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Washington, D.C. 20549

(Mark One)

or

Commission File Number 1-16463

701 Market Street,

St. Louis,

Missouri

63101-1826

(Address of principal executive offices)

(Zip Code)

Securities Registered Pursuant to Section 12(b) 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, 2023: Common Stock, par value $0.01 per share, $2.5 billion.

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 16, 2024: Common Stock, par value $0.01 per share, 128,363,495 shares outstanding.

Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s 2024 Annual Meeting of Shareholders (the Company’s 2024 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.

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,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “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 that the Company believes are 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 factors 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.

Item 1.    Business.

Peabody is a leading producer of metallurgical and thermal coal. At December 31, 2023, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia, including a 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount). In addition to its mining operations, the Company markets and brokers coal from other coal producers; trades coal and freight-related contracts; and, since 2022, is partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage.

During 2023, Peabody advanced the redevelopment of its North Goonyella Mine in Australia. During the fourth quarter, the mine was renamed to Centurion Mine to reflect the next stage of redevelopment and the Company’s agreement to acquire an adjacent coal deposit. The first development coal from the Centurion Mine is anticipated in the second quarter of 2024.

As of December 31, 2023, 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.

The maps that follow display Peabody’s active and development mine locations as of December 31, 2023. Also shown are the primary ports that the Company uses for its coal exports and the Company’s corporate headquarters in St. Louis, Missouri.

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 2023.

(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 restarted production in the second quarter of 2021 after being idled in the fourth quarter of 2020.

(4)Peabody owns a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. The tons shown reflect its share.

(5)The mine experienced a fire in March 2023 and restarted production in June 2023. In November 2021 the mine restarted production after being idled in the fourth quarter of 2020.

(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 1.2 million, 1.4 million and 2.0 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.

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 92%, 85% and 84% of the Company’s worldwide sales from its mining operations (by volume) for the years ended December 31, 2023, 2022 and 2021, respectively.

For the year ended December 31, 2023, Peabody derived 25% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 13 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2024 to 2025. Peabody’s largest customer in 2023 contributed revenue of approximately $341 million, or approximately 7% of Peabody’s total revenue from coal supply agreements, and has contracts expiring in 2024.

Backlog. Peabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 221 million and 314 million tons of coal as of January 1, 2024 and 2023, respectively. Contracts in backlog have remaining terms ranging from one to eight years and represent approximately two years of production based on the Company’s 2023 production volume of 126.7 million tons. Approximately 51% of its backlog is expected to be filled beyond 2024.

Seaborne Operations. Revenue from Peabody’s Seaborne Thermal and Seaborne Metallurgical segments represented approximately 56%, 59% and 50% of the Company’s total revenue from coal supply agreements for the years ended December 31, 2023, 2022 and 2021, respectively, during which all three periods the coal mining activities of those segments contributed approximately 18% of the Company’s sales volumes from mining operations. Production from these segments is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. 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 30% in 2023.

U.S. Thermal Operations. Revenue from Peabody’s Powder River Basin and Other U.S. Thermal segments, in aggregate, represented approximately 44%, 41% and 50% of the Company’s revenue from coal supply agreements for the years ended December 31, 2023, 2022 and 2021, respectively, during which all three periods the coal mining activities of those segments contributed approximately 82% of the Company’s sales volumes from mining operations. 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. Over the last few years, Peabody’s customers have shifted to long-term supply agreements with shorter durations, driven by the reduced utilization of plants and plant retirements, fluidity of natural gas pricing and the increased use of renewable energy sources.

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. Beginning in 2022, rail service constraints due, in part, to labor shortages and weather conditions experienced by Peabody’s rail service providers, negatively impacted U.S. thermal shipment volumes. The constraints began to lessen in 2023, resulting in improved rail performance compared to the prior year. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.

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 years ended December 31, 2022 and 2021. No tons were exported during the year ended December 31, 2023. The primary port used for U.S. thermal exports is the Kinder Morgan Terminal near Houston, Texas.

Mining Supplies and Equipment. The principal goods Peabody purchases in support of its mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (including roof control materials), lubricants and electricity. Peabody has many well-established, strategic relationships with its key suppliers of goods and does not believe that it is overly dependent on any of its individual suppliers.

In situations where Peabody has elected to concentrate a large portion of its purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases, benefit from long-term pricing for parts and ensure security of supply. Supplier concentration related to the Company’s mining equipment also allows it to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across its global platform, enhancing its flexibility to move equipment between mines and reduce working capital through inventory optimization.

Surface and underground mining equipment demand and lead times for parts and components stabilized throughout 2023. Peabody consistently uses its global leverage with major suppliers and comprehensive planning processes to ensure security of supply to meet the requirements of its active mines.

Services. Peabody also purchases services at its mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements. Peabody does not believe that it has undue operational or financial risk associated with its dependence on any individual service providers.

Throughout 2022 and 2023, inflationary pressures and supply chain constraints contributed to rising costs for mining equipment, supplies and services. While supply chain constraints eased and inflation somewhat moderated in 2023, future periods could continue to be impacted.

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.

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 $2.66 per mmBtu in 2023, versus $6.54 and $3.72 per mmBtu in 2022 and 2021, 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 increasing regulatory burdens, have contributed to a significant number of coal plant retirements. During 2023, approximately 14 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by approximately forty-one percent.

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. China’s unofficial ban on Australian coal concluded in January 2023, enabling the reestablishment of some traditional trade flows. Global thermal coal markets were turbulent during 2022 and 2023, due in part to the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries.

In addition to its alternative fuel source competitors, Peabody’s principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners; American Consolidated Natural Resources, Inc.; Arch Resources, Inc.; CONSOL Energy; Eagle Specialty Materials LLC; Foresight Energy; Hallador Energy; 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 China’s unofficial ban on Australian coal and sanctions imposed on Russian coal imports.

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

Peabody had approximately 5,400 employees as of December 31, 2023, including approximately 4,200 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, 2023, 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 2023, the Company achieved a global safety incidence rate of 1.18 incidents per 200,000 hours worked, which was 57% better than the 2023 U.S. industry average incidence rate of 2.72 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).

Peabody strives to offer an inclusive work environment and engages, recognizes and develops employees. Peabody seeks a workforce that is comprised of diverse backgrounds, thoughts and experiences as a means to drive innovation and excellence within its business, and has formalized inclusion programs and training in policy and practice. Such diversity may also serve to mitigate risks to the business in the current tight labor market. The Company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. Peabody believes in fostering an inclusive work environment built on mutual trust, respect and engagement. Peabody invests in its employees through health and wellness programs, competitive total rewards and development opportunities. Peabody actively seeks employees' feedback, including through surveys and focus groups on its employee value proposition.

The typical Peabody employee has approximately seven years of experience with the company, and approximately 47% of all Peabody employees remain employed with the company for more than five years. The 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 25% of open positions and 60% of director and above positions have been filled by internal candidates through promotions or lateral career development opportunities.

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.

(1)     As of February 16, 2024.

James C. Grech was named Peabody’s President and Chief Executive Officer in June 2021. He has over 30 years of experience in the natural resources industry. 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.

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.

Marc E. Hathhorn was named Peabody’s President - U.S. Operations in November 2021. He has executive responsibility for the Company’s U.S. operating platform, which includes leadership of health, safety and environment, people, operational performance and product delivery. Mr. Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America and in Australia. Mr. Hathhorn joined Peabody in 2011 as Senior Vice President - Midwest Operations, and subsequently served as Group Executive - Americas Operations Support from 2013 to 2016, Group Executive - Americas Operations from 2016 to 2019 and President - Australian Operations until assuming his current role. Previously, Mr. Hathhorn held various leadership positions with Drummond LTD in South America, including Mine Operations Superintendent, Port Manager, and Vice President - Mining Operations. Prior to joining Drummond LTD, Mr. Hathhorn held various engineering and supervisory positions with Newmont Mining Corporation. Mr. Hathhorn holds a Bachelor of Science Degree in Mining Engineering from the University of Idaho, College of Mines.

Jamie Frankcombe was named Peabody’s President - Australian Operations in November 2021. He has executive responsibility for the Company’s Australian operating platform, which includes leadership of health, safety and environment, people, operational performance and product delivery. He is a senior mining executive with 30 years of experience in developing and managing large-scale open cut and underground coal, iron ore, copper and gold mines in Australia, Indonesia, Asia and the Americas. Prior to joining Peabody, Mr. Frankcombe served as Deputy Managing Director for Phu Bia Mining in Laos managing the Phu Kham (copper & gold) and Ban Houayxai (gold & silver) operating assets from June 2021 to November 2021. Prior to that, Mr. Frankcombe served as Integration Team Lead with Aurelia Metals Ltd from November 2020 to April 2021 with the responsibility of integrating the Dargues Gold Mine project and operations into the Aurelia Metals Ltd portfolio. Prior to that, he spent seven years as Chief Operating Officer for Whitehaven Coal Mining Ltd., overseeing operational and safety leadership of four open cut coal mines and one underground mine. In addition, he served as a director of Coal Services Pty Ltd. from September 2017 to July 2021. Mr. Frankcombe holds a Bachelor of Engineering (Mining) from University of Wollongong and a Master of Business Administration (Technology) from Deakin University.

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.

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.

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 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. As a result of legislation enacted in December 2020, the excise tax rates were set at 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal for the year ending December 31, 2021. This enacted legislation expired on December 31, 2021 and the excise tax rates reverted back to 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal. Effective October 1, 2022, the excise tax rates reverted back to 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal due to the enactment of the Inflation Reduction Act of 2022.

Peabody recognized expense related to the tax of $57.4 million, $32.4 million and $51.5 million for the years ended December 31, 2023, 2022 and 2021, 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 proposed a rule in January 2023 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts. The public comment period for the proposed rule ended April 19, 2023.

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

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.

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 $965.9 million as of December 31, 2023. 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 $483.8 million as of December 31, 2023. 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 Tax Relief and Health Care Act of 2006, from October 1, 2012 through September 30, 2021, the fee was $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. As a result of the Abandoned Mine Land Reclamation Amendments of 2021, which Congress enacted on November 15, 2021 as part of the Infrastructure Investment and Jobs Act, from October 1, 2021 through September 30, 2034, the fee is $0.224 and $0.096 per ton of surface-mined and underground-mine coal, respectively. The Company recognized expense related to the fees of $22.2 million, $21.7 million and $27.0 million for the years ended December 31, 2023, 2022 and 2021, 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 revision to current standards are appropriate. On January 6, 2023, the EPA proposed to lower the level of the primary standard for particulate matter (PM). If enacted as proposed, this rule could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies, thereby increasing the cost of utilizing fossil fuels for electric generation and industrial uses.

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

Final 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.

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 United States Court of Appeals for the D.C. Circuit (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.

On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology. Status reports filed with the D.C. Circuit in North Dakota v. EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule.

EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs. On May 23, 2023, the EPA proposed a rule that includes five separate actions regarding the control of greenhouse gas (GHG) emissions from fossil fuel-fired power plants. The EPA proposed to revise NSPS to address CO2 emissions from both new fossil fuel-fired steam generating units and new fossil fuel-fired stationary combustion turbines. The EPA also proposed emission guidelines for existing coal- and oil/gas-fired steam generating units and for existing stationary combustion turbines. Finally, in the same proposed rule, the EPA proposed to repeal the Affordable Clean Energy Rule, promulgated by the EPA in 2019 and vacated by the D.C. Circuit in 2021.

If finalized in the form proposed, the regulations would require existing fossil fuel-fired steam generating units (primarily coal units) to use CCUS with 90% capture of CO2 if they plan to operate after December 31, 2039. These units, however, may also pursue a different compliance pathway that is based on making a commitment to cease operations. The proposed rule also would require existing stationary combustion turbines over 300 megawatts with a capacity factor greater than 50% (primarily units using natural gas) to either utilize CCUS by 2035 or pursue a pathway that would require co-firing with 30% low-GHG hydrogen by 2032, followed by co-firing with 96% low-GHG hydrogen by 2038. The EPA is also taking comments with regard to imposing standards for stationary combustion turbines under 300 megawatts.

All requirements related to existing affected units – whether fired by coal, oil or natural gas – will be imposed through state plans that can additionally take into account the remaining useful life of a generating unit when determining appropriate controls. The EPA, however, proposes that such plans generally be no less stringent than the emission reductions that would be obtained under the EPA’s guidelines. Under the proposed rule, existing steam generating units would need to comply with the standards by January 1, 2030 and existing stationary combustion turbines would be required to comply by either January 1, 2032 or January 1, 2035, depending on what option for compliance is chosen.

Finally, as part of the proposed rule, any newly constructed steam electric generating unit or newly constructed stationary combustion turbine would be subject to GHG standards as of May 23, 2023, the date of the proposed rule. In addition, as proposed, any new fossil-fuel steam generating unit will need to comply with partial CCUS upon startup as well as a requirement for 90% CO2 reduction through CCUS by 2040. Any new or reconstructed stationary combustion turbine will be subject to different standards based on whether it is considered low load, intermediate load or a base load unit.

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

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.

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. The rule has been challenged in several U.S. Courts of Appeal, including the D.C. Circuit. On December 20, 2023, the U.S. Supreme Court issued an order for oral argument regarding applications for a stay of the rule.

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%. The EPA is also proposing to require the use of continuous emissions monitoring systems, and to revise other requirements such as those applicable to the startup of generating units. Under the proposed rule, the EPA estimated that approximately 500 megawatts of coal-fired capacity would retire by 2028. The public comment period on the proposals ended on June 23, 2023.

Regional Haze. The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from manmade air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal. States are required to revise plans every 10 years.

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.

Federal Coal Leasing Moratorium. The Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium. Environmental groups took the issue to court (District of Montana) and in April 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review. On May 22, 2020, the court held that the Department of the Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations. Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI. On August 12, 2022, the court invalidated the Environmental Assessment and FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis. The August 2022 decision is currently on appeal to the U.S. Court of Appeals for the Ninth Circuit.

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, 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.

Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs. On March 29, 2023, the EPA proposed a rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate. If the proposed rule, expected in April 2024, is finalized in substantially the same form, the revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants. Concurrently, the EPA issued a direct final rule which extended the deadline through June 2023 for steam electric power plants to commit to the permanent cessation of coal combustion by December 31, 2028 in exchange for less stringent wastewater discharge requirements during the interim. The direct final rule could influence fuel switching or additional coal generating unit retirements by the end of 2028.

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 expects to finalize those changes in April 2024. Separately, the CEQ published NEPA Guidance on Consideration of Greenhouse Gas Emissions and Climate Change on January 9, 2023. The interim guidance was effective immediately, though the agency accepted comments on the guidance and expects to issue final guidance in April 2024.

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.

Proposed Rule for Disposal of 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 now expects to issue a final rule around March 2026. Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision. The EPA expects to issue two final rules addressing the remainder of that decision in April and October 2024.

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 Trump Administration, the Departments of the Interior and Commerce finalized five rules aiming to streamline and update the ESA. But in June 2021, agencies announced their plan to revise, rescind, or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives. The agencies issued proposed rules on June 22, 2023, and they expect to finalize revised rules in April 2024.

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.

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 21, 2022, the SEC proposed rules that would require public companies to disclose extensive climate-related information in certain SEC filings. Specifically, the proposed rules would add new Subpart 1500 to Regulation S-K and new Article 14 to Regulation S-X to require disclosure of climate-related risks that are reasonably likely to have a material impact on a public company’s business, results of operations or financial condition; GHG emissions associated with a public company that includes, in many cases, an attestation report by a GHG emissions attestation provider; and climate-related financial metrics to be included in a company’s audited financial statements. The Company is currently assessing the potential impact of the proposed rules. The public comment period on the proposed rules has concluded and final rules are expected in April 2024.

Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 was signed into law on August 16, 2022. Among its many provisions are programs that provide grants and other forms of direct and indirect financial assistance for the deployment of zero emission technologies as well as other actions that could affect energy markets and the future use of coal.

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.

New South Wales Coal Directions. The State of New South Wales (NSW) enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). On December 22, 2022, the State Premier declared such an emergency, intended to control coal and electricity pricing. Subsequently, directions were issued to Peabody Energy Australia Pty Ltd and other coal producers with operations in NSW, which have been amended at various dates. The most recent directions require Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and impose additional reporting obligations to demonstrate compliance. While these directions are currently not anticipated to significantly impact the Wambo Mines or the Wilpinjong Mine, the nature and extent of those obligations and associated reporting requirements may continue to evolve if further directions are issued.

Mining Tenements and Environmental. In Queensland and New South Wales, the development of a mine requires both the grant of a right to extract the resource and an approval which authorizes the environmental impact. These approvals are obtained under separate legislation from separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required. The environmental impacts of mining projects are regulated by state and federal governments. Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (for example, a water resource, an endangered species or particular protected places). Environmental approvals processes involve complex issues that, on occasion, require lengthy studies and documentation.

In February 2019, the New South Wales Land and Environment Court (LEC) upheld the government’s denial of a planning approval for a non-Peabody coal mining project (Gloucester Resources Limited v. Minister for Planning). Although the approval was refused for other reasons, the judge in that case discussed ‘Scope 3’ GHG emissions resulting from the consumption of coal to be mined under the proposed project. Such emissions are often raised as a ground of objection to Australian mining projects, including Peabody’s mining projects. For example, in a subsequent LEC decision (Australian Coal Alliance Incorporated v. Wyong Coal Pty Ltd), the approval of a coal mining project was confirmed after such emissions had been considered by the relevant authority. In August 2019, Peabody and Glencore received approval from the NSW Independent Planning Commission (IPC) for the United Wambo project, subject to conditions (Export Conditions) requiring the joint venture to prepare an Export Management Plan setting out protocols for using all reasonable and feasible measures to ensure that any coal extracted from the mine that is to be exported from Australia is only exported to countries that are parties to the Paris Agreement (as defined below) or countries that the NSW Planning Secretary considers to have similar policies for reducing GHG emissions. The IPC subsequently approved another non-Peabody coal mining project (Rix’s Creek) without any Export Conditions. In October 2019, the NSW government introduced into Parliament proposed amendments to legislation and policy that would, if passed, have the effect of invalidating Export Conditions imposed on future NSW planning approvals, as well as no longer requiring consent authorities to consider ‘downstream emissions’ when assessing developments for the purposes of mining, petroleum production or extractive industry. The NSW government has announced changes to the IPC and planning system process which aim to improve timeframes and efficiencies for project approvals and provide more clarity on the IPC’s role in determining applications including seeking guidance on government policy. In June 2020, the NSW Government released its Strategic Statement on Coal Exploration and Mining in NSW which provides a high level framework for the government's policy approach to the future of the coal sector, as well as details of a streamlined strategic release process. The strategy identifies some potential areas for possible new coal exploration, areas that are ruled out for coal mining and areas where new coal exploration can only occur adjacent to an existing coal title via the Operational Allocation process. In December 2020, the NSW Government finalized and published the Guideline for the Competitive Allocation of Coal, which details the process for considering areas for coal exploration and allocating them by public tender.

In Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 2008, Planning Act 2016, Coal Mining Safety and Health Act 1999, Minerals and Energy Resources (Common Provisions) Act 2014, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Biosecurity Act 2014, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959. Under the EP Act, policies have been developed to achieve the objectives of the law and provide guidance on specific areas of the environment, including air, noise, water and waste management. State planning policies address matters of Queensland state interest, and must be adhered to during mining project approvals. The Mineral Resources Act 1989 was amended effective September 27, 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements, and the coordination of activities and access to private and public land. In November 2016, amendments to the EP Act and the Water Act 2000 became effective that facilitate regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction. The ‘chain of responsibility’ provisions of the EP Act, which became effective in April 2016, allow the regulator to issue an environmental protection order (EPO) to a related person of a company in two circumstances: (a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later); or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company). A guideline has been issued that provides more certainty to the industry on the circumstances in which an EPO may be issued.

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

Under the EPA Act, environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve.

On August 25, 2017, the BC Act commenced in New South Wales and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied.

Sharma v Minister for the Environment. On March 15, 2022, the Full Court of the Federal Court of Australia overturned the decision in Sharma v Minister for the Environment [2021] FCA 560 (Sharma), a case which found in 2021 that the Federal Minister for the Environment had a duty to avoid causing personal injury or death to children in Australia as a result of carbon emissions when deciding an application to approve a coal mine expansion. In light of this decision, the Minister for the Environment no longer must consider the effects of carbon emissions when assessing referrals under the Environment Protection and Biodiversity Conservation Act 1999. Sharma did not lodge an application for special leave to the High Court of Australia to appeal this decision and is now out of time to do so.

Mining Rehabilitation (Reclamation). Mine reclamation is regulated by state-specific legislation. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding, or, in certain circumstances (see below in relation to the Mineral and Energy Resources (Financial Provisioning) Act 2018), make alternative financial contributions to the relevant state government as a safeguard to cover the costs of reclamation in circumstances where mine operators are unable to do so. 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. The Company operates in both the Queensland and New South Wales state jurisdictions.

Peabody’s reclamation bonding requirements in Australia were $332.8 million as of December 31, 2023. 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 $219.0 million as of December 31, 2023. The total bonding requirements for the Company’s Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is projected to be a number of years away, whereas the bonding amount represents the states’ calculated cost of reclamation if a mine ceases to operate immediately as well as different costs assumptions.

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

Through the Mining Act, environmental protection and reclamation are regulated by conditions in all mining leases including requirements for the submission of a mining operations plan (MOP) prior to the commencement of operations. All mining operations must be carried out in accordance with the MOP which describes site activities and the progress toward environmental and reclamation outcomes and are updated on a regular basis or if mine plans change. The mines publicly report their reclamation performance on an annual basis.

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

Queensland Reclamation. The EP Act is administered by the Department of Environment and Science, which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA. All mining operations must be carried out in a manner so as to ensure compliance with the conditions in the EA. The mines submit an annual return reporting on their EA compliance.

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

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.

Residual Risks. 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.

Native Title and Cultural Heritage. Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the federal government established a Senate Inquiry. The Senate Inquiry’s terms of reference included reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions; and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites. Following an interim report released on December 9, 2020, the Joint Standing Committee on Northern Australia released its final report on October 18, 2021. The final report sets out three key findings and eight recommendations, including that a new framework for cultural heritage protection be implemented at a national level by way of new legislated national minimum standards for State and Territory laws. The recommendations also include that a review of the Native Title Act 1993 (Cth) be undertaken to address inequalities in the negotiating position of Aboriginal and Torres Strait Islander peoples in the future act regime, including the ‘right to negotiate’ process which is associated with the grant of certain mining tenements. On November 24, 2022, the Environment Minister announced the Australian government’s support for all but one of the recommendations from the Senate Inquiry (whether final responsibility for heritage protection should sit with the Indigenous Affairs Minister or the Environment Minister is still being assessed) and indicated laws to protect Aboriginal cultural heritage would be strengthened following a further review of mining standards. Any legislation passed as a result of the recommendations in the final report could potentially impact the Company’s current and future mining tenements and operations.

Occupational Health and Safety. State legislation requires Peabody to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.

In September 2020, Safe Work Australia (SWA) recommended new national Workplace Exposure Standards (WES) of 1.5 milligrams per cubic meter (mg/m3) for coal dust and 0.05 mg/m3 for silica. In Queensland, workplace exposure standards for respirable crystalline silica require workplaces to observe an eight hour, time-weighted average airborne concentration of 0.05mg/m3. 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.

In addition, as part of a broader review of workplace exposure standards, SWA is currently considering a proposal to reduce the time weighted average (TWA) WES for CO2 in Australian coal mines from 12,500 ppm to 5,000 ppm. Currently there is a separate TWA for CO2 in coal mines, however SWA proposes to remove this to align with a general industry standard. If implemented, the change has the potential to affect underground mines operating in CO2 rich coal seams, including the primary coal seam of the Company’s Metropolitan Mine. Importantly, a minimum three-year transition period applies for any change to standards.

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

On May 20, 2020, the Queensland Parliament passed a bill into law that introduces the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are “senior officers” and companies in the mining industry. Individuals now face a maximum prison sentence of 20 years and companies could be fined up to approximately $13 million Australian dollars. This new law became effective July 1, 2020. The bill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity with an 18-month transition period which ended November 25, 2022.

Industrial Relations. A national industrial relations system, the Fair Work Act and National Employment Standards, administered by the federal government applies to all employers and employees. 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. In addition, employers will no longer be able to employ individuals on a fixed-term contract for more than two years and access to flexible working arrangements for employees has been expanded. A number of measures aimed at addressing the gender pay gap have also been introduced. .

Following this amendment, the Wambo Underground Mine and four other mines in New South Wales were served with an application for a single interest employer authorization by a union representing certain categories of employees. If the authorization is granted by the Fair Work Commission, this will initiate the bargaining process for a single enterprise agreement covering all five employers for those specified employee categories. Peabody is still assessing the potential impacts associated with the application.

In early September 2023, the Fair Work Legislation Amendment (Closing Loopholes) Bill 2023 was presented to the Australian Federal Parliament. The bill proposed amendments to the Fair Work Act 2009 to allow unions and employees to make application to the Fair Work Commission for a ‘regulated labour hire arrangement order’ that, if successful, would require employers to provide similar wages and conditions to regulated workers as those provided to permanent employees, unless the Fair Work Commission is satisfied that it is not fair and reasonable to do so. The bill passed the Australian Federal Parliament on December 7, 2023 and applications for regulated labor hire arrangements can be made beginning in November 2024. The reforms have the potential to increase labor and compliance costs for coal producers, and Peabody is currently considering mitigation strategies.

National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system. The Clean Energy Regulator administers the NGER Act. The federal Department of Environment and Energy is responsible for NGER Act-related policy developments and review.

On July 1, 2016, amendments to the NGER Act implemented the Emissions Reduction Fund Safeguard Mechanism. From that date, large designated facilities such as coal mines were issued with a baseline for their covered emissions and must take steps to keep their emissions at or below the baseline or face penalties.

The National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 outlines key elements of a responsible emitter’s duty to avoid an excess emissions situation and provides detail on how it can meet that requirement. The rule was amended between 2019 and 2021 to transition responsible emitters to new baseline setting arrangements. From the start of the 2020-21 compliance year, baselines must use prescribed production variables (an example being run of mine coal) and default emissions intensity values (being values set by the government to represent the industry average emissions intensity of production over five years) unless specific exemptions apply (such as a facility having site-specific values set).

In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015. The reforms commenced on July 1, 2023 and introduced site specific baseline emissions for heavy emitting facilities as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO2 in 2023-24, increasing with the Consumer Price Index plus 2% each year.

On March 27, 2023, the Australian federal government announced several additional emission reduction measures in the Safeguard Mechanism (Crediting) Amendments Bill 2023 which was introduced and passed both Houses of Parliament on March 30, 2023. The legislation introduced a cap on overall net emissions from facilities covered by the scheme through 2030. The legislation also set a cap of net zero tonnes carbon dioxide equivalent for any financial year beginning after June 30, 2049. 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 went into effect on July 1, 2023. The potential impact of these reforms to Peabody’s Australian operations is under review.

Queensland Royalty. As part of the Queensland government’s 2019-20 budget, the government committed to freeze royalty rates on coal and minerals for three years, provided companies voluntarily contributed to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The government contributed $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the Fund was approximately $1.7 million Australian dollars over the three-year period of 2019-2022.

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. Previously, the maximum royalty rate was 15% of the value of the coal sold above $150 Australian dollars per tonne. The change follows a three-year freeze on royalty rates for coal in the state. The increased rate structure may impact the Company’s future decisions about its Queensland operations.

New South Wales Royalty. In New South Wales, the royalty applicable to coal is charged as a percentage of the value of production (total revenue less allowable deductions). This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines. As part of its 2023-24 state budget the newly elected New South Wales government announced that from July 1, 2024 it would be increasing each of these rates by 2.6% to 8.8% for deep underground mines, 9.8% for underground mines and 10.8% for open-cut mines. The future impacts of this royalty rate rise on Peabody’s NSW mining operations is being assessed.

Sydney Water Catchment Areas. In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning and Environment (DPE) on the impact of underground mining activities in Sydney’s water catchment areas, including at the Company’s Metropolitan Mine. The Panel issued its final report in October 2019, which made findings and recommendations concerning mining activities and effects across the catchment as a whole.

In response to the Panel’s recommendations, in 2020 the DPE established an interagency taskforce to implement a detailed action plan which includes: ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies; establishing a new independent expert panel (Independent Advisory Panel) to advise on future mining applications in the catchment; strengthening surface and groundwater monitoring; improving access to and transparency of environmental data; adopting a more stringent approach to the assessment and conditioning of future mining proposals to minimize subsidence impacts; reviewing and updating current and potential future water losses from mining in line with the best available science; introducing a licensing regime to properly account for any water losses; and undertaking further research into mine closure planning to reduce potential long-term impacts.

When requested by the DPE, the Independent Advisory Panel is available to provide informed technical advice to the DPE or the Independent Planning Commission in relation to development applications and post-approval matters relating to the assessment and management of subsidence impacts associated with underground mining across NSW, with a particular focus on risks to the quantity of water in the catchment. The Independent Advisory Panel is comprised of an independent chair and experts in the fields of mining engineering and subsidence, surface water, groundwater and swamp hydrology and ecology. Advice that may be provided by the Independent Advisory Panel may include, but is not confined to, risks to the total water quantity and holding capacity of surface and groundwater systems, including swamps and reservoirs, and the types and reliability of methodologies used to predict, monitor, assess and report on mining effects, impacts and consequences.

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).

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 Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress. All such communications are subject to oversight and review protocols established by Peabody’s Board and executive leadership team.

The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements.

The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the ESG-related policies of financial institutions and other private companies. The Company has experienced, or may in the future experience, negative effects on its results of operations due to the following specific risks as a result of such factors:

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

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

•Increased costs associated with regulatory compliance;

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

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

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

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

•Reputational damage associated with involvement in GHG emissions.

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

•Disruption to water supplies vital to mining operations;

•Disruption to transportation and other supply chain activities;

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

Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change. Such developments are described below in the section “Regulations Related to Global Climate Change” within this Item 1.

The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.

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.

Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.

Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and the Company regularly discloses information regarding its production-related emissions in its annual ESG Report. The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal.

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.

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.

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.

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;

•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 2023 and 2022, 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 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. may be fueled by natural gas because gas-fired plants have been less expensive to construct, 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 could 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 26% and 32% of its revenue in 2023 and 2022, 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. Lower demand for metallurgical coal in international markets could reduce the amount of metallurgical coal that the Company sells and the prices that it receives for the metallurgical coal, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.

The balance between coal demand and supply, factoring in demand and supply of closely related and competing fuel sources, both domestically and internationally, could materially reduce coal prices and therefore materially reduce the Company’s revenue and profitability. The Company competes with other fuel sources used for electricity generation, such as natural gas, nuclear and renewables. The Company’s seaborne products compete with other producers as well as other fuel sources. Declines in the price of natural gas could cause demand for coal to decrease and adversely affect the price of coal. Sustained periods of low natural gas prices or low prices for other fuels may also cause utilities to phase out or close existing coal-fueled power plants or reduce construction of new coal-fueled power plants. In the U.S., no new coal-fueled power plants are being constructed or reopened after closure. These closures could have a material adverse effect on demand and prices for the Company’s coal, thereby reducing its revenue and materially and adversely affecting its business and results of operations.