 1, 2000 to December 31, 2018 and that is determined to be accountable for more than 1 billion metric tons of certain greenhouse gas emissions.

Responsible party does not include any person lacking “sufficient connection with the state to satisfy the nexus” of the U.S.

Constitution.

The Vermont law contains a similar definition of a responsible party, except that Vermont’s covered period extends from 1995 to 2024.

Both states have stated that they will enact future regulations to carry out the provisions of the law.

On December 30, 2024, the U.S.

Chamber of Commerce and American Petroleum Institute filed a lawsuit in the District of Vermont challenging the state’s Climate Superfund Act arguing that the law violates constitutional principles, including federal preemption, interstate commerce and due process, while also imposing excessive fines and an unconstitutional taking.

Additionally, on February 6, 2025, a group of 22 states, led by West Virginia, filed a lawsuit against New York State over its Climate Change Superfund Act, arguing that the law’s $75 billion penalty on fossil fuel producers unfairly shifts costs onto out-of-state energy producers and consumers and violates multiple constitutional protections.

The plaintiffs also claim that New York is overstepping its jurisdiction by imposing retroactive fines and discriminatory sanctions, potentially threatening U.S.

energy independence.

The Company expects the Climate Change Laws will continue to be challenged.

The impacts of these laws are currently being assessed.

Regulatory Matters — Australia

3 unchanged sentences

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.

New South Wales Coal Directions .

The State of New South Wales (NSW) enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers).

On December 22, 2022, the State Premier declared such an emergency, intended to control coal and electricity pricing.

Subsequently, directions were issued to Peabody Energy Australia Pty Ltd and other coal producers with operations in NSW, which have been amended at various dates.

The most recent directions require Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and impose additional reporting obligations to demonstrate compliance.

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

Metropolitan Mine Stormwater Discharge .

Over the past few years, there has been significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site.

While stormwater collected at the mine site is managed through two sedimentation dams, at times the heavy rainfall presented challenges with managing the significant volumes of stormwater, as the surface water management infrastructure has not had sufficient capacity.

As a result, on multiple occasions throughout 2021 and 2022 stormwater was discharged from the mine site.

Metropolitan Collieries Pty Ltd (MCPL), a wholly-owned subsidiary of PEC, removed accumulated material from the sedimentation dams to restore full site stormwater capacity by December 31, 2022 and identified and is implementing additional controls for the management of sediment moving forward.

Despite the measures undertaken by MCPL to manage and improve the situation, the Environment Protection Authority commenced a prosecution for five breaches of the Protection of the Environment Operations Act 1997 on September 6, 2023.

The Company continually monitors the laws and regulations for changes resulting from updated legislation, judicial decisions and changes in governmental administrations.

Australian Federal Government

Environmental Laws .

The environmental impacts of Australian mining projects are regulated by both state and federal governments.

Federal laws apply if a project is likely to significantly impact a Matter of National Environmental Significance (for example, a water resource, an endangered species or particular protected places).

Such mining projects are required to obtain approval under the Commonwealth Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act).

Environmental approval processes involve complex issues that, on occasion, require lengthy studies and documentation and are subject to legal challenge.

Peabody Energy Corporation 2024 Form 10-K

Mining Tenements and Environmental .

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There are bilateral agreements in place between the Federal Government and the Queensland and New South Wales State Governments that allow the environmental assessment process at the State level to be relied upon for a decision under the EPBC Act.

In Queensland and New South Wales, the development of a mine requires both the grant of a right to extract the resource and an approval which authorizes the environmental impact.

These approvals are obtained under separate legislation from separate government authorities.

These approvals are obtained under separate legislation for separate government authorities.

However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required.

The environmental impacts of mining projects are regulated by state and federal governments.

Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (for example, a water resource, an endangered species or particular protected places).

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

In February 2019, the New South Wales 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.

Minister for Planning ).

Although the approval was refused for other reasons, the judge in that case discussed ‘Scope 3’ GHG 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 Peabody’s mining projects.

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

Wyong Coal Pty Ltd ), the approval of a coal mining project was confirmed after such emissions had been considered by the relevant authority.

In August 2019, Peabody and Glencore received approval from the NSW Independent Planning Commission (IPC) for the United Wambo project, subject to conditions (Export Conditions) requiring the joint venture to prepare an Export Management Plan setting out protocols for using all reasonable and feasible measures to ensure that any coal extracted from the mine that is to be exported from Australia is only exported to countries that are parties to the Paris Agreement (as defined below) or countries that the NSW Planning Secretary considers to have similar policies for reducing GHG emissions.

The IPC subsequently approved another non-Peabody coal mining project (Rix’s Creek) without any Export Conditions.

In October 2019, the NSW government introduced into Parliament proposed amendments to legislation and policy that would, if passed, have the effect of invalidating Export Conditions imposed on future NSW planning approvals, as well as no longer requiring consent authorities to consider ‘downstream emissions’ when assessing developments for the purposes of mining, petroleum production or extractive industry.

The NSW government has announced changes to the IPC and planning system process which aim to improve timeframes and efficiencies for project approvals and provide more clarity on the IPC’s role in determining applications including seeking guidance on government policy.

In June 2020, the NSW Government released its Strategic Statement on Coal Exploration and Mining in NSW which provides a high level framework for the government's policy approach to the future of the coal sector, as well as details of a streamlined strategic release process.

The strategy identifies some potential areas for possible new coal exploration, areas that are ruled out for coal mining and areas where new coal exploration can only occur adjacent to an existing coal title via the Operational Allocation process.

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.

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.

Under the EP Act, policies have been developed to achieve the objectives of the law and provide guidance on specific areas of the environment, including air, noise, water and waste management.

State planning policies address matters of Queensland state interest, and must be adhered to during mining project approvals.

The Mineral Resources Act 1989 was amended effective September 27, 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements, and the coordination of activities and access to private and public land.

In November 2016, amendments to the EP Act and the Water Act 2000 became effective that facilitate regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction.

The ‘chain of responsibility’ provisions of the EP Act, which became effective in April 2016, allow the regulator to issue an environmental protection order (EPO) to a related person of a company in two circumstances:

(a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later);

or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company).

A guideline has been issued that provides more certainty to the industry on the circumstances in which an EPO may be issued.

Greenhouse and Energy Reporting Act 2007 (NGER Act).

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

The Clean Energy Regulator administers the NGER Act.

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

In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 .

The reforms commenced on July 1, 2023 and prescribed site specific baseline emissions for heavy emitting facilities as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030.

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

Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO 2 in 2023-2024, increasing with the Consumer Price Index plus 2% each year.

In June 2024 amendments to the NGER Act came into effect requiring open-cut mines covered by the Safeguard Mechanism that currently report fugitive methane emissions using a basic method with minimal data inputs (Method 1) to transition over a two-year period to a more complex method requiring site-level sampling and analysis (Methods 2 or 3).

This change in reporting methods is expected to increase the Safeguard Mechanism liability position of open-cut mining operations in Queensland.

The impacts of this change are currently being assessed.

On March 27, 2023, the Australian federal government announced several additional emission reduction measures in the Safeguard Mechanism (Crediting) Amendments Bill 2023 passed by the federal Parliament on March 30, 2023.

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

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

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

The legislation became effective on July 1, 2023.

Industrial Relations Laws.

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

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

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

In December 2022, the federal government passed The Fair Work Legislation Amendment (Secure Jobs, Better Pay) Act 2022, which amends the Fair Work Act.

The legislation introduced several changes to workplace laws in Australia including changes to enterprise agreement making and termination;

when industrial action can be taken;

and access to multi-employer bargaining or single interest employer authorizations.

Following this amendment, the Wambo Underground Mine and four other mines in New South Wales were served with an application for a single interest employer authorization which was granted by the Fair Work Commission against three employers including Peabody.

The three employers have appealed the authorization with the hearing currently scheduled for March 2025.

On December 7, 2023, the Fair Work Legislation Amendment (Closing Loopholes) Bill 2023 was passed by the Australian Federal Parliament.

The bill allows unions and/or employees to make application to the Fair Work Commission for a ‘regulated labour hire arrangement order’ that, if successful, requires employers to provide similar wages and conditions to regulated workers as those provided to permanent employees, unless the Fair Work Commission is satisfied that it is not fair and reasonable to do so.

Various union applications for regulated labor hire arrangements to apply at Australian coal mining operations are currently being considered by Australia’s Fair Work Commission.

Peabody Energy Corporation 2024 Form 10-K

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.

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

Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation.

Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales.

The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act.

As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified.

If a new development approval is required then this could take additional time to achieve.

On August 25, 2017, the BC Act commenced in New South Wales and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project.

The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means:

securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation.

The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts.

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

Sharma v Minister for the Environment.

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

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

Sharma did not lodge an application for special leave to the High Court of Australia to appeal this decision and is now out of time to do so.

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, 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.

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Native Title and Cultural Heritage Laws.

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.

Aboriginal and Torres Strait Islander Heritage Protection Act 1984.

On August 16, 2024, Australia’s Minister for the Environment and Water made a declaration under Section 10 of the Aboriginal and Torres Strait Islander Heritage Protection Act 1984 over a riverine area in NSW that is a proposed tailings dam site for a gold mining project.

The declaration prohibits any mining or related development activity in the area despite the project having previously obtained all necessary environmental and planning approvals under state and federal government laws.

The project proponent has indicated that the decision renders the mine project unviable and has initiated Federal Court proceedings seeking a judicial review of the decision-making process.

The first hearing is scheduled for March 4, 2025.

Australian Mine Rehabilitation (Reclamation) Laws.

Mine reclamation in Australia is regulated by state-specific legislation.

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

As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding or, in certain circumstances, 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.

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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 collateralized letter of credit program 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 $303.7 million as of December 31, 2024.

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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.

The Mining Act 1992 (Mining Act) is administered by the Department of Planning and Environment and the New South Wales Resources Regulator and authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the EPA Act and other auxiliary approvals and licenses.

New South Wales Government

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 and Petroleum Sites) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulation 2021, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, 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, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks and Wildlife Act 1974.

NSW Environmental Laws.

Under the NSW Environmental Planning and Assessment (EPA) Act 1979 applications for new planning consents or modifications to existing consents are evaluated in consideration of the likely impacts of the development, the suitability of the site, the provisions of environmental planning instruments and the public interest, amongst other matters.

New applications for mining projects are generally determined by the NSW Independent Planning Commission, whereas modifications to existing consents are determined under delegation by the NSW Department of Planning, Housing and Infrastructure.

Any modification to an existing planning consent must be substantially the same as the approved development, otherwise a new consent is required.

Peabody Energy Corporation 2024 Form 10-K

Through the Mining Act, environmental protection and reclamation are regulated by conditions in all mining leases including requirements for the submission of a mining operations plan (MOP) prior to the commencement of operations.

All mining operations must be carried out in accordance with the MOP which describes site activities and the progress toward environmental and reclamation outcomes and are updated on a regular basis or if mine plans change.

The mines publicly report their reclamation performance on an annual basis.

In support of the MOP process, a reclamation cost estimate is calculated periodically to determine the amount of bond support required to cover the cost of reclamation based on the extent of disturbance during the MOP period.

Queensland Reclamation.

The EP Act is administered by the Department of Environment and Science, which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA).

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In December 2023, the Climate Change (Net Zero Future) Act 2023 commenced, which legislates NSW Government’s target to achieve net zero GHG emissions by 2050 and interim targets of a 50% reduction on 2005 levels by 2030 and a 70% reduction by 2035.

In June 2024, the New South Wales Minister for Planning and Public Spaces requested the New South Wales Independent Planning Commission to consider the NSW Government’s emissions reduction targets and the Act’s guiding principles in its assessment of new planning applications.

The NSW Environment Protection Authority (EPA) released its final NSW Guide for Large Emitters in January 2025, which applies to new applications or significant modifications for large emitting premises, such as mining operations.

The NSW Guide for Large Emitters sets out the assessment requirements including a need to implement reasonable and feasible emissions reduction technologies, set long-term and interim emission goals for the project and describe any greenhouse gas offset strategies.

The Biodiversity Conservation Act 2016 (BC Act) regulates biodiversity assessment and offsetting requirements for mining projects in New South Wales.

Biodiversity offsets can be provided through security of land-based offsets, purchase of offset credits through a market system, or payment into a government-administered Biodiversity Conservation Fund.

In December 2024, the Biodiversity Conservation Amendment (Biodiversity Offsets Scheme) Bill 2024 passed New South Wales Parliament.

This Bill legislates a transition of the biodiversity offset scheme to “net positive biodiversity outcomes”.

It also requires proponents of projects to take all reasonable measures to firstly avoid, and then minimize, impacts on biodiversity values.

The recent changes to the biodiversity offset laws will affect approval processes and timeframes for future NSW mining projects.

NSW Reclamation Laws.

The Mining Act 1992 (Mining Act) is administered by New South Wales Resources within the Department of Primary Industries and Regional Development and the New South Wales Resources Regulator.

The Mining Act authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the EPA Act and other ancillary approvals and licenses.

Through the Mining Act, environmental protection and reclamation are regulated by standard conditions in all mining leases.

These conditions include requirements for the submission of reclamation outcome documents, a reclamation risk assessment and a forward program that includes a schedule of mining activities for the next three years, and a requirement that the reclamation of land disturbed by mining must occur as soon as reasonably practicable after the disturbance occurs.

Mines are required to publicly report their reclamation performance on an annual basis and are subject to regular inspections by the NSW Resources Regulator.

Through the forward program process, a reclamation cost estimate is calculated annually to determine the amount of the security deposit (bond) required to cover the cost of reclamation based on the activities proposed over the forward program period.

NSW Strategic Statement on Coal Exploration and Mining.

The New South Wales (NSW) Government released a Strategic Statement on Coal Exploration and Mining in June 2020 which provides a high level framework for the government's policy approach to the future of the coal sector.

The NSW Government has committed to a review of the Statement this year, however no specific date has been set for commencement of the review.

NSW Coal Royalty Laws.

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

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

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

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

NSW Coal Directions.

On December 22, 2022, the State Premier declared such an emergency, intended to control coal and electricity pricing.

Subsequently, directions were issued to Peabody Energy Australia Pty Ltd and other coal producers with operations in NSW, which were amended at various dates.

The most recent directions required Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and imposed additional reporting obligations to demonstrate compliance.

The Australian Energy Regulator has confirmed that the directions have ended, and the last report was submitted on July 12, 2024.

Peabody Energy Corporation 2024 Form 10-K

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NSW Industrial Manslaughter Laws.

On June 20, 2024, the Work Health and Safety Amendment (Industrial Manslaughter) Bill 2024 (Bill) passed the NSW Parliament.

The Bill amends the Work Health and Safety Act 2011 to include the offense of industrial manslaughter.

The offense will apply to a person conducting a business or undertaking (PCBU) or an officer of a PCBU who engages in conduct that constitutes a failure to comply with the person’s health and safety duty and causes the death of a worker or another individual to whom the duty is owed;

and the person engages in conduct with gross negligence.

The maximum penalty is $20 million Australian dollars for a body corporate or 25 years imprisonment for an individual.

The Bill also provides for an alternative finding of guilt.

That is, where a person is charged with industrial manslaughter, and on trial the court or jury is not satisfied that the person is guilty but is satisfied that the person is guilty of an offense against section 31 (Gross negligence or reckless conduct— Category 1) of the NSW WHS Act, the person may be found guilty and liable to punishment for that offense.

NSW Workplace Safety Laws.

In New South Wales, a respirable crystalline silica workplace exposure standard of 0.05 mg/m 3 applies;

a respirable coal dust workplace exposure standard of 1.5 mg/m 3 applies and mines must report exceedances of these standards to the NSW Resources Regulator.

Additionally, the NSW government requires an exposure standard for diesel particulate matter of 0.1 mg/m 3 .

Underground coal mine operators must also develop and implement safety management systems and procedures to minimize worker exposures to carbon dioxide, ensuring no worker is exposed to an 8-hour time-weighted average atmospheric concentration of carbon dioxide that is greater than 30,000 parts per million for short-term exposure or 12.500 parts per million otherwise.

Metropolitan Mine Stormwater Discharge.

Significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site resulted in stormwater being discharged from the mine site on several occasions in 2021 and 2022.

On September 6, 2023, the NSW Environment Protection Authority commenced a prosecution for five breaches of the Protection of the Environment Operations Act 1997 relating to the stormwater discharges.

On March 15, 2024, the Company pled guilty to two of the charges related to water pollution and two charges related to a failure to adequately maintain plant and equipment were consolidated into one charge to which the Company also pled guilty.

The remaining charge was discontinued.

A sentencing hearing was held in November 2024 and the judgment has been reserved.

The judgment is expected in the second quarter of 2025.

Queensland Government

A guideline has been issued that provides more certainty to the industry on the circumstances in which an EPO may be issued.

Queensland Environmental and Rehabilitation (Reclamation) Laws.

The EP Act is administered by the Department of the Environment, Tourism, Science and Innovation which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA).

Environmental protection and reclamation activities are regulated by conditions in the EA.

All mining operations must be carried out in a manner so as to ensure compliance with the conditions in the EA.

The mines submit an annual return reporting on their EA compliance.

In November 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 which provided for a new financial assurance (FA) framework and new progressive rehabilitation requirements.

Mines must submit an annual return reporting on their EA compliance.

In November 2016, amendments to the EP Act and the Water Act 2000 provided for regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction.

(a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later);

or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company).

In November 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 which introduced an updated financial assurance (FA) framework and progressive rehabilitation requirements.

The new FA framework created a pooled fund covering most mines and most of the total industry liability, plus other options for providing FA if not part of the pooled fund (for example, allowing insurance bonds or cash).

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The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which does not provide for discounting.

Peabody Energy Corporation 2024 Form 10-K

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The new progressive rehabilitation requirements, which commenced on November 1, 2019, require each mine to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation require regulatory approval.

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Under the legislation, an existing mine was exempt from the requirement to justify its NUMAs to the extent that its existing approvals provided for such areas.

Residual Risks .

Queensland Residual Risk Laws.

On August 20, 2020, the Environmental Protection and Other Legislation Amendment Act (Queensland) 2020 (EPOLA Act) became law, amending the residual risk framework that aims to ensure that any remaining risks on former resource sites are appropriately identified, costed and managed.

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Depending on the level of risk of a particular site, a cost calculator tool might be used or a panel of appropriately qualified experts might undertake a qualitative and quantitative risk assessment.

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.

Peabody Energy Corporation 2023 Form 10-K

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 Senate 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.

On November 24, 2022, the Environment Minister announced the Australian government’s support for all but one of the recommendations from the Senate Inquiry (whether final responsibility for heritage protection should sit with the Indigenous Affairs Minister or the Environment Minister is still being assessed) and indicated laws to protect Aboriginal cultural heritage would be strengthened following a further review of mining standards.

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

Queensland Mine Permitting Laws.

Queensland planning policies address matters of Queensland state interest and must be adhered to during mining project approvals.

The Mineral Resources Act 1989 is the principal legislation that regulates mining exploration, extraction and processing in Queensland, including coal mining.

The Act was amended in 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements, and the coordination of activities and access to private and public land.

Queensland Occupational Health and Safety Laws.

Queensland 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.

In September 2020, Safe Work Australia (SWA) recommended new national Workplace Exposure Standards (WES) of 1.5 milligrams per cubic meter (mg/m 3 ) for coal dust and 0.05 mg/m 3 for silica.

In Queensland, workplace exposure standards for respirable crystalline silica require workplaces to observe an eight hour, time-weighted average airborne concentration of 0.05mg/m 3 .

In New South Wales, a respirable crystalline silica workplace exposure standard of 0.05 mg/m 3 applies;

a respirable coal dust workplace exposure standard of 1.5 mg/m 3 applies and mines must report exceedances of these standards to the NSW Resources Regulator.

Additionally, the NSW government requires an exposure standard for diesel particulate matter of 0.1 mg/m 3 .

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) WES for 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.

In Queensland, workplace exposure standards for respirable crystalline silica require workplaces to observe an eight hour, time-weighted average airborne concentration of 0.05 mg/m 3 and 1.5 mg/m 3 for respirable coal dust.

The workplace exposure standard for CO 2 requires coal mine operators to ensure workers are not exposed to greater than 30,000 ppm for short-term exposure or 12.500 ppm otherwise.

Queensland Mine Safety Laws.

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

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It also provides for an independent Work Health and Safety Prosecutor to prosecute serious offenses under resources safety legislation.

On May 20, 2020, the Queensland Parliament passed a bill into law that introduces the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are “senior officers” and companies in the mining industry.

Individuals now face a maximum prison sentence of 20 years and companies could be fined up to approximately $13 million Australian dollars.

This new law became effective July 1, 2020.

The bill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity with an 18-month transition period which ended November 25, 2022.

Industrial Relations .

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

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.

Peabody Energy Corporation 2023 Form 10-K

In December 2022, the federal government passed The Fair Work Legislation Amendment (Secure Jobs, Better Pay) Act 2022, which amends the Fair Work Act.

The legislation introduced several changes to workplace laws in Australia including changes to enterprise agreement making and termination;

when industrial action can be taken;

and access to multi-employer bargaining.

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

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

Following this amendment, the Wambo Underground Mine and four other mines in New South Wales were served with an application for a single interest employer authorization by a union representing certain categories of employees.

If the authorization is granted by the Fair Work Commission, this will initiate the bargaining process for a single enterprise agreement covering all five employers for those specified employee categories.

Peabody is still assessing the potential impacts associated with the application.

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

The bill proposed amendments to the Fair Work Act 2009 to allow unions and employees to make application to the Fair Work Commission for a ‘ regulated labour hire arrangement order ’ that, if successful, would require employers to provide similar wages and conditions to regulated workers as those provided to permanent employees, unless the Fair Work Commission is satisfied that it is not fair and reasonable to do so.

The bill passed the Australian Federal Parliament on December 7, 2023 and applications for regulated labor hire arrangements can be made beginning in November 2024.

The reforms have the potential to increase labor and compliance costs for coal producers, and Peabody is currently considering mitigation strategies.

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

The Clean Energy Regulator administers the NGER Act.

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

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

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

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

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

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

In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015.

The reforms commenced on July 1, 2023 and introduced site specific baseline emissions for heavy emitting facilities as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030.

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

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

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

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

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

The legislation went into effect on July 1, 2023.

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

Peabody Energy Corporation 2023 Form 10-K

Queensland Royalty .

As part of the Queensland government’s 2019-20 budget, the government committed to freeze royalty rates on coal and minerals for three years, provided companies voluntarily contributed to a Resource Community Infrastructure Fund (the Fund) over this three-year period.

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

Peabody’s contribution to the Fund was approximately $1.7 million Australian dollars over the three-year period of 2019-2022.

Queensland Industrial Manslaughter Laws.

On May 20, 2020, the Queensland Parliament passed laws that introduced the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are senior officers and companies in the mining industry.

Individuals face a maximum prison sentence of 20 years and companies can be fined up to $13 million Australian dollars.

The bill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity.

Queensland Coal Royalties.

On and from July 1, 2022, the Queensland government introduced three new royalty tiers for coal produced and sold from the state.

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and a 40% tier for the portion of prices above $300 Australian dollars per tonne.

Previously, the maximum royalty rate was 15% of the value of the coal sold above $150 Australian dollars per tonne.

The change follows a three-year freeze on royalty rates for coal in the state.

The increased rate structure may impact the Company’s future decisions about its Queensland operations.

New South Wales Royalty .

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

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

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

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

Sydney Water Catchment Areas .

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

The Panel issued its final report in October 2019, which made findings and recommendations concerning mining activities and effects across the catchment as a whole.

In response to the Panel’s recommendations, in 2020 the DPE established an interagency taskforce to implement a detailed action plan which includes:

ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies;

establishing a new independent expert panel (Independent Advisory Panel) to advise on future mining applications in the catchment;

strengthening surface and groundwater monitoring;

improving access to and transparency of environmental data;

adopting a more stringent approach to the assessment and conditioning of future mining proposals to minimize subsidence impacts;

reviewing and updating current and potential future water losses from mining in line with the best available science;

introducing a licensing regime to properly account for any water losses;

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

When requested by the DPE, the Independent Advisory Panel is available to provide informed technical advice to the DPE or the Independent Planning Commission in relation to development applications and post-approval matters relating to the assessment and management of subsidence impacts associated with underground mining across NSW, with a particular focus on risks to the quantity of water in the catchment.

The Independent Advisory Panel is comprised of an independent chair and experts in the fields of mining engineering and subsidence, surface water, groundwater and swamp hydrology and ecology.

Advice that may be provided by the Independent Advisory Panel may include, but is not confined to, risks to the total water quantity and holding capacity of surface and groundwater systems, including swamps and reservoirs, and the types and reliability of methodologies used to predict, monitor, assess and report on mining effects, impacts and consequences.

Risks Related to Global Climate Change

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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 Energy Corporation 2024 Form 10-K

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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.

Peabody Energy Corporation 2023 Form 10-K

The Board 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.

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

Management believes that the Company’s external communications, including environmental regulatory filings and public notices, SEC filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress.

Management believes that the Company’s external communications, including environmental regulatory filings and public notices, SEC filings, its annual Sustainability Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress towards mitigating these risks.

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

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

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

The 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 policies of financial institutions and other private companies as related to safety, sustainability, human capital and governance practices.

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:

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• Reputational damage associated with involvement in GHG emissions;

• Increased cost and reputational damage related to climate litigation.

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

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

Peabody Energy Corporation 2024 Form 10-K

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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.

Numerous reports, such as the Sixth 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 has been 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, and volatility in the regulatory space is likely to continue.

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

Peabody Energy Corporation 2023 Form 10-K

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.

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, and ongoing actions to limit such emissions, such as carbon taxes, 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.

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

Peabody Energy Corporation 2024 Form 10-K

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

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

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

Peabody Energy Corporation 2023 Form 10-K

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 GHG emission targets for developed nations.

23 unchanged sentences

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