btu-20241231
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________
FORM 10-K
(Mark One)
For the Fiscal Year Ended December 31, 2024
or
Commission File Number 1-16463
____________________________________________
PEABODY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
(Address of principal executive offices) (Zip Code)
(314) 342-3400
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share BTU New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☑ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer☑ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
Aggregate market value of the voting and non-voting common equity held by non-affiliates (stockholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2024: Common Stock, par value $0.01 per share, $2.1 billion.
Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 14, 2025: Common Stock, par value $0.01 per share, 121,567,621 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s 2025 Annual Meeting of Shareholders (the Company’s 2025 Proxy Statement) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.
CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This report includes statements of the Company’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or the Company’s future financial performance. The Company uses words such as “anticipate,” “believe,” “expect,” “intend,” “may,” “forecast,” “project,” “should,” “estimate,” “goal,” “plan,” “outlook,” “target,” “likely,” “could,” “may,” “should,” “will,” “would,” “to be” or other similar words to identify forward-looking statements.
Without limiting the foregoing, all statements relating to the Company’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions and expectations that the Company believes in good faith to be reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These risks include but are not limited to those described in Part I, Item 1A. “Risk Factors.” Such factors are difficult to accurately predict and may be beyond the Company’s control.
When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in the Company’s other Securities and Exchange Commission (SEC) filings. These forward-looking statements speak only as of the date on which such statements were made, and the Company undertakes no obligation to update these statements except as required by federal securities laws.
Peabody Energy Corporation 2024 Form 10-K i
TABLE OF CONTENTS
Page
PART I.
Item 1. Business 2
Item 1A. Risk Factors 25
Item 1B. Unresolved Staff Comments 40
Item 1C. Cybersecurity 40
Item 2. Properties 41
Item 3. Legal Proceedings 56
Item 4. Mine Safety Disclosures 56
PART II.
Item 6. Reserved 58
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 77
Item 8. Financial Statements and Supplementary Data 79
Item 9A. Controls and Procedures 79
Item 9B. Other Information 82
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 82
PART III.
Item 10. Directors, Executive Officers and Corporate Governance 82
Item 11. Executive Compensation 82
Item 14. Principal Accountant Fees and Services 83
PART IV.
Item 15. Exhibits and Financial Statement Schedules 83
Signatures 91
Peabody Energy Corporation 2024 Form 10-K 1
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PART I
Item 1. Business.
Overview
Peabody is a leading producer of metallurgical and thermal coal. At December 31, 2024, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia, including a 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount).
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
As of December 31, 2024, Peabody reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin, Other U.S. Thermal and Corporate and Other. Refer to Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding the Company’s segments. Note 22. “Segment and Geographic Information” to the accompanying consolidated financial statements is incorporated herein by reference and also contains segment and geographic financial information.
Mining Locations
The maps that follow display Peabody’s active and development mine locations as of December 31, 2024. Also shown are the primary ports that the Company uses for its coal exports and the Company’s corporate headquarters in St. Louis, Missouri.
Peabody Energy Corporation 2024 Form 10-K 2
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U.S. Locations
Peabody Energy Corporation 2024 Form 10-K 3
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Australian Locations
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The table below summarizes information regarding the operating characteristics of each of the Company’s mines in the U.S. and Australia. The mines are listed within their respective reporting segment in descending order, as determined by tons produced in 2024.
Production
Seaborne Thermal (Tons in millions)
Wilpinjong New South Wales S D, T/S T R, EV Yes 12.6 12.0 12.1
Wambo Open-Cut (1) New South Wales S T/S T, C R, EV Yes 3.3 2.6 2.0
Wambo Underground (2) New South Wales U LW T, C R, EV Yes 1.4 1.2 1.1
Seaborne Metallurgical
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) Queensland S DL, D, T/S P R, EV Yes 1.7 2.2 2.4
Moorvale (4) Queensland S D, T/S C, P, T R, EV Yes 1.5 2.2 1.5
Centurion (5) Queensland U LW C R, EV Yes 0.2 — —
Middlemount (6) Queensland S D, T/S C, P R, EV Yes — — —
Powder River Basin
North Antelope Rochelle Wyoming S DL, D, T/S T R No 59.7 62.0 60.4
Caballo Wyoming S D, T/S T R No 10.8 15.3 12.1
Rawhide Wyoming S D, T/S T R No 9.1 9.8 10.3
Other U.S. Thermal
Bear Run Indiana S DL, D, T/S T Tr, R, EV Yes 5.0 5.5 6.7
El Segundo/Lee Ranch New Mexico S DL, D, T/S T R No 2.4 3.4 3.7
Gateway North Illinois U CM T Tr, R, R/B, T/B, EV Yes 2.1 2.5 2.4
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
Legend:
S Surface Mine B Barge
U Underground Mine Tr Truck
HW Highwall Miner R/B Rail to Barge
DL Dragline T/B Truck to Barge
D Dozer/Casting T/R Truck to Rail
T/S Truck and Shovel EV Export Vessel
LW Longwall T Thermal/Steam
CM Continuous Miner C Coking
R Rail P Pulverized Coal Injection
(1)Peabody owns a 50% undivided interest in an unincorporated joint venture that owns the Wambo Open-Cut Mine. The tons shown reflect its share. The Company’s 50% joint venture interest is subject to an outside non-controlling ownership interest.
(2)Majority-owned mine in which there is an outside non-controlling ownership interest.
(3)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 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. Because Middlemount is accounted for as an unconsolidated equity affiliate, the table above excludes tons produced from that mine, which totaled 1.3 million, 1.2 million and 1.4 million tons, respectively (on a 50% basis).
Refer to the Reserves and Resources tables within Item 2. “Properties,” which is incorporated by reference herein, for additional information regarding coal reserves and resources, and product characteristics associated with each mine.
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Coal Supply Agreements
Customers. Peabody’s coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of the Company’s sales from its mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions). A smaller portion of the Company’s sales from its mining operations are made under contracts with terms of less than one year, including sales made on a spot basis. Sales under long-term coal supply agreements comprised approximately 90%, 92% and 85% of the Company’s worldwide sales from its mining operations (by volume) for the years ended December 31, 2024, 2023 and 2022, respectively.
For the year ended December 31, 2024, Peabody derived 27% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 16 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2024 to 2028. Peabody’s largest customer in 2024 contributed revenue of approximately $340 million, or approximately 8% of Peabody’s total revenue from coal supply agreements, and has contracts expiring in 2025.
Backlog. 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 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 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. For its seaborne operations, the portion of sales volume under contracts with a duration of less than one year represented 36% in 2024.
U.S. Thermal Operations. Revenue from Peabody’s Powder River Basin and Other U.S. 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. thermal operating segments under existing long-term supply agreements. Certain customers utilize long-term sales agreements in recognition of the importance of reliability, service and predictable coal prices to their operations. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of those agreements may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Peabody’s approach is to selectively renew, or enter into new, long-term supply agreements when it can do so at prices and terms and conditions it believes are favorable.
Transportation
Methods of Distribution. Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. Peabody’s U.S. mine sites are typically adjacent to a rail loop; however, in limited circumstances coal may be trucked to a barge site or directly to customers. Title predominately passes to the purchaser at the rail or barge, as applicable. Peabody’s U.S. and Australian export coal is usually sold at the loading port, with purchasers paying ocean freight. In each case, the Company usually pays transportation costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time).
The Company believes it has good relationships with U.S. and Australian rail carriers and port and barge companies due, in part, to its modern coal-loading facilities and the experience of its transportation coordinators. 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.
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Export Facilities. Peabody has generally secured its ability to transport coal in Australia through rail and port contracts and access to five east coast coal export terminals that are primarily funded through take-or-pay arrangements (refer to the “Liquidity and Capital Resources” section in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information on its take-or-pay obligations). In Queensland, seaborne thermal and metallurgical coal from the Company’s mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by its joint venture Middlemount Mine. In New South Wales, the Company’s primary ports for exporting thermal and metallurgical coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group. Peabody has secured its ability to transport coal from its Shoal Creek Mine under barge and port contracts; the primary port is the McDuffie Terminal in Mobile, Alabama, which the Company utilizes without a take-or-pay arrangement.
Peabody’s U.S. thermal 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. thermal exports is the Kinder Morgan Terminal near Houston, Texas.
Suppliers
Mining Supplies and Equipment. 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.
Services. 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.
Competition
Demand for coal and the prices that the Company will be able to obtain for its coal are highly competitive and influenced by factors beyond the Company’s control, including but not limited to global economic conditions; the demand for electricity and steel; the cost of alternative sources; the impact of weather on heating and cooling demand; the capacity and cost of transportation; geopolitical risks; and taxes and environmental regulations imposed by the U.S. and foreign governments.
Thermal Coal. Demand for Peabody’s thermal coal products is impacted by economic conditions; demand for electricity, which is impacted by energy efficient products; and the cost of electricity generation from coal and alternative forms of generation. Regulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption. The Company’s products compete with producers of other forms of electricity generation, including natural gas, oil, nuclear, hydro, wind, solar and biomass, that provide an alternative to coal use. 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.
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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. The competitiveness of natural gas has been strengthened by continued growth in domestic natural gas production and new natural gas combined cycle generation capacity. The Henry Hub Natural Gas Prompt Price averaged $2.41 per mmBtu in 2024, versus $2.66 and $6.54 per mmBtu in 2023 and 2022, respectively. 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 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-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. The competitiveness and availability of natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Colombia, the U.S., Russia and South Africa, among others. 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. 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. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners; American Consolidated Natural Resources, Inc.; Core Natural Resources, Inc.; Eagle Specialty Materials LLC; Foresight Energy; Hallador Energy; Kiewit; and Navajo Transitional Energy Company LLC, among others. Major international direct coal supply competitors (listed alphabetically) include Adaro Energy; BHP; Bumi Resources; China Shenhua Energy; Coal India Limited; Drummond Company; Glencore; SUEK; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.
Metallurgical Coal. Demand for Peabody’s metallurgical coal products is impacted by economic conditions; government policies; demand for steel; and competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces. The Company competes on the basis of coal quality and characteristics, delivered energy cost (including transportation costs), customer service and support and reliability of supply.
Seaborne metallurgical coal import demand can be significantly impacted by the availability of domestic coal production, particularly in leading metallurgical coal import countries such as China, among others, and the competitiveness of seaborne metallurgical coal supply from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others. 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; BHP; Core Natural Resources, Inc.; Foxleigh; Glencore; Jellinbah; KRU; Oak Grove Mine; Stanmore; Warrior Met Coal; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.
Human Capital
Peabody had approximately 5,600 employees as of December 31, 2024, including approximately 4,300 hourly employees. Additional information on its employees and related labor relations matters is contained in Note 19. “Management — Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference. Peabody endeavors to engage with its organized workforce and foster strong relationships with those organizations built on trust and communication.
As of December 31, 2024, approximately 3,500 of Peabody’s employees are located in the U.S., with the remainder primarily located in Australia. About 94% of its team members work for mine operations in the U.S. and Australia, while the remaining are based out of its global headquarters in St. Louis or its business offices in Brisbane and Beijing.
Peabody strives to create a strong, united workforce with a commitment to safety as a way of life. In 2024, the Company achieved a global safety incidence rate of 0.81 incidents per 200,000 hours worked, which was 73% better than the 2023 U.S. industry average incidence rate of 2.98 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).
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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 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 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. During the past five years, approximately 28% of open positions and 63% of director and above positions have been filled by internal candidates through promotions or lateral career development opportunities.
Information About Our Executive Officers
Set forth below are the names, ages and positions of Peabody’s executive officers. Executive officers are appointed by, and hold office at the discretion of, Peabody’s Board of Directors (the Board), subject to the terms of any employment agreements.
Name Age (1) Position (1)
James C. Grech 63 President and Chief Executive Officer
Mark A. Spurbeck 51 Executive Vice President and Chief Financial Officer
Darren R. Yeates 64 Executive Vice President and Chief Operating Officer
Scott T. Jarboe 51 Chief Administrative Officer and Corporate Secretary
Patrick J. Forkin III 66 Chief Development Officer
Malcolm Roberts 51 Chief Marketing Officer
(1) As of February 14, 2025.
James C. Grech was named Peabody’s President and Chief Executive Officer in June 2021. He has over 30 years of experience in the coal and natural resources industry. Mr. Grech served as Chief Executive Officer and a member of the Board of Directors of Wolverine Fuels, LLC, a thermal coal producer and marketer based in Sandy, Utah, from July 2018 until May 2021. Prior to joining Wolverine Fuels, LLC, Mr. Grech served as President of Nexus Gas Transmission from October 2016 to July 2018, and previously held the position of Chief Commercial Officer and Executive Vice President of Consol Energy. Mr. Grech brings a strong operational, commercial and financial background in both mining and other energy business operations and has extensive utilities and capital markets experience. He serves as a director of Blue Danube. Mr. Grech holds a Bachelor of Science in Electrical Engineering from Lawrence Technological University and an MBA from the University of Michigan.
Mark A. Spurbeck was named Peabody’s Executive Vice President and Chief Financial Officer in June 2020, after serving in an interim capacity from January 2020 through June 2020. He oversees finance, treasury, tax, internal audit, financial reporting, financial planning, risk and mine finance, corporate accounting functions, investor relations and corporate communications, information technology and shared services. Mr. Spurbeck has more than 25 years of accounting and financial experience, most recently serving as the Company’s Senior Vice President and Chief Accounting Officer from early 2018 to January 2020. Prior to joining Peabody, Mr. Spurbeck served as Vice President of Finance and Chief Accounting Officer at Coeur Mining, Inc., a diversified precious metals producer, from March 2013 to January 2018. He also previously held multiple financial positions at Newmont Mining Corporation, a leading gold and copper producer, First Data Corporation, a financial services company, and Deloitte LLP, an international accounting, tax and advisory firm. Mr. Spurbeck is a Certified Public Accountant (inactive) and holds a Bachelor’s Degree in Accounting from Hillsdale College.
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Darren R. Yeates was named Peabody’s Executive Vice President and Chief Operating Officer in October 2020. He has executive responsibility for global operations including health, safety and environment, mine operations, technical, procurement, and sales and marketing. Mr. Yeates has over 40 years of mining industry experience. From May 2018 to December 2019, Mr. Yeates served as Chief Operating Officer of MACH Energy Australia, a developer and supplier of thermal coal to both the Australian domestic and Asian export markets. From January 2014 until June 2016, Mr. Yeates served as the Chief Executive Officer of GVK Hancock Coal, a joint venture developing the vast potential of the Galilee Basin in Central Queensland. Prior to that, he spent over 22 years with Rio Tinto, a global mining group, including as Acting Managing Director and Chief Operating Officer for Coal Australia, General Manager Ports and Infrastructure for Pilbara Iron and General Manager Tarong Coal. Prior to joining Rio Tinto, Mr. Yeates worked for six years for BHP, a mining, metals and petroleum company, in coal operations and metalliferous exploration. Mr. Yeates holds a Bachelor of Engineering (Mining) from the University of Queensland, a Graduate Diploma in Management from the University of Central Queensland and a Graduate Diploma of Applied Finance and Investment from the Securities Institute of Australia. He holds an Executive MBA from the Monash Mt Eliza Business School and is a Fellow of the Australian Institute of Company Directors.
Scott T. Jarboe was named Peabody’s Chief Administrative Officer and Corporate Secretary in November 2021 after serving as Chief Legal Officer and Corporate Secretary since March 2020. He leads the Company’s global human resources, legal, government affairs, and ethics and compliance functions. Mr. Jarboe joined Peabody in 2010 and has served in a variety of legal roles. Previously, Mr. Jarboe practiced law with Husch Blackwell LLP and Bryan Cave LLP. Mr. 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.
Patrick J. Forkin III was named Chief Development Officer in July 2022 after serving as Senior Vice President - Corporate Development and Strategy since November 2017. He leads global strategy, mergers and acquisitions, portfolio management and renewable energy development. Mr. Forkin joined Peabody in 2010 and has served in a variety of roles. He has an extensive background in corporate finance, the energy industry, mergers and acquisitions and equity market research. Prior to joining Peabody, Mr. Forkin was in senior leadership roles at a U.S. solar development company and investment banking firms specializing in renewable and conventional energy. He spent the first nine years of his career at Deloitte LLP. Mr. Forkin holds a Bachelor of Science degree in Accountancy from the University of Illinois at Urbana-Champaign and is a Certified Public Accountant (inactive).
Malcolm Roberts was named Chief Marketing Officer in May 2023. He has responsibility for all Peabody sales, marketing and logistics. Mr. Roberts joined Peabody in 2021 as Executive General Manager - Sales & Marketing. He has more than 25 years of experience in the resources and commodities industry, focused on the energy and steel sector, with roles encompassing key aspects of the value chain including finance, commercial, trading and sales and marketing. During the period of October 2018 to June 2020, Mr. Roberts was a senior trading lead within the trading division of Heidelberg Cement, a company with global operations in the cement and concrete industry. His responsibilities included leading a team of traders focused on the trading of solid fuel and other cementitious products. Prior to that, Mr. Roberts spent thirteen years in sales and marketing roles with Rio Tinto primarily within their Energy Product Group, including eleven years in leadership roles covering Rio Tinto’s global coal sales, marketing, trading, logistics and analytics functions, encompassing both metallurgical and thermal coal. Prior to this, Mr. Roberts worked within sales and marketing and finance roles in both mining and manufacturing industries. Mr. Roberts holds an undergraduate degree in Commerce and Management from Lincoln University in New Zealand and is a CA member of Chartered Accountants Australia and New Zealand.
Regulatory Matters — U.S.
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant requirements mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. Peabody believes that it has obtained all permits currently required to conduct its present mining operations.
The Company endeavors to conduct its mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. The Company continually monitors the laws and regulations for changes resulting from updated legislation, judicial decisions and changes in governmental administrations.
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Mine Safety and Health
Peabody is subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.
MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA employs various enforcement measures for noncompliance, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine.
In Part I, Item 4. “Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, the Company provides additional details on MSHA compliance.
Black Lung (Coal Workers’ Pneumoconiosis)
Black Lung Benefits. Under the U.S. Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator who was the last to employ a claimant for a cumulative year of employment, with the last day worked for the operator after July 1, 1973, must pay federal black lung benefits and medical expenses to claimants whose claims for benefits are allowed. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. The federal black lung program also includes automatic survivor benefits paid upon the death of a miner with an awarded black lung claim and a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.
The trust fund has been funded by an excise tax on U.S. production. 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.
Black Lung Benefits Act Self-Insurance Requirements. The Black Lung Benefits Act requires each coal mine operator to secure the payment of its potential benefits liability by either qualifying as a self-insurer or by purchasing and maintaining a commercial insurance contract. 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 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
Peabody is subject to various federal, state, local and tribal environmental laws and regulations. These laws and regulations place substantial requirements on its coal mining operations and require regular inspection and monitoring of its mines and other facilities to ensure compliance. The Company is also affected by various other federal, state, local and tribal environmental laws and regulations that impact its customers.
Surface Mining Control and Reclamation Act. In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSMRE), established mining, environmental protection and reclamation standards for surface mining and underground mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from OSMRE or from the respective state regulatory authority. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority, with oversight from OSMRE. States in which Peabody has active mining operations have achieved primacy control of enforcement through federal authorization. In Arizona, where Peabody performs reclamation work on tribal lands, the Company is regulated by OSMRE because the tribes do not have SMCRA authorization.
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SMCRA provides for three categories of bonds: surety bonds, collateral bonds and self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.
The Company’s total reclamation bonding requirements in the U.S. were $893.1 million as of December 31, 2024. The bond requirements for a mine represent the calculated cost to reclaim the current operations of a mine if it ceased to operate in the current period. The cost calculation for each bond must be completed according to the regulatory authority of each state or OSMRE. The Company’s asset retirement obligations calculated in accordance with generally accepted accounting principles for its active and inactive U.S. operations were $473.3 million as of December 31, 2024. The bond requirement amount for the Company’s U.S. operations significantly exceeds the financial liability for final mine reclamation because the asset retirement obligation liability is discounted from the end of the mine’s economic life to the balance sheet date in recognition that the final reclamation cash outlay is projected to be a number of years away. The bond amount, in contrast with the asset retirement obligation, presumes reclamation begins immediately, as well as different assumptions related to the cost of equipment and services utilized in the reclamation process.
After a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation bonding requirements.
In situations where the Company’s coal resources are federally owned, the U.S. Bureau of Land Management oversees a substantive exploration and leasing process. If surface land is managed by the U.S. Forest Service, that agency serves as the cooperating agency during the federal coal leasing process. Federal coal leases also require an approved federal mining permit under the signature of the Assistant Secretary of the Department of the Interior.
The SMCRA Abandoned Mine Land Fund requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund created by the Coal Industry Retiree Health Benefit Act of 1992. The fee amount can change periodically based on changes in federal legislation. 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.
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect the Company’s U.S. coal mining operations both directly and indirectly.
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 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/m3 to 9.0 μg/m3. 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. EPA, (D.C. Cir., No. 24-1050).
The EPA is also in the process of reviewing the current ozone NAAQS. The level of the ozone NAAQS can also affect requirements to install new or improved emission control technologies at fossil fuel-fired EGUs and non-EGU industrial sources.
Final 2015 New Source Performance Standards (NSPS) for Fossil Fuel-Fired EGUs. The EPA promulgated a final rule to limit carbon dioxide (CO2) 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.
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The rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for CO2 (known as the Best System of Emission Reduction (BSER)) which is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed EGUs must implement the most efficient generating technology based on the size of the unit.
Numerous legal challenges to the final rule were filed in the D.C. Circuit. Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports.
EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs. 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 CO2 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 CO2 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 CO2 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% CO2 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 CO2 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 CO2 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. EPA (D.C. Cir., No. 24-1120). 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 CO2 emission limits for existing power plants has also been challenged in West Virginia v. EPA (D.C. Cir., No. 24-1009).
EPA’s Permitting Regulations for Major Emission Sources. Coal-fired and other fossil-fuel fired power plants (as well as industrial facilities) may also be subject to emission limits contained in required CAA permits. These limits may be imposed through the Prevention of Significant Deterioration (PSD) program for newly constructed facilities that are considered to be major sources, as well as for existing facilities that undergo major modifications. The CAA also requires such facilities to obtain a title V operating permit. In general, most permits are issued by state environmental agencies that either implement EPA permitting programs or have an EPA-approved state program.
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Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. The CSAPR and related updates require numerous U.S. states and the District of Columbia to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine PM pollution in other states.
On March 15, 2023, the EPA issued a final rule to address regional ozone transport by imposing new federal ozone season emission budgets for nitrogen oxide (NOx) in 23 states, including California, Nevada, Oklahoma and Texas, as well as some Indian reservations. The rule includes state emission budgets for NOx affecting fossil fuel-fired power plants and a “backstop daily emissions rate” for large coal-fired power plants if they exceed specified limits. The rule also sets first-time limits on certain industrial sources that will apply starting with the 2026 ozone season in 20 states. The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million. These emission limitations would apply in addition to requirements contained in state implementation plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations. When implemented, this rule could influence the closure of some coal generating units that have not installed selective catalytic reduction technologies.
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; the D.C. 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). In 2012, the EPA published the final MATS rule, which revised the NSPS for NOx, sulfur dioxide and PM for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs.
On March 6, 2023, the EPA issued a final rule which reaffirmed its determination to regulate coal- and oil-fired EGUs under CAA section 112, including the regulation of HAPs from EGUs after considering cost. On April 24, 2023, the EPA proposed to amend the 2012 MATS rule and require an additional two-thirds reduction in the filterable PM emission of non-mercury HAP metals from existing coal-fired power plants and to reduce the mercury standard for lignite plants by 70%. 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. EPA (D.C. Cir., No. 24-1119).
Regional Haze. The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from man-made air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal.
States are required to revise plans every 10 years, 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). The CAA imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification. These requirements are contained in the CAA’s PSD and Nonattainment New Source Review programs, generally referred to as NSR.
The EPA has taken action on a number of different rules and guidance affecting the interpretation and application of NSR. 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.
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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, 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). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into jurisdictional waters. The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain permits from the Corps to place dredged or fill material in or mine through jurisdictional waters of the U.S.
States are empowered to develop and apply water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. Standards vary from state to state. Additionally, through the CWA Section 401 certification program, state and tribal regulators have approval authority over federal permits or licenses that might result in a discharge to their waters. State and tribal regulators consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.
CWA Definition of “Waters of the United States”. On January 18, 2023, the EPA and the Corps finalized a revised definition of “Waters of the United States” to clarify the scope of federal regulatory authority under the CWA. Several courts preliminarily enjoined that rule in 27 states. In addition, on May 25, 2023, the U.S. Supreme Court issued its decision in Sackett v. EPA, No. 21-454, which significantly narrowed the scope of federal regulatory authority over wetlands and non-navigable waters. The agencies finalized a rule on September 8, 2023, to conform key aspects of the regulatory definition to the Sackett decision. Pending litigation over the January 2023 definition 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. The EPA issued a final rule in 2020 that would have limited state and tribal regulators’ certification authority under CWA Section 401 by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances. On September 27, 2023, the EPA finalized a superseding rule that would expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. That rule took effect on November 27, 2023. 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. 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.
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National Environmental Policy Act. NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. Peabody must provide information to agencies when it proposes actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality (CEQ) issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. That final rule sought to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule. On 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 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. 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. 23-1067. 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). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA. While coal combustion residuals (CCR or coal ash) are exempted from regulation as hazardous waste, there are various EPA-imposed requirements regarding CCR management.
Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. Although the EPA had planned to finalize this rule in 2021, the EPA 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. 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). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.
Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans. During the 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. Peabody’s surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, it incurs costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. The storage of explosives is subject to strict federal regulatory requirements. The U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting materials. In addition to ATF regulation, the Department of Homeland Security is expected to finalize an ammonium nitrate security program rule.
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Federal Report on Climate Change. On November 29, 2023, the U.S. Global Change Research Program, a working group comprised of thirteen U.S. governmental departments and agencies, issued parts of the Fifth National Climate Assessment. The report addresses “projected vulnerabilities, risks and impacts associated with climate change across the United States and provides examples of response actions in many communities.” While there are no explicit regulatory actions that flow from the issuance of the report, both the legislative and executive branches of government may rely on its conclusions to shape and justify policies and actions going forward.
SEC Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition; certain greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider; and certain climate-related financial metrics to be included in a company’s audited financial statements. The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the 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
The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed. 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.
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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 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.
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 CO2 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.
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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. Peabody’s mines provide financial assurance to the relevant authorities which is calculated in accordance with current regulatory requirements. This financial assurance is in the form of cash, surety bonds or bank guarantees which are supported by a combination of cash collateral, deeds of indemnity and guarantee and letters of credit issued under the Company’s collateralized letter of credit program and accounts receivable securitization program.
Peabody’s reclamation bonding requirements in Australia were $303.7 million as of December 31, 2024. The bond requirements represent the states’ calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state. The cost calculation for each bond must be completed according to the regulatory authority of each state. The Company’s asset retirement obligations calculated in accordance with U.S. generally accepted accounting principles for its active and inactive Australian operations were $250.4 million as of December 31, 2024. 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 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.
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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. 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 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.
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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/m3 applies; a respirable coal dust workplace exposure standard of 1.5 mg/m3 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/m3. 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
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.
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. 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.
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).
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). The percentage rate of the total rehabilitation cost payable into the pooled fund takes into account the financial strength of the holder of the EA for the mine and the project strength of the mine. The total rehabilitation cost is determined using an updated rehabilitation cost calculator, which does not provide for discounting.
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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. If there is to remain an area within the mine that does not have a post-mining land use (referred to as a non-use management area or NUMA) then each such NUMA will need to pass a public interest evaluation test as part of the approval process. An example of a NUMA is the void that remains after open-cut mining activities have been completed. 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.
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. On completion of all mining activities, the holder of the EA for the mine can apply to surrender the EA once all conditions, requirements and rehabilitation obligations have been met. When approving the surrender, the government can request a residual risk payment from the holder of the EA for the mine to cover potential rehabilitation or maintenance costs incurred after the surrender has been accepted. It contemplates two approaches for determining residual risk payments. 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.
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 Queensland, workplace exposure standards for respirable crystalline silica require workplaces to observe an eight hour, time-weighted average airborne concentration of 0.05 mg/m3 and 1.5 mg/m3 for respirable coal dust. The workplace exposure standard for CO2 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. It establishes Resources Safety and Health Queensland (RSHQ) as a statutory body designed to ensure independence of the mining safety and health regulator. RSHQ includes inspectorates for coal mines, mineral mines and quarries, explosives and petroleum and gas. The new law seeks to enhance the role of advisory committees to identify, quantify and prioritize safety and health issues in the mining and quarrying industries. It also provides for an independent Work Health and Safety Prosecutor to prosecute serious offenses under resources safety legislation.
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. The new tier rates are 20% for the portion of prices above $175 Australian dollars per tonne; 30% for the portion of prices above $225 Australian dollars per tonne; and a 40% tier for the portion of prices above $300 Australian dollars per tonne.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to GHG emissions. The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2).
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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.
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. In addition, the Board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the Board of Directors and Peabody’s global workforce turns those objectives into meaningful actions.
Management believes that the Company’s external communications, including environmental regulatory filings and public notices, SEC filings, its annual 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.
The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements.
The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the 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:
•Reduced utilization or closure of existing coal-fired electricity generating plants;
•Electricity generators switching from coal to alternative fuels, when feasible;
•Increased costs associated with regulatory compliance;
•Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;
•Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes;
•Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions;
•Disruption to operations or markets due to anti-coal activism and litigation;
•Reputational damage associated with involvement in GHG emissions; and
•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:
•Disruption to water supplies vital to mining operations;
•Disruption to transportation and other supply chain activities;
•Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and
•Electrical grid failures and power outages.
While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:
•Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and CCUS technologies;
•Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and
•The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.
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Global climate issues continue to attract public and scientific attention. 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.
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. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.
From time to time, the Company’s Board of Directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.
Regulations Related to Global Climate Change
In the U.S., Congress has considered legislation addressing global climate issues and GHG emissions, but to date, no new comprehensive, regulatory legislation has been signed into law. The U.S. Congress, however, has approved legislation, the Inflation Reduction Act of 2022, that will provide substantial tax incentives, grants and loan guarantees for energy infrastructure, solar panels, wind turbines, nuclear and geothermal energy, hydrogen projects and carbon capture and storage. While it is possible that the U.S. will adopt additional climate legislation in the future, the timing and specific requirements of any such legislation are uncertain.
The EPA has also undertaken several steps to regulate GHG emissions under existing law, primarily the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” The EPA has indicated that it will continue these efforts and proceed with new regulations affecting GHG emissions from fossil fuel-fired electric generation, methane emissions from oil and gas production and carbon emissions from light and heavy-duty vehicles.
At the same time, a number of states in the U.S. have adopted programs to regulate GHG emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, and Pennsylvania joined in 2022. RGGI is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. California and the Canadian province of Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating.
Several other U.S. states have enacted legislation establishing GHG emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.
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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 Sustainability Report. The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal.
The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of GHG emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. In December 2012, Australia signed on to the second commitment period. During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reduction contributions after the second commitment period ends in 2020 (the Paris Agreement). The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global GHG emissions. On January 20, 2021, the U.S. reentered the Paris Agreement by accepting the agreement and all of its articles and clauses, after having announced its withdrawal from the agreement in November 2019.
In June 2022, the new Australian federal government announced plans to legislate for a 43% reduction in Australia’s GHG emissions by 2030 and to introduce changes by mid-2023 that will require heavy emitting companies producing more than 100,000 tonnes of carbon emissions annually to accelerate their emissions reduction activities. On September 13, 2022, the Australian government passed the Climate Change Act 2022 to set the GHG emissions reduction targets into law.
In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 (legislated through the National Greenhouse and Energy Reporting Act 2007 (Cth)). Refer to the section “Regulatory Matters —Australia” within this Item 1 for discussion of the reforms.
Available Information
Peabody files or furnishes annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC. These materials are available free of charge through the Company’s website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information included on the Company’s website does not constitute part of this document. These materials may also be accessed through the SEC’s website (www.sec.gov).
In addition, copies of the Company’s filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.
Item 1A. Risk Factors.
The Company operates in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company’s business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company’s business. New factors may emerge or changes to these risks could occur that could materially affect its business.
Risks Associated with Peabody’s Operations
The Company’s profitability depends upon the prices it receives for its coal.
The Company operates in a competitive and highly regulated industry that has at times experienced strong headwinds. Current pricing levels of both seaborne and domestic coal products may not be sustainable in the future. Declines in coal prices could materially and adversely affect the Company’s operating results and profitability and the value of its coal reserves and resources.
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Coal prices are dependent upon factors beyond the Company’s control, including:
•the demand for electricity and capacity utilization of electricity generating units (whether coal or non-coal);
•changes in the fuel consumption and dispatch patterns of electric power generators, whether based on economic or non-economic factors;
•the proximity, capacity and cost of transportation and terminal facilities;
•competition with and the availability, quality and price of coal and alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power;
•governmental regulations and taxes, including tariffs or other trade restrictions as well as those establishing air emission standards for coal-fueled power plants or mandating or subsidizing increased use of electricity from renewable energy sources;
•the strength of the global economy, including the relative exchange rates of U.S. dollars for foreign currencies;
•the unknown geopolitical consequences of current and future political and military conflicts, including between Russia and Ukraine;
•the global supply and production costs of thermal and metallurgical coal;
•the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of the Company’s metallurgical coal contracts;
•weather patterns, severe weather and natural disasters;
•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases;
•competing technologies used to make steel, some of which do not use coal as a manufacturing input, such as electric arc furnaces; and
•technological developments, including those related to alternative energy sources, those intended to convert coal-to-liquids or gas and those aimed at capturing, using and storing carbon dioxide.
Thermal coal accounted for the majority of the Company’s coal sales by volume during 2024 and 2023, with the vast majority of these sales to electric power generators. The demand for coal consumed for electric power generation is affected by many of the factors described above, but primarily by (i) the overall demand for electricity; (ii) the availability, quality and price of competing fuels, such as natural gas, nuclear, fuel oil and alternative energy sources; (iii) utilization of all electricity generating units (whether using coal or not), including the relative cost of producing electricity from multiple fuels, including coal; (iv) stringent environmental and other governmental regulations; (v) other sociopolitical views on coal; and (vi) the coal inventories of utilities. Gas-fueled generation has displaced and could continue to displace coal-fueled generation (particularly from older, less efficient coal-fueled generation units) as current and potentially increasing regulatory costs and other factors, such as declines in the price of natural gas, impact the operating decisions of electric power generators. In addition, some electric power generators have made decisions to close coal-fueled generation units given ongoing pressure to shift away from coal generation. Many of the new power plants in the U.S. are being fueled by natural gas because gas-fired plants have been less expensive to construct and operate, permits to construct these plants are easier to obtain based on emissions profiles and electric power generators may face public and governmental pressure to generate a larger portion of their electricity from natural gas-fueled units and alternative energy sources. Increasingly stringent regulations along with stagnant electricity demand in recent years have also reduced the number of new power plants being built. In recent years, these trends have reduced demand for the Company’s coal and the related prices. Lower demand for coal consumed by electric power generators has reduced and could continue to reduce the volume of thermal coal that the Company sells and the prices that it receives for the thermal coal, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.
The Company produces metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 25% and 26% of its revenue in 2024 and 2023, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for the Company’s metallurgical coal. The demand for foreign-produced steel both in foreign markets and in the U.S. market depends in part on factors such as tariff rates on steel. The Company’s customers may be affected by imposed tariffs to the extent their imports into other countries are curtailed as a result of tariffs.
In addition, the steel industry’s demand for metallurgical coal is affected by a number of factors, including the variable nature of that industry’s business, technological developments in the steel-making process and the availability of substitutes for steel, such as aluminum, composites and plastics. The steel industry increasingly relies on processes to make steel that do not use coal as a manufacturing input, such as electric arc furnaces. Lower demand for metallurgical coal in international markets would reduce the amount of metallurgical coal that Peabody sells and the prices that it receives for it, thereby reducing revenues and adversely impacting earnings and the value of its coal reserves. Foreign government policies related to coal production and consumption could also negatively impact pricing and demand for the Company’s products.
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If a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenue and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts.
Most of the Company’s sales are made under coal supply agreements, which are important to the stability and profitability of its operations. The execution of a satisfactory coal supply agreement is frequently the basis on which the Company undertakes the development of coal reserves and resources required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2024, the Company derived 27% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 16 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2024 to 2028.
Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. The Company may adjust these contract prices based on inflation or deflation, price indices and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. The Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of its expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the Company or the customer during the duration of specified events beyond the control of the affected party. Some coal supply agreements allow customers to vary the volumes of coal that they are required to purchase during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request that the Company amend the agreements to allow for such variation. Most of its coal supply agreements contain provisions requiring the Company to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow the Company’s customers to terminate their contracts in the event of changes in regulations affecting the coal industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.
On an ongoing basis, the Company discusses the extension of existing agreements or entering into new long-term agreements with various customers, but these negotiations may not be successful and these customers may not continue to purchase coal from the Company under long-term supply agreements.
The operating profits the Company realizes from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase its exposure to short-term coal price volatility. If a substantial portion of the Company’s coal supply agreements were modified or terminated, it could be materially adversely affected to the extent that it is unable to find alternate buyers for its coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, the Company cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that it will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, the Company’s revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand and oversupply, cost of competing fuels and environmental and other governmental regulations.
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Risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company.
The Company’s mining operations are subject to conditions that can impact the safety of its workforce, delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:
•elevated gas levels;
•fires and explosions, including from methane gas or coal dust;
•accidental mine water discharges;
•weather, flooding and natural disasters;
•hazardous events such as roof falls and high wall or tailings dam failures;
•seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•key equipment failures;
•supply chain constraints or unavailability of equipment or parts of the type, quantity and/or size needed to meet production expectations;
•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits and geologic conditions impacting mine sequencing;
•delays in moving its longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to its operations.
The Company maintains insurance policies that provide limited coverage for some of the risks referenced above, which may lessen the impact associated with these risks. However, there can be no assurance as to the amount or timing of recovery under its insurance policies in connection with losses associated with these risks.
The Company’s take-or-pay arrangements could unfavorably affect its profitability.
The Company has substantial take-or-pay arrangements with its port access and rail transportation providers, predominately in Australia, totaling $1.0 billion, with terms ranging up to 19 years, that commit the Company to pay a minimum amount for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow the Company to apply amounts paid for subsequent deliveries, but these provisions have limitations and the Company may not be able to apply all such amounts so paid in all cases. Also, the Company may not be able to utilize the amount of capacity for which it has previously paid. Additionally, the Company may continue to deliver coal during times when it might otherwise be optimal to suspend operations because these take-or-pay provisions effectively convert a variable cost of selling coal to a fixed operating cost.
The Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets.
The value of the Company’s assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond the Company’s control, including unfavorable changes in the economic environments in which it operates; declining coal-fired electricity generation; lower-than-expected coal pricing; technical and geological operating difficulties; an inability to economically extract its coal reserves and resources; and unanticipated increases in operating costs. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on the Company’s results of operations.
Because of the volatile and cyclical nature of coal markets, it is reasonably possible that the Company’s current estimates of projected future cash flows from its mining assets may change in the near term, which may result in the need for adjustments to the carrying value of its assets.
The Company’s ability to operate effectively could be impaired if it loses key personnel or fails to attract qualified personnel.
Peabody manages its business with a number of key personnel, the loss of whom could have a material adverse effect on the Company, absent the completion of an orderly transition. In addition, the Company believes that its future success will depend greatly on its continued ability to attract and retain highly skilled and qualified personnel in tight labor markets, particularly personnel with mining experience. Peabody cannot provide assurance that key personnel will continue to be employed by the Company or that it will be able to attract and retain qualified personnel in the future. Failure to retain key personnel or attract qualified personnel could have a material adverse effect on the Company.
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The Company could be negatively affected if it fails to maintain satisfactory labor relations.
As of December 31, 2024, the Company had approximately 5,600 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 4,300 hourly employees. The Company is party to labor agreements with various labor unions that represent certain of its employees. Such labor agreements are negotiated periodically, and, therefore, the Company is subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 40% of its hourly employees were represented by organized labor unions and generated approximately 21% of its coal production for the year ended December 31, 2024. Relations with its employees and, where applicable, organized labor are important to the Company’s success. If some or all of its current non-union operations were to become unionized, the Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if the Company fails to maintain good relations or successfully negotiate contracts with its employees who are represented by unions, the Company could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact its profitability.
The Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations.
U.S. federal and state laws and Australian laws require the Company to provide financial assurances related to requirements to reclaim lands used for mining; to pay federal and state workers’ compensation, such as black lung liabilities; to provide financial assurances for coal lease obligations; and to satisfy other miscellaneous obligations. Historically, the primary methods the Company has used to meet those obligations are to provide a third-party surety bond or a letter of credit. In recent years, the Company has also utilized deposits with regulatory authorities or cash-backed bank guarantees. As of December 31, 2024, the Company had $1,017.5 million of outstanding surety bonds; $262.3 million of letters of credit with third parties; $168.5 million of cash-backed bank guarantees; and $127.6 million of deposits with regulatory authorities in order to provide required financial assurances for post-mining reclamation, workers’ compensation and other insurance obligations, coal lease-related and other obligations and performance guarantees, in addition to collateral for sureties. Under the Company’s agreement with the providers of its surety portfolio, the Company has $394.6 million in cash held in trust accounts for the benefit of certain surety providers as of December 31, 2024.
The Company’s financial assurance obligations may increase or become more costly due to a number of factors, and surety bonds and letters of credit may not be available to the Company, particularly in light of some banks and insurance companies’ announced unwillingness to support thermal coal producers and other fossil fuel companies. Alternative forms of financial assurance such as self-bonding have been severely restricted or terminated in most of the regions where its mines reside. The Company’s failure to retain, or inability to obtain, surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, could have a material adverse effect on it. That failure could result from a variety of factors including:
•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit;
•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit; and
•lack of available fronting banks in certain countries where the Company must provide financial assurances but its primary surety providers are not licensed or admitted.
As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the Company has a surety transaction support agreement with the providers of its surety bond portfolio. The Company’s failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect its business and results of operations.
The Company’s failure to maintain adequate bonding would invalidate its mining permits and prevent mining operations from continuing, which could result in its inability to continue as a going concern.
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If the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated.
The Company’s asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. The Company’s management and engineers periodically review these estimates. If its assumptions do not materialize as expected, actual cash expenditures and costs that the Company incurs could be materially different than currently estimated. Moreover, regulatory changes could increase the Company’s obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from its assumptions, which could have a material adverse effect on its results of operations and financial condition.
The Company’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its ability to produce coal.
The coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:
•workplace health and safety;
•limitations on land use;
•mine permitting and licensing requirements;
•reclamation and restoration of mining properties after mining is completed;
•the storage, treatment and disposal of wastes;
•remediation of contaminated soil, sediment and groundwater;
•air quality standards;
•water pollution;
•protection of human health, plant-life and wildlife, including endangered or threatened species and habitats;
•protection of wetlands;
•the discharge of materials into the environment; and
•the effects of mining on surface water and groundwater quality and availability.
Regulatory agencies have the authority under certain circumstances following significant health and safety incidents to order a mine to be temporarily or permanently closed. In the event that such agencies ordered the closing of one of the Company’s mines, its production and sale of coal would be disrupted and it may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on the Company’s financial condition, results of operations and cash flows.
New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect the Company’s mining operations, its cost structure or its customers’ ability to use coal. New legislation, such as the “climate superfund” laws recently passed in New York and Vermont, or administrative regulations (or new interpretations by the relevant government of existing laws, regulations and approvals), including proposals related to the protection of the environment or the reduction of GHG emissions that would further regulate and tax the coal industry, may also require the Company or its customers to change operations significantly or incur increased costs. Some of the Company’s coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on the Company’s financial condition and results of operations. If the Company is determined to be subject to “climate superfund” laws and related regulations, it may be required to make significant payments to the relevant governments. These payments may be material and could adversely affect the Company’s results of operations, financial condition or cash flows.
For additional information about the various regulations affecting the Company, see the sections entitled “Regulatory Matters—U.S.” and “Regulatory Matters —Australia.”
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The Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company.
The Company’s operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including CERCLA and RCRA in the U.S. and similar laws in other countries where the Company operates, impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.
The Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its production, cash flows and profitability.
Numerous governmental permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this permitting process, when the Company applies for permits and approvals, it is required to prepare and present to governmental authorities data pertaining to the potential impact or effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals (including modifications and renewals of certain permits and approvals) and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or the performance of mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.
Additionally, the Company’s operations may be affected by sites within or near mining areas that have cultural heritage significance to indigenous peoples, and its mining permits may be rescinded or modified, or its mining plans may be voluntarily adjusted, to mitigate against adverse impacts to such sites.
The costs, liabilities and requirements associated with these permitting requirements and any related opposition may be extensive and time-consuming and may delay commencement or continuation of exploration or production which would adversely affect the Company’s coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict the Company’s ability to efficiently and economically conduct its mining activities, any of which would materially reduce its production, cash flows and profitability.
Concerns about the impacts of coal combustion on global climate are increasingly leading to conditions that have affected and could continue to affect demand for the Company’s products or its securities and its ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.
Global climate issues continue to attract public and scientific attention. 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 emissions of GHGs, including emissions of CO2 from coal combustion by power plants.