EDGAR 10-K Filing

Company CIK: 1064728
Filing Year: 2022
Filename: 1064728_10-K_2022_0001064728-22-000008.json

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ITEM 1. BUSINESS
Item 1. Business.
Overview
Peabody is a leading producer of metallurgical and thermal coal. At December 31, 2021, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia, including a 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount). In addition to its mining operations, the Company markets and brokers coal from other coal producers, both as principal and agent, and trades coal and freight-related contracts.
Segment and Geographic Information
As of December 31, 2021, Peabody reports its results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining 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 24. “Segment and Geographic Information” to the accompanying consolidated financial statements is incorporated herein by reference and also contains segment and geographic financial information.
Mining Locations
The maps that follow display Peabody’s active mine locations as of December 31, 2021. Also shown are the primary ports that the Company uses for its coal exports and the Company’s corporate headquarters in St. Louis, Missouri.
U.S. Locations
Peabody Energy Corporation 2021 Form 10-K
Australian Locations
Peabody Energy Corporation 2021 Form 10-K
The table below summarizes information regarding the operating characteristics of each of the Company’s mines in the U.S. and Australia. The mines are listed within their respective mining segment in descending order, as determined by tons produced in 2021.
Production
Segment/Mining Complex Location Mine Type Mining Method Coal Type Primary Transport Method Processing
Plants Year Ended December 31,
2021 2020 2019
Seaborne Thermal Mining (Tons in millions)
Wilpinjong New South Wales S D, T/S T R, EV Yes 13.2 14.2 14.1
Wambo Open-Cut (1)
New South Wales S T/S T R, EV Yes 2.4 4.0 3.4
Wambo Underground (2)
New South Wales U LW T, C R, EV Yes 1.4 1.5 2.2
Seaborne Metallurgical Mining
Coppabella (3)
Queensland S DL, D, T/S P R, EV Yes 2.1 2.2 2.4
Moorvale (3)
Queensland S D, T/S C, P, T R, EV Yes 1.3 1.2 1.7
Metropolitan (4)
New South Wales U LW C, P, T R, EV Yes 1.0 1.0 1.5
Shoal Creek (5)
Alabama U LW C B, EV Yes 0.1 0.6 1.9
Millennium (6)
Queensland S HW C, P R, EV No - 0.1 0.6
Middlemount (7)
Queensland S D, T/S C, P R, EV Yes - - -
Powder River Basin Mining
North Antelope Rochelle Wyoming S DL, D, T/S T R No 62.8 66.1 85.3
Caballo Wyoming S D, T/S T R No 13.9 11.6 12.6
Rawhide Wyoming S D, T/S T R No 11.6 9.5 10.1
Other U.S. Thermal Mining
Bear Run Indiana S DL, D, T/S T Tr, R Yes 6.0 5.2 6.8
El Segundo/Lee Ranch New Mexico S DL, D, T/S T R No 3.7 4.6 5.5
Wild Boar Indiana S D, T/S, HW T Tr, R, R/B, T/B Yes 2.4 2.0 2.5
Gateway North Illinois U CM T Tr, R, R/B, T/B Yes 1.8 1.8 3.0
Twentymile Colorado U LW T R, Tr Yes 1.7 1.2 2.6
Francisco Underground Indiana U CM T R Yes 1.5 1.6 2.0
Somerville Central (6)
Indiana S DL, D, T/S T R, R/B, T/B, T/R No - 0.4 1.2
Kayenta (8)
Arizona S DL, T/S T R No - - 3.8
Wildcat Hills
Underground (8)
Illinois U CM T T/B No - - 1.4
Cottage Grove (8)
Illinois S D, T/S T T/B No - - 0.1
Legend:
S Surface Mine B Barge
U Underground Mine Tr Truck
HW Highwall Miner R/B Rail to Barge
DL Dragline T/B Truck to Barge
D Dozer/Casting T/R Truck to Rail
T/S Truck and Shovel EV Export Vessel
LW Longwall T Thermal/Steam
CM Continuous Miner C Coking
R Rail P Pulverized Coal Injection
(1)In December 2020, the United Wambo Joint Venture, an unincorporated joint venture between Peabody and Glencore plc, began joint production. The tons shown reflect Peabody’s proportionate share throughout the years. The Company’s 50% joint venture interest is subject to an outside non-controlling ownership interest.
(2)Majority-owned mine in which there is an outside non-controlling ownership interest.
(3)Peabody owns a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. The tons shown reflect its share.
(4)The mine was idled in the fourth quarter of 2020. The mine restarted production in the second quarter of 2021.
(5)The mine was idled in the fourth quarter of 2020. The mine restarted production in November 2021.
(6)The mine ceased production during 2020.
(7)Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine. Because Middlemount is accounted for as an unconsolidated equity affiliate, the table above excludes tons produced from that mine, which totaled 2.0 million, 1.6 million and 1.4 million tons, respectively (on a 50% basis).
(8)The mine ceased production in 2019.
Refer to the Reserves and Resources tables within Item 2. “Properties,” which is incorporated by reference herein, for additional information regarding coal reserves and resources, and product characteristics associated with each mine.
Peabody Energy Corporation 2021 Form 10-K
Coal Supply Agreements
Customers. Peabody’s coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of the Company’s sales from its mining operations are made under long-term coal supply agreements (those with initial terms of one year or longer and which often include price reopener and/or extension provisions). A smaller portion of the Company’s sales from its mining operations are made under contracts with terms of less than one year, including sales made on a spot basis. Sales under long-term coal supply agreements comprised approximately 84%, 89% and 88% of the Company’s worldwide sales from its mining operations (by volume) for the years ended December 31, 2021, 2020 and 2019, respectively.
For the year ended December 31, 2021, Peabody derived 26% of its revenues from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 17 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2022 to 2026. Peabody’s largest customer in 2021 contributed revenue of approximately $258 million, or approximately 8% of Peabody’s total revenues from coal supply agreements, and has contracts expiring at various times from 2022 to 2025.
Backlog. Peabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 283 million and 264 million tons of coal as of January 1, 2022 and 2021, respectively. Contracts in backlog have remaining terms ranging from one to nine years and represent approximately two years of production based on the Company’s 2021 production volume of 126.9 million tons. Approximately 57% of its backlog is expected to be filled beyond 2022.
Seaborne Mining Operations. Revenues from Peabody’s Seaborne Thermal Mining and Seaborne Metallurgical Mining segments represented approximately 50%, 42% and 45% of its total revenues from coal supply agreements for the years ended December 31, 2021, 2020 and 2019, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 18%, 19% and 17% of its sales volumes from mining operations. The Company’s production is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Industry commercial practice, and Peabody’s typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a bi-annual, quarterly, spot or index basis. For its seaborne mining operations, the portion of sales volume under contracts with a duration of less than one year represented 45% in 2021.
U.S. Thermal Mining Operations. Revenues from Peabody’s Powder River Basin Mining and Other U.S. Thermal Mining segments, in aggregate, represented approximately 50%, 58% and 55% of its revenues from coal supply agreements for the years ended December 31, 2021, 2020 and 2019, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 82%, 81% and 83% of its sales volumes from mining operations. The Company expects to continue selling a significant portion of coal production from its U.S. thermal mining segments under existing long-term supply agreements. 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. However, recent trends indicate that customers may be less likely to enter into long-term supply agreements prospectively, driven by the reduced utilization of plants and plant retirements, fluidity of natural gas pricing and the increased use of renewable energy sources.
Transportation
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. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.
Peabody Energy Corporation 2021 Form 10-K
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 mining operations exported less than 1% of its annual tons sold during both the years ended December 31, 2021 and 2019. No tons were exported during the year ended December 31, 2020. The primary ports used for U.S. thermal exports are the United Bulk Terminal near New Orleans, Louisiana, the St. James Stevedoring Anchorages terminal in Convent, Louisiana and the Kinder Morgan terminal near Houston, Texas.
Suppliers
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 have increased in recent periods. Peabody consistently uses its global leverage with major suppliers and comprehensive planning processes to ensure security of supply to meet the requirements of its active mines.
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.
Competition
Demand for coal and the prices that the Company will be able to obtain for its coal are highly competitive and influenced by factors beyond the Company’s control, including but not limited to global economic conditions; the demand for electricity and steel; the cost of alternative sources; the impact of weather on heating and cooling demand; 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 accelerated growth in domestic natural gas production and new natural gas combined cycle generation capacity. The Henry Hub Natural Gas Prompt Price averaged $3.72 per mmBtu in 2021, versus $2.13 and $2.53 per mmBtu in 2020 and 2019, respectively. In addition, the competitiveness of other alternative fuel sources for electricity generation has been strengthened by the growth of government subsidized renewable energy generation. These pressures, coupled with increasing regulatory burdens, have contributed to a significant number of coal plant retirements. During 2021, approximately 8 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by approximately thirty-two percent.
Peabody Energy Corporation 2021 Form 10-K
Internationally, thermal coal also competes with alternative forms of electricity generation. The competitiveness and availability of natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Russia, Colombia, the U.S. 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.
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; Anglo American plc; BHP; Bumi Resources; China Shenhua Energy; Coal India Limited; Drummond Company; Glencore; South32; SUEK; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.
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.
Major international direct competitors (listed alphabetically) include Anglo American; Arch Resources, Inc.; BHP; Foxleigh; Glencore; Jellinbah; KRU; Teck Resources; Warrior Met Coal; Whitehaven Coal Limited; and Yancoal Australia Ltd, among others.
Cybersecurity Risk Management
Peabody uses digital technology to conduct its business operations and engage with its customers, vendors and partners. As the Company implements newer technologies such as cloud, analytics, automation and “internet of things,” the threats to its business operations from cyber intrusions, denial of service attacks, manipulation and other cyber misconduct affecting both the Company and its partners’ technologies increase. To address the risk, the Company continues to evolve its risk management approach in an effort to continually assess and improve its cybersecurity risk detection, deterrence and recovery capabilities. Peabody’s cybersecurity strategy emphasizes reduction of cyber risk exposure and continuous improvement of its cyber defense and resilience capabilities. These include: (i) proactive management of cyber risk to ensure compliance with contractual, legal and regulatory requirements, (ii) performing due diligence on third parties to ensure they have sound cybersecurity practices in place, (iii) ensuring essential business services remain available during a business disruption, (iv) implementing data policies and standards to protect sensitive company information and (v) exercising cyber incident response plans and risk mitigation strategies to address potential incidents should they occur.
During 2021, a software vendor that provides cloud services to the Company for its payroll function suffered a significant ransomware attack. The Company’s mitigation actions were adequate to avoid significant operational disruptions or material financial losses.
Human Capital
Peabody had approximately 4,900 employees as of December 31, 2021, including approximately 3,900 hourly employees. Additional information on its employees and related labor relations matters is contained in Note 21. “Management - Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference. Peabody endeavors to engage with its organized workforce and foster strong relationships with those organizations built on trust and communication, which was evidenced in 2021 by successful labor negotiations at its Shoal Creek, Wambo and Metropolitan Mines.
As of December 31, 2021, approximately 3,300 of Peabody’s employees are located in the U.S., with the remainder primarily located in Australia. About 94% of its team members work for mine operations in the U.S. and Australia, while the remaining are employed at its global headquarters in St. Louis or other business offices.
Peabody Energy Corporation 2021 Form 10-K
Peabody strives to create a strong, united workforce with a commitment to safety as a way of life. In 2021, the Company achieved a global safety incidence rate of 1.18 incidents per 200,000 hours worked, which was 56% better than the 2020 U.S. industry average incidence rate of 2.69 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).
Peabody strives to offer an inclusive work environment and engages, recognizes and develops employees. Peabody seeks a workforce that is comprised of diverse backgrounds, thoughts and experiences as a means to drive innovation and excellence within its business, and has formalized inclusion programs and training in policy and practice. The Company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. Peabody believes in fostering an inclusive work environment built on mutual trust, respect and engagement. Peabody invests in its employees through health and wellness programs, competitive total rewards and development opportunities. Peabody actively seeks employees' feedback, including through surveys and focus groups on its employee value proposition.
The typical Peabody employee has approximately eight years of experience with the company, and more than 51% of all Peabody employees remain employed with the company for more than five years. The Company offers a variety of learning events, including mentoring and development programs to aid its employees in their career growth. During the past five years, approximately 32% of open positions and 72% of director and above positions have been filled by internal candidates through promotions and lateral career development opportunities.
Information About Our Executive Officers
Set forth below are the names, ages and positions of Peabody’s executive officers. Executive officers are appointed by, and hold office at the discretion of, Peabody’s Board of Directors, subject to the terms of any employment agreements.
Name Age (1)
Position (1)
James C. Grech 60 President and Chief Executive Officer
Mark A. Spurbeck 48 Executive Vice President and Chief Financial Officer
Scott T. Jarboe 48 Chief Administrative Officer and Corporate Secretary
Darren R. Yeates 61 Executive Vice President and Chief Operating Officer
Marc E. Hathhorn 51 President - U.S. Operations
Jamie Frankcombe 61 President - Australian Operations
Patrick J. Forkin III 63 Senior Vice President - Corporate Development and Strategy
(1) As of February 11, 2022.
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 and holds a Bachelor’s Degree in Accounting from Hillsdale College.
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.
Peabody Energy Corporation 2021 Form 10-K
Darren R. Yeates was named Peabody’s Executive Vice President and Chief Operating Officer in October 2020. He has executive responsibility for operations, sales and marketing and technical services. Mr. Yeates has over 35 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 has 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 has an Executive MBA from the Monash Mt Eliza Business School and is a Fellow of the Australian Institute of Company Directors.
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 overseeing the areas of health and safety, operations, product delivery and support functions. 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 Gold 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 overseeing the areas of health and safety, environment, people, operational performance and product delivery. He is a senior mining executive with 30 years of experience in developing and managing large-scale open cut and underground coal, iron ore, copper and gold mines in Australia, Indonesia, Asia and the Americas. Prior to joining Peabody, Mr. Frankcombe served as Deputy Managing Director for Phu Bia Mining in Laos managing the Phu Kham (copper & gold) and Ban Houayxai (gold & silver) operating assets from June 2021 to November 2021. Prior to that, Mr. Frankcombe served as Integration Team Lead with Aurelia Metals Ltd from November 2020 to April 2021 with the responsibility of integrating the Dargues Gold Mine project and operations into the Aurelia Metals Ltd portfolio. Prior to that, he spent seven years as Chief Operating Officer for Whitehaven Coal Mining Ltd., overseeing operational and safety leadership of four open cut coal mines and one underground mine. In addition, he served as a director of Coal Services Pty Ltd. from September 2017 to July 2021. Mr. Frankcombe holds an Honours Degree in Engineering (Mining) and a Masters in Business Administration (Technology).
Patrick J. Forkin III joined Peabody in 2010 and was named Senior Vice President - Corporate Development and Strategy in November 2017. He has executive responsibility for mergers and acquisitions, portfolio management, global strategy, U.S. thermal coal sales and renewable energy development. Mr. Forkin has an extensive background in corporate finance, the energy industry, mergers and acquisitions and equity market research. Prior to joining Peabody, Mr. Forkin was in senior leadership roles at a U.S. solar development company and investment banking firms specializing in renewable and conventional energy. He spent the first nine years of his career at Deloitte LLP. 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).
Regulatory Matters - U.S.
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant requirements mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. Peabody believes that it has obtained all permits currently required to conduct its present mining operations.
The Company endeavors to conduct its mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry.
Peabody Energy Corporation 2021 Form 10-K
Mine Safety and Health
Peabody is subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.
MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA employs various enforcement measures for noncompliance, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine.
In Part I, Item 4. “Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, the Company provides additional details on MSHA compliance.
Black Lung (Coal Workers’ Pneumoconiosis)
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. Historically, very few of the miners who sought federal black lung benefits were awarded these benefits; however, the approval rate has increased following implementation of black lung provisions contained in the Affordable Care Act. The Affordable Care Act included significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.
The trust fund has been funded by an excise tax on U.S. production. As a result of legislation enacted in December of 2020, the excise tax rates were set at 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal for the year ending December 31, 2021. This enacted legislation expired on December 31, 2021 and the excise tax rates reverted back to 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal. On December 2, 2021 the Government Accountability Office (GAO) published a report titled “Black Lung Benefits Program: Continued Inaction on Coal Operator Self-Insurance Increases Financial Risk to Trust Fund.” This report notes that the Department of Labor (DOL) took some steps to improve its oversight of self-insured coal mine operators, but these efforts were complicated by the COVID-19 pandemic. The GAO states in the report that the DOL has not taken necessary action to prevent additional benefit liabilities from being transferred to the trust fund and recommends that the DOL act on recommendations made in 2020. Subsequently, the Office of Workers' Compensation Programs (OWCP) indicated that it plans to issue a Notice of Proposed Rulemaking in the upcoming months to update its regulations authorizing coal producers to self-insure and for determining appropriate security amounts, and that it plans to solicit public comments for that proposal. A change in requirements for security posted to self-insure black lung liabilities could result in the Company being required to post additional security for its obligations. OWCP recently requested the Company to refile its application for self-insurance.
Peabody recognized expense related to the tax of $51.5 million, $53.3 million and $31.4 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Environmental Laws and Regulations
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 the 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 will be performing reclamation work on tribal lands, the Company is regulated by the OSMRE because the tribes do not have SMCRA authorization.
Peabody Energy Corporation 2021 Form 10-K
SMCRA provides for three categories of bonds: 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 $1,054.5 million as of December 31, 2021. 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 U.S. operations were $518.6 million as of December 31, 2021. 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 $27.0 million, $28.4 million and $36.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect 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. As part of this recurring review process, the EPA in 2020 proposed to retain the ozone standards promulgated in 2015, including current secondary standards, and subsequently promulgated final standards to this effect. Fifteen states and other petitioners have filed a petition for review of the rule in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit). The litigation is currently in abeyance following a motion filed by the EPA to allow for review of the standards.
The EPA also proposed in 2020 to retain the particulate matter (PM) standards last revised in 2012. On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5) and the primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. This rule has also been challenged in the D.C. Circuit by several states and environmental organizations. The case is currently in abeyance following a motion filed by the EPA to allow for review of the standards.
More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to other NAAQS for nitrogen dioxide (NO2) and sulfur dioxide (SO2), although these standards are not subject to a statutorily-required review until 2023 for NO2 and 2024 for SO2.
Peabody Energy Corporation 2021 Form 10-K
Final NSPS for Fossil Fuel-Fired Electricity Utility Generating Units (EGUs). The EPA promulgated a final rule to limit carbon dioxide (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.
This rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb carbon dioxide per megawatt-hour gross output (CO2/MWh-gross). The standard (known as the Best System of Emission Reduction (BSER)) 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 units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/MWh-gross).
Numerous legal challenges to the final rule were filed in the D.C. Circuit. Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports.
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 carbon capture and storage 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 carbon capture and storage 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 Existing Fossil Fuel-Fired EGUs. On October 23, 2015, the EPA published a final rule in the Federal Register regulating greenhouse gas emissions from existing fossil fuel-fired electric generation units (EGUs) under Section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the Clean Power Plan or CPP) established emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).
The EPA subsequently proposed to repeal the CPP and in August 2018 issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule. In June 2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE. The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the Best System of Emission Reduction (BSER). The EPA’s final rule also revises certain regulations to give the states greater flexibility on the content and timing of their state plans.
Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C. Circuit matter seeking review of CPP, including the Company, filed a motion to dismiss, which the court granted in September 2019.
Numerous petitions for review challenging the ACE Rule were filed in the D.C. Circuit and subsequently consolidated. In January 2021, a 3-judge panel of the D.C. Circuit vacated and remanded the ACE Rule to the EPA, including its repeal of the CPP and amendments to the implementing regulations that extended the compliance timeline.
On October 29, 2021, the Supreme Court granted certiorari in four matters seeking review of the D.C. Circuit’s opinion vacating the ACE rule and invalidating the repeal of the CPP. In granting certiorari, the Supreme Court consolidated the cases to consider the breadth of the EPA’s scope pursuant to 42 U.S.C. Section 7411(d) of the CAA, specifically, issues pertaining to whether the EPA is limited to issuing standards for existing sources achievable through demonstrated technology and methods applied to such sources, or whether the EPA may also issue nationwide “performance standards” that can apply to the electric generation sector (such as cap and trade) which could effectively restructure the nation’s energy system. The Company will continue to monitor the consolidated matters.
Peabody Energy Corporation 2021 Form 10-K
EPA’s Greenhouse Gas Permitting Regulations for Major Emission Sources. In May 2010, the EPA published final rules requiring permitting and control technology requirements for greenhouse gases under the Prevention of Significant Deterioration (PSD) and Title V permitting programs that apply to stationary sources of air pollution. The EPA determined that these requirements were “triggered” by the EPA’s prior regulation of greenhouse gases from motor vehicles. These rules were subsequently upheld by the D.C. Circuit on June 26, 2012. On June 23, 2014, however, the U.S. Supreme Court ruled that the EPA could not require PSD and Title V permitting for greenhouse gases emitted from stationary sources if those sources were not otherwise considered to be “major sources” of conventional pollutants for purposes of PSD and Title V (known as Step 2 sources). In accordance with that decision, the D.C. Circuit vacated the federal regulations that implemented Step 2 of the Greenhouse Gas Tailoring Rule in 2015. Subsequently, the EPA removed the vacated elements from its rules to ensure that neither the PSD nor Title V rules require a source to obtain a permit solely because the source emits or has the potential to emit greenhouse gases above the applicable thresholds. The EPA therefore no longer has the authority to conduct PSD permitting for Step 2 sources, nor can the EPA approve provisions submitted by a state for inclusion in its state implementation plan providing this authority.
Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. In 2011, the EPA finalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states. In 2016, the EPA published the final CSAPR Update Rule which imposed additional reductions in nitrogen oxides (NOx) beginning in 2017 in 22 states subject to CSAPR.
In October 2020, the EPA proposed a rule to address a previous D.C. Circuit remand of the CSAPR Update Rule and in April 2021, the EPA published a final rule in the Federal Register which imposed further reductions of NOx emissions in 12 states that were subject to the original 2016 rule.
In the same rule, the EPA determined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions. In order to implement reductions in the 12 identified states, the EPA issued Federal Implementation Plans to lower state ozone season NOx budgets in 2021 to 2024, although limited emission trading can be used for compliance and states have the ability to replace federal plans with revised state plans that are no less stringent. A petition for review challenging the 2021 rule has been filed in the D.C. Circuit and briefing in this litigation commenced in November 2021, but this does not stay the effectiveness of the rule.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register in 2012. The MATS rule revised the new source performance standards (NSPS) for NOx, SO2 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.
In 2020, the EPA issued a final rule reversing a prior finding and determined that it is not “appropriate and necessary” under the CAA to regulate HAP emissions from coal- and oil-fired power plants. This rule also finalized residual risk and technology review standards for the coal- and oil-fired EGU source category. Both actions were challenged in the D.C. Circuit but this litigation was placed in abeyance. In 2021 EPA sent a draft rule to the Office of Management and Budget for review regarding reconsideration of the “appropriate and necessary” finding as well as residual risk and technology review standards for coal- and oil-fired EGUs.
Regional Haze. The Clean Air Act contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from manmade air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal. States are required to revise plans every 10 years.
Federal Coal Leasing Moratorium. 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. Environmental groups have since amended their complaint to challenge the Environmental Assessment and FONSI, and the litigation remains pending.
Peabody Energy Corporation 2021 Form 10-K
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
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 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. Although the EPA issued a final rule in 2020 that effectively could have in effect limited state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances, as a result of litigation developments this year, the 1971 certification rule is currently back in effect. The EPA plans to issue another proposal in 2022 to update the 1971 rule.
New Source Review (NSR). The Clean Air Act imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification. These requirements are contained in the Clean Air Act’s prevention of significant deterioration (PSD) and Nonattainment New Source Review (NNSR) programs, generally referred to as NSR. On August 4, 2020, the EPA released a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the New Source Review Regulations). PALs allow sources to make physical and operational changes under a plantwide emission limit without “triggering” NSR.
The EPA has also taken action on a number of different rules and guidance affecting the interpretation and application of NSR. In a final rule (83 Fed. Reg. 57,324 (Nov. 15, 2018)), the EPA completed reconsideration of a 2009 petition to clarify when certain actions must be “aggregated” for purposes of determining whether these actions are part of a single project to which NSR applies. The EPA has additionally published guidance on the definition of “ambient air” (Revised Policy on Exclusions from “Ambient Air,” Dec. 2, 2019) and guidance concerning when multiple air pollution-emitting activities may be considered to be “adjacent” so that they should be considered to be a single source (Interpreting “Adjacent” for New Source Review and Title V Source Determinations in All Industries Other Than Oil and Gas, Nov. 26, 2019). Additional memorandum and applicability determinations have also been made that address other NSR issues. These rules, guidance and memorandum may therefore 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.
CWA Definition of “Waters of the United States”. In January 2020 the EPA and the Army Corps of Engineers (Corps) finalized the Navigable Waters Protection Rule to revise the definition of “Waters of the United States” and thereby establish the scope of federal regulatory authority under the CWA. On August 30, 2021, a federal court in Arizona vacated the Navigable Waters Protection Rule, and on September 3, 2021, the EPA and the Corps announced that they had “halted implementation” of the rule nationwide and that they are interpreting “Waters of the United States” consistent with the pre-2015 regulatory framework. On December 7, 2021, the agencies published the first of two rulemaking proceedings to formally repeal the Navigable Waters Protection Rule, codify the pre-2015 regulatory framework, and then build upon that framework. The agencies plan to issue the second proposal in 2022, but the exact timing is unclear.
Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On October 13, 2020, the EPA issued a final rule revising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water. However, on August 3, 2021, the EPA announced it is undertaking a supplemental rulemaking to “strengthen certain discharge limits” applicable to steam electric power plants. As finalized, the revised effluent limitations guidelines could significantly increase costs for many coal-fired steam electric power plants.
Peabody Energy Corporation 2021 Form 10-K
National Environmental Policy Act (NEPA). NEPA, signed into law in 1970, requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. Peabody must provide information to agencies when it proposes actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality issued a final rule comprehensively updating and modernizing its longstanding NEPA regulations on July 16, 2020. That final rule sought to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of NEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule. On October 7, 2021, however, CEQ published a proposed rule announcing a two-phase rulemaking process to generally restore the pre-2020 NEPA regulations before more broadly revisiting the 2020 rule.
Resource Conservation and Recovery Act (RCRA). 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.
Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. On December 19, 2014, the EPA announced the final rule on coal combustion residuals (CCR or coal ash). As finalized, the rule continues the exemption of CCR from regulation as a hazardous waste, but does impose new requirements at existing CCR surface impoundments and landfills that will need to be implemented over a number of different time-frames in the coming months and years, as well as at new surface impoundments and landfills. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous.
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 EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around October 2022. Separately, on August 28, 2020, the EPA finalized certain amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision. Initially the EPA had planned to issue a proposal in mid-2021, but the EPA now expects to issue the proposal rule in September 2022. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous.
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.
Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA’s Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
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 issued finalized five rules aiming to streamline and update the ESA. But in June 2021, agencies announced their plan to revise, rescind, or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives.
Peabody Energy Corporation 2021 Form 10-K
Use of Explosives. 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. On July 30, 2019, the OSMRE officially withdrew its decision to initiate rulemaking related to emissions generated from blasting at coal mining operations. The decision cited its lack of statutory authority and the sufficiency of the existing regulatory framework.
Federal Report on Climate Change. On November 23, 2018, the U.S. Global Change Research Program, a working group comprised of 13 U.S. governmental departments and agencies, issued the Fourth National Climate Assessment. The report lists the observed effects of “increasing greenhouse gas concentrations on Earth’s climate” and enumerates the impacts of those observed effects. The report also discusses the alternatives for reducing the impacts of climate-related risks, including through mitigation and adaptation. 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. A Fifth National Climate Assessment is currently in development with an anticipated publication date in 2023.
Regulatory Matters - Australia
The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.
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 (NSW) Land and Environment Court (LEC) upheld the government’s denial of a planning approval for a non-Peabody coal mining project (Gloucester Resources Limited v. Minister for Planning). Although the approval was refused for other reasons, the judge in that case discussed ‘Scope 3’ greenhouse gas emissions resulting from the consumption of coal to be mined under the proposed project. Such emissions are often raised as a ground of objection to Australian mining projects, including 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 greenhouse gas 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 aims to improve timeframes and efficiencies for project approvals and providing 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.
Peabody Energy Corporation 2021 Form 10-K
In Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 2008, Planning Act 2016, Coal Mining Safety and Health Act 1999, Minerals and Energy Resources (Common Provisions) Act 2014, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Biosecurity Act 2014, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959. 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.
Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021. On February 25, 2021 the Commonwealth Government introduced the Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021 into Parliament, which proposes amendments to the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) following the release of the Final Report of the Independent Review of the Act undertaken by Professor Graeme Samuel (the Samuel Review) that made 38 recommendations for short and long-term reforms, and ultimately calls for a complete overhaul of the existing legislative framework by 2022, to be undertaken in several tranches, with a strong focus on the setting of National Environmental Standards, assurance and compliance, data availability and management, and indigenous engagement. The bill responds to some of the recommendations for immediate reform made in the Samuel Review, and seeks to: establish a framework for the making, varying, revoking and application of National Environmental Standards; apply the National Environmental Standards to bilateral agreements with States and Territories; and establish an Environment Assurance Commissioner to monitor and audit bilateral agreements and other processes under the EPBC Act. The bill passed the Australian Parliament’s House of Representatives in June 2021 and is now under consideration by the Australian Senate.
Peabody Energy Corporation 2021 Form 10-K
Mining Rehabilitation (Reclamation). Mine reclamation is regulated by state-specific legislation. As a condition of approval for mining operations, companies are required to progressively reclaim mined land and provide appropriate bonding, 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 credit facility and accounts receivable securitization program. The Company operates in both the Queensland and New South Wales state jurisdictions.
Peabody’s reclamation bonding requirements in Australia were $240.2 million as of December 31, 2021. The bond requirements represent the states’ calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state. The cost calculation for each bond must be completed according to the regulatory authority of each state. The costs associated with the Company’s Australian asset retirement obligations are calculated in accordance with U.S. generally accepted accounting principles and were $201.2 million as of December 31, 2021. The total bonding requirements for the Company’s Australian operations differ from the calculated costs associated with the asset retirement obligations because the costs associated with asset retirement obligations are discounted from the end of the mine’s economic life to the balance sheet date in recognition of the economic reality that reclamation is conducted progressively and final reclamation is projected to be a number of years away, whereas the bonding amount represents the states’ calculated cost of reclamation if a mine ceases to operate immediately as well as different costs assumptions.
New South Wales Reclamation. 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.
Under significant reforms proposed by the NSW Resources Regulator in October 2020, all new and existing mines in NSW will be regulated by new standard rehabilitation conditions. The conditions will apply to all new and existing mining leases and focus on transparently requiring progressive mine site rehabilitation throughout the life of the mine. The draft Mining Amendment (Standard Conditions of Mining Leases - Rehabilitation) Regulation 2020 has been released for consultation. The new conditions would apply to all new mining leases and would be introduced into existing mining leases over a 12 to 24 month transition period. The conditions require (amongst other things) that the leaseholder must rehabilitate land and water in the mining area that is disturbed by activities under the mining lease as soon as reasonably practicable after the disturbance occurs. The proposed rehabilitation management plan for the mining area which must be prepared for large mines is intended to replace the current approach of preparing a mining operation plan.
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 providing for a new financial assurance (FA) framework and new progressive rehabilitation requirements. The new FA framework creates 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 will take 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 no longer provides for discounting. The commencement date for the new FA framework was April 1, 2019 and there is a transitional period during which Peabody will move each of its mines in Queensland into the new FA framework.
Peabody Energy Corporation 2021 Form 10-K
The new progressive rehabilitation requirements commenced on November 1, 2019 and require each mine, within a three-year transitional period, to establish a schedule of rehabilitation milestones covering the life of the mine, and any significant changes to the timing of rehabilitation will require regulatory approval. 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, each current mine is exempt from the requirement to justify its NUMAs to the extent that its current approvals provide for such areas. The Company is of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of its Queensland mines.
Residual Risks. 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.
Federal Reclamation. In February 2017, the Australian Senate established a Committee of Inquiry into the rehabilitation of mining and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protection and Biodiversity Conservation Act 1999. The Committee released their report in March 2019. The Committee was unable to reach unanimous agreement on a set of recommendations. It is unclear the extent to which the report will impact policy reform at a federal government level.
Native Title and Cultural Heritage. Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.
Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Government established a Senate Inquiry. The Inquiry’s terms of reference included reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions; and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites. Following an interim report released on December 9, 2020, the Joint Standing Committee on Northern Australia released its final report on October 18, 2021. The final report sets out three key findings and eight recommendations, including that a new framework for cultural heritage protection be implemented at a national level by way of new legislated national minimum standards for State and Territory laws. The recommendations also include that a review of the Native Title Act 1993 (Cth) be undertaken to address inequalities in the negotiating position of Aboriginal and Torres Strait Islander peoples in the future act regime, including the ‘right to negotiate’ process which is associated with the grant of certain mining tenements. Any legislation passed as a result of the recommendations in the final report could potentially impact the Company’s current and future mining tenements and operations.
Occupational Health and Safety. State legislation requires Peabody to provide and maintain a safe workplace by providing safe systems of work, safety equipment and appropriate information, instruction, training and supervision. In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation specific to the coal mining industry. There are some differences in the application and detail of the laws, and mining operators, directors, officers and certain other employees are all subject to the obligations under this legislation.
Peabody Energy Corporation 2021 Form 10-K
In September 2020, Safe Work Australia (SWA) published its revised Workplace Exposure Standards (WES) for coal dust and silica based on toxicological information and other monitoring data. SWA have recommended exposure limits of 1.5 mg/m3 for coal dust (to apply from October 2022) and 0.05 mg/m3 for silica (to apply as soon as possible). In Queensland, a new workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05 milligrams per cubic meter (mg/m3)) took effect from July 1, 2020. In New South Wales, the new respirable crystalline silica workplace exposure standard of 0.05 mg/m3 commenced on July 1, 2020. The respirable coal dust workplace exposure standard of 2.5 mg/m3 was reduced to 1.5 mg/m3 on February 1, 2021 and mines need to report exceedances of the new exposure standard to the NSW Resources Regulator from this date. NSW is the first mining jurisdiction in Australia to implement an exposure standard for diesel particulate matter with the exposure standard of 0.1 mg/m3 which became enforceable on February 1, 2021.
In addition, as part of a broader review of workplace exposure standards, SWA is currently considering a proposal to reduce the time weighted average (TWA) Workplace Exposure Standard (WES) for carbon dioxide (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 ending 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.
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).
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 contribute to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The Government contributes $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the Fund was approximately $522,000 Australian dollars for the 2020-21 financial year and $713,000 Australian dollars for the 2019-20 financial year. Peabody’s contribution is expected to further decrease in year three based on an expected reduction in production at its Queensland mines.
Peabody Energy Corporation 2021 Form 10-K
New South Wales Royalty. 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.
Sydney Water Catchment Areas. In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning, Industry and Environment (DPIE) on the impact of underground mining activities in Sydney’s water catchment areas, including at the Company’s Metropolitan Mine. The Panel issued its final report in October 2019. The final report makes findings and recommendations concerning mining activities and effects across the catchment as a whole.
The DPIE considered the recommendations in the Panel’s final report and in April 2020 announced that it had accepted all 50 recommendations in the Panel’s report, and that it has established an interagency taskforce to implement a detailed action plan during 2020. The action plan 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 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.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to greenhouse gas (GHG) emissions. The Company’s largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2).
Peabody’s board of directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing global climate change solutions, and the company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal.
The board of directors has ultimate oversight for climate-related risk and opportunity assessments, and has delegated certain aspects of these assessments to subject matter committees of the board. In addition, the board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the board of directors and Peabody’s global workforce turns those objectives into meaningful actions.
Management believes that the Company’s external communications, including environmental regulatory filings and public notices, U.S. Securities and Exchange Commission filings, its annual Environmental, Social and Governance Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company’s material risks and progress. All such communications are subject to oversight and review protocols established by Peabody’s board of directors and executive leadership team.
The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements.
Peabody Energy Corporation 2021 Form 10-K
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 carbon capture, use and storage (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.
Peabody Energy Corporation 2021 Form 10-K
From time to time, the Company’s board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.
Regulations Related to Global Climate Change
In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no such legislation has been signed into law. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA has taken steps to regulate greenhouse gas emissions pursuant to the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” In particular, in 2015, the EPA announced final rules (known as the CPP) for regulating carbon dioxide emissions from existing and new fossil fuel-fired EGUs. Twenty-seven states and governmental entities, as well as utilities, industry groups, trade associations, coal companies (including Peabody), and other entities, challenged the CPP in federal court. Implementation of the CPP was stayed by the U.S. Supreme Court pending resolution of its legal challenges. In October 2017, the EPA proposed to change its legal interpretation of section 111(d) of the CAA, the authority that the agency relied on for the original CPP. The EPA relied on the proposed reinterpretation until August 2018, when it proposed the Affordable Clean Energy Rule (the ACE Rule) to replace the CPP with a system where states would develop emissions reduction plans using BSER measures (essentially efficiency heat rate improvements), and the EPA would approve the state plans if they use EPA-approved candidate technologies. Changes in the NSR program were also proposed to allow efficiency improvements to be made without triggering NSR requirements. In September 2019, the ACE Rule, which provides states with the flexibility to regulate on a plant-by-plant basis with a focus on coal-fired EGUs, became effective and the CPP was repealed. Proposed revisions to the regulations under the NSR program that were part of the ACE proposal were separated and the EPA indicated that it intends to take final action on the proposed NSR program reforms at a later date. Following the effectiveness of the ACE Rule, the case challenging the CPP in federal court was dismissed as being moot. On January 19, 2021, the D.C. Circuit Court of Appeals held that the ACE Rule and its repeal of the CPP were to be vacated and remanded to the EPA. It also vacated amendments to the implementing regulations that extended the compliance timeline.
At the same time, a number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, and Pennsylvania is expected to join in 2022. RGGI is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. Six mid-western states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets. It has been reported that, while the MGGRA has not been formally suspended, the participating states are no longer pursuing it. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011, the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. Of those five jurisdictions, only California and Quebec have adopted greenhouse gas cap-and-trade regulations to date and both programs have begun operating. Many of the states and provinces that left WCI, RGGI and MGGRA, along with many that continue to participate, have joined the new North America 2050 initiative, which seeks to reduce greenhouse gas emissions and create economic opportunities in ways not limited to cap-and-trade programs.
Several other U.S. states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.
Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.
Peabody Energy Corporation 2021 Form 10-K
Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and the Company regularly discloses information regarding its production-related emissions in its annual Environmental, Social and Governance Report. The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal.
The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gas emission targets for developed nations. 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 reductions contributions after the second commitment period ends in 2020 (the Paris Agreement). The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global greenhouse gas emissions. 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 October 2017, the Australian Federal Government released a plan aimed at delivering an affordable and reliable energy system that meets Australia’s international commitments to emissions reduction. The plan was referred to as the National Energy Guarantee (NEG) and was aimed at changing the National Electricity Market and associated legislative framework. The NEG was abandoned by the Australian government in September 2018. Following the outcome of the federal election in May 2019, the federal government confirmed it will not revive the former NEG policy. Instead, the government will pursue a new energy and climate change policy, which includes a $2 billion Australian dollars investment in projects to bring down Australia's greenhouse gas emissions. The Climate Solutions Fund is an extension of the former Emissions Reduction Fund. The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices.
Available Information
Peabody files or furnishes annual, quarterly and current reports (including any exhibits or amendments to those reports), proxy statements and other information with the SEC. These materials are available free of charge through the Company’s website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information included on the Company’s website does not constitute part of this document. These materials may also be accessed through the SEC’s website (www.sec.gov).
In addition, copies of the Company’s filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.

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ITEM 1A. RISK FACTORS
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.
Peabody Energy Corporation 2021 Form 10-K
Risks Associated with Peabody’s Operations
The Company’s profitability depends upon the prices it receives for its coal.
The Company operates in a competitive and highly regulated industry that has at times experienced strong headwinds. Current pricing levels of both seaborne and domestic coal products may not be sustainable in the future. Declines in coal prices could materially and adversely affect the Company’s operating results and profitability and the value of its coal reserves and resources.
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 2021 and 2020, 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 revenues 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 22% and 17% of its revenues in 2021 and 2020, 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 revenues and adversely impacting its earnings and the value of its coal reserves and resources.
Peabody Energy Corporation 2021 Form 10-K
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 revenues and profitability. The Company competes with other fuel sources used for electricity generation, such as natural gas 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 revenues and materially and adversely affecting its business and results of operations.
If a substantial number of the Company’s long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenues and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts.
Most of the Company’s sales are made under coal supply agreements, which are important to the stability and profitability of its operations. The execution of a satisfactory coal supply agreement is frequently the basis on which the Company undertakes the development of coal reserves and resources required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2021, the Company derived 26% of its revenues from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 17 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2022 to 2026.
Many of the Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. The Company may adjust these contract prices based on inflation or deflation, price indices and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. The Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of its expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the Company or the customer during the duration of specified events beyond the control of the affected party. Some coal supply agreements allow customers to vary the volumes of coal that they are required to purchase during a particular period, and where coal supply agreements do not explicitly allow such variation, customers sometimes request that the Company amend the agreements to allow for such variation. Most of its coal supply agreements contain provisions requiring the Company to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, volatile matter, coking properties, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements allow the Company’s customers to terminate their contracts in the event of changes in regulations affecting the coal industry that restrict the use or type of coal permissible at the customer’s plant or increase the price of coal beyond specified limits.
On an ongoing basis, the Company discusses the extension of existing agreements or entering into new long-term agreements with various customers, but these negotiations may not be successful and these customers may not continue to purchase coal from the Company under long-term supply agreements.
The operating profits the Company realizes from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase its exposure to short-term coal price volatility. If a substantial portion of the Company’s coal supply agreements were modified or terminated, it could be materially adversely affected to the extent that it is unable to find alternate buyers for its coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, the Company cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that it will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, the Company’s revenue could be adversely affected by a decline in customer purchases (including contractually obligated purchases) due to lack of demand and oversupply, cost of competing fuels and environmental and other governmental regulations.
Peabody Energy Corporation 2021 Form 10-K
Risks inherent to mining could increase the cost of operating the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company.
The Company’s mining operations are subject to conditions that can impact the safety of its workforce, delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:
•elevated gas levels;
•fires and explosions, including from methane gas or coal dust;
•accidental mine water discharges;
•weather, flooding and natural disasters;
•hazardous events such as roof falls and high wall or tailings dam failures;
•seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•key equipment failures;
•unavailability of equipment or parts;
•variations in coal seam thickness, coal quality, the amount of rock and soil overlying coal deposits and geologic conditions impacting mine sequencing;
•delays in moving its longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to its operations.
The Company maintains insurance policies that provide limited coverage for some of the risks referenced above, which may lessen the impact associated with these risks. However, there can be no assurance as to the amount or timing of recovery under its insurance policies in connection with losses associated with these risks.
The Company’s take-or-pay arrangements could unfavorably affect its profitability.
The Company has substantial take-or-pay arrangements with its port access and rail transportation providers, predominately in Australia, totaling $1.2 billion, with terms ranging up to 21 years, that commit the Company to pay a minimum amount for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow the Company to apply amounts paid for subsequent deliveries, but these provisions have limitations and the Company may not be able to apply all such amounts so paid in all cases. Also, the Company may not be able to utilize the amount of capacity for which it has previously paid. Additionally, the Company may continue to deliver coal during times when it might otherwise be optimal to suspend operations because these take-or-pay provisions effectively convert a variable cost of selling coal to a fixed operating cost.
The Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets.
The value of the Company’s assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond its control, including unfavorable changes in the economic environments in which it operates; declining coal-fired electricity generation; lower-than-expected coal pricing; technical and geological operating difficulties; an inability to economically extract its coal reserves and resources; and unanticipated increases in operating costs. During the year ended December 31, 2020, the Company recorded $1,487.4 million of impairment charges related to such factors, as further described in Note 3. “Asset Impairment” to the accompanying consolidated financial statements. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on the Company’s results of operations.
Because of the volatile and cyclical nature of coal markets, it is reasonably possible that the Company’s current estimates of projected future cash flows from its mining assets may change in the near term, which may result in the need for adjustments to the carrying value of its assets.
Peabody Energy Corporation 2021 Form 10-K
The Company could be negatively affected if it fails to maintain satisfactory labor relations.
As of December 31, 2021, the Company had approximately 4,900 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 3,900 hourly employees. The Company is party to labor agreements with various labor unions that represent certain of its employees. Such labor agreements are negotiated periodically, and, therefore, the Company is subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 34% of its hourly employees were represented by organized labor unions and generated approximately 16% of its coal production for the year ended December 31, 2021. Relations with its employees and, where applicable, organized labor are important to the Company’s success. If some or all of its current non-union operations were to become unionized, the Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if the Company fails to maintain good relations or successfully negotiate contracts with its employees who are represented by unions, the Company could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact its profitability.
The Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations.
U.S. federal and state laws and Australian laws require the Company to provide financial assurances related to requirements to reclaim lands used for mining; to pay federal and state workers’ compensation, such as black lung liabilities; to provide financial assurances for coal lease obligations; and to satisfy other miscellaneous obligations. The primary methods the Company uses to meet those obligations are to provide a third-party surety bond or a letter of credit. As of December 31, 2021, the Company had $1,463.7 million of outstanding surety bonds and $452.6 million of letters of credit with third parties in order to provide required financial assurances for post-mining reclamation, workers’ compensation and other insurance obligations, coal lease-related and other obligations and performance guarantees, in addition to collateral for sureties.
The Company’s financial assurance obligations may increase or become more costly due to a number of factors, and surety bonds and letters of credit may not be available to the Company, particularly in light of some banks and insurance companies’ announced unwillingness to support thermal coal producers and other fossil fuel companies. Alternative forms of financial assurance such as self-bonding have been severely restricted or terminated in most of the regions where its mines reside. The Company’s failure to retain, or inability to obtain, surety bonds, bank guarantees or letters of credit, or to provide a suitable alternative, could have a material adverse effect on it. That failure could result from a variety of factors including:
•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit; and
•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit.
As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in November 2020, the Company entered into a surety transaction support agreement with the providers of its surety bond portfolio. The Company’s failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect its business and results of operations.
The Company’s failure to maintain adequate bonding would invalidate its mining permits and prevent mining operations from continuing, which could result in its inability to continue as a going concern.
Peabody Energy Corporation 2021 Form 10-K
The Company’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its ability to produce coal.
The coal mining industry is subject to regulation by federal, state and local authorities with respect to matters such as:
•workplace health and safety;
•limitations on land use;
•mine permitting and licensing requirements;
•reclamation and restoration of mining properties after mining is completed;
•the storage, treatment and disposal of wastes;
•remediation of contaminated soil, sediment and groundwater;
•air quality standards;
•water pollution;
•protection of human health, plant-life and wildlife, including endangered or threatened species and habitats;
•protection of wetlands;
•the discharge of materials into the environment; and
•the effects of mining on surface water and groundwater quality and availability.
Regulatory agencies have the authority under certain circumstances following significant health and safety incidents to order a mine to be temporarily or permanently closed. In the event that such agencies ordered the closing of one of the Company’s mines, its production and sale of coal would be disrupted and it may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on the Company’s financial condition, results of operations and cash flows.
New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect the Company’s mining operations, its cost structure or its customers’ ability to use coal. New legislation or administrative regulations (or new interpretations by the relevant government of existing laws, regulations and approvals), including proposals related to the protection of the environment or the reduction of greenhouse gas emissions that would further regulate and tax the coal industry, may also require the Company or its customers to change operations significantly or incur increased costs. Some of the Company’s coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on the Company’s financial condition and results of operations.
For additional information about the various regulations affecting the Company, see the sections entitled “Regulatory Matters -U.S.” and “Regulatory Matters - Australia.”
The Company’s operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company.
The Company’s operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including CERCLA and RCRA in the U.S. and similar laws in other countries where the Company operates, impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal or other handling. Liability under RCRA, CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved.
Peabody Energy Corporation 2021 Form 10-K
The Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its production, cash flows and profitability.
Numerous governmental permits and approvals are required for mining operations. The permitting rules, and the interpretations of these rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical. As part of this permitting process, when the Company applies for permits and approvals, it is required to prepare and present to governmental authorities data pertaining to the potential impact or effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals (including modifications and renewals of certain permits and approvals) and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge the issuance of permits, the validity of environmental impact statements or the performance of mining activities. In recent years, the permitting required for coal mining has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups.
Additionally, the Company’s operations may be affected by sites within or near mining areas that have cultural heritage significance to indigenous peoples, and its mining permits may be rescinded or modified, or its mining plans may be voluntarily adjusted, to mitigate against adverse impacts to such sites.
The costs, liabilities and requirements associated with these permitting requirements and any related opposition may be extensive and time-consuming and may delay commencement or continuation of exploration or production which would adversely affect the Company’s coal production, cash flows and profitability. Further, required permits may not be issued or renewed in a timely fashion or at all, or permits issued or renewed may be conditioned in a manner that may restrict the Company’s ability to efficiently and economically conduct its mining activities, any of which would materially reduce its production, cash flows and profitability.
Concerns about the impacts of coal combustion on global climate are increasingly leading to conditions that have affected and could continue to affect demand for the Company’s products or its securities and its ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.
Global climate issues continue to attract public and scientific attention. Numerous reports, including 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 emissions of greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants.
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.
From time to time, the Company’s board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company’s operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company’s results of operations, financial condition or cash flows.
Peabody Energy Corporation 2021 Form 10-K
Numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting the Company’s future financial results, liquidity and growth prospects.
Several non-governmental organizations have undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation in the U.S. and across the globe. In an effort to stop or delay coal mining activities, activist groups have brought lawsuits challenging the issuance of individual coal leases, and challenging the federal coal leasing program more broadly. Other lawsuits challenge historical and pending regulatory approvals, permits and processes that are necessary to conduct coal mining operations or to operate coal-fueled power plants, including so-called “sue and settle” lawsuits where regulatory authorities in the past have reached private agreements with environmental activists that often involve additional regulatory restrictions or processes being implemented without formal rulemaking.
The effect of these and other similar developments has made it more costly and difficult to maintain the Company’s business. These cost increases and/or substantial or extended declines in the prices the Company receives for its coal due to these or other factors could reduce its revenue and profitability, cash flows, liquidity, and value of its coal reserves and resources, and could result in material losses.
The Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks.
In addition to coal price volatility, the Company is currently subject to price volatility on diesel fuel utilized in its mining operations and the Australian dollar. The Company may in the future enter into hedging arrangements, including economic hedging arrangements, to manage these risks or other exposures.
Some of these hedging arrangements may require the Company to post margin based on the value of the related instruments and other credit factors. If the fair value of its hedge portfolio moves significantly, or if laws, regulations or exchange rules are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, the Company could be required to post additional margin, which could negatively impact its liquidity.
If the assumptions underlying the Company’s asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated.
The Company’s asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, which is driven by the estimated economic life of the mine and the applicable reclamation laws. These cash flows are discounted using a credit-adjusted, risk-free rate. The Company’s management and engineers periodically review these estimates. If its assumptions do not materialize as expected, actual cash expenditures and costs that the Company incurs could be materially different than currently estimated. Moreover, regulatory changes could increase the Company’s obligation to perform reclamation, mine closing and post-closure activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from its assumptions, which could have a material adverse effect on its results of operations and financial condition.
The Company’s future success depends upon its ability to continue acquiring and developing coal reserves and resources that are economically recoverable.
The Company’s recoverable reserves and resources decline as it produces coal. The Company has not yet applied for the permits required or developed the mines necessary to use all of its reserves and resources. Moreover, the amount of coal reserves and resources described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Actual production, revenues and expenditures with respect to its coal reserves and resources may vary materially from estimates.
Peabody Energy Corporation 2021 Form 10-K
The Company’s future success depends upon it conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves and resources. The Company’s current strategy includes increasing its reserves and resources through acquisitions of government and other leases and producing properties and continuing to use its existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of the Company’s reserves and resources, potentially creating conflicting interests between it and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing the Company’s coal reserves and resources. These lessees may also seek damages from the Company based on claims that its coal mining operations impair their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2021, the Company leased a total of 44,287 acres from the federal government subject to those limitations.
The Company’s planned mine development projects and acquisition activities may not result in significant additional reserves and resources, and it may not have success developing additional mines. Most of its mining operations are conducted on properties owned or leased by the Company. Its right to mine some of its reserves and resources may be materially adversely affected if defects in title or boundaries exist. In order to conduct its mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, in order to develop its reserves and resources, the Company must also own the rights to the related surface property and receive various governmental permits. The Company cannot predict whether it will continue to receive the permits or appropriate land access necessary for it to operate profitably in the future. The Company may not be able to negotiate or secure new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves and resources or maintain its leasehold interest in properties on which mining operations have not commenced or have not met minimum quantity or product royalty requirements. From time to time, the Company has experienced litigation with lessors of its coal properties and with royalty holders. In addition, from time to time, its permit applications and federal and state coal leases have been challenged, causing production delays.
To the extent that the Company’s existing sources of liquidity are not sufficient to fund its planned mine development projects or reserve and resource acquisition activities, it may require access to capital markets, which may not be available to it or, if available, may not be available on satisfactory terms. If the Company is unable to fund these activities, it may not be able to maintain or increase its existing production rates and could be forced to change its business strategy, which could have a material adverse effect on its financial condition, results of operations and cash flows.
The Company faces numerous uncertainties in estimating its coal reserves and resources and inaccuracies in its estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Coal is economically recoverable when the price at which the Company’s coal can be sold exceeds the costs and expenses of mining and selling the coal. The costs and expenses of mining and selling the coal are determined on a mine-by-mine basis, and as a result, the price at which its coal is economically recoverable varies based on the mine. Forecasts of the Company’s future performance are based on, among other things, estimates of its recoverable coal reserves and resources. The Company bases its reserve and resource information on engineering, economic and geological data assembled and analyzed by its staff and third parties, which includes various engineers and geologists. The Company's estimates are also subject to SEC regulations regarding classification of reserves and resources, including the recently adopted subpart 1300 of Regulation S-K. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and resources and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves and resources, including many factors beyond the Company’s control.
Peabody Energy Corporation 2021 Form 10-K
Estimates of economically recoverable coal reserves and resources necessarily depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:
•geologic and mining conditions, which may not be fully identified by available exploration data and may differ from the Company’s experience in areas it currently mines;
•demand for coal;
•current and future market prices for coal, contractual arrangements, operating costs and capital expenditures;
•severance and excise taxes, royalties and development and reclamation costs;
•future mining technology improvements;
•the effects of regulation by governmental agencies;
•the ability to obtain, maintain and renew all required permits;
•employee health and safety; and
•historical production from the area compared with production from other producing areas.
The conversion of reported mineral resources to mineral reserves should not be assumed, and the reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed. As such, actual coal tonnage recovered from identified reserve and resource areas or properties and revenues and expenditures with respect to the Company’s reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect its actual reserves and resources. Any material inaccuracy in the Company’s estimates related to its reserves and resources could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially and adversely affect its business, results of operations, financial position and cash flows.
Joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company’s operating standards.
The Company participates in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not the Company holds majority interests or maintains operational control in its joint ventures, its partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, the Company’s; (2) seek to block actions that the Company believes are in its or the joint venture’s best interests; or (3) be unable or unwilling to fulfill their obligations under the joint venture or other agreements, such as contributing capital, each of which may adversely impact the Company’s results of operations and its liquidity or impair its ability to recover its investments.
Where the Company’s joint ventures are jointly controlled or not managed by it, the Company may provide expertise and advice but have limited control over compliance with its operational standards. The Company also utilizes contractors across its mining platform, and may be similarly limited in its ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to the Company’s could unfavorably affect safety results, operating costs and productivity and adversely impact its results of operations and reputation.
The Company’s business, results of operations, financial condition and prospects could be materially and adversely affected by pandemic or other widespread illnesses and the related effects on public health.
The Company’s operations are susceptible to widespread outbreaks of illness or other public health issues, such as the continuing global COVID-19 pandemic. Pandemic illnesses could have a material adverse effect on the Company’s business, results of operations, financial condition and prospects, including its ability to comply with covenants under its debt agreements.
Governmental mandates and the Company’s efforts to act in the best interests of its employees, customers, suppliers, vendors and joint venture and other business partners, could affect its business and operations, causing the Company to modify a number of its normal business practices. Governmental mandates could require forced shutdowns of its mines and other facilities for extended or indefinite periods and widespread outbreaks in locations significant to its operations could adversely affect its workforce, resulting in serious health issues and absenteeism. In addition, pandemic illnesses could cause supply chains and distribution channels to be interrupted, slowed or rendered inoperable. If the Company’s operations were curtailed, it may need to seek alternate sources of supply for commodities, services and labor, which may be more expensive. Alternate sources may not be available or may result in delays in shipments to its customers. Further, if the Company’s customers’ businesses were similarly affected, they might delay, reduce or cancel purchases from the Company. Adverse changes in the general domestic and global economic conditions and disrupted domestic and international credit markets, could negatively affect its customers’ ability to pay the Company as well as its ability to access capital that could negatively affect its liquidity.
Peabody Energy Corporation 2021 Form 10-K
Despite its efforts to manage these potential impacts, their ultimate impact would also depend on factors beyond the Company’s knowledge or control, including the duration and severity of the pandemic as well as third-party actions taken to contain its spread and mitigate its public health effects. The Company could also face disruption to supply chain and distribution channels, potentially increasing costs of production, storage and distribution, and potential adverse effects to its workforce, each of which could have a material adverse effect on its business, financial condition, results of operations and prospects.
The Company’s expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect.
The Company pays postretirement health and life insurance benefits to eligible retirees. Its total accumulated postretirement benefit obligation related to such benefits was a liability of $232.6 million as of December 31, 2021, of which $20.5 million was classified as a current liability.
These liabilities are actuarially determined. The Company uses various actuarial assumptions, including the discount rate, future cost trends, mortality tables and rates of return on plan assets to estimate the costs and obligations for these items. Its discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service its liabilities. A decrease in the discount rate used to determine its postretirement benefit and defined benefit pension obligations could result in an increase in the valuation of these obligations, thereby increasing the cost in subsequent fiscal years. The Company has made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Its medical trend assumption is developed by annually examining the historical trend of its cost per claim data. If the Company’s assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could differ materially from its current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase its obligation to satisfy these or additional obligations. The Company develops its actuarial determinations of liabilities using actuarial mortality tables it believes best fit its population’s actual results. In deciding which mortality tables to use, the Company periodically reviews its population’s actual mortality experience and evaluates results against its current assumptions as well as consider recent mortality tables published by the Society of Actuaries Retirement Plans Experience Committee in order to select mortality tables for use in its year end valuations. If the Company’s mortality tables do not anticipate its population’s mortality experience as accurately as expected, actual cash expenditures and costs that the Company incurs could differ materially from its current estimates. Additionally, the Company’s reported defined benefit pension funding status may be affected, and it may be required to increase employer contributions, due to increases in its defined benefit pension obligation or poor financial performance in asset markets in future years.
The Company is subject to various general operating risks which may be fully or partially outside of its control.
The Company’s results of operations, financial position or cash flows could be adversely impacted by various general operating risks which may be fully or partially outside of its control. Such risks stem from internal and external sources and include:
•global economic recessions and/or credit market disruptions;
•deterioration of the creditworthiness of its customers or counterparties to financial instruments, and their ability to perform under contracts;
•inability of suppliers and other counterparties, including those related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the terms of their contracts with the Company;
•decreases in the availability or increases in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
•disruption to, or increased costs within, the transportation chain for coal, including rail, barge, trucking, overland conveyor, ports and ocean-going vessels;
•failure to attract and retain skilled and qualified personnel, or increases in the costs required to attract and retain skilled and qualified personnel, particularly as the prevalence of coal-fired electricity generation declines;
•new or increased forms of taxation imposed by federal, state, provincial or local governmental authorities, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes;
•uncertainties associated with the Company’s global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates; and
•cyber-attacks or other cybersecurity incidents that disrupt the operations of the Company or third-parties with which the Company does business, including cloud-based software service providers, or result in the dissemination of proprietary or confidential information about it, its employees, its customers or other third-parties.
Peabody Energy Corporation 2021 Form 10-K
Risks Related to Peabody’s Indebtedness and Capital Structure
The Company’s financial performance could be adversely affected by its funded indebtedness (Indebtedness).
As of December 31, 2021, the Company had approximately $1.1 billion of Indebtedness outstanding, excluding finance leases and debt issuance costs.
The degree to which the Company is leveraged could have important consequences, including, but not limited to:
•making it more difficult for the Company to pay interest and satisfy its debt obligations;
•increasing the cost of borrowing;
•increasing the Company’s vulnerability to general adverse economic and industry or regulatory conditions;
•requiring the dedication of a substantial portion of the Company’s cash flow from operations to the payment of principal and interest on its Indebtedness, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, business development or other general corporate requirements;
•limiting its ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements;
•limiting its ability to make certain investments;
•limiting the Company’s ability to refinance or otherwise exchange existing debt at commercially acceptable rates;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing, particularly during periods in which credit markets are weak;
•limiting the Company’s flexibility in planning for, or reacting to, changes in its business and in the coal industry;
•causing a decline in its credit ratings; and
•placing the Company at a competitive disadvantage compared to less leveraged competitors.
A downgrade in the Company’s credit ratings or other unfavorable indicators could result in, among other matters, a requirement to post additional collateral on derivative trading instruments that it may enter into, the loss of trading counterparties for corporate hedging and trading and brokerage activities or an increase in the cost of, or a limit on its access to, various forms of credit used in operating its business.
If the Company’s cash flows and capital resources are insufficient to fund its debt service obligations, it may be forced to sell assets, seek additional capital or seek to restructure or refinance its Indebtedness. These alternative measures may not be successful and may not permit the Company to meet its scheduled debt service obligations. Its Indebtedness may restrict the use of the proceeds from any such sales. The Company may not be able to complete those sales and the proceeds may not be adequate to meet any debt service obligations then due.
Despite the Company’s Indebtedness, it may still be able to incur more debt, which could further increase the risks associated with its Indebtedness.
The Company may be able to incur additional Indebtedness in the future. Although covenants under the indentures governing its senior secured notes and the agreements governing its other Indebtedness, including its credit facility, letter of credit facility, and finance leases, limit its ability to incur additional Indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, debt incurred in compliance with these restrictions can be material. In addition, the indenture governing the senior secured notes and the agreements governing the Company’s other Indebtedness do not limit it from incurring obligations that do not constitute Indebtedness as defined therein.
The terms of the indentures governing the Company’s senior secured notes and the agreements and instruments governing its other Indebtedness and surety bonding obligations impose restrictions that may limit its operating and financial flexibility.
The indentures governing the Company’s senior secured notes and the agreements governing its other Indebtedness and surety bonding obligations contain certain restrictions and covenants which restrict its ability to incur liens and/or debt or provide guarantees in respect of obligations of any other person and other restrictions, all of which could adversely affect the Company’s ability to operate its business, as well as significantly affect its liquidity, and therefore could adversely affect its results of operations.
Peabody Energy Corporation 2021 Form 10-K
These covenants limit, among other things, the Company’s ability to:
•incur additional Indebtedness;
•pay dividends on or make distributions in respect of stock or make certain other restricted payments, such as share repurchases;
•make capital or other investments;
•enter into agreements that restrict distributions from certain subsidiaries;
•sell or otherwise dispose of assets;
•use for general purposes the cash received from certain allowable asset sales or disposals;
•enter into transactions with affiliates;
•create or incur liens;
•merge, consolidate or sell all or substantially all of its assets; and
•receive dividends or other payments from subsidiaries in certain cases.
The Company’s ability to comply with these covenants may be affected by events beyond its control and the Company may need to refinance existing debt in the future. A breach of any of these covenants together with the expiration of any cure period, if applicable, could result in a default under its senior secured notes. If any such default occurs, subject to applicable grace periods, the holders of its senior secured notes may elect to declare all outstanding senior secured notes, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If the obligations under its senior secured notes were to be accelerated, the Company’s financial resources may be insufficient to repay the notes and any other Indebtedness becoming due in full. The terms of the Company’s Indebtedness provide that if it cannot meet its debt service obligations, the lenders could foreclose against the assets securing their borrowings and the Company could be forced into bankruptcy or liquidation.
In addition, if the Company breaches the covenants in the indentures governing the senior secured notes and do not cure such breach within the applicable time periods specified therein, the Company would cause an event of default under the indenture governing the senior secured notes and a cross-default to certain of its other Indebtedness and the lenders or holders thereunder could accelerate their obligations. If the Company’s Indebtedness is accelerated, it may not be able to repay its Indebtedness or borrow sufficient funds to refinance it. Even if the Company is able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to the Company. If the Company’s Indebtedness is in default for any reason, its business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for the Company to successfully execute its business strategy and compete against companies who are not subject to such restrictions.
The number and quantity of viable financing and insurance alternatives available to the Company may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around its efforts with respect to environmental and social matters and related governance considerations could harm the perception of the Company by a significant number of investors or result in the exclusion of its securities from consideration by those investors.
Certain banks, other financing sources and insurance companies have taken actions to limit available financing and insurance coverage for the development of new coal-fueled power plants and coal producers and utilities that derive a majority of their revenue from coal, and particularly from thermal coal. This may adversely impact the future global demand for coal. Increasingly, the actions of such financial institutions and insurance companies are informed by non-standardized “sustainability” scores, ratings and benchmarking studies provided by various organizations that assess environmental, social and governance matters. Further, there have been efforts in recent years by members of the general financial and investment communities, including investment advisors, sovereign wealth funds, public pension funds, universities and other institutional investors, to divest themselves and to promote the divestment of securities issued by companies involved in the fossil fuel extraction market, or that have low ratings or scores in studies and assessments of the type noted above, including coal producers. These entities also have been pressuring lenders to limit financing available to such companies.
Peabody Energy Corporation 2021 Form 10-K
These efforts may have adverse consequences, including, but not limited to:
•restricting the Company’s ability to access capital and financial markets in the future;
•reducing the demand and price for its equity securities;
•increasing the cost of borrowing;
•causing a decline in the Company’s credit ratings;
•reducing the availability, and/or increasing the cost of, third-party insurance;
•increasing the Company’s retention of risk through self-insurance;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and
•limiting the Company’s flexibility in business development activities such as mergers, acquisitions and divestitures.
Risks Related to Ownership of Peabody’s Securities
The price of Peabody’s securities may be volatile and could fall below the minimum allowed by New York Stock Exchange (NYSE) listing requirements.
The price of Peabody’s common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of its Common Stock regardless of its operating performance, including, among others:
•actual or anticipated fluctuations in Peabody’s quarterly and annual results and those of other public companies in its industry;
•industry cycles and trends;
•mergers and strategic alliances in the coal industry;
•changes in government regulation;
•potential or actual military conflicts or acts of terrorism;
•the failure of securities analysts to publish research about Peabody or to accurately predict the results it actually achieves;
•changes in accounting principles;
•announcements concerning Peabody or its competitors;
•the purchase and sale of shares of its Common Stock by significant shareholders;
•lack of or excess of trading liquidity; and
•the general volatility of securities markets.
As a result of all of these factors, investors in Peabody’s Common Stock may not be able to resell their stock at or above the price they paid or at all. In the recent past, Peabody’s closing stock price has fallen below $1.00 per share for a limited number of trading days. If Peabody’s stock were to trade below $1.00 per share for 30 consecutive trading days, NYSE could commence suspension and delisting procedures. Further, Peabody could be the subject of securities class action litigation due to any such stock price volatility, which could divert management’s attention and have a material adverse effect on its results of operation.
Peabody’s Common Stock is subject to dilution and may be subject to further dilution in the future.
Peabody’s Common Stock is subject to dilution from its long-term incentive plan. In addition, Peabody may continue issuing equity securities in connection with future investments, acquisitions, debt-for-equity exchanges or capital raising transactions. Such issuances or grants could constitute a significant portion of the then-outstanding Common Stock, which may result in significant dilution in ownership of Common Stock.
There may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests.
Circumstances may arise in which the interests of a significant stockholder may be in conflict with the interests of the Company’s other stakeholders. A significant stockholder may exert substantial influence over the Company to cause the Company to take action that aligns with their interests, for example, to pursue or prevent acquisitions, divestitures or other transactions, including the issuance or repurchase of additional shares or debt, that, in its judgment, could enhance its investment in Peabody or another company in which it invests. Such transactions may advance the interests of the significant stockholder and not necessarily those of other stakeholders, which might adversely affect Peabody or other holders of its Common Stock or debt instruments.
Peabody Energy Corporation 2021 Form 10-K
The future payment of dividends on Peabody’s stock or future repurchases of its stock is dependent on a number of factors and cannot be assured.
As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” restrictive covenants in the Company’s debt and surety agreements limit its ability to pay cash dividends and repurchase shares. Such restrictions may negatively impact the trading price of the Common Stock. The payment of future cash dividends and future repurchases will depend upon these restrictions, as well as Peabody’s earnings, economic conditions, liquidity and capital requirements, and other factors, including its leverage and other financial ratios. Accordingly, the Company cannot make any assurance that future dividends will be paid or future repurchases will be made.
General Business Risks
The Company may not be able to fully utilize its deferred tax assets.
The Company is subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2021, the Company had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $2,176.9 million and $83.4 million, respectively, as described further in Note 9. “Income Taxes” to the accompanying consolidated financial statements. At that date, the Company also had recorded a valuation allowance of $2,120.8 million.
The Company’s ability to use its U.S. NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 of the Internal Revenue Code of 1986, as amended. An ownership change generally occurs if certain stockholders increase their aggregate percentage ownership of a corporation’s stock by more than 50 percentage points over their lowest percentage ownership at any time during the testing period, which is generally the three-year period preceding any potential ownership change.
Although the Company may be able to utilize some or all of those deferred tax assets in the future if it has income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that it will be able to do so. Further, the Company is presently unable to record tax benefits on future losses in the U.S. and Australia until such time as sufficient income is generated by its operations in those jurisdictions to support the realization of the related net deferred tax asset positions. The Company’s results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.
Acquisitions and divestitures are a potentially important part of the Company’s long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits.
The Company may engage in acquisition or divestiture activity based on its set of investment criteria to produce outcomes that increase shareholder value or provide potential strategic benefits. If the Company fails to accurately estimate the future results and value of an acquired or divested business or assets and the related risk associated with such a transaction, or are unable to successfully integrate the businesses or assets it acquires, its business, financial condition or results of operations could be negatively affected. Moreover, any transactions the Company pursues could materially impact its liquidity and an acquisition could increase capital resource needs and may require it to incur Indebtedness, seek equity capital or both. The Company may not be able to satisfy these liquidity and capital resource needs on acceptable terms or at all. In addition, future acquisitions could result in its assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions.
Peabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in Peabody’s certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire it, even if doing so might be beneficial to its stockholders. Provisions of Peabody’s by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of its Common Stock and may have the effect of delaying or preventing a change in control.
Peabody Energy Corporation 2021 Form 10-K
Diversity in interpretation and application of accounting literature in the mining industry may impact the Company’s reported financial results.
The mining industry has limited industry-specific accounting literature and, as a result, the Company understands diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, the Company may need to restate its reported results if the resulting interpretations differ from its current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of the Company’s significant accounting policies.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
None.

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ITEM 2. PROPERTIES
Item 2. Properties.
Coal Reserves and Resources
Information concerning the Company’s mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to the Company for the year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires disclosure of mineral resources, in addition to mineral reserves, as of December 31, 2021, both in the aggregate and for each of our individually material mining properties. The Company’s coal reserves and resources are estimated by individuals deemed Qualified Persons (QP) according to the standards set forth in subpart 1300 of Regulation S-K.
Mineral resources and reserves are defined in subpart 1300 of Regulation S-K as follows:
•Mineral resource. A concentration or occurrence of material of economic interest in or on the earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.
•Mineral reserve. An estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of a QP, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.
Under subpart 1300 of Regulation S-K, mineral resources may not be classified as mineral reserves unless the determination has been made by a QP that such mineral resources can be the basis of an economically viable project. The conversion of reported mineral resources to mineral reserves should not be assumed.
Coal resources are estimated from geological models constructed from an extensive historical database of drill holes and the Company’s ongoing drilling program. Data from individual drill holes is compiled in a computerized drill-hole database, including the depth, thickness and, where core drilling is used, the quality of the coal observed. For coal deposits, the density of a drill pattern is one of the important factors which determine whether the related coal will be classified as measured, indicated, or inferred.
Mineral resource classifications are differentiated under subpart 1300 of Regulation S-K, in part, as follows:
•Measured resource. That part of a mineral resource with the highest level of geological confidence; quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit.
•Indicated resource. That part of a mineral resource with a level of geological confidence between that of measured and inferred resources; quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit.
•Inferred resource. That part of a mineral resource with the lowest level of geological confidence; quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability.
Peabody Energy Corporation 2021 Form 10-K
The geological confidence surrounding resource classification is first determined by a drill hole spacing analysis performed by a QP using geostatistical techniques. A QP may also use qualitative analysis to determine the geologic confidence based on historical experience with a specific coal deposit. Resources are further evaluated using a set of structure and quality parameters to determine the reasonable prospects for economic extraction. The structure parameters include coal thickness, depth, dipping angle, and strip ratio, among others. The quality parameters include ash and sulfur content, yield, and heat value, among others. Each coal deposit is different with respect to geology, potential mining methods, logistics, and markets. The cut-off criteria of those structure and quality parameters are different for each deposit, and a QP generally forms those criteria based upon experience with the Company’s existing mining operations or adjacent operations with similar geological conditions. Other factors, such as coal control, or surface and underground obstacles are also considered in connection with resource estimates. The reclassification of reported mineral resources from lower to higher levels of geological confidence should not be assumed.
The economically mineable part of a measured coal resource is considered a proven coal reserve and has the highest degree of assurance of economic viability. The economically mineable part of indicated, and sometimes measured, coal resources are considered probable coal reserves and have a moderate degree of assurance of economic viability.
For each mine or future mine, the Company develops Life-of-Mine (LOM) plans which employ a market-driven, risk-adjusted capital allocation process to guide long-term mine planning of active operations and development projects. QPs rely on LOM planning as an integral process for coal reserve and resource estimates. The LOM plans consider dilution and losses during mining and processing as recoverability factors to estimate saleable coal. The LOM plans are developed in consideration of market demands and operational constraints. The LOM plans project, among other things, annual quantities and qualities for each coal product. The saleable product mix for a mine may include multiple thermal and metallurgical products with different targeted qualities and sales prices. The expected volumes for each mine and product, as well as annual pricing forecasts for each product, developed as described below, and related cost forecasts, developed as described below, are then evaluated to determine the economically viable coal in the LOM plans. Other factors impacting the assessment include geological conditions, production expectations for certain areas, the effects of regulation and taxes by governmental agencies, future price and operating cost assumptions and adverse changes in market conditions and mine closure activities.
The Company periodically reviews and updates coal reserve and resource estimates to reflect the production of coal, new drill hole data, the effects of mining activities, analysis of new engineering and geological data, changes in property control, modification of mining methods and other factors.
Mineral Rights
The Company controls coal rights through direct ownership and numerous lease agreements with government or private parties. The majority of our coal reserves and resources are controlled through lease agreements with the U.S. and Australian governments. In addition, surface rights are required to conduct certain mining-related activities. The Company holds the majority of the required surface rights to meet mid- to long-term production requirements. The additional surface rights to meet long-term production requirements are expected to be acquired as needed.
The Company is party to numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover Peabody’s principal reserves in the Powder River Basin and other reserves and resources in Alabama, Colorado and New Mexico. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The U.S. Bureau of Land Management (BLM) has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2021, the Company leased 1,610 acres of federal land in Alabama, 3,480 acres in Colorado, 282 acres in New Mexico and 38,915 acres in Wyoming, for a total of 44,287 acres nationwide subject to those limitations. The Company also lease coal-mining properties from various state governments in the U.S.
Private U.S. coal leases normally have terms of between 10 and 20 years and usually give the Company the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many private U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of private U.S. leases are normally extended by active production at or near the end of the lease term. Private U.S. leases containing undeveloped coal properties may expire or these leases may be renewed periodically.
Peabody Energy Corporation 2021 Form 10-K
Mining and exploration in Australia are generally carried out under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally, landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or court process. Surface rights are typically acquired directly from landowners through agreement or court determination, subject to some exceptions.
Pricing
The pricing information used in support of the Company’s reserve and resource estimates include internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, price forecasts are based on a thorough analytical process utilizing detailed supply and demand models, global economic indicators, projected foreign exchange rates, analyses of price relationships among various commodities, competing fuels analyses, projected supply and demand fundamentals for steel production and electricity generation, analyses of supplier costs and other variables. Price forecasts, supply and demand models and other key assumptions and analyses are stress-tested against independent third-party research (not commissioned by the Company) to confirm the conclusions reached through analytical processes, and that price forecasts fall within the ranges of the projections included in this third-party research. The development of the analyses, price forecasts, supply and demand models and related assumptions are subject to multiple levels of management review.
Below is a description of some of the specific factors that the Company evaluates in developing price forecasts for thermal and metallurgical coal products on a mine-by-mine and product-by-product basis. Differences between the assumptions and analyses included in the price forecasts and realized factors could cause actual pricing to differ from the forecasts.
Thermal. Several factors can influence thermal coal supply and demand and pricing. Demand is sensitive to total electric power generation volumes, which are determined in part by the impact of weather on heating and cooling demand, inter-fuel competition in the electric power generation mix (such as from natural gas and renewable sources), changes in capacity (additions and retirements), competition from other producers, coal stockpiles and policy and regulations. Supply considerations impacting pricing include coal reserve and resource positions, mining methods, strip ratios, production costs and capacity and the cost of new supply (greenfield developments or extensions at existing mines).
In the United States, natural gas is the most significant substitute for thermal coal for electricity generation and can be one of the largest drivers of shifts in supply and demand and pricing. The competitiveness of natural gas as a generation fuel source has been strengthened by accelerated growth in domestic natural gas production, new natural gas combined cycle generation capacity and comparatively low natural gas prices versus historic levels. The build out of renewable generation and subsidized power can also be a key driver of power market pricing and hence coal prices.
Internationally, thermal coal-fueled generation also competes with alternative forms of electricity generation. The competitiveness and availability of generation fueled by natural gas, oil, nuclear, hydro, wind, solar and biomass vary by country and region and can have a meaningful impact on coal pricing. Policy and regulations, which vary from country to country, can also influence prices. 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, and the competitiveness of seaborne supply from leading thermal coal exporting countries, including Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others.
Metallurgical. Several factors can influence metallurgical coal supply and demand and pricing. Demand is impacted by economic conditions, government policies and demand for steel, and is also impacted by competing technologies used to make steel, some of which do not use coal as a manufacturing input. Competition from other types of coal is also a key price consideration and can be impacted by the 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, as well as country-specific policies restricting or promoting domestic supply. 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, is also an important price consideration.
In addition to the factors noted above, the prices which may be obtained at each mine or future mine can be impacted by factors such as (i) the mine’s location, which impacts the total delivered energy costs to its customers, (ii) quality characteristics, particularly if they are unique relative to competing mines, (iii) assumed transportation costs and (iv) other mine costs that are contractually passed on to customers in certain commercial relationships.
Peabody Energy Corporation 2021 Form 10-K
Costs
The cost estimates used to establish LOM plans are generally made according to internal processes that project future costs based on historical costs and expected trends. The estimated costs normally include mining, processing, transportation, royalty, add-on tax and other mining-related costs. Estimated mining and processing costs reflect projected changes in prices of consumable commodities (mainly diesel fuel, explosives and steel), labor costs, geological and mining conditions, targeted product qualities and other mining-related costs. Estimates for other sales-related costs (mainly transportation, royalty and add-on tax) are based on contractual prices or fixed rates. Specific factors that may impact the Company’s operating costs include:
•Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Company geologists conduct the exploration program and provide geological models for the LOM process. Coal seam depth, thickness, dipping angle, partings and quality constrain the available mining methods and size of operations. Shallow coal is typically mined by surface mining methods by which the primary cost is overburden removal. Deep coal is typically mined by underground mining methods where the primary costs include coal extraction, conveyance and roof control.
•Scale of operations and the equipment sizes. For surface mines, dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. Longwall operations are generally more cost-effective than room-and-pillar operations for underground mines.
•Commodity prices. For surface mines, the costs of diesel fuel and explosives are major components of the total mining cost. For underground mines, the steel used for roof control represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models used to establish reserve and resource estimates.
•Target product quality. By targeting a premium quality product, mining and processing processes may experience more coal losses. By lowering product quality the coal losses can be minimized and therefore a lower cost per ton can be achieved. In the Company’s LOM plans, product qualities are estimated to correspond to existing contracts and forecasted market demands.
•Transportation costs. Transportation costs vary by region. Most of the Company’s U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in U.S. thermal cost estimates. The Company’s seaborne operations typically sell coal at designated ports. The estimated costs for seaborne operations include rail and barge transportation and related fees at ports.
•Royalty costs. Royalty costs are based upon contractual agreements for the coal leased from governments or private owners. The royalty rates for coal leased from governments differ by country and, in some cases, by mining method. Estimated add-on taxes and other sales-related costs are determined according to government regulations or historical costs.
•Exchange rates. Costs related to the Company’s Australian production are predominantly denominated in Australian dollars, while the Australian coal exported is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.
Summary of Coal Reserves and Resources
Peabody controlled an estimated 2.5 billion tons of coal reserves and 2.4 billion tons of coal resources as of December 31, 2021. Approximately 95% of the Company’s coal reserves and 98% of the Company’s coal resources are held under lease, and the remainder is held through fee ownership.
The following tables summarize the Company’s estimated coal reserves and resources as of December 31, 2021. The quantity of the coal resources is estimated on an in situ basis as attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as attributable to Peabody. The coal reserves and resources are reported on selected key quality parameters and on different moisture bases generally referenced by sales contracts for each mining property.
Peabody Energy Corporation 2021 Form 10-K
SUMMARY COAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2021 (1)
(Tons in millions)
Peabody
Mining Coal Proven Coal Reserves Probable Coal Reserves Total Coal Reserves Interest
Segment / Mining Complex Country State Stage Method Type Amount Quality Amount Quality Amount Quality (10)
Seaborne Thermal Mining:(2)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Tons %Ash %Sulfur Kcal/kg(6)
Wilpinjong AUS NSW P S T 71 24.3 0.5 5,940 5 29.7 0.4 5,478 76 24.7 0.5 5,910 100%
Wambo Opencut (9)
AUS NSW P S T 28 10.8 0.3 7,098 2 11.3 0.3 7,055 30 10.8 0.3 7,095 50%
Wambo Underground AUS NSW P U T 2 12.2 0.3 6,802 - - - - 2 12.2 0.3 6,802 100%
South Wambo AUS NSW E U T/C - - - - 74 9.8 0.3 7,034 74 9.8 0.3 7,034 100%
Total 101 81 182
Seaborne Metallurgical Mining:(3)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Shoal Creek USA AL P U C 16 10.2 0.7 30.4 2 10.2 0.7 30.3 18 10.2 0.7 30.3 100%
Coppabella AUS QLD P S P 8 8.9 0.2 10.3 4 9.4 0.2 8.6 12 9.1 0.2 9.7 73.3%
Moorvale AUS QLD P S C/P/T 2 11.8 0.3 16.2 - - - - 2 11.8 0.3 16.2 73.3%
Metropolitan AUS NSW P U C/T 4 14.0 0.4 18.6 12 14.6 0.4 18.6 16 14.5 0.4 18.6 100%
North Goonyella AUS QLD I U C 46 7.4 0.5 21.4 24 7.5 0.5 21.1 70 7.4 0.5 21.3 100%
Moorvale South AUS QLD D S C/P 4 11.0 0.4 18.4 2 9.7 0.4 17.4 6 10.6 0.4 18.1 73.3%
Middlemount (9)
AUS QLD P S C/P 28 10.3 0.4 18.0 9 10.3 0.4 18.0 37 10.3 0.4 18.0 50.0%
Total 108 53 161
Powder River Basin Mining:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
North Antelope Rochelle USA WY P S T 1,378 4.4 0.2 8,889 106 4.4 0.2 8,965 1,484 4.4 0.2 8,895 100%
Caballo USA WY P S T 266 5.1 0.3 8,504 52 5.4 0.4 8,205 318 5.1 0.3 8,455 100%
Rawhide USA WY P S T 124 5.6 0.4 8,274 3 5.5 0.4 8,359 127 5.6 0.4 8,269 100%
Total 1,768 161 1,929
Other U.S. Thermal Mining:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Bear Run USA IN P S T 82 10.5 3.1 11,068 55 10.0 2.6 11,052 137 10.3 2.9 11,062 100%
El Segundo/Lee Ranch USA NM P S T 16 15.8 0.9 9,249 1 16.3 0.7 9,345 17 15.8 0.9 9,243 100%
Gateway North USA IL P U T 36 8.9 2.9 10,892 5 9.0 2.9 10,878 41 8.9 2.9 10,890 100%
Twentymile USA CO P U T 7 10.7 0.5 11,282 1 10.1 0.5 11,227 8 10.6 0.5 11,272 100%
Wild Boar USA IN P S T 9 8.4 2.6 11,034 10 8.1 2.7 11,203 19 8.2 2.6 11,127 100%
Francisco Underground USA IN P U T 1 8.6 3.1 11,515 7 8.8 3.1 11,402 8 8.8 3.1 11,425 100%
Total 151 79 230
Grand total 2,128 374 2,502
Stage Mining Method Coal Type
P Producing S Surface Mine T Thermal
I Idle U Underground Mine C Coking
D Development P Pulverized Coal Injection
E Exploration
Peabody Energy Corporation 2021 Form 10-K
SUMMARY COAL RESOURCES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2021 (1)
(Tons in millions)
Measured and Indicated Peabody
Mining Coal Measured Coal Resources Indicated Coal Resources Coal Resources Inferred Coal Resources Interest
Deposit Country State Stage Method Type Amount Quality Amount Quality Amount Quality Amount Quality (10)
Seaborne Thermal Mining:(2)(4)
Tons %Ash %Sulfur Kcal/kg(5)
Tons %Ash %Sulfur Kcal/kg(5)
Tons %Ash %Sulfur Kcal/kg(5)
Tons %Ash %Sulfur Kcal/kg(5)
Wilpinjong AUS NSW P S T 103 23.0 0.5 6,042 25 25.4 0.5 5,851 128 23.5 0.5 6,004 6 27.3 0.5 5,707 100%
Wambo Opencut (9)
AUS NSW P S T 105 20.5 0.4 6,150 176 23.6 0.4 5,850 281 22.4 0.4 5,962 276 24.8 0.4 5,800 50%
Wambo South AUS NSW E U T/C 219 21.5 0.3 6,068 83 27.2 0.3 5,571 302 23.1 0.3 5,931 47 36.3 0.3 4,745 100%
Total 427 284 711 329
Seaborne Metallurgical Mining:(3)(4)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Tons %Ash %Sulfur VM%(7)
Shoal Creek USA AL P U C 40 9.6 0.7 25.1 35 9.9 0.7 24.1 75 9.8 0.7 24.6 7 10.3 0.7 24.0 100%
Metropolitan AUS NSW P U C/T 7 15.4 0.4 18.6 8 15.3 0.3 18.7 15 15.3 0.4 18.6 2 16.0 0.3 19.0 100%
Coppabella AUS QLD P S P 13 15.8 0.3 13.1 48 14.3 0.2 12.8 61 14.6 0.2 12.9 73 15.5 0.2 12.3 73.3%
Moorvale AUS QLD P S P 18 18.3 0.3 16.7 14 17.2 0.3 16.7 32 17.8 0.3 16.7 5 15.9 0.3 16.7 73.3%
Moorvale South AUS QLD D S C/P 3 18.3 0.4 18.4 7 18.2 0.4 18.3 10 18.2 0.4 18.3 6 16.8 0.4 17.7 73.3%
NGC GLB2 AUS QLD E U C - - - - 1 15.3 0.6 20.7 1 15.3 0.6 20.7 8 13.6 0.5 20.7 100%
Coppabella North AUS QLD E U P 255 15.8 0.3 14.6 102 16.8 0.3 14.6 357 16.1 0.3 14.6 12 16.5 0.3 14.3 75.5%
Yeerun AUS QLD E S P 16 16.0 0.4 14.3 57 16.2 0.5 15.0 73 16.2 0.4 14.8 46 17.8 0.5 14.7 83.0%
Moorvale North AUS QLD E U P 21 26.0 0.4 12.9 25 24.5 0.5 13.2 46 25.2 0.4 13.1 25 23.2 0.5 13.4 73.3%
Gundyer AUS QLD E U P - - - - 54 16.4 0.2 19.7 54 16.4 0.2 19.7 70 18.3 0.2 18.3 90.0%
Total 373 351 724 254
Powder River Basin Mining:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Caballo USA WY P S T 42 4.7 0.3 8,428 82 5.2 0.4 8,231 124 5.0 0.4 8,298 2 5.4 0.4 8,245 100%
Rawhide USA WY P S T 1 5.5 0.4 8,286 91 5.2 0.3 8,362 92 5.2 0.3 8,361 7 5.7 0.4 8,243 100%
Total 43 173 216 9
Other U.S. Thermal Mining:(5)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Tons %Ash %Sulfur Btu(8)
Bear Run USA IN P S T 6 13.7 3.4 10,975 50 16.3 4.0 10,613 56 16.1 4.0 10,652 57 16.5 3.7 10,579 100%
Wild Boar USA IN P S T - - - - 3 11.8 5.8 11,300 3 11.8 5.8 11,300 1 12.3 5.4 11,230 100%
Total 6 53 59 58
Grand total 849 861 1,710 650
Peabody Energy Corporation 2021 Form 10-K
(1)
The sales price assumptions supporting economic recoverability vary depending upon factors such as coal quality and existing customer volume commitments. For the five-year period 2022 through 2026, the estimated sales prices for seaborne metallurgical mines are based upon estimated premium hard coking coal benchmark prices ranging from $150.00 to $162.00 per tonne. For seaborne thermal mines, the estimated sales prices for the same period range from approximately $42.00 to $104.00 per tonne, and approximately $9.00 to $45.00 per ton for U.S. thermal mines. Subsequent to 2026, for all mines, sales price escalation is assumed at 2.0% to 3.0% per annum through the end of each LOM plan.
(2)
The moisture condition for Seaborne Thermal Mining segment coal quality is on an air-dry basis.
(3)
The moisture condition for the Seaborne Metallurgical Mining segment coal quality is on an air-dry basis, except for Shoal Creek Mine which is on a dry basis.
(4)
The quantities for Australian coal reserves are estimated on an as-shipped moisture basis; quantities for Australian coal resources are estimated on an in situ moisture basis.
(5)
The quality and quantity estimates for U.S. thermal reserves are calculated on as-shipped moisture basis; the quality and quantity estimates for U.S. thermal resources are calculated on an in situ moisture basis.
(6)
Kcal/kg (kilocalories per kilogram) is the net calorific value (net heating value) of coal
(7)
VM (volatile matter) represents the proportion of certain organic and mineral components in coal, for example, water, carbon dioxide, or sulfur dioxide. Volatile matter is inversely related to coal rank.
(8)
Btu (British thermal unit) is the gross heating value of coal per pound, which includes the weight of moisture in coal on an as-sold basis. The range of variability of the moisture content in coal may affect the actual shipped Btu content.
(9)
Reserve and resource data is maintained and provided by joint venture managing partners utilizing the Australasian Code for Reporting of Exploration Results, Mineral Resources and Ore Reserves.
(10)
The quantities of reserves and resources are disclosed at Peabody’s proportional ownership share.
Individual Property Disclosure
To determine the Company’s individually material mining operations in accordance with subpart 1300 of Regulation S-K, management considered both quantitative and qualitative factors, assessed in the context of the Company’s overall business and financial condition. Such assessment included the Company’s aggregate mining operations on all of its mining properties, regardless of the stage of production or the type of coal produced. Quantitative factors included, among others, mining operations’ relative contributions to the Company’s aggregate historical and estimated revenues, cash flows, and Adjusted EBITDA (as defined in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”) Qualitative factors may include, as applicable, capital expansion plans, long-term pricing outlook, the regulatory environment and various strategic priorities. The Company concluded that, as of December 31, 2021, its individually material mines are North Antelope Rochelle Mine (NARM), Shoal Creek Mine, Wilpinjong Mine, and the Coppabella-Moorvale Joint Venture. The Company will update its assessment of individually material mines on an annual basis. The reserve and resource tables that follow do not include comparative information for resources as of December 31, 2020 as the Company did not present such data previously under the SEC Industry Guide 7 requirements and such data is not required to be presented in connection with the adoption of the disclosure requirements of subpart 1300 of Regulation S-K.
The information that follows relating to such individually material mines is derived, for the most part, from, and in some instances is an extract from, the technical report summaries (“TRS”) relating to such properties prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS, incorporated herein by reference and made a part of this Annual Report on Form 10-K. The relevant TRS for NARM, Shoal Creek Mine, Wilpinjong Mine, and the Coppabella-Moorvale Joint Venture are included as Exhibits 96.1, 96.2, 96.3 and 96.4, respectively, to this Annual Report on Form 10-K, and specific sections of such TRS are referenced below using the corresponding exhibit number.
Peabody Energy Corporation 2021 Form 10-K
North Antelope Rochelle Mine
The North Antelope Rochelle Mine (NARM) is a production-stage surface coal mine located sixty-five miles south of Gillette, Wyoming, USA. NARM is situated in the Gillette Coal Field on the east flank of the Powder River Basin. NARM began operations in 1999 after Peabody combined its interests in the formerly separate North Antelope Mine and Rochelle Mine.
NARM extracts coal from the Wyodak-Anderson coal seam, which ranges from 60- to 80-feet thick and lies from 100 to 400 feet below the surface in the mining area. The Company has secured mineral rights through Federal and State lease agreements which cover 30,159 acres. The typical royalty rate for Federal and State coal leases is 12.5% of realized revenue. Generally, the leases continue indefinitely with periodic renewal, provided there is diligent coal production or other development within the lease area. As of December 31, 2021, all required licenses and permits were in place for the operations of NARM. For additional information regarding mineral rights and permitting, refer to sections 3 and 17 in Exhibit 96.1.
The mining operation consists of multiple open pits in four main mining areas, which allows for quality blending and other optimization strategies. Overburden is removed by dragline, truck and shovel, dozer and cast blasting methods. Coal is hauled by truck to one of five dump locations, where it is then crushed and conveyed to silos adjacent to rail load-outs for customer delivery. Coals of varying characteristics may be blended at a central blending facility along the loadout rail loop. Coal is sold unwashed, as a run-of-mine (ROM) product. NARM coal is well recognized for domestic thermal power generation. For additional information regarding mining and processing methods, refer to sections 13 and 14 in Exhibit 96.1.
The key supporting infrastructure for NARM includes rail services provided by the BNSF Railway Company and Union Pacific Corporation, road access via interstate and state highways and roads, electrical power from a dedicated substation with 230kV and 69kV transmission lines, and water supply from a mine dewatering system and deep wells. The mining industry in the Powder River Basin anchors numerous communities from which the mine attracts qualified personnel. For additional information regarding the mine’s infrastructure, refer to sections 13 and 15 in Exhibit 96.1.
Peabody Energy Corporation 2021 Form 10-K
The property, plant, equipment and mine development assets of NARM had a net book value of approximately $406 million at December 31, 2021. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls, and necessary capital replacements are generally included in the LOM plan to support future production. For additional information regarding capital and equipment, refer to sections 13 and 18 in Exhibit 96.1.
The table below presents NARM coal reserve estimates at December 31, 2021, along with comparative quantities at December 31, 2020. NARM did not hold any coal resources as of December 31, 2021. These reserve estimates were supported by the analyses of 4,778 total drill holes within the coal lease area. The quantity of the coal reserves is estimated on a saleable product basis and deemed 100% attributable to Peabody. In addition to quantity, the table presents selected key quality parameters on an as-shipped basis. For additional information regarding coal reserve and resource estimates, refer to sections 11 and 12 in Exhibit 96.1.
NARM - SUMMARY OF RESERVES (1)
(Tons in millions)
December 31, 2021 December 31, 2020
Coal Reserves (2)(3)(4)
Tons %Ash %Sulfur Btu % Mine Yield(5)
Tons
Proven 1,378 4.4 0.2 8,889 100% 1,431
Probable 106 4.4 0.2 8,965 100% 115
Total 1,484 1,546
Year-over-year decrease -4%
The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
(1)
Economic recoverability is based upon an estimated average sales price per ton of $13.18 for the five-year period ending December 31, 2026 and assumed escalation of 2.5% per annum during the subsequent period through the end of the LOM plan. Refer to section 19 of Exhibit 96.1 for detailed price assumptions.
(2)
The cut-off grade and metallurgical recovery are not limiting factors for reserve estimates due to consistent coal thickness and established trends of coal quality in the leased area. The strip ratio increases gradually, but the existing pit length allows an average mineable strip ratio. Besides the results of drill hole analyses, the main limiting factors include surface infrastructure and lease boundaries.
(3)
The quality of coal reserves is estimated on an as-shipped basis.
(4)
The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration 92% mining recovery. The results of the LOM planning process demonstrate the economic recoverability of the coal reserve estimates. Refer to section 19 of Exhibit 96.1 for economic analysis.
(5)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons, with processing loss considered.
Peabody Energy Corporation 2021 Form 10-K
Shoal Creek Mine
The Shoal Creek Mine is a production-stage underground longwall metallurgical coal mine located thirty-five miles west of Birmingham, Alabama, USA. The mine is within the east-central portion of the Warrior Coal Field, which is part of the Southern Appalachian coal-producing region. The Drummond Corporation began producing coal at the mine in 1994. Peabody Energy acquired the mine from the Drummond Corporation in December 2018. The mine was idled in the fourth quarter of 2020 due to market conditions and resumed production in November 2021.
Shoal Creek Mine extracts coal from the Mary Lee and Blue Creek coal seams at depths of 1,000 to 1,300 feet. The Company has secured mineral rights through a combination of private, federal and state mineral leases and surface rights agreements which encompass a total of 31,747 acres of mineral control and 3,490 acres of surface land control. The majority of the mineral leases are private leases with negotiated royalty rates set at minimum amounts per ton or as percentages of sales realization. Shoal Creek Mine’s largest lease agreement, representing 28,517 acres of mineral control, expires in 2031 with an option to negotiate an extension. The expiration dates vary for other leases, but typically include extension provisions. As of December 31, 2021, all required licenses and permits were in place for the operations of the Shoal Creek Mine. For additional information regarding mineral rights and permitting, refer to sections 3 and 17 in Exhibit 96.2.
Coal is produced primarily using longwall systems. The mine also uses continuous miner units for longwall development and limited production. Mined coal is processed through a wash plant, conveyed to barge loadout facilities on the Black Warrior River, and transported by barge 370 miles to McDuffie Coal Terminal in Mobile Bay, Alabama, in the Gulf of Mexico, for export via ocean-going vessels. Shoal Creek Mine metallurgical coal has a well-established customer base in Europe, South America, and East Asia for steel making. For additional information regarding mining and processing methods, refer to sections 13 and 14 in Exhibit 96.2.
The key supporting infrastructure for Shoal Creek Mine includes road access via interstate and state highways and roads, third-party barge services and a barge loadout on the Black Warrior River, the McDuffie Coal Terminal, electrical power provided by 69kV transmission lines, and water supplied from the Black Warrior River and recycled underground water. The mine’s workforce is drawn primarily from Jasper and Tuscaloosa, Alabama and other adjacent communities. For additional information regarding the mine’s infrastructure, refer to section 15 in Exhibit 96.2.
Peabody Energy Corporation 2021 Form 10-K
The property, plant, equipment and mine development assets of Shoal Creek Mine had a net book value of approximately $296 million at December 31, 2021. The mine’s operating equipment and facilities meet contemporary mining standards and are adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. While the mine was idled for parts of 2020 and 2021, the Company upgraded the mine’s coal handling and preparation plant and made other capital investments to improve its prospective cost structure. For additional information regarding capital and equipment, refer to sections 13 and 18 in Exhibit 96.2.
The tables below present Shoal Creek Mine’s estimated coal reserves and resources at December 31, 2021, along with comparative quantities for coal reserves at December 31, 2020. These reserve and resource estimates were supported by the analyses of 1,178 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves and resources are estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on a dry basis. For additional information regarding coal reserve and resource estimates, refer to sections 11 and 12 in Exhibit 96.2.
SHOAL CREEK MINE - SUMMARY OF RESERVES AND RESOURCES (1)
(Tons in millions)
December 31, 2021 December 31, 2020
Coal Reserves (2)(4)(5)(6)
Tons %Ash %Sulfur %VM % Mine Yield (7)
Tons
Proven 16 10.2 0.7 30.4 46% 51
Probable 2 10.2 0.7 30.3 46% 1
Total 18 52
Year-over-year decrease -65%
December 31, 2021
Coal Resources (2)(3)(4)(5)
Tons %Ash %Sulfur VM%
Measured 40 9.6 0.7 25.1
Indicated 35 9.9 0.7 24.1
Measured and indicated 75 9.8 0.7 24.6
Inferred 7 10.3 0.7 24.0
Total 82
The year-over-year decrease in coal reserves reflects 2021 production depletion and the reclassification of certain mine areas to resources until further drilling and studies are completed. Refer to section 19 of Exhibit 96.2 for additional information.
(1)
Economic recoverability is based upon an estimated average sales price per ton of $125.37 for the five-year period ending December 31, 2026 and assumed escalation of 2.8% per annum during the subsequent period through the end of the LOM plan. Refer to section 19 of Exhibit 96.2 for detailed price assumptions.
(2)
The quality of coal reserves and resources are estimated on a dry basis.
(3)
The quantity of resource estimates are on an in situ basis, which doesn’t take into consideration coal loss during mining and processing.
(4)
The coal resource boundary is established by considering various factors, including results from drill hole analyses, coal control, geological features, faults and other surface features.
(5)
The cut-off grade and metallurgical recovery are not limiting factors for the reserve and resource estimates due to relatively consistent coal quality and float recovery from the lab results within the assessed area. The historically mined coal thickness has been used as the main criteria for the resource boundary based on the mine’s actual performance in the last two decades.
(6)
The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration of unmined coal (pillars, etc.), 20% coal loss during mining and processing, and additional washing recovery. The results from the LOM planning process demonstrate the economic recoverability of the coal reserve estimate. Refer to section 19 of Exhibit 96.2 for economic analysis.
(7)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
Peabody Energy Corporation 2021 Form 10-K
Wilpinjong Mine
The Wilpinjong Mine is a production-stage surface thermal coal mine situated approximately 25 miles northeast of Mudgee in New South Wales, Australia. Peabody acquired the mine as part of its acquisition of Excel Coal Pty Ltd (Excel) in 2006. Excel began the development of Wilpinjong Mine in 2006 and it commenced production under Peabody ownership in 2007. A third-party contactor managed mining operations until 2013, when the Company converted the mine to owner-operated.
The Wilpinjong Mine extracts coal from the Moolarben and Ulan coal seams which have a combined thickness from 6 to 10 meters and a typical depth less than 60 meters in the Illawarra Coal Measures on the northwest margin of the Sydney Basin. The Company secured two exploration licenses of 1,518 hectares and three mining licenses of 3,723 hectares through the New South Wales Minister of Planning. The typical royalty rate is 8.2% of the value of coal recovered. The mining licenses require renewal upon expiration in 2027 for 2,863 hectares and in 2039-2040 for 860 acres. The renewal application for two exploration licenses is currently pending approval. As of December 31, 2021, all required licenses and permits were in place for the operations of Wilpinjong. For additional information regarding mineral rights and permitting, refer to sections 3 and 17 in Exhibit 96.3.
Conventional open cut mining methods are used at the Wilpinjong Coal Mine, with multiple pits at a low strip ratio allowing for relatively rapid pit advance. Overburden is removed by a combination of cast blasting, doze, and truck and shovel methods. Haul trucks transport coal to various hoppers and pads for blending and temporary storage, as necessary, and then to a coal handling and processing plant to be crushed and washed. Coal is conveyed to a rail loadout and transported by train to either domestic customers or to the Port of Newcastle and seaborne customers for thermal power generation. For additional information regarding mining and processing methods, refer to sections 13 and 14 in Exhibit 96.3.
The key supporting infrastructure for Wilpinjong Mine includes road access via public roads, port service at two terminals at the Port of Newcastle, above and below rail services, electrical power from a 66kV transmission line, and water supply from captured surface runoff and deep wells. The mine’s proximity to other large coal producers in the region provides access to a significant pool of experienced mining personnel. For additional information regarding the mine’s infrastructure, refer to section 15 in Exhibit 96.3.
Peabody Energy Corporation 2021 Form 10-K
The property, plant, equipment and mine development assets of Wilpinjong Mine had a net book value of approximately $386 million at December 31, 2021. The mine’s operating equipment meets contemporary mining standards and is adequately maintained to execute the LOM plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. During 2018, the Company began an expansion project at Wilpinjong Mine that will extend the mine life from 2026 to 2030 and allow higher annual production rates through access to an additional 55 million tonnes of coal reserves. The Company capitalized approximately $61 million related to the project through December 31, 2021 and expects the total cost to reach approximately $74 million. For additional information regarding capital and equipment, refer to sections 13 and 18 in Exhibit 96.3.
The tables below present Wilpinjong Mine’s estimated coal reserves and resources at December 31, 2021, along with comparative quantities of coal reserves at December 31, 2020. These reserve and resource estimates were supported by the analyses of 1,271 total drill holes within the coal lease area. The quantity of the coal resources is estimated on an in situ basis as 100% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as 100% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dried basis. For additional information regarding coal reserve and resource estimates, refer to sections 11 and 12 in Exhibit 96.3.
WILPINJONG MINE - SUMMARY OF RESERVES AND RESOURCES (1)
(Tons in millions)
December 31, 2021 December 31, 2020
Coal Reserves (5)(6)
Tons %Ash %Sulfur Kcal/kg % Mine Yield(7)
Tons
Proven 71 24.3 0.5 5,940 81% 91
Probable 5 29.7 0.4 5,478 95% 2
Total 76 93
Year-over-year decrease -18%
December 31, 2021
Coal Resources (2)(3)(4)
Tons %Ash %Sulfur Kcal/kg
Measured 103 23.0 0.5 6,042
Indicated 25 25.4 0.5 5,851
Measured and indicated 128 23.5 0.5 6,004
Inferred 6 27.3 0.5 5,707
Total 134
The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
(1)
Economic recoverability is based upon product-specific estimated average sales prices per tonne of $39.18 to $47.98 for the five-year period ending December 31, 2026 and assumed escalation of 2.5% to 3.0% per annum during the subsequent period through the end of the LOM plan. Refer to section 19 of Exhibit 96.3 for detailed price assumptions.
(2)
The quality of coal resources is on an in situ, air-dry basis.
(3)
The quantity of coal resource estimates is on an in situ basis, which does not take into consideration coal loss during mining and processing.
(4)
Besides the results from drill hole analyses, the raw ash is a key quality parameter that is relevant to both the cut-off grade and metallurgical recovery. The resource is limited by a maximum of 50% raw ash (air-dry basis). Due to the relatively consistent coal thickness and shallow depth, no other geological limiting factors are applied except for known geological anomalies such as paleochannels and igneous intrusion.
(5)
The quality of coal reserves is based on an air-dry basis. It is the laboratory results from the core samples with adjustments that reflect the reconciliation results from actual production.
(6)
The quantity of coal reserves is estimated on a saleable product basis, which takes into consideration of mining and processing loss. The economic results from the LOM planning process demonstrate the economic viability of the coal reserve estimate. Refer to section 19 of Exhibit 96.3 for economic analysis.
(7)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
Peabody Energy Corporation 2021 Form 10-K
Coppabella-Moorvale Joint Venture
The Company’s Coppabella Moorvale Joint Venture (CMJV) mines are located approximately 75 miles southwest of Mackay, near the township of Coppabella, in central Queensland, Australia. The CMJV includes two production-stage surface coal mines, the Coppabella Mine and the Moorvale Mine, and one surface coal mine under development, Moorvale South. Peabody owns 73.3% of the joint venture and is responsible for operations management. CMJV originally was developed by Macarthur Coal Limited (Macarthur), with production commencing in 1998 at Coppabella Mine and 2002 at Moorvale Mine. Peabody acquired Macarthur in December 2011 and assumed its majority interest in CMJV.
The CMJV mines primarily extract coal from the Leichardt seam in the Rangal Coal Measures of the Bowen Basin. The seam has a thickness from 5 to 10 meters and a typical depth of less than 250 meters. A portion of the Vermont seam is expected to be economically mineable at Moorvale South, once developed. The CMJV mines operate with a total of fourteen mining leases and one mineral development license issued by the Queensland state government, covering 13,459 hectares in total. Coal production is subject to royalties payable to the Queensland state government ranging from 7% to 15% of realized revenue, depending upon the lease. In addition, there are special private royalty agreements established in relation to exploration efforts. The primary mining leases for the Coppabella Mine expire in 2040 and other peripheral leases expire between 2023 and 2035. The Moorvale Mine has two mining leases which expire in 2023, and a third in 2028. The proposed Moorvale South mine has two mining leases which expire in 2030, and its relevant mineral development license expires in 2024. As of December 31, 2021, all required licenses and permits were in place for the operations of CMJV. For additional information regarding mineral rights and permitting, refer to sections 3 and 17 in Exhibit 96.4.
Conventional open cut mining methods are used at the CMJV mines. Coppabella Mine utilizes a dragline and two electric rope shovels to perform the majority of overburden removal, supplemented by diesel hydraulic excavators, which are also used to extract coal. Moorvale Mine utilizes only diesel hydraulic excavators for overburden removal. Both mines utilize cast and dozer push operations where applicable. Coal is trucked via internal haul roads for direct dumping to the hopper, or rehandled from pads to the dump hopper. Coal is crushed and washed at two processing plants, then transported by rail to the Dalrymple Bay Coal Terminal for seaborne customers. The CMJV produces a range of products including pulverized coal injection coal, coking coal and thermal coal. For additional information regarding mining and processing methods, refer to sections 13 and 14 in Exhibit 96.4.
Peabody Energy Corporation 2021 Form 10-K
The key supporting infrastructure for CMJV includes the port service at Dalrymple Bay Coal Terminal, above and below rail services, road access via public roads, electrical power from 66kV transmission lines, and water supply from captured surface runoff and commercial pipelines. Temporary housing near the mine sites provides employees with overnight accommodations, as necessary. The mines draw personnel primarily from nearby Moranbah, Nebo and Mackay, Queensland. For additional information regarding the mine’s infrastructure, refer to section 15 in Exhibit 96.4.
The property, plant, equipment and mine development assets of CMJV had a net book value of approximately $170 million at December 31, 2021. The CMJV’s operating equipment meets contemporary mining standards and is adequately maintained to execute the mine plan. Routine maintenance, overhauls and necessary capital replacements are generally included in the LOM plan to support future production. For additional information regarding capital and equipment, refer to sections 13 and 18 in Exhibit 96.4.
The tables below present estimates of the CMJV coal reserves and resources as of December 31, 2021, along with comparative quantities of coal reserves at December 31, 2020. These reserve and resource estimates were supported by the analyses of 4,763 total drill holes within the coal lease areas. The quantity of the coal resources is estimated on an in situ basis as 73.3% attributable to Peabody. Coal resources are reported exclusive of coal reserves. The quantity of the coal reserves is estimated on a saleable product basis as 73.3% attributable to Peabody. Coal reserves and resources are reported on selected key quality parameters on an air-dry basis. For additional information regarding coal reserve and resource estimates, refer to sections 11 and 12 in Exhibit 96.4.
CMJV - SUMMARY OF RESERVES AND RESOURCES (1)
(Tons in millions)
December 31, 2021 December 31, 2020
Coal Reserves (5)(6)
Tons %Ash %Sulfur %VM % Mine Yield (7)
Tons
Proven 14 9.8 0.3 13.1 76% 21
Probable 6 9.5 0.3 11.8 70% 13
Total 20 34
Year-over-year decrease -41%
December 31, 2021
Coal Resources (2)(3)(4)
Tons %Ash %Sulfur VM%
Measured 34 17.4 0.3 15.5
Indicated 69 15.3 0.3 14.1
Measured and indicated 103 16.0 0.3 14.6
Inferred 84 15.6 0.3 12.9
Total 187
The decrease in reserves reflects 2021 production depletion and reclassification of certain mine areas to resources until further drilling and studies are completed.
Peabody Energy Corporation 2021 Form 10-K
(1)
Economic recoverability is based upon product-specific estimated average sales prices per tonne of $107.61 to $116.49 for the five-year period ending December 31, 2026 and assumed escalation of 2.5% per annum during the subsequent period through the end of the LOM plan. Refer to section 19 of Exhibit 96.4 for detailed price assumptions.
(2)
The quality of coal resources is estimated on an in situ, air-dry basis.
(3)
The quantity of coal resource is estimated on an in situ basis, which doesn’t take into consideration coal loss during mining and processing.
(4)
Besides the results from drill hole analyses, the resource estimates are based on the following criteria:
- Open cut resources are limited to an area defined by pit shell with RF150 (revenue factor 150%), with exception of Moorvale South MDL 3034 open cut resources are limited to 150m depth of cover
- Minimum mining thickness of 0.3m for open cut
- Minimum mining thickness of 2m for underground resources
- Underground resources excluded in areas of seam dip exceeding 15 degrees
- Underground resources depth cutoff at 500m depth of cover, with exception of Moorvale Mine depth cutoff at 300m depth of cover
- A seam quality cut-off greater than 50% raw ash (a.d.) is excluded from resources
- No weathered coal included
- Intrusive sills and dykes within seams are excluded from the resources
- Heat-affected coal is included in the resources
- Other limiting factors include surface infrastructure and lease boundary
(5)
The quality of coal reserves is estimated on an air-dry basis.
(6)
The quantity of coal reserves is estimated on a saleable product basis which takes into consideration of mining and processing loss. The economic results from the LOM planning process demonstrate the economic viability of the coal reserve estimate. Refer to section 19 of Exhibit 96.4 for economic analysis.
(7)
Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered.
Internal Controls
The preparation of coal reserve and resource estimates is completed in accordance with the Company’s prescribed internal control procedures, which are designed specifically to ensure the reliability of such estimates presented herein. Annually, QPs and other employees review the estimates of mineral reserves and mineral resources, the supporting documentation, and compliance with applicable internal controls. Such controls employ management systems, standardized procedures, workflow processes, multi-functional supervision and management approval, internal and external reviews, reconciliations, and data security covering record keeping, chain of custody and data storage.
The internal controls for reserve and resource estimates also cover exploration activities, sample preparation and analysis, data verification, processing, metallurgical testing, recovery estimation, mine design and sequencing, and reserve and resource evaluations, with environmental, social and regulatory considerations. The quality assurance and control protocols over the assaying of drill hole samples are performed by reputable commercial laboratories following certification and accreditation programs established by the American Society for Testing and Materials (ASTM) or Australian National Association of Testing Authorities (NATA).
The reserve and resource estimates have inherent risks due to data accuracy, uncertainty from geological interpretation, mine plan assumptions, uncontrolled rights for mineral and surface properties, environmental challenges, uncertainty for future market supply and demand, and changes in laws and regulations. Management and QPs are aware of those risks that might directly impact the assessment of coal reserves and resources. The current coal reserves and resources are estimated based on the best information available and are subject to re-assessment when conditions change. Refer to Item 1A. “Risk Factors” for discussion of risks associated with the estimates of the Company’s reserves and resources.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
See Note 23. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of Peabody’s pending legal proceedings, which information is incorporated herein by reference.
Peabody Energy Corporation 2021 Form 10-K

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Peabody’s “Safety and Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and environmental stewardship across the Company’s business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, risk management and assurance. Peabody also partners with other companies and certain governmental agencies to pursue new technologies that have the potential to improve its safety performance and provide better safety protection for employees.
Peabody continually monitors its safety performance and regulatory compliance. The information concerning mine safety violations or other regulatory matters required by SEC regulations is included in Exhibit 95 to this Annual Report on Form 10-K.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Peabody’s Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 11, 2022 there were 152 holders of the Company’s Common Stock, as determined by counting its record holders and the number of participants reflected in a security position listing provided to the Company by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of Peabody’s Common Stock on behalf of their customers, the Company does not know the actual number of unique shareholders represented by these record holders.
Dividends
The Company declared and paid quarterly dividends every quarter in 2019, and a supplemental dividend was declared and paid during the first quarter of 2019. The Company suspended dividends in 2020. As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020, the Company entered into a transaction support agreement with its surety bond providers which prohibits the payment of dividends through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in its credit facility and in the indentures governing its senior secured notes also limit the Company's ability to pay cash dividends.
Share Relinquishments
The Company routinely allows employees to relinquish Common Stock to pay estimated taxes upon the vesting of restricted stock units and the payout of performance units that are settled in Common Stock under its equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of the Company’s Common Stock on the dates of the respective relinquishments.
Share Repurchase Program
On August 1, 2017, the Company announced that its Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of its common stock and/or preferred stock (Repurchase Program), which was eventually expanded to $1.5 billion during 2018. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2021, the Company has repurchased 41.5 million shares of its Common Stock for $1,340.3 million, which included commissions paid of $0.8 million, leaving $160.5 million available for share repurchase under the Repurchase Program.
The Company suspended share repurchases in 2019, and similar to the payment of dividends as described above, the same agreements with its surety bond providers prohibit share repurchases through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in its credit facility and in the indentures governing its senior secured notes also limit the Company’s ability to repurchase shares. Prior to the suspension, repurchases were made at the Company’s discretion. The specific timing, price and size of purchases depended upon the share price, general market and economic conditions and other considerations, including compliance with various debt agreements in effect at the time the repurchases were made.
Peabody Energy Corporation 2021 Form 10-K
Issuances of Equity Securities
In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its Common Stock. The at-the-market equity offering program was further expanded to 32.5 million shares during 2021. The shares are offered and sold pursuant to the Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by prospectus supplements dated June 4, 2021, September 17, 2021, and December 17, 2021 relating to the offer and sale of the shares. During the year ended December 31, 2021, the Company sold approximately 24.8 million shares for net cash proceeds of $269.8 million.
Also during the year ended December 31, 2021, the Company completed multiple bilateral transactions with holders of the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes in which the Company issued an aggregate 10.0 million shares of its Common Stock in exchange for $37.3 million aggregate principal amount of the 2022 Notes, $47.2 million aggregate principal amount of the 2025 Notes and $21.6 million aggregate principal amount of the 2024 Peabody Notes. The issuance of shares of common stock in exchange for the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes was made in reliance on the exemption from registration provided in Section 3(a)(9) under the Securities Act of 1933, based in part on representations of holders of the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes, and on the basis that the exchange was completed with existing holders of the Company's securities and no commission or other remuneration was paid or given for soliciting the exchange.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended December 31, 2021:
Period Total Number of Shares
Purchased (1)
Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program Maximum Dollar Value of Shares that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions)
October 1 through October 31, 2021
546 $ 15.65 - $ 160.5
November 1 through November 30, 2021
- - - 160.5
December 1 through December 31, 2021
- - - 160.5
Total
546 15.65 -
(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program.
Stock Performance Graph
The following performance graph compares the cumulative total return on Peabody’s common stock from April 4, 2017, the date its common stock began trading following the effective date of its plan of reorganization, through December 31, 2021, with the cumulative total return of the following indices: (i) the S&P MidCap 400 Stock Index and (ii) Custom Composite Index (a peer group comprised of Arch Resources, Inc., Hallador Energy Co., and Warrior Met Coal, Inc.). The Custom Composite Index reflects publicly listed U.S. companies within the coal industry of similar size or product type.
The graph assumes that the value of the investment was $100 at April 4, 2017 for BTU and the Custom Composite Index (Warrior Met Coal, Inc. began trading on the New York Stock Exchange on April 13, 2017) and at March 31, 2017, for the S&P Midcap 400 Index. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2021.
These indices are included for comparative purposes only and do not necessarily reflect management's opinion that such indices are an appropriate measure of the relative performance of the stock involved and are not intended to forecast or be indicative of possible future performance of the common stock.
Peabody Energy Corporation 2021 Form 10-K

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved.
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The Company’s discussion and analysis of the year ended December 31, 2021 compared to the year ended December 31, 2020 is included herein. For discussion and analysis of the year ended December 31, 2020 compared to the year ended December 31, 2019, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Peabody’s Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 23, 2021 and is incorporated by reference herein.
Non-GAAP Financial Measures
The following discussion of Peabody’s results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of its segments’ operating performance.
Peabody Energy Corporation 2021 Form 10-K
Also included in the following discussion of Peabody’s results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of its mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7.
In its discussion of liquidity and capital resources, Peabody includes references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of its financial performance and its ability to generate excess cash flow from its business operations.
Peabody believes non-GAAP performance measures are used by investors to measure its operating performance and lenders to measure its ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 7 for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Overview
In 2021, Peabody produced and sold 126.9 million and 130.1 million tons of coal, respectively, from continuing operations.
As of December 31, 2021, the Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining and Corporate and Other.
The business of the Company’s seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of its thermal and metallurgical coal sold within Australia. Generally, revenues from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. The Company classifies its seaborne mines within the Seaborne Thermal Mining or Seaborne Metallurgical Mining segments based on the primary customer base and coal reserve type of each mining operation. A small portion of the coal mined by the Seaborne Thermal Mining segment is of a metallurgical grade. Similarly, a small portion of the coal mined by the Seaborne Metallurgical Mining segment is of a thermal grade. Additionally, the Company may market some of its metallurgical coal products as a thermal coal product from time to time depending on market conditions.
The Company’s Seaborne Thermal Mining operations consist of mines in New South Wales, Australia. The mines in that segment utilize both surface and underground extraction processes to mine low-sulfur, high Btu thermal coal.
The Company’s Seaborne Metallurgical Mining operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama, USA. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and pulverized coal injection coal.
The principal business of the Company’s thermal mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a relatively small portion sold as international exports as conditions warrant. The Company’s Powder River Basin Mining operations consist of its mines in Wyoming. The mines in that segment are characterized by surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). The Company’s Other U.S. Thermal Mining operations historically reflect the aggregation of its Illinois, Indiana, New Mexico and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, the Company’s Powder River Basin Mining operations mine sub-bituminous coal deposits and its Other U.S. Thermal Mining operations mine both bituminous and sub-bituminous coal deposits.
The Company’s Corporate and Other segment includes selling and administrative expenses, results from equity affiliates, corporate hedging activities, trading and brokerage activities, minimum charges on certain transportation-related contracts, the closure of inactive mining sites and certain commercial matters.
Peabody Energy Corporation 2021 Form 10-K
Resource Management. As of December 31, 2021, Peabody controlled approximately 2.5 billion tons of proven and probable coal reserves, 2.4 billion tons of resources and approximately 400,000 acres of surface property through ownership and lease agreements. The Company has an ongoing asset optimization program whereby its property management group regularly reviews these reserves, resources and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves, resources and surface lands. These surface lands include acres where Peabody has completed post-mining reclamation. In addition, the Company generates revenue through royalties from coal reserves and oil and gas rights leased to third parties and farm income from surface lands under third-party contracts.
Middlemount Mine. Peabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and low-volatile pulverized coal injection (LV PCI) coal for sale into seaborne coal markets through Abbot Point Coal Terminal, with some capacity also secured at Dalrymple Bay Coal Terminal. Mining operations first commenced at the Middlemount Mine in late 2011. During the years ended December 31, 2021 and 2020, the mine sold 2.0 million and 1.6 million tons of coal, respectively (on a 50% basis).
Summary
Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the year ended December 31, 2021 is set forth in the table below.
The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the year ended December 31, 2021 due to quality differentials and the majority of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a bi-annual, quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the year ended December 31, 2021 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. 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. Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company’s realized pricing.
High Low Average December 31, 2021
Premium HCC (1)
$ 408.50 $ 99.50 $ 226.24 $ 357.25
Premium PCI coal (1)
$ 290.00 $ 91.50 $ 164.34 $ 244.00
Newcastle index thermal coal (1)
$ 253.55 $ 80.78 $ 137.95 $ 165.86
API 5 thermal coal (1)
$ 170.90 $ 50.75 $ 82.59 $ 101.68
PRB 8,800 Btu/Lb coal (2)
$ 37.00 $ 11.85 $ 17.70 $ 29.00
Illinois Basin 11,500 Btu/Lb coal (2)
$ 92.00 $ 29.75 $ 51.95 $ 88.00
(1) Prices expressed per metric tonne.
(2) Prices expressed per short ton.
Within the global coal industry, supply and demand disruptions were widespread as the coronavirus (COVID-19) pandemic forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19. The global coal industry data for the year ended December 31, 2021 presented herein may not be indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration.
Peabody Energy Corporation 2021 Form 10-K
Within the seaborne metallurgical coal market, a combination of robust steel production, decade-high steel margins and tight coal availability have driven Australian spot prices to record levels. The year ended December 31, 2021 saw China’s unofficial ban on Australian coal remain in place and several countries such as India, Brazil and Vietnam achieve record annual import volumes of seaborne metallurgical coal. China’s unofficial ban on Australian coal has caused a redistribution of trade flows with Australian suppliers increasing market share in Europe, South America, India and North Asia while other suppliers targeted China, incentivized by a significant price advantage. However, recent measures introduced by China to reduce steel production and increase domestic coal output have temporarily dampened seaborne demand and driven delivered China prices in line with or below the rest of the market. Despite this, supply availability remains exceedingly tight with the spread of COVID-19 and weather impacts in Australia, Canada, Mongolia and Russia. The Company believes energy shortages in some markets present a risk to industrial activity but the underlying market fundamentals remain constructive.
Within the seaborne thermal coal market, Newcastle thermal coal prices remained elevated for the year ended December 31, 2021, compared to the prior year, driven by a combination of tight supplies and elevated demand. China’s domestic thermal coal supply was hampered by heightened safety inspections and mine suspensions through much of the year. Thermal electricity generation in China was strong for the year ended December 31, 2021, and the relaxation of China’s import controls combined with tight domestic supply pushed import demand higher for the year. In Europe, gas supply constraints have pushed standby coal plants to resume operation to help supply strong electricity demand. Despite the strong demand, the supply response has been muted from key exporters such as Australia, Colombia and South Africa, keeping thermal coal prices elevated.
In the United States, overall electricity demand increased 3% year-over-year, positively impacted by weather and the prior year economic impacts of the COVID-19 pandemic. Electricity generation from thermal coal has notably improved year-over-year as a result of higher natural gas prices and stronger overall electricity demand. This has positively impacted coal’s share of electricity generation for the year ended December 31, 2021, with a rise to approximately 22% compared to approximately 19% in the prior year, while causing natural gas’s share to decline to approximately 38% compared to approximately 40% in the prior year. Stronger coal use and a limited supply response in coal production has contributed to decreasing coal stockpile levels. Since December 2020, coal inventories have fallen by approximately 38 million tons, a 29% decline. Through the year ended December 31, 2021, utility consumption of PRB coal rose approximately 22% compared to the prior year period.
Other
Peabody’s North Goonyella Mine in Queensland, Australia experienced a fire in 2018 which resulted in the suspension of mining operations. In 2020, the Company commenced a review of strategic alternatives for North Goonyella which is currently ongoing. During the years ended December 31, 2019 and 2018, Peabody recorded provisions for equipment losses of $83.2 million and $66.4 million, respectively, related to the fire. The Company has also incurred containment and idling costs subsequent to the mine’s suspension which amounted to $13.0 million, $32.3 million and $111.5 million during the years ended December 31, 2021, 2020 and 2019, respectively.
In March 2019, Peabody entered into an insurance claim settlement agreement with its insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. The Company collected the settlement in 2019.
Results of Operations
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020
Peabody’s revenues for the year ended December 31, 2021 increased compared to the same period in 2020 ($437.2 million) primarily due to the impacts of higher seaborne thermal and metallurgical pricing, partially offset by lower seaborne volumes and net unrealized mark-to-market losses on derivative contracts related to forecasted sales and other financial trading.
Results from continuing operations, net of income taxes for the year ended December 31, 2021 increased compared to the same period in the prior year ($2,207.2 million) primarily due to the asset impairment charges recorded in the prior year ($1,487.4 million), the favorable revenue variance described above and improved results from equity affiliates ($142.2 million).
Adjusted EBITDA for the year ended December 31, 2021 reflected a year-over-year increase of $657.9 million.
As of December 31, 2021, Peabody’s available liquidity was approximately $996 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of factors affecting the Company’s available liquidity.
Peabody Energy Corporation 2021 Form 10-K
Tons Sold
The following table presents tons sold by operating segment:
(Decrease) Increase
Year Ended December 31, to Volumes
2021 2020 Tons %
(Tons in millions)
Seaborne Thermal Mining 17.3 19.0 (1.7) (8.9) %
Seaborne Metallurgical Mining 5.5 5.6 (0.1) (1.8) %
Powder River Basin Mining 88.4 87.2 1.2 1.4 %
Other U.S. Thermal Mining 16.9 18.3 (1.4) (7.7) %
Total tons sold from mining segments 128.1 130.1 (2.0) (1.5) %
Corporate and Other 2.0 2.5 (0.5) (20.0) %
Total tons sold 130.1 132.6 (2.5) (1.9) %
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Year Ended December 31, Increase (Decrease)
2021 2020 $ %
Revenues per Ton - Mining Operations (1)
Seaborne Thermal $ 54.09 $ 37.46 $ 16.63 44.4 %
Seaborne Metallurgical 131.83 86.33 45.50 52.7 %
Powder River Basin 10.99 11.37 (0.38) (3.3) %
Other U.S. Thermal 40.75 38.73 2.02 5.2 %
Costs per Ton - Mining Operations (1) (2)
Seaborne Thermal $ 33.64 $ 28.87 $ 4.77 16.5 %
Seaborne Metallurgical 99.55 109.44 (9.89) (9.0) %
Powder River Basin 9.46 9.14 0.32 3.5 %
Other U.S. Thermal 31.04 29.51 1.53 5.2 %
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2)
Seaborne Thermal $ 20.45 $ 8.59 $ 11.86 138.1 %
Seaborne Metallurgical 32.28 (23.11) 55.39 239.7 %
Powder River Basin 1.53 2.23 (0.70) (31.4) %
Other U.S. Thermal 9.71 9.22 0.49 5.3 %
(1)This is an operating/statistical measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.
Peabody Energy Corporation 2021 Form 10-K
Revenues
The following table presents revenues by reporting segment:
Increase (Decrease)
Year Ended December 31, to Revenues
2021 2020 $ %
(Dollars in millions)
Seaborne Thermal Mining $ 934.0 $ 711.8 $ 222.2 31.2 %
Seaborne Metallurgical Mining 727.7 486.5 241.2 49.6 %
Powder River Basin Mining 971.2 991.1 (19.9) (2.0) %
Other U.S. Thermal Mining 689.1 707.3 (18.2) (2.6) %
Corporate and Other (3.7) (15.6) 11.9 76.3 %
Revenues $ 3,318.3 $ 2,881.1 $ 437.2 15.2 %
Seaborne Thermal Mining. The increase in segment revenues during the year ended December 31, 2021 compared to the prior year was due to favorable realized coal pricing ($280.8 million), partially offset by unfavorable volume and mix variances ($58.6 million).
Seaborne Metallurgical Mining. Segment revenues increased during the year ended December 31, 2021 compared to the prior year due to favorable realized coal pricing ($257.7 million), partially offset by unfavorable volume and mix variances ($16.5 million).
Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2021 compared to the prior year primarily due to unfavorable realized coal pricing ($27.6 million), offset by increased demand ($7.7 million).
Other U.S. Thermal Mining. The decrease in segment revenues during the year ended December 31, 2021 compared to the prior year was primarily due to lower volumes ($64.3 million), offset by favorable realized pricing ($46.1 million).
Corporate and Other. Segment revenues increased during the year ended December 31, 2021 compared to the prior year due to primarily due to higher results from trading activities ($88.9 million), partially offset by net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales and other financial trading ($79.2 million).
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of the Company’s reporting segments:
Increase (Decrease) to
Year Ended December 31, Adjusted EBITDA
2021 2020 $ %
(Dollars in millions)
Seaborne Thermal Mining $ 353.1 $ 163.2 $ 189.9 116.4 %
Seaborne Metallurgical Mining 178.2 (130.2) 308.4 236.9 %
Powder River Basin Mining 134.9 194.8 (59.9) (30.7) %
Other U.S. Thermal Mining 164.2 168.4 (4.2) (2.5) %
Corporate and Other 86.3 (137.4) 223.7 162.8 %
Adjusted EBITDA (1)
$ 916.7 $ 258.8 $ 657.9 254.2 %
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Seaborne Thermal Mining. Segment Adjusted EBITDA increased during the year ended December 31, 2021 compared to the same period in the prior year as a result of higher realized net coal pricing ($258.7 million) and product mix ($27.7 million). The increases were partially offset by unfavorable volume variances ($51.8 million), unfavorable foreign currency impacts ($31.5 million) and higher commodity pricing ($10.5 million).
Seaborne Metallurgical Mining. Segment Adjusted EBITDA increased during the year ended December 31, 2021 compared to the same period in the prior year due to higher realized net coal pricing ($238.7 million), cost improvements across the operations ($80.7 million) and favorable volume variances ($26.8 million), offset by unfavorable foreign currency impacts ($41.8 million).
Peabody Energy Corporation 2021 Form 10-K
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2021 compared to the same period in the prior year due to the unfavorable impacts of higher commodity pricing ($28.4 million), lower realized net coal pricing ($23.0 million), higher costs for materials, services and repairs ($14.1 million) and unfavorable volume and mix variances ($12.6 million). The decreases were partially offset by favorable mine sequencing impacts ($11.9 million) and lower leasing costs ($6.3 million).
Other U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2021 compared to the same period in the prior year due to higher costs for materials, services and repairs ($28.9 million) and higher commodity pricing ($23.7 million), offset by higher realized net coal pricing ($43.9 million) and favorable mine sequencing impacts ($7.5 million).
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
Increase (Decrease)
Year Ended December 31, to Income
2021 2020 $ %
(Dollars in millions)
Middlemount (1)
$ 48.2 $ (29.2) $ 77.4 265.1 %
Resource management activities (2)
6.9 15.3 (8.4) (54.9) %
Selling and administrative expenses
(84.9) (99.5) 14.6 14.7 %
Other items, net (3)
116.1 (24.0) 140.1 583.8 %
Corporate and Other Adjusted EBITDA $ 86.3 $ (137.4) $ 223.7 162.8 %
(1)Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference. Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $73.8 million and $29.9 million during the years ended December 31, 2021 and 2020, respectively.
(2)Includes gains (losses) on certain surplus coal reserve, resource and surface land sales and property management costs and revenues.
(3)Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the North Goonyella Mine and expenses related to other commercial activities.
The increase in Corporate and Other Adjusted EBITDA during the year ended December 31, 2021 compared to the same period in the prior year was due to favorable trading results ($63.7 million); the gain recognized in the current year on the sale of the Company’s Millennium Mine ($26.1 million) as discussed in Note 19. “Other Events”; a favorable variance in Middlemount’s results due to the combined impacts of higher sales pricing, improved production, cost improvements and the insurance settlement attributable to a business interruption and property damage claim from 2019; lower postretirement health care costs ($38.5 million) primarily due to changes made to the Company’s postretirement health care benefit plans announced in 2021 and 2020; and lower containment and holding costs for the Company’s North Goonyella Mine ($19.3 million).
Peabody Energy Corporation 2021 Form 10-K
Income (Loss) From Continuing Operations, Net of Income Taxes
The following table presents income (loss) from continuing operations, net of income taxes:
Increase (Decrease) to Income
Year Ended December 31,
2021 2020 $ %
(Dollars in millions)
Adjusted EBITDA (1)
$ 916.7 $ 258.8 $ 657.9 254.2 %
Depreciation, depletion and amortization
(308.7) (346.0) 37.3 10.8 %
Asset retirement obligation expenses (44.7) (45.7) 1.0 2.2 %
Restructuring charges (8.3) (37.9) 29.6 78.1 %
Transaction costs related to joint ventures - (23.1) 23.1 100.0 %
Asset impairment - (1,487.4) 1,487.4 100.0 %
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates
33.8 (30.9) 64.7 209.4 %
Interest expense (183.4) (139.8) (43.6) (31.2) %
Net gain on early debt extinguishment 33.2 - 33.2 n.m.
Interest income 6.5 9.4 (2.9) (30.9) %
Net mark-to-market adjustment on actuarially determined liabilities
43.4 5.1 38.3 751.0 %
Unrealized losses on derivative contracts related to forecasted sales (115.1) (29.6) (85.5) (288.9) %
Unrealized (losses) gains on foreign currency option contracts (7.5) 7.1 (14.6) (205.6) %
Take-or-pay contract-based intangible recognition 4.3 8.2 (3.9) (47.6) %
Income tax provision
(22.8) (8.0) (14.8) (185.0) %
Income (loss) from continuing operations, net of income taxes $ 347.4 $ (1,859.8) $ 2,207.2 118.7 %
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment:
(Decrease) Increase
Year Ended December 31, to Income
2021 2020 $ %
(Dollars in millions)
Seaborne Thermal Mining $ (107.7) $ (88.0) $ (19.7) (22.4) %
Seaborne Metallurgical Mining
(73.3) (85.4) 12.1 14.2 %
Powder River Basin Mining (41.5) (85.3) 43.8 51.3 %
Other U.S. Thermal Mining (67.4) (72.1) 4.7 6.5 %
Corporate and Other
(18.8) (15.2) (3.6) (23.7) %
Total $ (308.7) $ (346.0) $ 37.3 10.8 %
Additionally, the following table presents a summary of the Company’s weighted-average depletion rate per ton for active mines in each of its mining segments:
Year Ended December 31,
2021 2020
Seaborne Thermal Mining $ 2.19 $ 1.90
Seaborne Metallurgical Mining
1.18 2.30
Powder River Basin Mining 0.25 0.50
Other U.S. Thermal Mining 1.15 1.04
Peabody Energy Corporation 2021 Form 10-K
Depreciation, depletion and amortization expense decreased during the year ended December 31, 2021 compared to the same period in the prior year primarily due to the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 ($46.2 million). The increase in the weighted-average depletion rate per ton for the Seaborne Thermal Mining segment during the year ended December 31, 2021 compared to the same period in the prior year reflects the impact of the transition to the United Wambo Joint Venture. The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the year ended December 31, 2021 compared to the same period in the prior year reflects the volume and mix variances which impacted the Company’s revenues as described above. The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the year ended December 31, 2021 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020.
Restructuring Charges. Restructuring charges decreased during the year ended December 31, 2021 compared to the same period in the prior year as the result of workforce reductions made across the organization during the prior year.
Transaction Costs Related to Joint Ventures. The charges recorded during the prior year period related to the proposed PRB Colorado joint venture with Arch Resources, Inc. which was terminated during the third quarter of 2020.
Asset Impairment. The Company recognized $1,487.4 million in aggregate asset impairment charges during the year ended December 31, 2020, primarily related to the fair value of its North Antelope Rochelle Mine in its Powder River Basin Mining segment. Refer to Note 3. “Asset Impairment” to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference.
Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates. During the year ended December 31, 2021, the Company reversed a valuation allowance of approximately $33 million that had been established in the prior year on Middlemount’s net deferred tax position. The Company reversed the valuation allowance due to the realization of deferred tax assets as a result of pricing improvements. Refer to Note 6. “Equity Method Investments” to the accompanying consolidated financial statements for further information regarding these changes, which information is incorporated herein by reference.
Interest Expense. The increase in interest expense during the year ended December 31, 2021 compared to the prior year was the result of a series of refinancing transactions completed by the Company during the first quarter of 2021, partially offset by the impacts of debt reductions made throughout 2021 as described in Note 11. “Long-term Debt” to the accompanying consolidated financial statements.
Net Gain on Early Debt Extinguishment. The gain recognized during the year ended December 31, 2021 was primarily related to debt retirements made through various open market purchases throughout the year as further discussed in Note 11. “Long-term Debt” to the accompanying consolidated financial statements.
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2021 was driven by increases to the discount rates for actuarially determined liabilities ($37.6 million); the favorable impacts of changes for the postretirement benefit plans related to updated claims experience ($22.0 million) and a mortality update ($16.6 million); and the favorable impact of an update to the Company’s census data for actuarially determined liabilities ($10.3 million). These increases were offset by mark-to-market losses on pension and postretirement benefit plan assets ($43.1 million).
The gain recorded during the year ended December 31, 2020 was driven by gains on pension and postretirement benefit plan assets ($73.7 million), the favorable impacts of a mortality update for actuarially determined liabilities ($39.5 million) and changes related to claims for the postretirement benefit plans ($21.2 million). These increases were offset by decreases to the discount rates for actuarially determined liabilities ($116.5 million).
Unrealized Losses on Derivative Contracts Related to Forecasted Sales. Unrealized losses primarily relate to mark-to-market activity on derivatives related to forecasted sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
Unrealized (Losses) Gains on Foreign Currency Option Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
Income Tax Provision. The increase in the income tax provision during the year ended December 31, 2021 compared to the prior year period was primarily due to year-over-year increases in taxable income, partially offset by a decrease in the provision related to the remeasurement of foreign income tax accounts. Refer to Note 9. “Income Taxes” to the accompanying consolidated financial statements for additional information.
Peabody Energy Corporation 2021 Form 10-K
Net Income (Loss) Attributable to Common Stockholders
The following table presents net income (loss) attributable to common stockholders:
Increase to
Year Ended December 31, to Income
2021 2020 $ %
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes $ 347.4 $ (1,859.8) $ 2,207.2 118.7 %
Income (loss) from discontinued operations, net of income taxes 24.0 (14.0) 38.0 271.4 %
Net income (loss) 371.4 (1,873.8) 2,245.2 119.8 %
Less: Net income (loss) attributable to noncontrolling interests 11.3 (3.5) 14.8 422.9 %
Net income (loss) attributable to common stockholders $ 360.1 $ (1,870.3) $ 2,230.4 119.3 %
Income (Loss) from Discontinued Operations, Net of Income Taxes. The increase in results from discontinued operations, net of income taxes during the year ended December 31, 2021 compared to the prior year period was primarily due to the gain of $24.6 million recognized on the sale of the Wilkie Creek Mine as discussed in Note 19. “Other Events” and increases to the discount rates for black lung liabilities.
Net Income (Loss) Attributable to Noncontrolling Interests. The increase in net results attributable to noncontrolling interests during the year ended December 31, 2021 compared to the prior year period was primarily due to higher results of Peabody’s majority-owned mines in which there is an outside non-controlling interest.
Diluted EPS
The following table presents diluted EPS:
Increase to
Year Ended December 31, EPS
2021 2020 $ %
Diluted EPS attributable to common stockholders:
Income (loss) from continuing operations $ 3.00 $ (18.99) $ 21.99 115.8 %
Income (loss) from discontinued operations 0.22 (0.15) 0.37 246.7 %
Net income (loss) attributable to common stockholders $ 3.22 $ (19.14) $ 22.36 116.8 %
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 112.0 million and 97.7 million for the years ended December 31, 2021 and 2020, respectively.
Peabody Energy Corporation 2021 Form 10-K
Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDA is defined as income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below.
Year Ended December 31,
2021 2020
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes $ 347.4 $ (1,859.8)
Depreciation, depletion and amortization
308.7 346.0
Asset retirement obligation expenses 44.7 45.7
Restructuring charges 8.3 37.9
Transaction costs related to joint ventures - 23.1
Asset impairment - 1,487.4
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates
(33.8) 30.9
Interest expense 183.4 139.8
Net gain on early debt extinguishment (33.2) -
Interest income (6.5) (9.4)
Net mark-to-market adjustment on actuarially determined liabilities
(43.4) (5.1)
Unrealized losses on derivative contracts related to forecasted sales 115.1 29.6
Unrealized losses (gains) on foreign currency option contracts 7.5 (7.1)
Take-or-pay contract-based intangible recognition (4.3) (8.2)
Income tax provision
22.8 8.0
Adjusted EBITDA $ 916.7 $ 258.8
Revenues per Ton and Adjusted EBITDA Margin per Ton are equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:
Year Ended December 31,
2021 2020
(Dollars in millions)
Operating costs and expenses $ 2,553.1 $ 2,524.9
Unrealized (losses) gains on foreign currency option contracts (7.5) 7.1
Take-or-pay contract-based intangible recognition 4.3 8.2
Net periodic benefit credit, excluding service cost (38.3) (1.8)
Total Reporting Segment Costs $ 2,511.6 $ 2,538.4
The following table presents Reporting Segment Costs by reporting segment:
Year Ended December 31,
2021 2020
(Dollars in millions)
Seaborne Thermal Mining $ 580.9 $ 548.6
Seaborne Metallurgical Mining 549.5 616.7
Powder River Basin Mining 836.3 796.3
Other U.S. Thermal Mining 524.9 538.9
Corporate and Other 20.0 37.9
Total Reporting Segment Costs $ 2,511.6 $ 2,538.4
Peabody Energy Corporation 2021 Form 10-K
The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment:
Year Ended December 31, 2021
Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining
(Amounts in millions, except per ton data)
Tons sold 17.3 5.5 88.4 16.9
Revenues $ 934.0 $ 727.7 $ 971.2 $ 689.1
Reporting Segment Costs 580.9 549.5 836.3 524.9
Adjusted EBITDA
$ 353.1 $ 178.2 $ 134.9 $ 164.2
Revenues per Ton
$ 54.09 $ 131.83 $ 10.99 $ 40.75
Costs per Ton
33.64 99.55 9.46 31.04
Adjusted EBITDA Margin per Ton
$ 20.45 $ 32.28 $ 1.53 $ 9.71
Year Ended December 31, 2020
Seaborne Thermal Mining Seaborne Metallurgical Mining Powder River Basin Mining Other U.S. Thermal Mining
(Amounts in millions, except per ton data)
Tons sold 19.0 5.6 87.2 18.3
Revenues $ 711.8 $ 486.5 $ 991.1 $ 707.3
Reporting Segment Costs 548.6 616.7 796.3 538.9
Adjusted EBITDA
$ 163.2 $ (130.2) $ 194.8 $ 168.4
Revenues per Ton
$ 37.46 $ 86.33 $ 11.37 $ 38.73
Costs per Ton
28.87 109.44 9.14 29.51
Adjusted EBITDA Margin per Ton
$ 8.59 $ (23.11) $ 2.23 $ 9.22
Free Cash Flow is defined as net cash provided by (used in) operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP.
Year Ended December 31,
2021 2020
(Dollars in millions)
Net cash provided by (used in) operating activities $ 420.0 $ (9.7)
Net cash used in investing activities (131.5) (206.7)
Free Cash Flow $ 288.5 $ (216.4)
Liquidity and Capital Resources
Overview
The Company’s primary source of cash is proceeds from the sale of its coal production to customers. The Company has also generated cash from the sale of non-strategic assets, including coal reserves, resources and surface lands, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral and margining requirements, and selling and administrative expenses. Recently, the Company has also used cash for early debt retirements, and historically it has also used cash for dividends and share repurchases.
Peabody Energy Corporation 2021 Form 10-K
Any future determinations to return capital to stockholders, such as dividends or share repurchases will depend on a variety of factors, including the restrictions set forth under the Company’s debt and surety agreements, its net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. The Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on its future financial performance, which in turn depends on the successful implementation of its strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to its industry, many of which are beyond the Company’s control. The Company has presently suspended the payment of dividends and share repurchases, as discussed in Part II, Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
Liquidity
As of December 31, 2021, the Company’s cash balances totaled $954.3 million, including approximately $542 million held by Australian subsidiaries, approximately $368 million held by U.S. subsidiaries, and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. The subsidiaries that conduct the operations of the Wilpinjong Mine held cash of approximately $207 million at December 31, 2021. A significant majority of the cash held by the Company’s foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia.
The Company’s available liquidity increased from $728.7 million as of December 31, 2020 to $995.9 million as of December 31, 2021. Available liquidity was comprised of the following:
December 31,
2021 2020
(Dollars in millions)
Cash and cash equivalents $ 954.3 $ 709.2
Credit facility availability 15.3 0.2
Accounts receivable securitization program availability 26.3 19.3
Total liquidity $ 995.9 $ 728.7
Indebtedness
The Company’s total funded indebtedness (Indebtedness) as of December 31, 2021 and 2020 is presented in the table below.
December 31,
Debt Instrument (defined below, as applicable) 2021 2020
(Dollars in millions)
6.000% Senior Secured Notes due March 2022 (2022 Notes) $ 23.1 $ 459.0
8.500% Senior Secured Notes due December 2024 (2024 Peabody Notes) 62.6 -
10.000% Senior Secured Notes due December 2024 (2024 Co-Issuer Notes) 193.9 -
Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) 206.0 -
6.375% Senior Secured Notes due March 2025 (2025 Notes) 334.9 500.0
Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) 322.8 388.2
Revolving credit facility - 216.0
Finance lease obligations 29.3 27.3
Less: Debt issuance costs (34.8) (42.7)
1,137.8 1,547.8
Less: Current portion of long-term debt 59.6 44.9
Long-term debt $ 1,078.2 $ 1,502.9
The Company’s Indebtedness will require estimated principal and interest payments, assuming interest rates in effect at December 31, 2021, of approximately $110 million in 2022, $85 million in 2023, $545 million in 2024, $660 million in 2025, and $10 million thereafter.
Peabody Energy Corporation 2021 Form 10-K
Refinancing and Related Transactions
During the fourth quarter of 2020 and the first quarter of 2021, the Company entered into a series of interrelated agreements with its surety bond providers, the revolving lenders under its credit agreement and certain holders of its senior secured notes to extend a significant portion of its near-term debt maturities to December 2024 and to stabilize collateral requirements for its existing surety bond portfolio. Such agreements and related activities are described below.
Organizational Realignment
In July and August 2020, the Company effected certain changes to its corporate structure in contemplation of a debt-for-debt exchange, which included, among other steps, the formation of certain wholly-owned subsidiaries (the Co-Issuers). In connection with the change in structure, the Company’s subsidiary which owns and operates its Wilpinjong Mine in Australia became a subsidiary of the Co-Issuers. The Co-Issuers and the Wilpinjong subsidiary were designated as unrestricted subsidiaries under the Company’s credit agreement (Credit Agreement) and its senior notes’ indenture (the Existing Indenture).
Surety Agreement
In November 2020, the Company entered into a surety transaction support agreement (Surety Agreement) with the providers of its surety bond portfolio (Participating Sureties) to resolve previous collateral demands made by the Participating Sureties. In accordance with the Surety Agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit.
Upon completion of the Refinancing Transactions, as defined below, other provisions of the Surety Agreement became effective. In particular, the Company granted second liens on $200.0 million of certain mining equipment and will post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the Participating Sureties, plus other amounts in accordance with the Surety Agreement. Further, the Participating Sureties have agreed to a standstill through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025), during which time, the Participating Sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves or cancel any existing surety bond. The Company will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties.
Under the Surety Agreement, additional collateral postings are required if the Company generates more than $100.0 million of free cash flow in any twelve-month period. As calculated in accordance with the agreement, the Company posted an additional $13 million of collateral in January 2022 in the form of letters of credit.
Refinancing Transactions
On January 29, 2021 (the Settlement Date), the Company completed a series of transactions (collectively, the Refinancing Transactions) to, among other things, provide it with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity and financial flexibility. The Refinancing Transactions included a senior notes exchange and related consent solicitation, a revolving credit facility exchange and various amendments to its existing debt agreements, as summarized below.
Exchange Offer
On the Settlement Date, the Company settled an exchange offer (Exchange Offer) pursuant to which $398.7 million aggregate principal amount of its 6.000% Senior Secured Notes due March 2022 (2022 Notes) were validly tendered, accepted by the Company and exchanged for aggregate consideration consisting of (a) $193.9 million aggregate principal amount of new 10.000% Senior Secured Notes due 2024 issued by the Co-Issuers (2024 Co-Issuer Notes), (b) $195.1 million aggregate principal amount of new 8.500% Senior Secured Notes due 2024 issued by Peabody (Peabody Notes), and (c) a cash payment of approximately $9.4 million. Concurrently with the exchange, the requisite number of holders of the 2022 Notes consented to amend the notes’ underlying indenture to render them unsecured and not subject to substantially all of the restrictive covenants. The holders of $60.3 million of the 2022 Notes did not participate in the exchange offer. In connection with the exchange requirements, the Company purchased $22.4 million of the 2024 Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest, during the first quarter of 2021.
Peabody Energy Corporation 2021 Form 10-K
The 2024 Co-Issuer Notes and Co-Issuer Term Loans are subject to mandatory prepayment offers at the end of each six-month period whereby the Excess Cash Flow (as defined in the 2024 Co-Issuer Notes Indenture) generated by the Wilpinjong Mine during each such period may be applied to the principal of the 2024 Co-Issuer Notes and the Co-Issuer Term Loans on a pro rata basis, provided that the liquidity attributable to the Co-Issuers would not fall below $60.0 million. Such prepayments may be accepted or declined at the option of the debt holders. Based upon the Wilpinjong Mine’s results for the six-month period ended December 31, 2021, a total offer to prepay $105.6 million of principal was made on a pro rata basis in February 2022, including $51.2 million of the Co-Issuer Notes and $54.4 million of the Co-Issuer Term Loan. The offer for the Co-Issuer Notes expires March 14, 2022. The Company expects to prepay $17.2 million of principal under the now-expired Co-Issuer Term Loan offer, which is reflected within the current portion of long-term debt in the accompanying consolidated balance sheet as of December 31, 2021. There was no prepayment offer made with respect to the six-month period ended June 30, 2021.
Revolver Transactions
In connection with the Refinancing Transactions, the Company restructured the revolving loans under the Credit Agreement by (i) making a pay down of revolving loans thereunder in the aggregate amount of $10.0 million, (ii) the Co-Issuers incurring $206.0 million of term loans under a credit agreement, dated as of the Settlement Date (Co-Issuer Term Loans, Co-Issuer Term Loan Agreement), (iii) Peabody entering into a letter of credit facility (the Company LC Agreement), and (iv) amending the Credit Agreement (collectively, the Revolver Transactions).
On the Settlement Date, the Company entered into the Company LC Agreement with the revolving lenders party to the Credit Agreement, pursuant to which the Company obtained a $324.0 million letter of credit facility under which its existing letters of credit under the Credit Agreement were deemed to be issued. The commitments under the Company LC Agreement mature on December 31, 2024. Undrawn letters of credit under the Company LC Agreement bear interest at 6.00% per annum and unused commitments are subject to a 0.50% per annum commitment fee.
In connection with the Revolver Transactions, the Company amended the Credit Agreement to make certain changes in consideration of the Company LC Agreement. After giving effect to the Revolver Transactions, there remain no revolving commitments or revolving loans under the Credit Agreement and the first lien net leverage ratio covenant was eliminated. The Company LC Agreement requires that the Company’s restricted subsidiaries maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2024. As such, liquidity attributable to the Co-Issuers, its subsidiaries and other unrestricted subsidiaries is excluded from the calculation. Liquidity calculated in this manner amounted to $771.9 million at December 31, 2021.
The indenture which governs the Peabody Notes and the Company LC Agreement allow the Company to make open market debt repurchases, subject to certain limitations, including, but not limited to: (i) the Company’s unrestricted subsidiaries’ liquidity must be greater than or equal to $200.0 million after giving effect to such repurchases and (ii) for every $4 of principal repurchased in any fiscal quarter, the Company must make an offer on a pro rata basis to purchase $1 of principal amount of debt from holders of the Peabody Notes and the priority lien obligations under the Company LC Agreement within 30 days of the end of such fiscal quarter at a price equal to the weighted average repurchase price paid over that quarter (Mandatory Repurchase Offer).
Other Debt Financing
The Refinancing Transactions did not significantly impact the Company’s existing senior secured term loan under the Credit Facility (Senior Secured Term Loan), or its $500.0 million of 6.375% senior secured notes due March 2025 (2025 Notes), but these debt instruments were impacted by subsequent financing transactions described below. The term loan requires quarterly principal payments of $1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, through December 2024 with the remaining balance due in March 2025. The senior secured notes require semi-annual interest payments each March 31 and September 30 until maturity.
The Company’s debt agreements impose various restrictions and limits on certain categories of payments that the Company may make, such as those for dividends, investments, and stock repurchases. The Company is also subject to customary affirmative and negative covenants. The Company was compliant with all covenants under its debt agreements including the minimum liquidity covenant under the Company LC Agreement at December 31, 2021.
Subsequent Financing Transactions
Subsequent to the Refinancing Transactions, the Company completed a series of financing transactions intended to improve its capital structure.
During 2021, the Company announced an at-the-market equity offering program pursuant to which, as amended, the Company could offer and sell up to 32.5 million shares of its common stock. Through December 31, 2021, the Company sold approximately 24.8 million shares for net cash proceeds of $269.8 million.
Peabody Energy Corporation 2021 Form 10-K
Through December 31, 2021, the Company retired $91.4 million of 2024 Peabody Notes, $117.8 million of 2025 Notes and $61.7 million of its Senior Secured Term Loan primarily through various open market purchases at an aggregate cost of $232.4 million. During the year ended December 31, 2021, the Company recorded net gains on early debt extinguishment of $28.8 million related to these retirements.
Through December 31, 2021, the Company also completed multiple bilateral transactions with holders of the 2022 Notes, the 2025 Notes and the 2024 Peabody Notes in which the Company issued an aggregate 10.0 million shares of its common stock in exchange for $37.3 million aggregate principal amount of the 2022 Notes, $47.2 million aggregate principal amount of the 2025 Notes and $21.6 million aggregate principal amount of the 2024 Peabody Notes.
As a result of the Company’s open market purchases of its debt during the three months ended December 31, 2021, on January 14, 2022, the Company announced a Mandatory Repurchase Offer of up to $38.6 million of 2024 Peabody Notes, at 94.940% of their aggregate accreted value, plus accrued and unpaid interest, and a concurrent repurchase offer of priority lien obligations under the Company LC Agreement. The offers expire on March 4, 2022, unless extended by the Company.
Considering the Refinancing Transactions and the subsequent financing transactions described above, the Company expects to incur approximately $157 million of interest expense, including approximately $17 million of non-cash interest expense, during the year ended December 31, 2022. Approximately $80 million of the total cash interest expense expected to be incurred in 2022 is related to the Company’s Indebtedness, and the remainder relates primarily to its surety bonding and securitization programs.
Refer to Note 11. “Long-term Debt” of the accompanying consolidated financial statements for additional information related to the subsequent financing transactions described above.
Accounts Receivable Securitization Program
As described in Note 22. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” of the accompanying consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017. The securitization program was amended in January 2022 to extend its maturity to January 2025 and reduce the available funding capacity from $250.0 million to $175.0 million, which better aligns with the current average borrowing base. Funding capacity is limited to the availability of eligible receivables and is accounted for as a secured borrowing. Funding capacity under the program may also be utilized for letters of credit in support of other obligations. At December 31, 2021, the Company had no outstanding borrowings and $143.9 million of letters of credit issued under the program, which were primarily in support of portions of the Company’s reclamation obligations. The Company was not required to post cash collateral under the Securitization Program at December 31, 2021.
Collateralized Letter of Credit Agreement
In February 2022, the Company entered into a new agreement, which provides up to $250.0 million of capacity for irrevocable standby letters of credit in support of reclamation bonding. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum. The Company receives a deposit rate of 0.25% per annum on the amount of cash collateral posted in support of letters of credit, with the rate subject to increases over time. The agreement has an initial expiration date of December 31, 2025.
Capital Expenditures
For 2022, the Company is targeting total capital expenditures of approximately $190 million, which includes approximately $80 million of major project and growth capital expenditures.
Other Requirements
The Company will incur significant future cash outflows for certain liabilities related to its prior mining activities and former employees. Such cash flows pertain to postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and end-of-mine closure costs and exploration obligations and are estimated to amount to approximately $205 million in 2022, $155 million in 2023, $150 million in 2024, $145 million in 2025, $135 million in 2026, and $1,640 million thereafter.
The Company has various short- and long-term take-or-pay arrangements in Australia and the U.S. associated with rail and port commitments for the delivery of coal, including amounts relating to export facilities. The estimated future cash flows associated with such arrangements are approximately $85 million in 2022, $90 million in 2023, $95 million in 2024, $90 million in 2025, $85 million in 2026, and $710 million thereafter.
Peabody Energy Corporation 2021 Form 10-K
The Company’s operating lease commitments, excluding potential contingent rental amounts, will require cash payments of approximately $19 million in 2022, $17 million in 2023, and $13 million thereafter.
Cash Flows and Free Cash Flow
The following table summarizes the Company’s cash flows for the years ended December 31, 2021 and 2020, as reported in the accompanying consolidated financial statements. Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Year Ended December 31,
2021 2020
(Dollars in millions)
Net cash provided by (used in) operating activities $ 420.0 $ (9.7)
Net cash used in investing activities (131.5) (206.7)
Net cash (used in) provided by financing activities (43.4) 193.4
Net change in cash, cash equivalents and restricted cash 245.1 (23.0)
Cash, cash equivalents and restricted cash at beginning of period 709.2 732.2
Cash, cash equivalents and restricted cash at end of period $ 954.3 $ 709.2
Net cash provided by (used in) operating activities $ 420.0 $ (9.7)
Net cash used in investing activities (131.5) (206.7)
Free Cash Flow $ 288.5 $ (216.4)
Operating Activities. The net increase in net cash provided by (used in) operating activities for the year ended December 31, 2021 compared to the prior year was driven by a year-over-year increase in cash from the Company’s mining operations ($526.6 million) partially offset by increased cash utilized to satisfy the margin requirements associated with derivative financial instruments ($96.9 million).
Investing Activities. The decrease in net cash used in investing activities for the year ended December 31, 2021 compared to the prior year was compared to the same period in the prior year was driven by cash receipts from the Company’s equity method investee, Middlemount ($44.7 million), and lower advances to related parties ($22.7 million).
Financing Activities. The decrease in net cash provided by financing activities for the year ended December 31, 2021 compared to the prior year was driven by $375.0 million of revolving loan and securitization borrowings in the prior year, higher repayments of debt principal ($115.9 million) and payments for deferred financing costs ($15.5 million) in the current year, partially offset by $269.8 million proceeds from the issuance of common stock in the current year.
Financial Assurances
In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying consolidated balance sheets. At December 31, 2021, such instruments included $1,463.7 million of surety bonds and $452.6 million of letters of credit. Such financial instruments provide support for its reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in its consolidated balance sheets.
Peabody Energy Corporation 2021 Form 10-K
As of December 31, 2021, the Company was party to financial instruments with off-balance sheet risk in support of the following obligations:
Reclamation Health and welfare (1)
Contract performance (2)
Leased property and equipment Other (3)
Total
(Dollars in millions)
Surety bonds and bank guarantees $ 1,294.7 $ 42.1 $ 79.9 $ 30.9 $ 16.1 $ 1,463.7
Letters of credit outstanding under letter of credit facility 205.8 90.9 7.1 5.0 - 308.8
Letters of credit outstanding under accounts receivable securitization program 117.2 18.9 7.7 - - 143.8
1,617.7 151.9 94.7 35.9 16.1 1,916.3
Less: Letters of credit in support of surety bonds (4)
(315.9) (29.9) - (1.2) - (347.0)
Less: Cash collateral in support of surety bonds (4)
(15.0) - - - - (15.0)
Obligations supported, net $ 1,286.8 $ 122.0 $ 94.7 $ 34.7 $ 16.1 $ 1,554.3
(1) Obligations include pension and health care plans, workers’ compensation, and property and casualty insurance.
(2) Obligations pertain to customer and vendor contracts.
(3) Obligations primarily pertain to the disturbance or alteration of public roadways in connection with the Company’s mining activities that is subject to future restoration.
(4) Serve as collateral for certain surety bonds at the request of surety bond providers. The Company has also posted $8.8 million in incremental collateral directly with the beneficiary that is not supported by a surety bond.
Financial assurances associated with new reclamation bonding requirements, surety bonds or other obligations may require additional collateral in the form of cash or letters of credit causing a decline in the Company’s liquidity.
As described in Note 22. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to the accompanying consolidated financial statements, the Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. Self-bonding in the U.S. has become increasingly restricted in recent years, leading to the Company’s increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on its liquidity due to increased collateral requirements and surety and related fees.
At December 31, 2021, the Company had total asset retirement obligations of $719.8 million which were backed by a combination of surety bonds, bank guarantees and letters of credit.
Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.
Guarantees and Other Financial Instruments with Off-Balance Sheet Risk. See Note 22. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” to the accompanying consolidated financial statements for a discussion of the Company’s accounts receivable securitization program and guarantees and other financial instruments with off-balance sheet risk.
Critical Accounting Policies and Estimates
The Company’s discussion and analysis of its financial condition, results of operations, liquidity and capital resources is based upon its financial statements, which have been prepared in accordance with U.S. GAAP. The Company is also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, the Company evaluates its estimates. The Company bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
Peabody Energy Corporation 2021 Form 10-K
Impairment of Long-Lived Assets. The Company evaluates its long-lived assets held and used in operations for impairment as events and changes in circumstances indicate that the carrying amount of such assets might not be recoverable. Factors that would indicate potential impairment to be present include, but are not limited to, a sustained history of operating or cash flow losses, an unfavorable change in earnings and cash flow outlook, prolonged adverse industry or economic trends and a significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition. The Company generally does not view short-term declines in thermal and metallurgical coal prices as a triggering event for conducting impairment tests because of historic price volatility. However, the Company generally views a sustained trend of depressed coal pricing (for example, over periods exceeding one year) as an indicator of potential impairment. Because of the volatile and cyclical nature of coal prices and demand, it is reasonably possible that coal prices may decrease and/or fail to improve in the near term, which, absent sufficient mitigation such as an offsetting reduction in the Company’s operating costs, may result in the need for future adjustments to the carrying value of its long-lived mining assets and mining-related investments.
Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For its active mining operations, the Company generally groups such assets at the mine level, or the mining complex level for mines that share infrastructure, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for remaining economic life based on transferability to ongoing operating sites or for expected salvage. For its development and exploration properties and portfolio of surface land and coal reserve and resource holdings, the Company considers several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of a sale to a third party.
When indicators of impairment are present, the Company evaluates its long-lived assets for recoverability by comparing the estimated undiscounted cash flows in the LOM plan expected to be generated by those assets under various assumptions to their carrying amounts. If such undiscounted cash flows indicate that the carrying value of the asset group is not recoverable, impairment losses are measured by comparing the estimated fair value of the asset group to its carrying amount. As quoted market prices are unavailable for the Company’s individual mining operations, fair value is determined through the use of an expected present value technique based on the income approach, except for non-strategic coal reserves and resources, surface lands and undeveloped coal properties excluded from its long-range mine planning. In those cases, a market approach is utilized based on the most comparable market multiples available. The estimated future cash flows and underlying assumptions used to assess recoverability and, if necessary, measure the fair value of the Company’s long-lived mining assets are derived from those developed in connection with its planning and budgeting process. The Company believes its assumptions to be consistent with those a market participant would use for valuation purposes. The most critical assumptions underlying its projections and fair value estimates include those surrounding future tons sold, coal prices for unpriced coal, production costs (including costs for labor, commodity supplies and contractors), transportation costs, foreign currency exchange rates and a risk-adjusted, cost of capital (all of which generally constitute unobservable Level 3 inputs under the fair value hierarchy), in addition to market multiples for non-strategic coal reserves and resources, surface lands and undeveloped coal properties excluded from the Company’s long-range mine planning (which generally constitute Level 2 inputs under the fair value hierarchy).
There were no impairment charges of long-lived assets recorded for the year ended December 31, 2021. Impairment charges of $1,487.4 million of long-lived assets were recorded for the year ended December 31, 2020. The assumptions used are based on the Company’s best knowledge at the time it prepare its analysis but can vary significantly due to the volatile and cyclical nature of coal prices and demand, regulatory issues, unforeseen mining conditions, commodity prices and cost of labor. Additionally, the decline of coal-fired electricity generation in the U.S., driven by the reduced utilization of plants and plant retirements, sustained low natural gas pricing and the increased use of renewable energy sources, was a significant consideration in the Company’s analysis. These factors may cause the Company to be unable to recover all or a portion of the carrying value of its long-lived assets.
The Company has identified certain assets with an aggregate carrying value of approximately $0.5 billion at December 31, 2021 in its Other U.S. Thermal Mining and Corporate and Other segments whose recoverability is most sensitive to coal pricing, cost pressures, customer demand, customer concentration risk and future economic viability. The Company conducted a review of those assets as of December 31, 2021 and determined that no further impairment charges were necessary as of that date.
See Note 3. “Asset Impairment” to the accompanying consolidated financial statements for additional information regarding impairment charges.
Peabody Energy Corporation 2021 Form 10-K
Income Taxes. Peabody accounts for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities to be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or all of the deferred tax asset will not be realized. In its evaluation of the need for a valuation allowance, Peabody takes into account various factors, including the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income in carryback years. As of December 31, 2021, the Company had valuation allowances for income taxes totaling $2,120.8 million. If actual results differ from the assumptions made in the annual evaluation of its valuation allowance, Peabody may record a change in valuation allowance through income tax expense in the period such determination is made.
Peabody’s liability for unrecognized tax benefits contains uncertainties because management is required to make assumptions and to apply judgment to estimate the exposures associated with its various filing positions. Peabody recognizes the tax benefit from an uncertain tax position only if it is “more likely than not” that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position must be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. As of December 31, 2021, the Company had net unrecognized tax benefits of $11.0 million included in recorded liabilities in the consolidated balance sheet. Peabody believes that its judgments and estimates are reasonable; however, to the extent it prevails in matters for which liabilities have been established, or are required to pay amounts in excess of its recorded liabilities, the Company’s effective tax rate in a given period could be materially affected.
See Note 9. “Income Taxes” to the accompanying consolidated financial statements for additional information regarding valuation allowances and unrecognized tax benefits.
Postretirement Benefit and Pension Liabilities. Peabody has long-term liabilities for its employees’ postretirement benefit costs and defined benefit pension plans. Its pension obligations are funded in accordance with the provisions of applicable laws and the Company’s policies. Liabilities for postretirement benefit costs are funded at its discretion. For the year ended December 31, 2021 Peabody recorded a total benefit related to postretirement benefit costs and pension of $38.2 million, while employer contributions were $26.8 million. An actuarial gain of $41.8 million was recorded for the year ended December 31, 2021.
Each of these liabilities is actuarially determined and Peabody uses various actuarial assumptions, including the discount rate, future cost trends, mortality tables, demographic assumptions and expected asset returns to estimate the costs and obligations for these items. Peabody’s discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service its liabilities. The Company makes assumptions related to future trends for medical care costs in the estimates of postretirement benefit costs. Its medical trend assumption is developed by annually examining the historical trend of cost per claim data. In deciding which mortality tables to use, the Company periodically reviews its population’s actual mortality experience and evaluates results against its current assumptions as well as consider recent mortality tables published by the Society of Actuaries Retirement Plans Experience Committee in order to select mortality tables for use in its year end valuations. In addition, the Company makes assumptions related to rates of return on plan assets. If its assumptions do not materialize as expected, actual cash expenditures and costs that Peabody incurs could differ materially from its current estimates. Moreover, regulatory changes could affect Peabody’s obligation to satisfy these or additional obligations.
Peabody Energy Corporation 2021 Form 10-K
For the Company’s postretirement benefit obligation, assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for its health care plans. Below the Company has provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
For Year Ended December 31, 2021
One-Percentage-
Point Increase One-Percentage-
Point Decrease
(Dollars in millions)
Health care cost trend rate:
Effect on total net periodic postretirement benefit cost $ 1.0 $ (0.9)
Effect on total postretirement benefit obligation $ 16.6 $ (14.3)
For Year Ended December 31, 2021
One-Half
Percentage-
Point Increase One-Half
Percentage-
Point Decrease
(Dollars in millions)
Discount rate:
Effect on total net periodic postretirement benefit cost $ 1.4 $ (1.5)
Effect on total postretirement benefit obligation $ (9.6) $ 10.8
Expected return on assets:
Effect on total net periodic postretirement benefit cost $ (0.1) $ 0.1
For the Company’s pension obligation, assumed discount rates and expected returns on assets have a significant effect on the expense and funded status amounts reported for its defined benefit pension plans. Below the Company has provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
For Year Ended December 31, 2021
One-Half
Percentage-
Point Increase One-Half
Percentage-
Point Decrease
(Dollars in millions)
Discount rate:
Effect on total net periodic pension cost $ 2.7 $ (3.0)
Effect on defined benefit pension plans’ projected benefit obligation $ (34.4) $ 37.4
Expected return on assets:
Effect on total net periodic pension cost $ (4.1) $ 4.1
As a result of discretionary contributions made in recent years, its defined benefit pension plans have become nearly fully funded. As a result of the funding level, the asset allocation mix reflected Peabody’s target asset mix of 100% fixed income investments and the pensions plans’ assets provide a significant hedge to the funded status against interest rate movements. If the discount rate moves, Peabody’s actual results would be different than those shown above as substantially all of the change in the discount rate should be offset by changes to the expected return on plan assets.
See Note 14. “Postretirement Health Care and Life Insurance Benefits” and Note 15. “Pension and Savings Plans” to the accompanying consolidated financial statements for additional information regarding postretirement benefit and pension plans.
Peabody Energy Corporation 2021 Form 10-K
Asset Retirement Obligations. The Company’s asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws and regulations in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. If the Company’s assumptions do not materialize as expected, actual cash expenditures and costs that it incurs could be materially different than currently estimated. Moreover, regulatory changes could increase its obligation to perform reclamation and mine closing activities. Amortization associated with the Company’s asset retirement obligation assets of $27.1 million for the year ended December 31, 2021 was included in “Depreciation, depletion and amortization” in the Company’s consolidated statements of operations. Asset retirement obligation expense, consisting of both accretion expense and expense related to reclamation activities at the Company’s active locations, for the year ended December 31, 2021 was $44.7 million and payments totaled $39.3 million. See Note 13. “Asset Retirement Obligations” to the accompanying consolidated financial statements for additional information regarding the Company’s asset retirement obligations.
Contingent liabilities. From time to time, Peabody is subject to legal and environmental matters related to its continuing and discontinued operations and certain historical, non-coal producing operations. In connection with such matters, the Company is required to assess the likelihood of any adverse judgments or outcomes, as well as potential ranges of probable losses.
A determination of the amount of reserves required for these matters is made after considerable analysis of each individual issue. Peabody accrues for legal and environmental matters within “Operating costs and expenses” when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Peabody provides disclosure surrounding loss contingencies when it believes that it is at least reasonably possible that a material loss may be incurred or an exposure to loss in excess of amounts already accrued may exist. Adjustments to contingent liabilities are made when additional information becomes available that affects the amount of estimated loss, which information may include changes in facts and circumstances, changes in interpretations of law in the relevant courts, the results of new or updated environmental remediation cost studies and the ongoing consideration of trends in environmental remediation costs.
Accrued contingent liabilities exclude claims against third parties and are not discounted. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the Company’s consolidated balance sheets. In general, legal fees related to environmental remediation and litigation are charged to expense. The Company includes the interest component of any litigation-related penalties within “Interest expense” in its consolidated statements of operations. See Note 23. “Commitments and Contingencies” to the accompanying consolidated financial statements for further discussion of the Company’s contingent liabilities.
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The potential for changes in the market value of the Company’s coal and freight-related trading, crude oil, diesel fuel and foreign currency contract portfolios, as applicable, is referred to as “market risk.” Market risk related to its coal trading and freight-related contract portfolio, which includes bilaterally-settled and over-the-counter (OTC) exchange-settled trading, in addition to, from time to time, the brokered trading of coal, is evaluated using a value at risk (VaR) analysis. VaR analysis is not used to evaluate the Company’s non-trading diesel fuel or foreign currency hedging portfolios, as applicable, or coal trading activities it employs in support of coal production (as discussed below). The Company attempts to manage market price risks through diversification, controlling position sizes and executing hedging strategies. Due to a lack of quoted market prices and the long-term, illiquid nature of the positions, the Company has not quantified market price risk related to its non-trading, long-term coal supply agreement portfolio.
Peabody Energy Corporation 2021 Form 10-K
Coal Trading Activities and Related Commodity Price Risk
Coal Price Risk Monitored Using VaR. Peabody engages in direct and brokered trading of physical coal and freight-related commodities in OTC markets. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. Peabody actively measures, monitors, manages and hedges market price risk due to current and anticipated trading activities to remain within risk limits prescribed by management. For example, it has policies in place that limit the amount of market price risk, as measured by VaR, that the Company may assume at any point in time from its trading and brokerage activities.
Peabody generally accounts for its coal trading activities using the fair value method, which requires it to reflect contracts with third parties that meet the definition of a derivative at market value in its consolidated financial statements, with the exception of contracts for which it has elected to apply the normal purchases and normal sales exception. Peabody’s trading portfolio included futures, forwards and options as of December 31, 2021. The use of VaR allows the Company to quantify in dollars, on a daily basis, a measure of price risk inherent in its trading portfolio. VaR represents the expected loss in portfolio value due to adverse market price movements over a defined time horizon (liquidation period) within a specified confidence level. Peabody’s VaR model is based on a variance/co-variance approach, which captures its potential loss exposure related to future, forward, swap and option positions. Peabody’s VaR model assumes a 15-day holding period at the time of VaR measurement and produces an output corresponding with a 95% one-tailed confidence interval, which means that there is a one in 20 statistical chance that its portfolio could lose more than the VaR estimates during the assumed liquidation period. Peabody’s volatility calculation incorporates an exponentially weighted moving average algorithm based on price movements during the previous 60 market days, which makes its volatility more representative of recent market conditions while still reflecting an awareness of historical price movements. VaR does not estimate the maximum potential loss expected in the 5% of the time that changes in the portfolio value during the assumed liquidation period is expected to exceed measured VaR. The Company uses stress testing and scenario analysis to help provide visibility in such cases, as discussed further below.
VaR analysis allows the Company to aggregate market price risk across products in the portfolio, compare market price risk on a consistent basis and identify the drivers of risk and changes thereto over time. Peabody uses historical data to estimate price volatility as an input to VaR. Given its reliance on historical data, the Company believes VaR is reasonably effective in characterizing market price risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. Nonetheless, an inherent limitation of VaR is that past changes in market price risk factors may not produce accurate predictions of future market price risk. Due to that limitation, combined with the subjectivity in the choice of the liquidation period and reliance on historical data to calibrate its models, the Company performs stress and scenario analyses as needed to estimate the impacts of market price changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of its VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market price-related risks.
During the year ended December 31, 2021, the actual low, high and average VaR associated with the Company’s trading and brokerage function was $0.8 million, $18.4 million and $6.8 million, respectively.
Other Risk Exposures. Peabody also uses its coal trading and brokerage platform to support various coal production-related activities. These transactions may involve coal to be produced from its mines, coal sourcing arrangements with third-party mining companies, joint venture positions with producers or offtake agreements with producers. While the support activities (such as the forward sale of coal to be produced and/or purchased) may ultimately involve instruments sensitive to market price risk, the sourcing of coal in these arrangements does not involve market risk sensitive instruments and does not encompass the commodity price risks that the Company monitors through VaR analysis, as discussed above.
Future Realization. As of December 31, 2021, the total estimated future realization of the value of the Company’s trading portfolio is expected to occur over 2022 and 2023.
Peabody also monitors other types of risk associated with its coal trading activities, including credit, market liquidity and counterparty nonperformance.
Peabody Energy Corporation 2021 Form 10-K
Credit and Nonperformance Risk
The fair values of Peabody’s derivative instruments utilized for corporate hedging and coal trading activities reflect adjustments for credit risk, as necessary. The Company’s exposure is substantially with electric utilities, energy marketers, steel producers and nonfinancial trading houses. Its policy is to independently evaluate each counterparty’s creditworthiness prior to entering into transactions and to regularly monitor exposures. Peabody manages its counterparty risk from its hedging activities related to foreign currency and fuel exposures, as applicable, through established credit standards, diversification of counterparties, utilization of investment grade commercial banks, adherence to established tenor limits based on counterparty creditworthiness and continual monitoring of that creditworthiness. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), Peabody has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for Peabody’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, Peabody seeks to enter into netting agreements with counterparties that permit it to offset asset and liability positions with such counterparties and, to the extent required, Peabody will post or receive margin amounts associated with exchange-cleared and certain OTC positions. Peabody also continually monitors counterparty and contract nonperformance risk, if present, on a case-by-case basis.
Foreign Currency Risk
The Company has historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements. As of December 31, 2021, the Company had currency options outstanding with an aggregate notional amount of $535.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures during the first nine months of 2022. Assuming the Company had no foreign currency hedging instruments in place, its exposure in operating costs and expenses due to a $0.10 change in the Australian dollar/U.S. dollar exchange rate is approximately $140 to $150 million for the next twelve months. Based upon the Australian dollar/U.S. dollar exchange rate at December 31, 2021, the currency option contracts outstanding at that date would limit the Company’s net exposure to a $0.10 unfavorable change in the exchange rate to approximately $90 million for the next twelve months.
Coal Price Risk
The Company predominantly manages its commodity price risk for its non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year) to the extent possible, rather than through the use of derivative instruments. Sales under such agreements comprised approximately 84%, 89% and 88% of its worldwide sales (by volume) for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021, the Company had approximately 104 million tons of U.S. thermal coal priced and committed for 2022. This includes approximately 86 million tons of PRB coal and 18 million tons of other U.S. thermal coal. The Company has the flexibility to increase volumes should demand warrant. Peabody is estimating 2022 thermal coal sales volumes from its Seaborne Thermal Mining segment of 17.0 million to 18.5 million tons comprised of thermal export volume of 9.5 million to 10.5 million tons and domestic volume of 7.5 million to 8.0 million tons. Peabody is estimating full year 2022 metallurgical coal sales from its Seaborne Metallurgical Mining segment of 6.5 million to 7.5 million tons. Sales commitments in the metallurgical coal market are typically not long-term in nature, and the Company is therefore subject to fluctuations in market pricing.
Diesel Fuel Price Risk
Previously, the Company managed price risk of the diesel fuel used in its mining activities through the use of derivatives, primarily swaps. As of December 31, 2021, the Company did not have any diesel fuel derivative instruments in place. The Company also manages the price risk of diesel fuel through the use of cost pass-through contacts with certain customers.
The Company expects to consume 95 to 105 million gallons of diesel fuel during the next twelve months. A $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease its annual diesel fuel costs by approximately $23 million based on its expected usage.
Peabody Energy Corporation 2021 Form 10-K
Interest Rate Risk
Peabody’s objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. From time to time, Peabody manages its debt to achieve a certain ratio of fixed-rate debt and variable-rate debt as a percent of net debt through the use of various hedging instruments. As of December 31, 2021, Peabody had approximately $849.9 million of fixed-rate borrowings and $323.3 million of variable-rate borrowings outstanding and had no interest rate swaps in place. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $3 million on its variable-rate borrowings. With respect to its fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $20 million in the estimated fair value of these borrowings.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
See Part IV, Item 15. “Exhibits and Financial Statement Schedules” of this report for the information required by this Item 8, which information is incorporated by reference herein.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Peabody’s disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal accounting officer, on a timely basis. As of December 31, 2021, the end of the period covered by this Annual Report on Form 10-K, the Company carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures. Based upon that evaluation, Peabody’s Chief Executive Officer and Chief Financial Officer have concluded that such disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of December 31, 2021 were effective to provide reasonable assurance that the desired control objectives were achieved.
Changes in Internal Control Over Financial Reporting
Peabody periodically reviews its internal control over financial reporting as part of its efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, Peabody routinely reviews its system of internal control over financial reporting to identify potential changes to its processes and systems that may improve controls and increase efficiency, while ensuring that the Company maintains an effective internal control environment. Changes may include such activities as implementing new systems; consolidating the activities of acquired business units; migrating certain processes to its shared services organizations and/or managed third parties; formalizing and refining policies, procedures and control documentation requirements; improving segregation of duties and adding monitoring controls. In addition, when Peabody acquires new businesses, it incorporate its controls and procedures into the acquired business as part of its integration activities.
There have been no changes in Peabody’s internal control over financial reporting that occurred during the three months ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for maintaining and establishing adequate internal control over financial reporting. An evaluation of the effectiveness of the design and operation of the Company’s internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, as of the end of the period covered by this report was performed under the supervision and with the participation of management, including its Chief Executive Officer and Chief Financial Officer. This evaluation is performed to determine if the Company’s internal controls over financial reporting provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Peabody Energy Corporation 2021 Form 10-K
Management conducted an assessment of the effectiveness of the Company’s internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2021.
Peabody’s Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited Peabody’s internal control over financial reporting, as stated in their unqualified opinion report included herein.
/s/ James C. Grech /s/ Mark A. Spurbeck
James C. Grech
President and Chief Executive Officer
Mark A. Spurbeck
Executive Vice President and Chief Financial Officer
February 18, 2022
Peabody Energy Corporation 2021 Form 10-K
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of Peabody Energy Corporation
Opinion on Internal Control over Financial Reporting
We have audited Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Peabody Energy Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”) of the Company, and our report dated February 18, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young, LLP
St. Louis, Missouri
February 18, 2022
Peabody Energy Corporation 2021 Form 10-K

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10.Directors, Executive Officers and Corporate Governance.
The information required by Item 401 of Regulation S-K is included under the caption Proposal 1 - “Election of Directors” in Peabody’s 2022 Proxy Statement and in Part I, Item 1. “Business” of this report under the caption “Information About Our Executive Officers.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Stock Ownership,” “Additional Information Concerning the Board of Directors - Corporate Governance - Code of Business Conduct and Ethics” and “Additional Information Concerning the Board of Directors - Committee Overview - Audit Committee” in Peabody’s 2022 Proxy Statement. Such information is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.Executive Compensation.
The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included under the captions “Additional Information Concerning the Board of Directors - Director Compensation,” “Compensation Discussion and Analysis,” “Compensation Committee Interlocks and Insider Participation,” “Compensation Committee Report,” “Risk Assessment in Compensation Programs,” “Executive Compensation Tables” and “Pay Ratio Disclosure” in Peabody’s 2022 Proxy Statement and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by Item 403 of Regulation S-K is included under the caption “Stock Ownership - Security Ownership of Directors and Management and Certain Beneficial Owners” in Peabody’s 2022 Proxy Statement and is incorporated herein by reference.
Equity Compensation Plan Information
As required by Item 201(d) of Regulation S-K, the following table provides information regarding Peabody’s equity compensation plans as of December 31, 2021:
(a)
Number of Securities
to be Issued
upon Exercise of
Outstanding Options,
Warrants and Rights Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding
Securities
Reflected in Column
(a))
Plan Category
Equity compensation plans approved by security holders
872,839 (1)
$ - (2)
7,045,005
Equity compensation plans not approved by security holders
- - -
Total 872,839 $ - 7,045,005
(1)Shares issuable pursuant to outstanding performance units and vested but not issued deferred stock units. Performance units are shown at target and could change based on actual metrics achieved.
(2)The weighted-average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards.
Refer to Note 17. “Share-Based Compensation” to the accompanying consolidated financial statements for additional information regarding the material features of Peabody’s current equity compensation plans.
Peabody Energy Corporation 2021 Form 10-K

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.Certain Relationships and Related Transactions, and Director Independence.
The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Review of Related Person Transactions” and “Additional Information Concerning the Board of Directors - Board Independence” in Peabody’s 2022 Proxy Statement and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14.Principal Accountant Fees and Services.
The information required by Item 9(e) of Schedule 14A is included under the caption “Audit Fees” in Peabody’s 2022 Proxy Statement and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15.Exhibits and Financial Statement Schedules.
(a) Documents Filed as Part of the Report
(1) Financial Statements.
The following consolidated financial statements of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are included herein on the pages indicated:
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Consolidated Statements of Operations - For the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Comprehensive Income (Loss) - For the Years Ended December 31, 2021, 2020 and 2019
Consolidated Balance Sheets - December 31, 2021 and 2020
Consolidated Statements of Cash Flows - For the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statements of Changes in Stockholders’ Equity - For the Years Ended December 31, 2021, 2020 and 2019
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules.
The following financial statement schedule of Peabody Energy Corporation is at the page indicated:
Page
Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are not applicable and, therefore, have been omitted.
(3) Exhibits.
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
Exhibit No. Description of Exhibit
2.1 Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code as revised March 15, 2017 (Incorporated by reference to Exhibit 2.2 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017).
2.2 Order Confirming Debtors’ Second Amended Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code on March 17, 2017 (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed March 20, 2017).
Peabody Energy Corporation 2021 Form 10-K
2.3 Asset Purchase Agreement, dated as of September 20, 2018, by and between Drummond Company, Inc. and Peabody Southeast Mining, LLC, and, for certain limited purposes, Peabody Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed September 24, 2018).
2.4 Implementation Agreement, dated as of June 18, 2019, between Peabody Energy Corporation and Arch Coal, Inc. (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K/A filed on June 19, 2019).
3.1 Fourth Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed April 3, 2017).
3.2 Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.3 of the Registrant’s Current Report on Form 8-K filed April 3, 2017).
4.1 Specimen of stock certificate representing the Registrant’s common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 to Amendment No. 4 to the Registrant’s Form S-1 Registration Statement No. 333-55412, filed May 1, 2001).
4.2 Indenture, dated as of February 15, 2017, between Peabody Securities Finance Corporation and Wilmington Trust, National Association, as Trustee, governing 6.000% Senior Secured Notes due 2022 and 6.375% Senior Secured Notes due 2025 (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed February 15, 2017).
4.3 First Supplemental Indenture, dated as of April 3, 2017, among the Registrant, Peabody Securities Finance Corporation, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
4.4 Second Supplemental Indenture, dated as of May 7, 2018, among the Registrant, NGS Acquisition Corp., LLC, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
4.5 Third Supplemental Indenture, dated as of August 9, 2018, between the Registrant and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2018).
4.6 Fourth Supplemental Indenture, dated as of December 7, 2018, among the Registrant, Peabody Southeast Mining, LLC, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.6 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
4.7 Description of Securities (Incorporated by reference to Exhibit 4.7 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019).
4.8 Indenture dated as of January 29, 2021, by and among the Co-Issuers, Wilmington Trust, National Association, as trustee, and the Company (on a limited basis, to the extent of its obligations specifically set forth therein) (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
4.9 Indenture dated as of January 29, 2021, by and among Peabody, the guarantors party thereto, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
4.10 Seventh Supplemental Indenture, dated as of January 8, 2021, by and among the Company and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
4.11 Eighth Supplemental Indenture, dated as of January 29, 2021, by and among the Company and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
4.12 First Supplemental Indenture, dated as of February 3, 2021, by and among the Co-Issuers, Wilmington Trust, National Association, as trustee, and Peabody (on a limited basis, to the extent of its obligations specifically set forth therein) (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on February 5, 2021).
4.13 First Supplemental Indenture, dated as of February 3, 2021, by and among Peabody, the guarantors party thereto, and Wilmington Trust, National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on February 5, 2021).
10.1 Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.2 Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.3 Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.4 Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.5 Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
Peabody Energy Corporation 2021 Form 10-K
10.6 Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 to the Registrant’s Form S-4 Registration Statement No. 333-59073, filed September 8, 1998).
10.7 Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1998).
10.8 Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004).
10.9 Federal Coal Lease WYW150210: North Antelope Rochelle Mine (Incorporated by reference to Exhibit 10.8 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
10.10 Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
10.11 Federal Coal Lease Readjustment WYW78633: Caballo (Incorporated by reference to Exhibit 10.24 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.12 Transfer by Assignment and Assumption of Federal Coal Lease WYW172657: Caballo West (Incorporated by reference to Exhibit 10.25 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.13 Federal Coal Lease WYW176095: Porcupine South (Incorporated by reference to Exhibit 10.26 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.14 Federal Coal Lease WYW173408: North Porcupine (Incorporated by reference to Exhibit 10.27 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.15 Federal Coal Lease WYW172413: School Creek (Incorporated by reference to Exhibit 10.28 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012).
10.16 Separation Agreement, Plan of Reorganization and Distribution, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.17 Tax Separation Agreement, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.18 Coal Act Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.19 Salaried Employee Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.20 Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by reference to Exhibit 10.6 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.21 Settlement Agreement entered into as of October 24, 2013, by and among Patriot Coal Corporation, on behalf of itself and its affiliates, the Registrant, on behalf of itself and its affiliates, and the United Mine Workers of America, on behalf of itself and the UMWA Employees and UMWA Retirees (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 30, 2013).
10.22 Purchase and Sale Agreement, dated as of November 20, 2015, by and between Four Star Holdings, LLC and Western Megawatt Resources, LLC (Incorporated by reference to Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2015).
10.23* Employment Agreement entered into as of August 21, 2013, by and between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 27, 2013).
10.24* Restrictive Covenant Agreement entered into as of August 21, 2013, by and between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on August 27, 2013).
10.25* Letter dated January 27, 2015 to Glenn L. Kellow from the Chairman of the Compensation Committee of the Peabody Energy Corporation Board of Directors (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 28, 2015).
10.26* Letter Agreement entered into as of January 27, 2015, by and between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on January 28, 2015).
10.27* Letter Agreement entered into as of April 20, 2015, by and between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on April 21, 2015).
Peabody Energy Corporation 2021 Form 10-K
10.28* Form of Addendum to Participation Agreement executed by Glenn L. Kellow and Charles F. Meintjes (2020) (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.29* Employment Transition Agreement, dated March 18, 2021, between Peabody Energy Corporation and Glenn L. Kellow (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 18, 2021).
10.30* Contract of Employment, dated October 22, 2020, between Peabody Energy Australia Coal Pty Ltd and Darren R. Yeates (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 26, 2020).
10.31* Variation of Employment Contract, dated August 11, 2021, between Peabody Energy Australia Coal Pty Ltd and Darren R. Yeates (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K, filed August 13, 2021).
10.32* Restated Employment Agreement entered into as of December 20, 2012 by and between the Registrant and Kemal Williamson (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 26, 2012).
10.33* Peabody Energy Corporation 2019 Executive Severance Plan. (Incorporated by reference to Exhibit 10.32 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.34 Termination Agreement, dated as of October 5, 2020, between Peabody Energy Corporation and Arch Resources, Inc. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed on October 6, 2020).
10.35 Limited Waiver to Purchase and Sale Agreement by and between Four Star Holdings, LLC and Western Megawatt Resources, LLC dated March 30, 2016 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed March 31, 2016).
10.36 Fifth Amended and Restated Receivables Purchase Agreement, dated as of March 25, 2016, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed March 31, 2016).
10.37 First Amendment to the Fifth Amended and Restated Receivables Purchase Agreement, dated as of April 12, 2016, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as the Sole Purchaser, Committed Purchaser, LC Bank and LC Participant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 13, 2016).
10.38 Second Amendment to the Fifth Amended and Restated Receivables Purchase Agreement, dated as of April 18, 2016, by and among Peabody Energy Corporation, P&L Receivables Company, LLC, the various Sub-Servicers listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as the Sole Purchaser, Committed Purchaser, LC Bank and LC Participant (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 22, 2016).
10.39 Sixth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of June 30, 2020, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.40 Receivables Purchase Facility Commitment Letter entered into as of January 27, 2017, by and among the Registrant, P&L Receivables Company, LLC and PNC Bank, National Association (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2017).
10.41 Notice Letter and Term Sheet dated as of February 15, 2017, for Amendments to the Receivables Purchase Facility Commitment Letter entered into as of January 27, 2017, by and among the Registrant, P&L Receivables Company, LLC and PNC Bank, National Association (Incorporated by reference to Exhibit 10.128 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2016).
10.42 Settlement Agreement dated as of March 13, 2017 by and among the Registrant, certain subsidiaries of the Registrant, and the United Mine Workers of America 1974 Pension Plan and Trust (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on March 17, 2017).
10.43 Sixth Amended and Restated Receivables Purchase Agreement, dated as of April 3, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed April 3, 2017).
Peabody Energy Corporation 2021 Form 10-K
10.44 First Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of June 30, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various parties identified on the signature pages thereto as Sub-Servicers, Metropolitan Collieries Pty Ltd, and PNC Bank, National Association, as Administrator and as the sole Purchaser Agent, Committed Purchaser, LC Bank and LC Participant on the date thereof (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q, filed August 14, 2017).
10.45 Second Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of December 13, 2017, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, Regions Bank, and PNC Bank, National Association, as Administrator and as the sole Purchaser Agent, Committed Purchaser, LC Bank and LC Participant on the date thereof (Incorporated by reference to Exhibit 10.57 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017).
10.46 Fifth Amendment to the Sixth Amended and Restated Receivables Purchase Agreement, dated as of April 3, 2019, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, all Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 4, 2019).
10.47 Credit Agreement dated as of April 3, 2017, among the Registrant, as Borrower, Goldman Sachs Bank USA, as Administrative Agent, and the other lenders party thereto (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
10.48 Amendment No. 1 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of the Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of September 18, 2017 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed September 18, 2017).
10.49 Amendment No. 2 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of November 17, 2017 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed November 20, 2017).
10.50 Amendment No. 3 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of December 18, 2017 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 19, 2017).
10.51 Amendment No. 4 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of April 11, 2018 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 11, 2018).
10.52 Amendment No. 5 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto and Goldman Sachs Bank USA, as administrative agent, dated as of June 27, 2018 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
10.53 Amendment No. 6 to Credit Agreement, by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the incremental revolving lenders party thereto, Goldman Sachs Bank USA, as existing administrative agent, and JPMorgan Chase Bank, N.A., as successor administrative agent, dated as of September 17, 2019 (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.54 Amendment No. 7 to Credit Agreement by and among Peabody Energy Corporation, the subsidiaries of the Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto, and JPMorgan Chase Bank, N.A., as successor administrative agent, dated as of September 17, 2019 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.55 Amendment No. 8 to Credit Agreement by and among Peabody Energy Corporation, the subsidiaries of Peabody Energy Corporation party thereto as reaffirming parties, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent, dated as of January 29, 2021 (as successor to Goldman Sachs Bank USA in its capacity as administrative agent) (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
10.56 Credit Agreement, dated as of January 29, 2021, among the Co-Issuers, as borrowers, Peabody Energy Corporation, as parent, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
10.57 Credit Agreement, dated as of January 29, 2021, among the Registrant, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
10.58* Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 4.6 of the Registrant’s Registration Statement on Form S-8, filed April 3, 2017).
Peabody Energy Corporation 2021 Form 10-K
10.59 Registration Rights Agreement, dated as of April 3. 2017, among the Registrant and the stockholders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed, April 3, 2017).
10.60 Form of Indemnification Agreement (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.61* Form of Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.7 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
10.62* Form of Restrictive Covenant Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.8 of the Registrant’s Current Report on Form 8-K, filed April 3, 2017).
10.63* Form of Deferred Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.12 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017).
10.64* Form of Performance Share Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan. (Incorporated by reference to Exhibit 10.68 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017).
10.65 Form of Indemnification Agreement (Incorporated by reference to Exhibit 10.73 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.66* Form of Deferred Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.74 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018).
10.67* Form of Restricted Stock Unit Agreement (ELT Level 2019 Special Award) under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.75 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.68* Form of Restricted Stock Unit Agreement (Director Level and Above 2019 Special Award) under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.76 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.69* Form of Deferred Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.70* Form of Restricted Stock Unit Agreement (Director Level and Above 2020 Off-Cycle Award) under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.71* Form of Performance Share Units Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.72* Form of Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.5 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020).
10.73* Form of 2021 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 5, 2021).
10.74* Form of Amendment No. 1 to 2021 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on March 5, 2021).
10.75* † Form of 2022 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (US Employees).
10.76* † Form of 2022 Performance-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (US Employees).
10.77* † Form of 2022 Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (US Employees).
10.78* † Form of 2022 Global Restricted Stock Unit Agreement under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees).
10.79* † Offer of Restricted Stock Units to Australian Resident Grantees under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees).
10.80* † Form of 2022 Service-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees).
Peabody Energy Corporation 2021 Form 10-K
10.81* † Form of 2022 Performance-Based Cash Award Agreement under the Peabody Energy Corporation 2017 Incentive Plan (AUS Employees).
10.82 Agreement, dated as of February 4, 2020, by and among Peabody Energy Corporation, Elliott Investment Management L.P., Elliott Associates, L.P. and Elliott International, L.P. (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed February 5, 2020).
10.83 Management Services Agreement, dated as of August 4, 2020, by and between Peabody Investments Corp. and each of the Client Companies listed on the signature page thereto (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.84 Management Services Agreement, dated as August 4, 2020, by and between Peabody Energy Australia Pty Ltd and each of the Client Companies listed on the signature page thereto (Incorporated by reference to Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.85 Transaction Support Agreement, dated as of November 6, 2020, between Peabody Energy Corporation, certain subsidiaries of Peabody Energy Corporation and the Participating Sureties (Incorporated by reference to Exhibit 10.5 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).
10.86 Transaction Support Agreement, dated as of December 24, 2020, between Peabody, certain subsidiaries of Peabody, the Revolving Lenders, the Administrative Agent, and the Consenting Noteholders (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 28, 2020).
10.87 Amended and Restated Transaction Support Agreement, dated as of December 31, 2020, between Peabody, certain subsidiaries of Peabody, the Revolving Lenders, the Administrative Agent, and the Consenting Noteholders (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed January 4, 2021).
10.88 First Amendment to Amended and Restated Transaction Support Agreement, dated as of January 29, 2021, between Peabody, certain subsidiaries of Peabody, the Revolving Lenders, the Administrative Agent, and the Consenting Noteholders (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed on February 1, 2021).
10.89† Agreement for Irrevocable Standby Letters of Credit, dated as of February 17, 2022, between Peabody and Goldman Sachs Bank USA.
21† List of Subsidiaries.
23.1† Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
23.2† Consents of Qualified Persons for Technical Report Summary for the North Antelope Rochelle Mine.
23.3† Consents of Qualified Persons for Technical Report Summary for the Shoal Creek Mine.
23.4† Consents of Qualified Persons for Technical Report Summary for the Wilpinjong Mine.
23.5† Consents of Qualified Persons for Technical Report Summary for the Coppabella Moorvale Joint Venture.
31.1† Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2† Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1† Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer.
32.2† Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer.
95† Mine Safety Disclosure required by Item 104 of Regulation S-K.
96.1† Technical Report Summary for the North Antelope Rochelle Mine, effective as of December 31, 2021.
96.2† Technical Report Summary for the Shoal Creek Mine, effective as of December 31, 2021.
96.3† Technical Report Summary for the Wilpinjong Mine, effective as of December 31, 2021.
96.4† Technical Report Summary for the Coppabella Moorvale Joint Venture, effective as of December 31, 2021.
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101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
Peabody Energy Corporation 2021 Form 10-K
104 Cover Page Interactive Data File (embedded within the Inline XBRL document).
* These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(a)(3) and 15(b) of this report.
† Filed herewith.
Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the Company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.