The table below summarizes information regarding the operating characteristics of each of ourthe Company’s mines that were active in 2019 in the U.S. and Australia. The mines are listed within their respective miningreporting segment in descending order, as determined by tons soldproduced in 2019.2022.
Coal Supply Agreements
Customers. OurPeabody’s coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of ourthe Company’s sales from ourits 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 ourthe Company’s sales from ourits 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 88%85%, 87%84% and 83%89% of ourthe Company’s worldwide sales from ourits mining operations (by volume) for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, respectively. A recent trend has been for our customers under long-term coal supply agreements to seek contracts of shorter duration.
For the year ended December 31, 2019, we2022, Peabody derived 33%28% of our revenuesits revenue from coal supply agreements from ourits five largest customers. Those five customers were supplied primarily from 4316 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 20202023 to 2025. ThePeabody’s largest customer contributing the greatest amountin 2022 contributed revenue of annual revenue in 2019 was approximately $477$358 million, or approximately 11%7% of our 2019Peabody’s total revenuesrevenue from coal supply agreements, and has contracts expiring at various times from 20212023 to 2023.2024.
Backlog. OurPeabody’s sales backlog, which includes coal supply agreements subject to price reopener and/or extension provisions, was approximately 327314 million and 401283 million tons of coal as of January 1, 20202023 and 2019,2022, respectively. Contracts in backlog have remaining terms ranging from one to seventen years and represent approximately twothree years of production based on our 2019the Company’s 2022 production volume of 164.7122.9 million tons. Approximately 59%62% of ourits backlog is expected to be filled beyond 2020.2023.
Seaborne Mining Operations. RevenuesRevenue from ourPeabody’s Seaborne Thermal Mining and Seaborne Metallurgical Mining segments represented approximately 45%59%, 48%50% and 46%42% of ourthe Company’s total revenuesrevenue from coal supply agreements for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, respectively, during which periods the coal mining activities of those segments contributed respective amounts of 17%18%, 16%18% and 16%19% of ourthe Company’s sales volumes from mining operations. Our productionProduction from these segments is primarily sold into the seaborne thermal and metallurgical markets, with a majority of those sales executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically.periodically, with spot, index and quarterly sales arrangements also utilized. Industry commercial practice, and ourPeabody’s typical practice, is to negotiate pricing for seaborne thermal coal contracts on an annual, spot or index basis and seaborne metallurgical coal contracts on a quarterly, spot or index basis. For ourits seaborne mining operations, the portion of sales volume under contracts with a duration of less than one year represented 29%41% in 2019.2022.
U.S. Thermal Mining Operations. RevenuesRevenue from ourPeabody’s Powder River Basin Mining Westernand Other U.S. Mining and Midwestern U.S.Thermal Mining segments, in aggregate, represented approximately 55%41%, 52%50% and 53%58% of our revenuesthe Company’s revenue from coal supply agreements for the years ended December 31, 2019, 20182022, 2021 and 2017,2020, respectively, during which periods the coal mining activities of those segments contributed respective aggregate amounts of approximately 83%82%, 84%82% and 84%81% of ourthe Company’s sales volumes from mining operations. We expectThe Company expects to continue selling a significant portion of coal production from ourits U.S. thermal miningoperating segments under existing long-term supply agreements, andagreements. Certain customers of those segments generally favorutilize 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. OurPeabody’s approach is to selectively renew, or enter into new, long-term supply agreements when weit can do so at prices and terms and conditions we believeit believes are favorable. Over the last few years, Peabody’s customers have shifted to long-term supply agreements with shorter durations, driven by the reduced utilization of plants and plant retirements, fluidity of natural gas pricing and the increased use of renewable energy sources.
Transportation
Methods of Distribution. Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. OurPeabody’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. OurPeabody’s U.S. and Australian export coal is usually sold at the loading port, with purchasers paying ocean freight. In each case, wethe Company usually paypays 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).
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Peabody Energy Corporation | 2022 Form 10-K | 6 |
The Company believes it has good relationships with U.S. and Australian rail carriers and port and barge companies due, in part, to ourits modern coal-loading facilities and the experience of ourits transportation coordinators. During the year ended December 31, 2022, rail service constraints due, in part, to labor shortages and weather conditions experienced by Peabody’s rail service providers, have negatively impacted U.S. thermal shipment volumes. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.
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Peabody Energy Corporation | 2019 Form 10-K | 6 |
Export Facilities. Our seaborne mining operations sold approximately 71%, 75% and 73% of its tons into the seaborne coal markets for the years ended December 31, 2019, 2018 and 2017, respectively. We havePeabody has generally secured ourits ability to transport coal in Australia through rail and port contracts and access to five east coast coalcoal 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 ourits take-or-pay obligations). In Queensland, seaborne thermal and metallurgical coal from ourthe Company’s mines is exported through the Dalrymple Bay Coal Terminal, in addition to the Abbot Point Coal Terminal used by ourits joint venture Middlemount Mine. In New South Wales, ourthe 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. We havePeabody has secured ourits ability to transport coal from ourits Shoal Creek Mine under barge and port contracts; the primary port is the McDuffie Terminal in Mobile, Alabama, which we utilizethe Company utilizes without a take-or-pay arrangement.
OurPeabody’s U.S. thermal mining operations exported less than 1%, approximately 1% and approximately 1% of itstheir annual tons sold forduring both the years ended December 31, 2019, 20182022 and 2017, respectively.2021. 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 we purchasePeabody purchases in support of ourits mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road tires, steel-related products (including roof control materials), lubricants and electricity. We havePeabody has many well-established, strategic relationships with ourits key suppliers of goods and dodoes not believe that we areit is overly dependent on any of ourits individual suppliers.
In situations where we havePeabody has elected to concentrate a large portion of ourits 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 and/or allow for equipment fleet standardization.supply. Supplier concentration related to ourthe Company’s mining equipment also allows usit to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across ourits global platform, enhancing ourits flexibility to move equipment between mines and reduce working capital through inventory optimization.
Surface and underground mining equipment demand and lead times for parts and components have remained steadyincreased in recent periods. WePeabody consistently use ouruses its global leverage with major suppliers and comprehensive planning processes to ensure security of supply to meet the requirements of ourits active mines.
Services. WePeabody also purchasepurchases services at ourits mine sites, including services related to maintenance for mining equipment, construction, temporary labor, use of explosives and various other requirements. We doPeabody does not believe that we haveit has undue operational or financial risk associated with ourits dependence on any individual service providers.
Throughout 2022, inflationary pressures and supply chain constraints have contributed to rising costs for mining equipment, supplies and services. This trend may continue to impact future periods. Competition
Demand for coal and the prices that wethe Company will be able to obtain for ourits coal are highly competitive and influenced by factors beyond ourthe Company’s control, including but not limited to global economic conditions; the demand for electricity and steel; the cost of alternative fuels, including wind, solar, oil, hydro, nuclear, natural gas and biomass;sources; the impact of weather on heating and cooling demand; the capacity and cost of transportation; geopolitical risks; and taxes and environmental regulations imposed by the U.S. and foreign governments.
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Peabody Energy Corporation | 2022 Form 10-K | 7 |
Thermal Coal
Coal. Demand for ourPeabody’s thermal coal products is impacted by economic conditions,conditions; demand for electricity, including the impact ofwhich is impacted by energy efficient products,products; and the cost of electricity generation from coal and alternative forms of generation. OurRegulatory 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 fuelsfuel sources and the generation of electricity utilizing alternative fuels, with customers focused on securing the lowest cost fuel supply in order to coordinate the most efficient utilization of generating resources in the economic dispatch of the power grid at the most competitive price. Regulatory policies and environmental, social and governance considerations can also have an impact on generation choices and coal consumption.
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Peabody Energy Corporation | 2019 Form 10-K | 7 |
In the U.S., natural gas is highly competitive (along with other alternative fuel sources) with thermal coal for electricity generation. The competitiveness of natural gas has been strengthened by accelerated growth in domestic natural gas production and new natural gas combined cycle generation capacity as well as comparatively low natural gas prices (versus historic levels).capacity. The Henry Hub Natural Gas Prompt Price averaged $2.53$6.54 per mmBtu in 2019,2022, versus $3.07$3.72 and $3.02$2.13 per mmBtu in 20182021 and 2017,2020, respectively. The growth in domestic natural gas production and logistical constraints has led to discounts for regional gas prices versus the Henry Hub price, further driving lower natural gas price trends. In addition, the competitiveness of other alternative fuel sources for electricity generation with coal has been strengthened by the growth of low-cost and government subsidized generation fueled by other alternative fuel sources.renewable energy generation. These pressures, coupled with increasing regulatory burdens, have contributed to a significant number of coal plant retirements. During 2019,2022, approximately 1412 gigawatts of U.S. coal power capacity was retired, and since 2010, U.S. coal power capacity has fallen by more than a quarter.approximately thirty-six percent.
Internationally, thermal coal also competes with alternative forms of electricity generation. The competitiveness and availability of natural gas, liquefied natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Russia, Colombia, the U.S., Russia and South Africa, among others. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, among others. China’s unofficial ban on Australian coal in recent years continued until January 2023 and impeded traditional trade flows. Global thermal coal markets have been turbulent during 2022, due in part to the Russian-Ukrainian conflict and the subsequent ban of Russian coal by European countries.
In addition to ourits alternative fuel source competitors, ourPeabody’s principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners,Partners; American Consolidated Natural Resources, Inc.; Arch Resources, Inc.; CONSOL Energy,Energy; Eagle Specialty Materials LLC, Murray Energy CorporationLLC; 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,plc; BHP; Bumi Resources; China Shenhua Energy,Energy; Coal India Limited,Limited; Drummond Company, Glencore, PT Adaro Energy Tbk, SUEK,Company; Glencore; South32; SUEK; Whitehaven Coal LimitedLimited; and Yancoal Australia Ltd, among others.
Metallurgical Coal
Coal. Demand for ourPeabody’s metallurgical coal products is impacted by economic conditions,conditions; government policies,policies; demand for steelsteel; and competing technologies used to make steel, some of which do not use coal as a manufacturing input. We competeinput, 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 including from leading metallurgical coal exporting countries of Australia, the U.S., Russia, Canada, Mongolia and Mozambique, among others. Trade flow disruptions have occurred during 2022 related to China’s unofficial ban on Australian coal and sanctions imposed on Russian coal imports.
Major international direct competitors (listed alphabetically) include Anglo American, BHP, Glencore, Jellinbah, KRU, Shanxi Coking Coal Group,American; Arch Resources, Inc.; BHP; Foxleigh; Glencore; Jellinbah; KRU; Stanmore; Teck Resources,Resources; Warrior Met Coal; Whitehaven Coal LimitedLimited; and Yancoal Australia Ltd, and , among others.
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Peabody Energy Corporation | 2022 Form 10-K | 8 |
Cybersecurity Risk Management
We usePeabody uses digital technology to conduct ourits business operations and engage with ourits customers, vendors and partners. As we implementthe Company implements newer technologies such as cloud, analytics, automation and “internet of things”,things,” the threats to ourits 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, we continuethe Company continues to evolve ourits risk management approach in an effort to continually assess and improve ourits cybersecurity risk detection, deterrence and recovery capabilities. Ourcapabilities, under oversight from Peabody’s Board of Directors. Peabody’s cybersecurity strategy emphasizes reduction of cyber risk exposure and continuous improvement of ourits cyber defense and resilience capabilities. These include: (i) proactive management of cyber risk to ensure compliance with contractual, legal and regulatory requirements, (ii) performing due diligence on third parties to ensure they have sound cybersecurity practices in place, (iii) ensuring essential business services remain available during a business disruption, (iv) implementing data policies and standards to protect sensitive company information and (v) exercising cyber incident response plans and risk mitigation strategies to address potential incidents should they occur. For more information regarding the risks associated with these matters, see “Item 1A. Risk Factors.”
WorkingHuman Capital
We generally fund our working capital requirements through a combination of existing cash and cash equivalents and proceeds from the sale of our coal production to customers. Our current accounts receivable securitization program and revolving credit facility are also available to fund our working capital requirements to the extent we have remaining availability. Refer to the “Liquidity and Capital Resources” section of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding working capital.
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Peabody Energy Corporation | 2019 Form 10-K | 8 |
Employees
We had approximately 6,6005,500 employees as of December 31, 2019,2022, including approximately 5,0004,300 hourly employees. Additional information on ourits employees and related labor relations matters is contained in Note 24.19. “Management — Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference. Peabody endeavors to engage with its organized workforce and foster strong relationships with those organizations built on trust and communication.
As of December 31, 2022, approximately 3,600 of Peabody’s employees are located in the U.S., with the remainder primarily located in Australia. About 94% of its team members work for mine operations in the U.S. and Australia, while the remaining are based out of its global headquarters in St. Louis or its business offices in Brisbane and Beijing. Peabody strives to create a strong, united workforce with a commitment to safety as a way of life. In 2022, the Company achieved a global safety incidence rate of 1.13 incidents per 200,000 hours worked, which was 59% better than the 2022 U.S. industry average incidence rate of 2.77 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).
Peabody strives to offer an inclusive work environment and engages, recognizes and develops employees. Peabody seeks a workforce that is comprised of diverse backgrounds, thoughts and experiences as a means to drive innovation and excellence within its business, and has formalized inclusion programs and training in policy and practice. Such diversity may also serve to mitigate risks to the business in the current tight labor market. The Company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. Peabody believes in fostering an inclusive work environment built on mutual trust, respect and engagement. Peabody invests in its employees through health and wellness programs, competitive total rewards and development opportunities. Peabody actively seeks employees' feedback, including through surveys and focus groups on its employee value proposition.
The typical Peabody employee has approximately seven years of experience with the company, and more than 47% of all Peabody employees remain employed with the company for more than five years. The Company offers a variety of learning events, including mentoring and development programs to aid its employees in their career growth. During the past five years, approximately 27% of open positions and 64% 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 ourPeabody’s executive officers. Executive officers are appointed by, and hold office at the discretion of, ourPeabody’s Board of Directors, subject to the terms of any employment agreements.
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Name | | Age (1) | | Position (1) |
Glenn L. KellowJames C. Grech | | 5261 | | President and Chief Executive Officer |
Mark A. Spurbeck | | 4649 | | Interim Chief Financial Officer |
A. Verona Dorch | | 52 | | Executive Vice President and Chief LegalFinancial Officer Governmental Affairs and Corporate Secretary |
Charles F. MeintjesDarren R. Yeates | | 5762 | | Executive Vice President and Chief Operating Officer |
Paul V. RichardScott T. Jarboe | | 6049 | | Senior Vice PresidentChief Administrative Officer and Chief Human Resources OfficerCorporate Secretary |
Marc E. Hathhorn | | 4952 | | President - U.S. Operations |
Jamie Frankcombe | | 62 | | President - Australian Operations |
Kemal WilliamsonPatrick J. Forkin III | | 6064 | | President - U.S. OperationsChief Development Officer |
(1) As of February 18, 2020.17, 2023.
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Peabody Energy Corporation | 2022 Form 10-K | 9 |
James C. Grech was named our President and Chief Operating Officer in August 2013; our President, Chief Executive Officer-elect and a director in January 2015; and ourPeabody’s President and Chief Executive Officer in May 2015. Mr. Kellow’s careerJune 2021. He has over 30 years of experience enables him to provide the Company with valuable insights from miner, competitor fuel and industrial customer perspectives. From 1985 to 2013, he worked for BHP Ltd. in the United States, Australianatural resources industry. Mr. Grech served as Chief Executive Officer and South America.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. Kellow hasGrech served as President of Nexus Gas Transmission from October 2016 to July 2018, and previously held chief executive leadership, operatingthe position of Chief Commercial Officer and Executive Vice President of Consol Energy. Mr. Grech brings a strong operational, commercial and financial rolesbackground in globalboth mining and other energy business in the coal, copper, nickel, aluminum, steel, oiloperations and gas sectors.has extensive utilities and capital markets experience. He serves as Chairman of the World Coal Association, a director and executive committee member of the U.S. National Mining Association and the Vice Chairman of the International Energy Agency Coal Industry Advisory Board.Blue Danube. Mr. Kellow is a graduate of the Advanced Management Program at the University of Pennsylvania’s Wharton School of Business,Grech holds a MasterBachelor of Business Administration DegreeScience in Electrical Engineering from Lawrence Technological University and a Bachelor’s Degree in Commercean MBA from the University of Newcastle. He also holds an honorary Doctor of Science degree from the South Dakota School of Mines and Technology.Michigan.
Mark A. Spurbeck was named our InterimPeabody’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 2025 years of accounting and financial experience, most recently serving as the Company’s Senior Vice President and Chief Accounting Officer since March 2018. In this role, he has overseen Peabody’s finance, treasury, tax, internal audit, financial reporting and corporate accounting functions.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, including Group Executive, Assistant Controller. Mr. Spurbeck also previously served in several financial positions at 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.
A. Verona DorchDarren R. Yeates was named our Executive Vice President, Chief Legal Officer, Governmental Affairs and Corporate Secretary in August 2015. In this role, she has executive responsibility for providing comprehensive legal and government relations counsel for Peabody’s business activities and leads the Company’s global legal, government affairs and compliance functions. Ms. Dorch has close to 25 years of legal experience counseling diverse global businesses. Prior to joining Peabody, from 2006 to March 2015, she served in a variety of roles for Harsco Corporation, a leading global industrial services company, where she advised the leadership team and board on strategic legal and business initiatives, most recently serving as Chief Legal Officer, Chief Compliance Officer and Corporate Secretary. She also has experience in corporate and securities law from top-tier law firms and with Sumitomo Chemical Co. following a multi-year secondment in Tokyo, Japan. Ms. Dorch is a Fellow of the American Bar Foundation and is a member of the board of directors of Enterprise Bank & Trust, a regional bank with over $5.5 billion in assets, and is a member of the boards of directors of Girls Inc. (St. Louis) and the United Way (St. Louis). Ms. Dorch holds a Bachelor’s Degree from Dartmouth College and a Juris Doctor degree from Harvard Law School.
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Peabody Energy Corporation | 2019 Form 10-K | 9 |
Charles F. Meintjes was named our Executive Vice President - Corporate Services and Chief Commercial Officer in April 2017 and our Executive Vice President and Chief Operating Officer in July 2019. Mr. MeintjesOctober 2020. He has executive responsibility for operations, sales and marketing and technical services. Mr. MeintjesYeates has extensive senior operational, strategy, continuous improvement and information technology experience withover 35 years of mining companies on three continents. He has also led financial and technical functions, large re-engineering programs, information technology system implementations and large industrial construction projects. He joined us in 2007, and priorindustry experience. From May 2018 to serving in his current post, he was our President - Australia. Other past positions with us include Acting President - Americas, Group Executive of Midwest and Colorado Operations, Senior Vice President of Operations Improvement and Senior Vice President Engineering and Continuous Improvement. Prior to joining us,December 2019, Mr. MeintjesYeates served as Chief Operating Officer of MACH Energy Australia, a consultantdeveloper and supplier of thermal coal to Exxaro Resources Limited in South Africa,both the Australian domestic and is a former Executive Director and Board Member for Kumba Resources Limited in South Africa. He has senior management experience in the steel and the aluminum industries with Iscor and Alusaf in South Africa.Asian export markets. From January 2014 until June 2016, Mr. Meintjes holds dual Bachelor of Commerce degrees in accounting from Rand Afrikaans University and the University of South Africa. He is a Chartered Accountant in South Africa and completed the advanced management program at the University of Pennsylvania’s Wharton School of Business.
Paul V. Richard was named our Senior Vice President and Chief Human Resources Officer in November 2017. He has executive responsibility for organizational and employee development, benefits, compensation, international human resources, security, travel and facilities management. Mr. Richard has more than 30 years of human resources experience and has been instrumental in leading his prior organizations to achieve Great Place to Work and Top Training Organization designations. From 2002 to May 2017, Mr. RichardYeates served as Vice President - Human Resources for Shaw Industries Group, Inc.,the Chief Executive Officer of GVK Hancock Coal, a leading flooring materials producer and a subsidiaryjoint venture developing the vast potential of Berkshire Hathaway, Inc.the Galilee Basin in Central Queensland. Prior to that, he served as a human resources leader for 19spent over 22 years at Ferro Corporation,with Rio Tinto, a global supplier of technology-based manufacturing,mining group, including fouras 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 as Vice President - Human Resources.for BHP, a mining, metals and petroleum company, in coal operations and metalliferous exploration. Mr. RichardYeates holds a Bachelor of Science DegreeEngineering (Mining) from the University of Queensland, a Graduate Diploma in Management from the University of Central Queensland and a MastersGraduate Diploma of Applied Finance and Investment from the Securities Institute of Australia. He holds an Executive MBA from the Monash Mt Eliza Business AdministrationSchool and is a Fellow of the Australian Institute of Company Directors.
Scott T. Jarboe was named Peabody’s Chief Administrative Officer and Corporate Secretary in November 2021 after serving as Chief Legal Officer and Corporate Secretary since March 2020. He leads the Company’s global human resources, legal, government affairs, and ethics and compliance functions. Mr. Jarboe joined Peabody in 2010 and has served in a variety of legal roles. Previously, Mr. Jarboe practiced law with Husch Blackwell LLP and Bryan Cave LLP. Mr. Jarboe holds a Bachelor of Arts Degree from Louisiana Tech University.the University of Kansas, a Master’s Degree from the University of Missouri – Kansas City and a Juris Doctor degree from Washington University School of Law.
Marc E. Hathhorn was named ourPeabody’s President - AustralianU.S. Operations in August 2019.November 2021. He has executive responsibility for our Australianthe Company’s U.S. operating platform, which includes overseeing the areasleadership of health, safety and safety, operations,environment, people, operational performance and product delivery and support functions.delivery. Mr. Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America.America and in Australia. Mr. Hathhorn joined usPeabody in 2011 as our Senior Vice President - Midwest Operations, and subsequently served as our Group Executive - Americas Operations Support from 2013 to 2016, and Group Executive - Americas Operations from 2016 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.
Kemal Williamson was named our President - Americas in October 2012 and his title was updated to President - U.S. Operations in June 2019. He has executive responsibility for our U.S. operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions. Mr. Williamson has more than 30 years of experience in mining engineering and operations roles across North America and Australia. He most recently served as Group Executive of Operations for the Peabody Energy Australia operations. He also has held executive leadership roles across project development, as well as in positions overseeing our Western U.S., Powder River Basin and Midwest operations. Mr. Williamson joined us in 2000 as Director of Land Management. Prior to that, he served for two years at Cyprus Australia Coal Corporation as Director of Operations and managed coal operations in Australia for half a decade. He also has mining engineering, financial analysis and management experience across Colorado, Kentucky and Illinois. Mr. Williamson holds a Bachelor of Science Degree in Mining Engineering from Pennsylvania State University as well as a Master of Business Administration Degree from the Kellogg School of Management, Northwestern University in Evanston, Illinois.
Filing Under Chapter 11 of the United States Bankruptcy Code
On April 13, 2016, Peabody and a majority of its wholly owned domestic subsidiaries as well as one international subsidiary in Gibraltar (collectively with Peabody, the Debtors) filed voluntary petitions for reorganization under Chapter 11 of Title 11 of the U.S. Code in the U.S. Bankruptcy Court for the Eastern District of Missouri (the Bankruptcy Court). The Debtors’ Chapter 11 cases (collectively, the Chapter 11 Cases) were jointly administered under the caption In re Peabody Energy Corporation, et al., Case No. 16-42529 (Bankr. E.D. Mo.).
On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763, confirming the Debtors’ Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan). On April 3, 2017 (the Effective Date), the Debtors satisfied the conditions to effectiveness set forth in the Plan, the Plan became effective in accordance with its terms and the Debtors emerged from the Chapter 11 Cases.
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Peabody Energy Corporation | 20192022 Form 10-K | 10 |
On March 22, 2017, a group of creditors (the Ad Hoc Committee) that held certain interestsJamie Frankcombe was named Peabody’s President - Australian Operations in November 2021. He has executive responsibility for the Company’s prepetition indebtedness appealed the Bankruptcy Court’s order confirming the Plan, requesting that the United States District Court for the Eastern DistrictAustralian operating platform, which includes leadership of Missouri (the District Court) reverse the Bankruptcy Court’s confirmationhealth, safety and environment, people, operational performance and product delivery. He is a senior mining executive with 30 years of the Planexperience in developing and managing large-scale open cut and underground coal, iron ore, copper and gold mines in Australia, Indonesia, Asia and the order approvingAmericas. Prior to joining Peabody, Mr. Frankcombe served as Deputy Managing Director for Phu Bia Mining in Laos managing the Private Placement AgreementPhu Kham (copper & gold) and Backstop Commitment Agreement. On December 29,Ban Houayxai (gold & silver) operating assets from June 2021 to November 2021. Prior to that, Mr. Frankcombe served as Integration Team Lead with Aurelia Metals Ltd from November 2020 to April 2021 with the responsibility of integrating the Dargues Gold Mine project and operations into the Aurelia Metals Ltd portfolio. Prior to that, he spent seven years as Chief Operating Officer for Whitehaven Coal Mining Ltd., overseeing operational and safety leadership of four open cut coal mines and one underground mine. In addition, he served as a director of Coal Services Pty Ltd. from September 2017 to July 2021. Mr. Frankcombe holds a Bachelor of Engineering (Mining) from University of Wollongong and a Master of Business Administration (Technology) from Deakin University.
Patrick J. Forkin III was named Chief Development Officer in July 2022 after serving as Senior Vice President - Corporate Development and Strategy since November 2017. He leads global strategy, mergers and acquisitions, portfolio management, U.S. thermal coal sales and renewable energy development. Mr. Forkin joined Peabody in 2010 and has served in a variety of roles. He has an extensive background in corporate finance, the District Court entered an order dismissing the Ad Hoc Committee’s appeal,energy industry, mergers and acquisitions and equity market research. Prior to joining Peabody, Mr. Forkin was in the alternative, affirming the order confirming the Plan. On January 26, 2018, the Ad Hoc Committee appealed the District Court’s order to the United States Court of Appeals for the Eighth Circuit (the Eighth Circuit). In its appeal, the Ad Hoc Committee asked the Eighth Circuit to award the Ad Hoc Committee members either unspecified damages or the right to buy an unspecified amount of Company stocksenior leadership roles at a discount. Oral argument onU.S. solar development company and investment banking firms specializing in renewable and conventional energy. He spent the appeal was held April 16, 2019,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 the Eighth Circuit issuedis a unanimous opinion in Peabody’s favor on August 9, 2019. The Ad Hoc Committee did not seek rehearing or petition the Supreme Court for certiorari by the deadline of November 7, 2019.Certified Public Accountant (inactive).
Upon emergence, in accordance with Accounting Standards Codification (ASC) 852, we applied fresh start reporting to our consolidated financial statements as of April 1, 2017 and became a new entity for financial reporting purposes reflecting the Successor (as defined below) capital structure. As a new entity, a new accounting basis in the identifiable assets and liabilities assumed was established with no retained earnings or accumulated other comprehensive income (loss). For additional details, refer to Note 1. “Summary of Significant Accounting Policies” and Note 2. “Reorganization Items” to the accompanying consolidated financial statements.
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. We believePeabody believes that we haveit has obtained all permits currently required to conduct ourits present mining operations.
We endeavorThe Company endeavors to conduct ourits 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.
Mine Safety and Health
We arePeabody is subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.
The MSHA is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA employs various enforcement measures for noncompliance, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine.
In Part I, Item 4. “Mine Safety Disclosures” and in Exhibit 95 to this Annual Report on Form 10-K, we providethe Company provides additional details on MSHA compliance.
Black Lung (Coal Workers’ Pneumoconiosis)
Black Lung Benefits. Under the U.S. Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator who was the last to employ a claimant for a cumulative year of employment, with the last day worked for the operator after July 1, 1973, must pay federal black lung benefits and medical expenses to claimants whose claims for benefits are allowed. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. 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 trust fund has been funded by an excise tax on U.S. production. In 2008, the excise tax rates were set through December 31, 2018 at $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. On January 1, 2019 the rate reverted back to $0.50 per ton of underground coal and $0.25 per ton of surface coal, not to exceed 2% of the gross sales price. In December of 2019, legislation was passed that increased the rate for the year ending December 31, 2020. The enacted legislation mandates the previous rates of $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
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Peabody Energy Corporation | 2019 Form 10-K | 11 |
We recognized expense related to the tax of $31.4 million, $78.6 million, $60.9 million and $20.1 million for the years ended December 31, 2019 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017, respectively.
The Affordable Care Act includesincluded significant changes to the federal black lung program including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have
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Peabody Energy Corporation | 2022 Form 10-K | 11 |
The trust fund has been funded by an excise tax on U.S. production. As a material impactresult of legislation enacted in December 2020, the excise tax rates were set at 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal for the year ending December 31, 2021. This enacted legislation expired on our costs expendedDecember 31, 2021 and the excise tax rates reverted back to 2% of the gross sales price not to exceed $0.50 per ton of underground coal and $0.25 per ton of surface coal. Effective October 1, 2022, the excise tax rates reverted back to 4.4% of the gross sales price not to exceed $1.10 per ton of underground coal and $0.55 per ton of surface coal due to the enactment of the Inflation Reduction Act of 2022.
Peabody recognized expense related to the tax of $32.4 million, $51.5 million and $53.3 million for the years ended December 31, 2022, 2021 and 2020, respectively. During the year ended December 31, 2022, Peabody recognized additional expense of approximately $8 million as a result of the higher excise tax rates.
Black Lung Benefits Act Self-Insurance Requirements. The Black Lung Benefits Act requires each coal mine operator to secure the payment of its potential benefits liability by either qualifying as a self-insurer or by purchasing and maintaining a commercial insurance contract. The Department of Labor’s (DOL) Office of Workers’ Compensation Programs (OWCP) is responsible for authorizing coal mine operators to self-insure and for setting the security amounts. As part of its ongoing efforts to reform the self-insurance program to ensure that operators are adequately securing their liabilities, the OWCP proposed a rule in association withJanuary 2023 to update its regulations for authorizing operators to self-insure and for determining appropriate security amounts. The public comment period for the federalproposed rule ends March 20, 2023.
A change in requirements for security posted to self-insure black lung program.liabilities could result in the Company being required to post additional security for its obligations. At the request of OWCP, the Company recently refiled its application for self-insurance.
Environmental Laws and Regulations
We arePeabody is subject to various federal, state, local and tribal environmental laws and regulations. These laws and regulations place substantial requirements on ourits coal mining operations, and require regular inspection and monitoring of ourits mines and other facilities to ensure compliance. We areThe Company is also affected by various other federal, state, local and tribal environmental laws and regulations that impact ourits 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. Except for Arizona, statesStates in which we havePeabody has active mining operations have achieved primacy control of enforcement through federal authorization. In Arizona, we minewhere Peabody performs reclamation work on tribal lands, and arethe Company is regulated by the OSMRE because the tribes do not have SMCRA authorization.
SMCRA provides for three categories of bonds: surety bonds, collateral bonds and self-bonds. A surety bond is an indemnity agreement in a sum certain payable to the regulatory authority, executed by the permittee as principal and which is supported by the performance guarantee of a surety corporation. A collateral bond can take several forms, including cash, letters of credit, first lien security interest in property or other qualifying investment securities. A self-bond is an indemnity agreement in a sum certain executed by the permittee or by the permittee and any corporate guarantor made payable to the regulatory authority.
OurThe Company’s total reclamation bonding requirements in the U.S. were $1,263.9$1,035.0 million as of December 31, 2019.2022. 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. OurThe Company’s asset retirement obligations calculated in accordance with generally accepted accounting principles for ourits active and inactive U.S. operations were $527.9$533.3 million as of December 31, 2019.2022. The bond requirement amount for ourthe 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.immediately, as well as different assumptions related to the cost of equipment and services utilized in the reclamation process.
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Peabody Energy Corporation | 2022 Form 10-K | 12 |
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 ourthe 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 iswas $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. WeAs 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 $36.5$21.7 million, $40.9 million, $31.6$27.0 million and $10.3$28.4 million for the years ended December 31, 20192022, 2021 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017,2020, respectively.
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Peabody Energy Corporation | 2019 Form 10-K | 12 |
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect ourthe Company’s U.S. coal mining operations both directly and indirectly.
Direct impacts on coal mining and processing operations may occur through theNational Ambient Air Quality Standards (NAAQS). The CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), nitrogen dioxide, ozone and sulfur dioxide (SO2). In recent years,requires the United States Environmental Protection Agency (EPA) has adopted more stringentto review national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO2. It is possible that these modifications, as well as future modificationsevery five years to NAAQS, could directly or indirectly impact our mining operations in a manner that includes, but is not limiteddetermine whether revision to designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle emissioncurrent standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.
In 2009,are appropriate. As part of this recurring review process, the EPA adopted revised rulesin 2020 proposed to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. The PM NAAQS was thereafter revised and made more stringent in 2012. In 2015, the EPA issued a final rule settingretain the ozone NAAQS at 70 parts per billion (ppb). (80 Fed. Reg. 65,292 (Oct. 25, 2015)).promulgated in 2015, including both the primary (public health) and secondary (public welfare) standards. The primary ozone standard was upheld byEPA subsequently promulgated final standards to this effect. In 2021, fifteen states and other petitioners 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 Murray Energy v. EPA, (D.C. Cir. 2019), Slip Op. 15-1385. The court, however, remanded the secondary ozone NAAQS standard toabeyance following a motion filed by the EPA and vacated a “grandfathering” provision concerning the useto allow for review of the prior ozone NAAQS in certain permitting actions.standards.
The EPA also proposed in 2020 to retain the particulate matter (PM) NAAQS 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 additionally considering revisionscurrently in abeyance following a motion filed by the EPA to the 2015 PM NAAQS as partallow for review of the periodic review process required bystandards. On January 6, 2023, the CAA, with any revisionsEPA proposed to lower the standards projected for late 2020,level of the same timeframe as it contemplates possible revisions forannual PM2.5 NAAQS from 12.0 ug/m3 to within the 2015 ozone NAAQS. range of 9.0 to 10.0 ug/m3.
More stringent PM or ozone standards would require new state implementation plans to be developed and filed with the EPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxidedioxide (NO2) and SOsulfur dioxide (SO2), although these standards are not subject to a statutorily-required review until 2023 for NO2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQSand 2024 for SO2 of 75 ppb averaged over an hour.2.
The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of SO2, nitrogen oxides, mercury, PM and other substances emitted by coal-fueled electricity generating plants, imposing more capital and operating costs on such facilities. In addition, other CAA programs may require further emission reductions to address the interstate transport of air pollution or regional haze. The air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution Rule (CSAPR) and the CSAPR Update Rule,Final New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and source permitting programs, including requirements related to New Source Review.
In addition, since 2011, the EPA has required underground coal mines to report on their greenhouse gas emissions. Regulations regarding reporting requirements for underground coal mines were updated in 2016 and now include the ability to cease reporting if mines are abandoned and sealed. At present, however, the EPA does not directly regulate such emissions.
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).
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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. Thus, the NSPS remains in effect.
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On December 6,20, 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. The proposal now defines(83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the Best System of Emission Reduction (BSER)2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA has notedindicated that the primary reason for this proposed revision isrevising BSER was the high costscost and limited geographic availability of carbon capture and storage technology. The comment periodStatus 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 concluded on February 19, 2019.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 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 (GHG) emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline).
Following Federal Register publication, 39 separate petitions for review of the CPP by approximately 157 entities were filed in the D.C. Circuit. The petitions reflected challenges by 27 states and governmental entities, as well as by utilities, industry groups, trade associations, coal companies and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (in which other states also joined) (D.C. Cir. No. 15-1363). On October 29, 2015, we filed a motion to intervene in the case filed by West Virginia and Texas, in support of the petitioning states. The motion was granted on January 11, 2016. Numerous states and other entities also intervened in support of the EPA.
On February 9, 2016, the U.S. Supreme Court granted a motion to stay implementation of the CPP until the legal challenges were resolved. Thereafter, oral arguments in the case were heard in the D.C. Circuit sitting en banc. On April 28, 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance while the agency reconsidered the rule. The D.C. Circuit case has been in abeyance since, so no opinion has been issued.
In October 2017, the EPA subsequently proposed to repeal the CPP. (82 Fed. Reg. 48,035 (Oct. 16, 2017)). InCPP and in August 2018 the EPA issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule. (83 Fed. Reg. 44,746 (August 31, 2018)). OnIn June 19, 2019, the EPA issued a combined package that finalizesfinalized the CPP repeal rule as well as the replacement rule, ACE. Repeal of the Clean Power Plan; Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations, EPA-HQ-OAR-2017-0355.
The final ACE rule sets emissions guidelines for greenhouse gasGHG emissions from existing EGUs based on usinga determination that efficiency heat rate improvements as “Best System of Emission Reduction” measures. The EPA’s final rule also revisesconstitute the CAA Section 111(d) regulations to give the states greater flexibility on the content and timing of their state plans. Proposed revisions to the regulations under the New Source Review (NSR) program that were part ofBSER. Numerous petitions for review challenging the ACE proposalRule were separated, and the EPA indicated that it intends to take final action on the proposed NSR program reforms at a later date.
Based on the EPA’s final rules repealing and replacing the CPP, petitionersfiled in the D.C. Circuit matterand 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 of the United States (Supreme Court) granted certiorari in four consolidated matters seeking review of the D.C. Circuit’s opinion vacating the ACE rule and invalidating the repeal of the CPP. On June 30, 2022, the Supreme Court issued its opinion in West Virginia v. EPA, No. 20-1530. The Supreme Court ruled that the EPA does not have Congressional authority under Section 111(d) of the CAA to limit emissions at existing power plants through generation shifting to other fuels and/or renewable energy, but still can regulate emissions at plants by emissions reductions technologies as the EPA has done in the past. The D.C. Circuit’s opinion was reversed and remanded, leaving neither the CPP including Peabody, filed a motion to dismiss, which the court granted in September 2019. Meanwhile, challengers toor the ACE Rule have filed petitionsin effect. Thus, it will be necessary for judicial review, and thatthe EPA to initiate new litigation is expectedrulemaking in order to control GHG emissions from EGUs using section 111(d) of the CAA. The EPA tentatively plans to propose emission guidelines for EGUs in 2023. The Company will continue into 2020.to monitor EPA rulemaking in this regard.
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 (SIP) providing this authority.
Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. On July 6,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. Following litigation in the D.C. Circuit and U.S. Supreme Court, the first phase of the nitrogen oxide and SO2 emissions reductions required by CSAPR commenced in January 2015; further reductions of both pollutants in the second phase of CSAPR became effective in January 2017. The EPA subsequently revised CSAPR requirements for the state of Texas to remove that state from second phase requirements regarding SO2 (82 Fed. Reg. 45,481 (Sept. 29, 2017)).
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Peabody Energy Corporation | 2019 Form 10-K | 14 |
On October 26,In 2016, the EPA published the final CSAPR Update Rule to address implementation of the 2008 ozone NAAQS. This rulewhich imposed furtheradditional reductions in nitrogen oxides emissions(NOx) beginning in 2017 in 22 states subject to CSAPR. Several states and utilities as well as agricultural and industry groups filed petitions for review of the CSAPR Update Rule in the D.C. Circuit. On September 13, 2019, the CSAPR Update RuleThis rule was subsequently remanded back to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines.EPA. Wisconsin v. EPA, No. 16-1406 (D.C. Cir. 2019). At this time, it is unknown whether rehearing will be sought.938 F.3d 303.
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In April 2021, the EPA published a final rule in the Federal Register to address the D.C. Circuit remand. This rule imposed further reductions of NOx emissions in 12 states that were subject to the original 2016 rule, which was based on the 2008 ozone NAAQS.
In 2018,the same rule, the EPA alsodetermined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions. The EPA subsequently issued a final determination thatFederal Implementation Plans (FIPs) to lower state ozone season NOx budgets in 2021 to 2024 in the existing CSAPR Update fully addressedaffected states. A petition for review challenging the CAA’s “good neighbor” requirements for 20 states with respect to the 2008 NAAQS for ground-level ozone. (83 Fed. Reg. 65,878 (Dec. 21, 2018)).This determination2021 rule was also challengedfiled in the D.C. Circuit (No. 19-1019). On October 1, 2019,Circuit. Briefing is completed and oral arguments were held September 28, 2022, but this does not stay the D.C. Circuit issued a judgment vacating this rule on the basiseffectiveness of the court’s decisionrule.
On April 6, 2022, the EPA proposed FIPs to address regional ozone transport for the 2015 ozone NAAQS. The proposed rule would result in new ozone season emission budgets for NOWisconsin v.x in 25 states, including four Western states, and additionally contains provisions that would require daily “backstop” emission limits for coal-fired power plants over 100 megawatts. The proposed rule would also set first-time limits on certain industrial sources. The EPA. At this time, it is unknown whether rehearing estimates that by 2026 the compliance cost will be sought.$1.1 billion. These emission limitations would apply in addition to requirements contained in State Implementation Plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16,in 2012. The MATS rule revised the NSPS for nitrogen oxides,NOx, SO2 and PM for new and modified coal-fueled electricity generating plants, and imposed MACTmaximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. The rule provided three years for compliance with MACT standards and a possible fourth year if a state permitting agency determined that such was necessary for the installation of controls.
Following issuance of the final rule, numerous petitions for review were filed. The D.C. Circuit upheld the NSPS portion of the rulemaking in a unanimous decision on March 11, 2014, and upheld the limits on HAPs against all challenges on April 15, 2014, in a two-to-one decision. Industry groups and a number of states filed and were granted review of the D.C. Circuit decision in the U.S. Supreme Court. On June 29, 2015 the U.S. Supreme Court held that the EPA interpreted the CAA unreasonably when it deemed cost irrelevant to the decision to regulate HAPs from power plants. The court reversed the D.C. Circuit and remanded the case for further proceedings. On December 1, 2015, in response to the court’s decision the EPA published a proposed supplemental finding in the Federal Register that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.
On April 14, 2016,In 2020, the EPA issued a final supplementalrule reversing a prior finding and determined that largely tracked its proposed finding. Several states, companiesit is not “appropriate and industry groupsnecessary” 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 electricity utility generating units source category. Both actions were challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated (D.C. Cir. No. 116-1127). Several states and environmental groups also filed as intervenors for the respondent EPA. Although briefing inbut this litigation has concluded, the case remainswas placed in abeyance.
On December 27, 2018,February 9, 2022 the EPA issuedproposed a proposed revised Supplemental Cost Finding for the MATS rule that wouldto revoke the determination2020 finding and to reaffirm the agency’s 2016 finding that regulating HAPs from coal-fired power plants isit remains “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants under Section 112(n)(1)(A)112 of the CAA. In the same proposal, the EPA solicited comments on the performance and cost of new or improved technologies to control HAPs from these power plants as part of the agency’s review of related residual risk and technology review standards.
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.
New Source Review (NSR). The Clean Air Act imposes permitting requirements when a new proposed finding was based onsource undergoes construction or when an EPA assessment that health and environmental benefits from the MATS rule thatexisting source is reconstructed or undergoes a major modification. These requirements are not directly related to mercury pollution should not be includedcontained in the benefit portion of the analysis. In the new proposed cost-benefit analysis,CAA’s PSD and Nonattainment New Source Review (NNSR) programs, generally referred to as NSR. On August 4, 2020, the EPA foundreleased a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the costs “grossly outweigh” any possible benefits. The comment period for this proposed rule closed in spring 2019 with overNew Source Review Regulations). PALs allow sources to make physical and operational changes under a half million public comments filed. The final rule was expected in the fall but stalled after being sent to the White House in October 2019 for final review before public release. It is unclear when the final rule will be published.plantwide emission limit without “triggering” NSR.
The EPA Science Advisory Board, made uphas also taken action on a number of non-EPA scientistsdifferent rules and experts who reviewguidance affecting the EPA’s basis for regulatory decisions, recommended in December 2019 thatinterpretation and application of NSR. In a final rule (83 Fed. Reg. 57,324 (Nov. 15, 2018)), the EPA conductcompleted reconsideration of a new risk assessment2009 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 and the rule.EPA has also taken steps to review and potentially revise previously issued rules and guidance, including those related to project emissions accounting and fugitive emissions. PSD rules, guidance and memorandum may affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis.
The plan would leave the emissions standards | | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 15 |
Federal Coal Leasing Moratorium. MoratoriumPresident Trump’s. 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 September 2018, WyomingApril 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 Montana opposedFinding of No Significant Impact (FONSI) remedied the suits inprior NEPA violations. Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI. On August 12, 2022, the court invalidated the Environmental Assessment and defended againstFONSI and reinstated the freeze possibly being reinstated. This litigationmoratorium until completion of a sufficient NEPA analysis. The August 2022 decision is ongoing.currently on appeal to the U.S. Court of Appeals for the Ninth Circuit.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
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Peabody Energy Corporation | 2019 Form 10-K | 15 |
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. On August 9, 2019, theThe EPA issued a proposedfinal rule intended to clarify the scope of the state or tribal regulators’ authorityin 2020 that if adopted in its current form, would in effectcould limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections.objections in some circumstances. That rule was temporarily vacated by a district court, but a Supreme Court order on April 7, 2022, effectively reinstated the rule. The comment periodEPA issued another proposal in June 2022 that would supersede the 2020 rule and expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. Comments for this proposed rule closed on October 21, 2019.
Awere due August 8, 2022 and final rule defining the scopeis expected in early 2023.
CWA Definition of waters protected under the CWA (commonly called the Waters“Waters of the United States, or WOTUS) (WOTUS Rule), was published by the EPA and the Corps in June 2015. Several states and others subsequently filed lawsuits challenging the WOTUS Rule. On October 22, 2019, the EPA and the Corps jointly published a final rule, which became effective on December 23, 2019, repealing the WOTUS Rule and recodifying the regulatory definitions of WOTUS that existed prior to the implementation of the WOTUS Rule. Several states subsequently filed a lawsuit against the EPA, claiming that the rollback of protections for certain U.S. waterways pursuant to the final rule is arbitrary, capricious and not in accordance with law. OnStates”. In January 23, 2020 the EPA and the Corps finalized the Navigable Waters Protection Rule to definerevise 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 30, 2022, the agencies released the pre-publication version of a final rule that formally repeals the Navigable Waters Protection Rule and codifies a revised definition of “Waters of the United States” that is generally consistent with the pre-2015 regulatory framework that they are currently implementing. The final rule will become effective 60 days after publicationwas published in the Federal Register. Once effective, it replacesRegister on January 18, 2023 and takes effect on March 20, 2023. In addition, the rule publishedSupreme Court is currently considering Sackett v. EPA, No. 21-454, a case involving the scope of federal regulatory authority over wetlands. The Court heard oral arguments on October 22, 2019.3, 2022, and the opinion is forthcoming. Depending on the outcome of that case, the agencies may need to revisit the most recent rulemaking.
Effluent Limitations Guidelines for the Steam Electric Power Generating IndustryIndustry. . 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 April 12, 2019, the U.S. Court of Appeals for the Fifth Circuit agreed with environmental groups that the portions of the rule regulating legacy wastewater and residual combustion leachate are unlawful. The Court vacated those portions of the rule. On November 22, 2019,October 13, 2020, the EPA issued a proposedfinal rule to reviserevising 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. The comment period for this proposed rule closed on January 21, 2020. IfEPA expects to issue that proposal in early 2023. As finalized, the proposed rule is adopted in its current form, therevised effluent limitations guidelines willcould significantly increase costs for many coal-fired steam electric power plants.
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Peabody Energy Corporation | 2022 Form 10-K | 16 |
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. WePeabody must provide information to agencies when we proposeit proposes actions that will be under the authority of the federal government. The NEPA process involves public participation and can involve lengthy timeframes. The White House Council on Environmental Quality (CEQ) issued an Advance Noticea 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 Proposed RulemakingNEPA reviews, among other things. States and environmental groups have filed several lawsuits challenging the final rule. On April 20, 2022, however, the CEQ published the final Phase 1 rule that partially amended the 2020 rule by restoring key provisions of the pre-2020 NEPA regulations. The CEQ plans to propose a Phase 2 rule in June 2018 seeking commentthe near future that makes broader changes to the 2020 rule. Separately, the CEQ published NEPA Guidance on a numberConsideration of ways to streamlineGreenhouse Gas Emissions and improveClimate Change on January 9, 2023. The interim guidance was effective immediately, though the NEPA process. The comment period closed in August��2018. Itagency is unclear how far reachingaccepting comments on the changes will be and if they will be able to withstand expected court challenges.guidance.
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. The U.S. Court of Appeals for the D.C. Circuit held that certain provisions of the EPA’s CCR rule were not sufficiently protective, and it invalidated those provisions. On December 2, 2019, the EPA issued a proposed rule to implement amended rules regarding CCR in response to the court decisions. The comment period for this proposed rule closed on January 31, 2020. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardoushazardous.
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Peabody Energy Corporation | 2019 Form 10-K | 16 |
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 July 2023. Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision. The EPA expects to finalize additional revisions in August 2023.
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 ourPeabody’s costs or ourits ability to mine some of ourits properties in accordance with ourits current mining plans. The DepartmentDuring the Trump Administration, the Departments of the Interior and Commerce issued three proposedfinalized five rules in 2018 aiming to streamline and update the ESA. But in June 2021, agencies announced their plan to revise, rescind, or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives. The three finalagencies plan to begin issuing proposed rules became effective on September 26, 2019.in mid-2023.
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Peabody Energy Corporation | 2022 Form 10-K | 17 |
Use of Explosives. OurPeabody’s surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incurit 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.
Grid Resiliency Pricing Rule. On October 10, 2017, the Secretary of Energy (the Secretary) published a Notice of Proposed Rulemaking entitled the Grid Resiliency Pricing Rule (the Proposed Rule). The Proposed Rule was issued by the Secretary pursuant to Section 403 of the Department of Energy Organization Act. (42 U.S.C. § 7173). In the Proposed Rule, the Secretary instructed the Federal Energy Regulatory Commission (FERC) to impose rules to ensure that reliability and resiliency attributes of certain electric generation units with a 90-day on-site fuel supply are fully compensated for the benefits and services they provide to grid operations. The Secretary directed FERC to take final action on the Proposed Rule within 60 days of publication or, in the alternative, to issue the rule as an interim final rule immediately, with provision for later modifications after consideration of public comments. The Proposed Rule cites the retirements of coal and nuclear plants as a potential threat to grid reliability and resilience, and provides for the creation of a “reliability and resiliency rate” that would compensate certain eligible resources for the benefits and services they provide to grid operations, allowing such eligible resources to recover their fully allocated costs and a fair return on equity. The “reliability and resiliency rate” would be available to eligible resources operating within FERC-approved independent system operators or regional transmission organizations with energy and capacity markets. The rate would apply only to generators that are not currently subject to cost-of-service regulation by a state or other authority. On January 8, 2018, FERC unanimously denied the petition and requested additional information from power grid operators thus putting off any new rulemaking by at least two months, dismissing the Secretary’s call to act immediately. FERC has opened a new proceeding to “take additional steps to explore resilience issues in the [regional transmission organizations and independent system operators].” That docket will aim to develop an understanding of what resilience actually means for the grid and to understand how each grid operator addresses the issue.
Wyoming Land Quality Division Self-Bonding Rules. On August 20, 2018, the Wyoming Land Quality Division, through the Land Quality Advisory Board, offered for public comment proposed changes to self-bonding rules related to reclamation obligations. The proposal included requiring that the self-bonding guarantor be the ultimate parent company and that the maximum amount of bonding be limited to 75% of the company’s calculated bond amount. Additionally, the proposal required the self-bonding party to be of investment grade quality using ratings issued by nationally recognized credit rating services, such as Moody’s Investor Service or Standard and Poor’s Corporation. This requirement would replace the current qualifying tests using a bonding party’s audited financial statements. The proposed rule was approved by the Wyoming Land Quality Advisory Board on September 19, 2018, and the Environmental Quality Counsel on February 19, 2019. It was signed by the governor of Wyoming on May 3, 2019. The Company currently meets all its bonding obligations in Wyoming through the use of commercial surety bonds. Under the new rules, the Company does not qualify for self-bonding based on its current credit rating.
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Peabody Energy Corporation | 2019 Form 10-K | 17 |
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.
SEC Climate-Related Disclosures. On March 21, 2022, the SEC proposed rules that would require public companies to disclose extensive climate-related information in certain SEC filings. Specifically, the proposed rules would add new Subpart 1500 to Regulation S-K and new Article 14 to Regulation S-X to require disclosure of climate-related risks that are reasonably likely to have a material impact on a public company’s business, results of operations, or financial condition; GHG emissions associated with a public company that includes, in many cases, an attestation report by a GHG emissions attestation provider; and climate-related financial metrics to be included in a company’s audited financial statements. The Company is currently assessing the potential impact of the proposed rules. The public comment period on the proposed rules has concluded and final rules are expected in 2023. Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 was signed into law on August 16, 2022. Among its many provisions are programs that provide grants and other forms of direct and indirect financial assistance for the deployment of zero emission technologies as well as other actions that could affect energy markets and the future use of coal. The Company is currently assessing the potential environmental impacts of the legislation.
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.
Native TitleFair Work Act. In December 2022, the federal government passed The Fair Work Legislation Amendment (Secure Jobs, Better Pay) Act 2022, which amends the Fair Work Act. The legislation introduces several changes to workplace laws in Australia including changes to enterprise agreement making and Cultural Heritagetermination, to when industrial action can be taken and to access to multi-employer bargaining. In addition, employers will no longer be able to employ individuals on a fixed-term contract for more than two years, and access to flexible working arrangements for employees has been expanded. A number of measures aimed at addressing the gender pay gap have also been introduced.
New South Wales Coal Directions. Since 1992,The State of New South Wales (NSW) enacted the Australian courts have recognizedEnergy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). On December 22, 2022, the State Premier declared a coal market price emergency on the basis that native titlethe declaration was necessary to landsreduce the risk that increases in coal prices could contribute to an increase in electricity prices. On December 23, 2022, Peabody and water, as recognized under the lawsa number of other coal producers in NSW were issued with directions that require those coal producers to reserve and customssell a portion of the Aboriginal inhabitantscoal produced to NSW power generators at a capped price until June 30, 2024. On January 31, 2023, amended directions were issued. The directions, as they currently stand, apply to the Wilpinjong Mine and also impose a number of Australia,additional reporting obligations with respect to coal produced from the Wilpinjong Mine. However, the NSW government is in ongoing discussions with coal producers and power generators regarding issuing additional directions. It is anticipated that these directions will not impact Wilpinjong Mine, but may have survivedrequire the reservation of coal at the Wambo Mines; however, the nature and extent of those obligations and associated reporting requirements are still evolving and require further clarification from the NSW government.
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Peabody Energy Corporation | 2022 Form 10-K | 18 |
Metropolitan Mine Stormwater Discharge. Over the past two years, there has been significantly high rainfall in New South Wales, including unprecedented rain totals at the Metropolitan Mine site. While stormwater collected at the mine site is managed through two sedimentation dams, at times the heavy rainfall has presented challenges with managing the significant volumes of stormwater, as the surface water management infrastructure has not had sufficient capacity. As a result, on multiple occasions throughout 2021 and 2022 stormwater has been discharged from the mine site. Metropolitan Collieries Pty Ltd (MCPL), a wholly-owned subsidiary of Peabody, removed accumulated material from the sedimentation dams to restore full site stormwater capacity by December 31, 2022 and has identified and is implementing additional controls for the management of sediment moving forward. Despite the measures undertaken by MCPL to manage and improve the situation, the Environment Protection Authority is currently undertaking an investigation in relation to the discharges of sediment laden water from the mine site and a review 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 withMetropolitan Mine’s environmental protection license. The Environment Protection Authority is investigating potential offenses against the traditional owners (and potentiallyenvironmental protection legislation arising from 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.discharges.
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 ourPeabody’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. In September 2019, the IPC declined to approve a non-Peabody ‘greenfield’ coal mining project (Bylong) for various reasons, including Scope 3 greenhouse gas emissions.The applicant for that project has applied for the IPC’s decision to be judicially reviewed. 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.
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Peabody Energy Corporation | 20192022 Form 10-K | 1819 |
InIn Queensland, laws and regulations related to mining include, but are not limited to, the Mineral Resources Act 1989, Environmental Protection Act 1994 (EP Act), Environmental Protection Regulation 2008, Planning Act 2016, Coal Mining Safety and Health Act 1999, Minerals and Energy Resources (Common Provisions) Act 2014, Explosives Act 1999, Aboriginal Cultural Heritage Act 2003, Water Act 2000, State Development and Public Works Organisation Act 1971, Queensland Heritage Act 1992, Transport Infrastructure Act 1994, Nature Conservation Act 1992, Vegetation Management Act 1999, Biosecurity Act 2014, Land Act 1994, Regional Planning Interests Act 2014, Fisheries Act 1994 and Forestry Act 1959. Under the EP Act, policies have been developed to achieve the objectives of the law and provide guidance on specific areas of the environment, including air, noise, water and waste management. State planning policies address matters of Queensland state interest, and must be adhered to during mining project approvals. The Mineral Resources Act 1989 was amended effective September 27, 2016 to include significant changes to the management of overlapping coal and coal seam gas tenements, and the coordination of activities and access to private and public land. In November 2016, amendments to the EP Act and the Water Act 2000 became effective that facilitate regulatory scrutiny of the environmental impacts of underground water extraction during the operational phase of resource projects for all tenements yet to commence mineral extraction. The ‘chain of responsibility’ provisions of the EP Act, which became effective in April 2016, allow the regulator to issue an environmental protection order (EPO) to a related person of a company in two circumstances: (a) if an EPO has been issued to the company, an EPO can also be issued to a related person of the company (at the same time or later); or (b) if the company is a high risk company (as defined in the EP Act), an EPO can be issued to a related person of the company (whether or not an EPO has also been issued to the company). A guideline has been issued that provides more certainty to the industry on the circumstances in which an EPO may be issued.
In New South Wales, laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulations 2000, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Radiation Control Act 1990, Biodiversity Conservation Act 2016 (BC Act), Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Land Management Act 2016, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Forestry Act 2012, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks & Wildlife Act 1974.
Under the EPA Act, environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve.
On August 25, 2017, the BC Act commenced in New South Wales and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied.
Sharma v Minister for the Environment. On March 15, 2022, the Full Court of the Federal Court of Australia overturned the decision in Sharma v Minister for the Environment [2021] FCA 560 (Sharma), a case which found in 2021 that the Federal Minister for the Environment had a duty to avoid causing personal injury or death to children in Australia as a result of carbon emissions when deciding an application to approve a coal mine expansion. In light of this decision, the Minister for the Environment no longer must consider the effects of carbon emissions when assessing referrals under the Environment Protection and Biodiversity Conservation Act 1999. However, an application by Sharma for special leave to appeal to the High Court of Australia remains probable, and the duty could be reinstated.
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Peabody Energy Corporation | 2022 Form 10-K | 20 |
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. OurPeabody’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 ourthe Company’s credit facility, collateralized letter of credit program and accounts receivable securitization program. We operateThe Company operates in both the Queensland and New South Wales state jurisdictions.
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Peabody Energy Corporation | 2019 Form 10-K | 19 |
OurPeabody’s reclamation bonding requirements in Australia were $243.9$215.1 million as of December 31, 2019.2022. The bond requirements represent the states’ calculated cost to reclaim the current operations of a mine if it ceases to operate in the current period less any discounts agreed with the state. The cost calculation for each bond must be completed according to the regulatory authority of each state. The costs associated with our AustralianCompany’s asset retirement obligations are calculated in accordance with U.S. generally accepted accounting principles for its active and inactive Australian operations were $224.4$216.7 million as of December 31, 2019.2022. The total bonding requirements for ourthe 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.immediately as well as different costs assumptions.
New South Wales Reclamation. The Mining Act 1992 (Mining Act) is administered by the Department of Planning and Environment and the New South Wales Resources Regulator and authorizes the holder of a mining tenement to extract a mineral subject to obtaining consent under the EPA Act and other auxiliary approvals and licenses.
Through the Mining Act, environmental protection and reclamation are regulated by conditions in all mining leases including requirements for the submission of a mining operations plan (MOP) prior to the commencement of operations. All mining operations must be carried out in accordance with the MOP which describes site activities and the progress toward environmental and reclamation outcomes and are updated on a regular basis or if mine plans change. The mines publicly report their reclamation performance on an annual basis.
In support of the MOP process, a reclamation cost estimate is calculated periodically to determine the amount of bond support required to cover the cost of reclamation based on the extent of disturbance during the MOP period.
Queensland Reclamation. The EP Act is administered by the Department of Environment and Science, which authorizes environmentally relevant activities such as mining activities relating to a mining lease through an Environmental Authority (EA). Environmental protection and reclamation activities are regulated by conditions in the EA. All mining operations must be carried out in a manner so as to ensure compliance with the conditions in the EA. The mines submit an annual return reporting on their EA compliance.
In November 2018, the Queensland government passed the Mineral and Energy Resources (Financial Provisioning) Act 2018 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 wePeabody will move each of ourits mines in Queensland into the new FA framework.
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. We areThe 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 ourits Queensland mines.
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Peabody Energy Corporation | 2022 Form 10-K | 21 |
Residual Risks. On November 19, 2018,August 20, 2020, the Queensland government released for public consultation a discussion paperEnvironmental 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 managing ‘residual risks’ of mining activities.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. The discussion paperIt 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. Industry
Native Title and Cultural Heritage. Since 1992, the Company continueAustralian courts have recognized that native title to consultlands 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 government ontraditional owners (and potentially the proposed residual risk payment regime.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 Reclamation. In February 2017,Government established a Senate Inquiry. The Senate Inquiry’s terms of reference included reviewing the effectiveness and adequacy of state and federal laws in relation to Aboriginal and Torres Strait Islander cultural heritage in each of the Australian jurisdictions; and how these cultural heritage laws might be improved to guarantee the protection of culturally and historically significant sites. Following an interim report released on December 9, 2020, the Joint Standing Committee on Northern Australia released its final report on October 18, 2021. The final report sets out three key findings and eight recommendations, including that a new framework for cultural heritage protection be implemented at a national level by way of new legislated national minimum standards for State and Territory laws. The recommendations also include that a review of the Native Title Act 1993 (Cth) be undertaken to address inequalities in the negotiating position of Aboriginal and Torres Strait Islander peoples in the future act regime, including the ‘right to negotiate’ process which is associated with the grant of certain mining tenements. On November 24, 2022, the Environment Minister announced the Australian government’s support for all but one of the recommendations from the Senate establishedInquiry (whether final responsibility for heritage protection should sit with the Indigenous Affairs Minister or the Environment Minister is still being assessed) and indicated laws to protect Aboriginal cultural heritage would be strengthened following a Committee of Inquiry into the rehabilitationfurther review of mining standards. Any legislation passed as a result of the recommendations in the final report could potentially impact the Company’s current and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protectionfuture mining tenements 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.operations.
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Peabody Energy Corporation | 2019 Form 10-K | 20 |
Occupational Health and Safety. State legislation requires usPeabody 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.
Beginning in 2015, a small number of coal mine workers in Queensland and New South Wales were diagnosed with coal workers’ pneumoconiosis (CWP, also known as black lung) following decades of assumed eradication of the disease. The Queensland government held a Parliamentary inquiry into the re-emergence of CWP in the state, which included public hearings with appearances by representatives of the coal mining industry, coal mine workers, the regulator and others. The Queensland Parliamentary Committee conducting the inquiry issued its final report on May 29, 2017. In finding that it is highly unlikely CWP was ever eradicated in Queensland, the Committee made 68 recommendations to ensure the safety and health of coal mine workers. These include an immediate reduction to the occupational exposure limit for respirable coal dust equivalent to 1.5mg/m3 for coal dust and 0.05 mg/m3 for silica and the establishment of a new and independent Mine Safety Authority to be funded by a dedicated proportion of coal and mineral royalties and overseeing the Mines Safety Inspectorate. The Queensland government has instituted increased reporting requirements for dust monitoring results, broader coal mine worker health assessment requirements and voluntary retirement examinations for coal mine workers to be arranged by the relevant employer and further reform may follow.
September 2020, Safe Work Australia (SWA) is currently reviewing thepublished its revised Workplace Exposure Standards (WES) for all airborne contaminants including welding fumes and diesel particulate matter and giving priority to the WES for coal dust and silica. The review is expected to continue until June 2020. SWA’s draft evaluation reports will include recommendations for exposure limits. The exposure limits recommended by SWA aresilica based on toxicological information and other monitoring data. SWA have recommended exposure limits of 1.5mg/1.5 milligrams per cubic meter (mg/m3) for coal dust (to apply from October 2022) and 0.05 mg/m3 for silica.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 0.05mg/m
Since August 2017,3) took effect from July 1, 2020. In New South Wales, the Workers’ Compensationnew 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 Rehabilitation Act 2003 provides for a medical examination process for retired or former coal workers with suspected CWP and an additional lump sum compensation for workers with CWP, and additionally clarifies that a worker with CWP can access further workers’ compensation entitlements if they experience disease progression.
In October 2018mines need to report exceedances of the Queensland government passed the Mines Legislation (Resources Safety) Amendment Act 2018, which introduces significant changesnew exposure standard to the Coal MiningNSW 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) WES for CO2 in Australian coal mines from 12,500 ppm to 5,000 ppm. Currently there is a separate TWA for CO2 in coal mines, however SWA proposes to remove this to align with a general industry standard. If implemented, the change has the potential to affect underground mines operating in CO2 rich coal seams, including the primary coal seam of the Company’s Metropolitan Mine. Importantly, a minimum three-year transition period applies for any change to standards. SWA expects to make recommendations to the Work Health and Safety and Health Act 1999 concerning, among other things, dutiesMinisters on the proposed workplace exposure standards in the first quarter of officers, reporting requirements for coal mine worker diseases, reporting defects and hazards affecting plant and substances, contractor and service provider safety and health management plans, new powers to suspend or cancel an individual’s statutory certificate2023.
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Peabody Energy Corporation | 2022 Form 10-K | 22 |
FollowingOn July 1, 2020, the re-identification of coal workers’ pneumoconiosis and six mining and quarrying fatalities that occurred over a 12-month period, the Resources Safety and Health Queensland Bill 2019 was introduced into Queensland Parliament in September 2019. The billAct 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 will includeincludes inspectorates for coal mines, mineral mines and quarries, explosives and petroleum and gas. The billnew 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 offencesoffenses under resources safety legislation.
In FebruaryOn May 20, 2020, the Queensland government has introducedParliament passed a bill into Parliament legislation which will introducelaw that introduces the criminal offense of ‘industrial manslaughter’ for executive officers, individuals who are “senior officers” and companies in the mining industry. Individuals wouldnow 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 legislation hasbill also introduced the requirement for statutory role holders to be employees of the coal mine operator entity with a 12-monthan 18-month transition period. The bill is currently under review by a Parliamentary Committee.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 ourthe 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.
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Peabody Energy Corporation | 2019 Form 10-K | 21 |
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 in Marchbetween 2019 withand 2021 to transition responsible emitters to new baseline setting arrangements. From the effect that all current reported covered emissionsstart of the 2020-21 compliance year, baselines will expire on June 30, 2020,must use prescribed production variables (an example being run of mine coal) and there will be alternatives for setting new baselines, including by reference to default emissions intensity values.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).
On January 10, 2023, the Australian federal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime. The reforms will commence on July 1, 2023 utilizing site specific baseline emissions as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO2 in 2023-24, increasing with the Consumer Price Index plus 2% each year. After further consultation, the Australian government aims to finalize the legislative amendments to implement the Safeguard Mechanism reforms by April 2023. The potential impact of these reforms to Peabody’s Australian operations is under review.
Queensland Royalty. Royalties are payableAs part of the Queensland government’s 2019-20 budget, the government committed to freeze royalty rates on coal and minerals for three years, provided companies voluntarily contributed to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The government contributed $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the StateFund was approximately $457,000 Australian dollars for the 2021-22 financial year, $522,000 Australian dollars for the 2020-21 financial year and $713,000 Australian dollars for the 2019-20 financial year.
On and from July 1, 2022, the Queensland government introduced three new royalty tiers for coal produced and sold from the state. The new tier rates are 20% for the portion of Queensland at a rate of 12.5% on coal prices over $100above $175 Australian dollars per tonne and up to $150tonne; 30% for the portion of prices above $225 Australian dollars per tonnetonne; and 15.0% on pricing overa 40% tier for the portion of prices above $300 Australian dollars per tonne. Previously, the maximum royalty rate was 15% of the value of the coal sold above $150 Australian dollars per tonne. The rate is 7.0%change follows a three-year freeze on royalty rates for coal sold below $100in the state. Through December 31, 2022, the Company paid additional royalties of $69.9 million Australian dollars per tonne. The periodic impact of these royalty rates is dependent upon the volume of tonnes produced at each of our Queensland mining locations and coal prices received for those tonnes. The Queensland Office of State Revenue issues determinations setting out its interpretationas a result of the laws that impose royalties and provide guidance on how royalty rates should be calculated.new rates. The increased rate structure may impact the Company’s future decisions about its Queensland operations.
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Peabody Energy Corporation | 2022 Form 10-K | 23 |
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)(DPE) on the impact of underground mining activities in Sydney’s water catchment areas, including at ourthe Company’s Metropolitan Mine. The Panel issued an initial report to DPIE in November 2018, which was publicly released in December 2018 and only concerned mining activities at two mines, our Metropolitan Mine and a competitor’s Dendrobium Mine. After consultation with stakeholders, including Peabody, aits final report was released in October 2019. The final report updates and finalizes the initial report and also makes2019, which made findings and recommendations concerning mining activities and effects across the catchment as a whole.
In response to the Panel’s recommendations, in 2020 the DPE established an interagency taskforce to implement a detailed action plan which includes: ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies; establishing a new independent expert panel (Independent Advisory Panel) to advise on future mining applications in the catchment; strengthening surface and groundwater monitoring; improving access to and transparency of environmental data; adopting a more stringent approach to the assessment and conditioning of future mining proposals to minimize subsidence impacts; reviewing and updating current and potential future water losses from mining in line with the best available science; introducing a licensing regime to properly account for any water losses; and undertaking further research into mine closure planning to reduce potential long-term impacts.
When requested by the DPE, the Independent Advisory Panel is available to provide informed technical advice to the DPE or the Independent Planning Commission in relation to development applications and post-approval matters relating to the assessment and management of subsidence impacts associated with underground mining across NSW, with a particular focus on risks to the quantity of water in the catchment. The Panel’s reports acknowledgeIndependent Advisory Panel is comprised of an independent chair and experts in the major effort at the Metropolitanfields of mining engineering and Dendrobium Mines over the last decade to employ best practice modeling and assessment methods undertaken by suitable specialists, with expert peer review while recommending continued rigorous monitoring and impact assessment in order to build on the knowledge base regarding mining-induced subsidence, and its impacts onsurface water, groundwater and swamp hydrology and ecology. Advice that may be provided by the Independent Advisory Panel may include, but is not confined to, risks to the total water quantity and holding capacity of surface water.and groundwater systems, including swamps and reservoirs, and the types and reliability of methodologies used to predict, monitor, assess and report on mining effects, impacts and consequences.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to GHG emissions. The reports endorseCompany’s largest contribution to GHG emissions occurs indirectly, through the government taking an incremental approach to mining approvals that provides for considering existing and emerging information and knowledge gaps. The Panel concludedcoal used by its customers in the final report that the average daily water inflow over the last three years at the Metropolitan Mine is generally less than 0.2 megaliters per day and shows no evidencegeneration of connected fracture regime to surface or correlation with rainfall. It also concluded that the potential for water to be diverted out of Woronora Reservoir and into other catchments through valley closure shear planes and geological structures will require careful assessment in the future because it is planned that most of the remaining longwall panels in the approved mining area will pass beneath the reservoir. A range of matters remain to be considered by the Panel, including the cumulative impacts of flow losseselectricity and the relative significanceproduction of these for water suppliessteel (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 practicalitiesfugitive methane emissions associated with establishingcoal 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 robust regional water balance model.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 DPIE will now consider the recommendations in the Panel’s final reportboard of directors has ultimate oversight for climate-related risk and opportunity assessments, and has saiddelegated 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 in the meantime no new development applications for mining inCompany’s external communications, including environmental regulatory filings and public notices, U.S. Securities and Exchange Commission filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the catchment will be determined. We do not currently have anyCompany’s material risks and progress. All such applications awaiting determination. communications are subject to oversight and review protocols established by Peabody’s board of directors and executive leadership team.
The latest extraction plans forCompany faces risks from both the Metropolitan Mine are progressing on an incremental basisglobal transition to a net-zero emissions economy and we continue to conduct robust monitoring, data collectionthe potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and reportingother impacts as the Company meets various mitigation and have been actively consulting with the government on Metropolitan’s approval processes and mine design to ensure that operational impacts are appropriately managed and minimized as far as possible.
adaptation requirements.
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Peabody Energy Corporation | 20192022 Form 10-K | 2224 |
The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the ESG-related policies of financial institutions and other private companies. The Company has experienced, or may in the future experience, negative effects on its results of operations due to the following specific risks as a result of such factors:
•Reduced utilization or closure of existing coal-fired electricity generating plants;
•Electricity generators switching from coal to alternative fuels, when feasible;
•Increased costs associated with regulatory compliance;
•Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;
•Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes;
•Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions;
•Disruption to operations or markets due to anti-coal activism and litigation; and
•Reputational damage associated with involvement in GHG emissions.
With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks:
•Disruption to water supplies vital to mining operations;
•Disruption to transportation and other supply chain activities;
•Damage to the Company’s, customers’ or suppliers’ plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and
•Electrical grid failures and power outages.
While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:
•Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and CCUS technologies;
•Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and
•The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change. Such developments are described below in the section “Regulations Related to Global Climate Change” within this Item 1.
The enactment of future laws or the passage of regulations regarding emissions from the use of coal by the U.S., some of its states or other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. Further, policies limiting available financing for the development of new coal-fueled power stations could adversely impact the global demand for coal in the future. The potential financial impact on Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such as China, India and Japan, included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy.
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Peabody Energy Corporation | 2022 Form 10-K | 25 |
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 gasGHG emissions, but to date, no suchnew comprehensive, regulatory legislation has been signed into law. The U.S. Congress, however, has approved legislation, the Inflation Reduction Act of 2022, that will provide substantial tax incentives, grants and loan guarantees for energy infrastructure, solar panels, wind turbines, nuclear and geothermal energy, hydrogen projects and carbon capture and storage. While it is possible that the U.S. will adopt additional climate legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the
The EPA is undertakinghas also undertaken several steps to regulate greenhouse gasGHG emissions pursuant tounder existing law, primarily the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” 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 EPAhas 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. The ACE Rule is being challenged in the D.C. Circuit Court of Appealswill continue these efforts and its ultimate impact will depend on state implementation plan requirementsproceed with new regulations affecting GHG emissions from fossil fuel-fired electric generation, methane emissions from oil and the outcome of associated legal challenges.gas production and carbon emissions from light and heavy-duty vehicles.
At the same time, a number of states in the U.S. have adopted programs to regulate greenhouse gasGHG 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, whichand Pennsylvania joined in 2022. RGGI is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. 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 gasGHG emissions and create economic opportunities in ways not limited to cap-and-trade programs.
Several other U.S. states have enacted legislation establishing greenhouse gasGHG 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.
WeIncreasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.
Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and wethe Company regularly disclosediscloses information regarding its production-related emissions in ourits annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by us in the U.S.ESG Report. The vast majority of ourthe Company’s emissions are generated by the operation of heavy machinery to extract and transport material at ourits mines and fugitive emissions from the extraction of coal.
In 2013, the U.S. and a number of international development banks, including the World Bank, the European Investment Bank and the European Bank for Reconstruction and Development, announced that they would no longer provide financing for the development of new coal-fueled power plants or would do so only in narrowly defined circumstances. Other international development banks, such as the Asian Development Bank and the Japanese Bank for International Cooperation, have continued to provide such financing. Other banks (such as BNP Paribas and HSBC) have pledged to end financing of certain fossil fuel projects and companies. Some insurance companies (such as Zurich and Swiss Re) have announced that they will no longer insure coal operations and companies. And some large investors (including Lloyd’s of London) have announced that they plan to divest coal stocks from their investment holdings.
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Peabody Energy Corporation | 20192022 Form 10-K | 2326 |
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 gasGHG 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 gasGHG emissions. TheOn January 20, 2021, the U.S. has begun the process of withdrawing fromreentered the Paris Agreement which cannot be completed until 2020 underby accepting the termsagreement and all of its articles and clauses, after having announced its withdrawal from the agreement.agreement in November 2019.
In October 2017,June 2022, the new Australian Federal Government releasedfederal government announced plans to legislate for a plan aimed at delivering an affordable43% reduction in Australia’s GHG emissions by 2030 and reliable energy systemto introduce changes by mid-2023 that meets Australia’s international commitmentswill require heavy emitting companies producing more than 100,000 tonnes of carbon emissions annually to accelerate their 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 byreduction activities. On September 13, 2022, the Australian government in September 2018. Followingpassed the outcomeClimate Change Act 2022 to set the GHG emissions reduction targets into law.
On January 10, 2023, the Australian federal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime (legislated through the National Greenhouse and Energy Reporting Act 2007 (Cth)). Refer to the section “Regulatory Matters —Australia” within this Item 1 for discussion of the 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.proposed reform.
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 us of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. 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, we attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require that we make significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on our operations, financial condition or cash flow. We do not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on our results of operations, financial condition or cash flows.
Available Information
We filePeabody files or furnishfurnishes 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 ourthe 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 ourthe 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 ourthe Company’s filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.
Item 1A. Risk Factors.
We operateThe 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 ourthe 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 ourthe Company’s business. New factors may emerge or changes to these risks could occur that could materially affect ourits business.
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Peabody Energy Corporation | 2019 Form 10-K | 24 |
Risks Associated with Our Emergence from the Chapter 11 Cases
As a result of our emergence from our Chapter 11 Cases, our historical financial information is not indicative of our future financial performance.
Our capital structure was significantly altered through the implementation of our Plan. As a result, we are subject to the fresh start reporting rules required under the Financial Accounting Standards Board ASC Topic 852, Reorganizations. Under applicable fresh start reporting rules, our assets and liabilities were adjusted to fair values and our accumulated deficit was restated to zero. Accordingly, our consolidated financial condition and results of operations from and after April 2, 2017 are not directly comparable to the financial condition or results of operations reflected in our consolidated historical financial statements.
Risks Associated with OurPeabody’s Operations
OurThe Company’s profitability depends upon the prices we receiveit receives for ourits coal.
We operateThe Company operates in a competitive and highly regulated industry that has previouslyat times experienced strong headwinds. Current pricing levels of both seaborne and domestic coal products may not be sustainable in the future. IfDeclines in coal prices decrease ourcould materially and adversely affect the Company’s operating results and profitability and the value of ourits coal reserves could be materially and adversely affected.resources.
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Peabody Energy Corporation | 2022 Form 10-K | 27 |
Coal prices are dependent upon factors beyond ourthe 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;
the relative price of natural gas and other energy sources used to generate electricity;
•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;
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 our metallurgical coal contracts;
weather patterns, severe weather and natural disasters;
•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.
For U.S. thermal coal, our approach is to selectively renew, or enter into new, long-term supply agreements when we can do so at prices we believe are favorable. For seaborne coal, we negotiate pricing for metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
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Peabody Energy Corporation | 2019 Form 10-K | 25 |
Thermal coal accounted for the majority of ourthe Company’s coal sales by volume during 20192022 and 2018. The2021, with the vast majority of ourthese sales of thermal coal were 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 (v)(vi) the coal inventories of utilities. Gas-fueled generation has displaced and is expected tocould 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 are making uneconomichave 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. TheseIn recent years, these trends have reduced demand for ourthe Company’s coal and the related prices. Any further reduction in the amount ofLower demand for coal consumed by electric power generators could reduce the volume and price of thermal coal that we minethe Company sells and sell.the prices that it receives for the thermal coal, thereby reducing its revenue and adversely impacting its earnings and the value of its coal reserves and resources.
Lower demand for metallurgical coal by steel producers would reduce our revenues and could further reduce the price of our metallurgical coal. We produceThe Company produces metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 32% and 22% of its revenue in 2022 and 28% of our revenues in 2019 and 2018,2021, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for ourthe Company’s metallurgical coal. Lower demand for metallurgical coal in international markets could reduce the amount of metallurgical coal that we sellthe Company sells and the prices that we receiveit receives for it,the metallurgical coal, thereby reducing our revenuesits revenue and adversely impacting ourits earnings and the value of ourits coal reserves.reserves and resources.
The balance between coal demand and supply, factoring in demand and supply of closely related and competing segments such as natural gas,fuel sources, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenuesthe Company’s revenue and profitability. In the U.S., we competeThe Company competes with other fuel sources used for electricity generation, such as natural gas, nuclear and renewables. OurThe Company’s seaborne products compete with other producers as well as other fuel sources. Declines in the price of natural gas or continued low natural gas prices, 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 United States,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 ourthe Company’s coal, thereby reducing our revenuesits revenue and materially and adversely affecting ourits business and results of operations.
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Peabody Energy Corporation | 2022 Form 10-K | 28 |
If a substantial number of ourthe 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, our revenuesits revenue and operating profits could suffer if we arethe Company is unable to find alternate buyers willing to purchase ourits coal on comparable terms to those in ourits contracts.
Most of ourthe Company’s sales are made under coal supply agreements, which are important to the stability and profitability of ourits operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertakethe 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, 2022, the Company derived 28% of its revenue from coal supply agreements from its five largest customers. Those five customers were supplied primarily from 16 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2023 to 2025.
Many of ourthe Company’s coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. WeThe 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. WeThe Company may experience reductions in coal prices in new long-term coal supply agreements replacing some of ourits expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by usthe 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 wethe Company amend the agreements to allow for such variation. Most of ourits coal supply agreements contain provisions requiring usthe 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 ourthe Company’s customers to terminate their contracts in the event of changes in regulations affecting ourthe 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.
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Peabody Energy Corporation | 2019 Form 10-K | 26 |
The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal industry overall or by mining region and cannot provide assurance that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
For the year ended December 31, 2019, we derived 33% of our total revenues from our five largest customers. Those five customers were supplied primarily from 43 coal supply agreements (excluding trading transactions) expiring at various times from 2020 to 2025. On an ongoing basis, we discussthe 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 usthe 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 numbersubstantial portion of these customers significantly reduce their purchases ofthe Company’s coal from us,supply agreements were modified or if we areterminated, it could be materially adversely affected to the extent that it is unable to sellfind 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 them on terms as favorable to us asreplace existing long-term coal supply agreements at the terms under our current agreements, our financial condition and results of operations could suffer materially.same prices or with similar profit margins when they expire. In addition, ourthe 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.
One of our five largest customers, the Navajo Generating Station, was exclusively served by our Kayenta Mine, included in our Western U.S. Mining operations, that had no other customers. During the third quarter of 2019, the Kayenta Mine shipped its final tons. The mine’s approximate Adjusted EBITDA contribution, approximate depreciation, depletion and amortization and asset retirement obligation expense, and tons of coal sold are presented in the table below for the respective periods. Depreciation, depletion and amortization and asset retirement obligation expense for the Successor periods are not comparable to those of the Predecessor periods due to the revaluation of the Company’s property, plant, equipment, and mine development to fair value in connection with fresh start reporting.
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| Successor | Predecessor |
| Year Ended December 31, 2019 | | Year Ended December 31, 2018 | | April 2 through December 31, 2017 | January 1 through April 1, 2017 |
| (Dollars and tons in millions) |
Adjusted EBITDA | $ | 170 |
| | $ | 110 |
| | $ | 77 |
| $ | 27 |
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Depreciation, depletion and amortization and asset retirement obligation expense | $ | 111 |
| | $ | 120 |
| | $ | 60 |
| $ | 19 |
|
Tons of coal sold | 4.0 |
| | 6.6 |
| | 4.8 |
| 1.5 |
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Our trading and hedging activities do not cover certain risks and may expose us to earnings volatility and other risks.
We historically entered into hedging arrangements designed primarily to manage price volatility of the Australian dollar, coal and diesel fuel. Currently, we primarily enter into derivative financial instruments, including financial swaps and options, designed to manage coal price volatility and increases in the Australian dollar exchange rate. We are currently subject to price volatility on diesel fuel utilized in our mining operations. We may in the future enter into hedging arrangements to manage this price risk, or other exposures.
Some of these derivative trading instruments require us to post margin based on the value of those instruments and other credit factors. If the fair value of our hedge portfolio moves significantly, or if laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin, which could negatively impact our liquidity.
Through our trading and hedging activities, we are also exposed to nonperformance and credit risk with various counterparties, including exchanges and other financial intermediaries. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements, which could negatively impact our profitability and/or liquidity.
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Peabody Energy Corporation | 20192022 Form 10-K | 2729 |
Our operating results could be adversely affected by unfavorable economic and financial market conditions.
Our profits are affected, in large part, by industry conditions. Industry conditions are subject to a variety of factors beyond our control. A global economic recession and/or a worldwide financial and credit market disruption could have a negative impact on us and on the coal industry generally. If any of these conditions occur, if coal prices recede to or below levels experienced in 2015 and early 2016 for a prolonged period or if there are downturns in economic conditions, particularly in developing countries such as China and India, our business, financial condition or results of operations could be adversely affected. While we are focused on cost control, productivity improvements, increased contributions from our higher-margin operations and capital discipline, there can be no assurance that these actions, or any others we may take, would be sufficient in response to challenging economic and financial conditions.
Our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates.
Our ability to receive payment for coal sold and delivered or for financially settled contracts will depend on the continued creditworthiness and contractual performance of our customers and counterparties. Our customer base has changed with deregulation in the U.S. as utilities have sold their power plants to their non-regulated affiliates or third parties. These new customers may have credit ratings that are below investment grade or are not rated. If deterioration of the creditworthiness of our customers occurs or if they fail to perform the terms of their contracts with us, our accounts receivable securitization program and our business could be adversely affected.
Risks inherent to mining could increase the cost of operating ourthe Company’s business, and events and conditions that could occur during the course of ourits mining operations could have a material adverse impact on us.the Company.
OurThe Company’s mining operations are subject to conditions that can impact the safety of ourits workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include:
•elevated gas levels;
•fires and explosions, including from methane gas or coal dust;
•accidental mine water discharges;
•weather, flooding and natural disasters;
•hazardous events such as roof falls and high wall or tailings dam failures;
•seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•key equipment failures;
•supply chain constraints or unavailability of equipment or parts;
•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 ourits longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to ourits operations.
We maintainThe Company maintains insurance policies that provide limited coverage for some of the risks referenced above, and those insurance policieswhich may lessen the impact associated with these risks. However, there can be no assurance as to the amount or timing of recovery under ourits insurance policies in connection with losses associated with these risks.
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Peabody Energy Corporation | 2019 Form 10-K | 28 |
Our North Goonyella Mine in Queensland, Australia experienced a fire in a portion of the mine during September 2018 and mining operations have been suspended since then. During the first quarter of 2019, we completed segmenting of the mine into multiple zones to facilitate a phased reventilation and re-entry of the mine. We commenced reventilation of the first zone of the mine during the second quarter of 2019 and subsequently re-entered the area in the third quarter. Following these activities and a detailed review and assessment of North Goonyella, we determined that due to the time, cost and required regulatory approach to ventilate and re-enter the rest of the mine, we will not pursue attempts to access certain portion of the mine through existing mine workings, but instead will move to the southern panels. We are currently in discussions with the Queensland Mines Inspectorate (QMI) regarding ventilation and re-entry of the second zone of the current mine configuration. Based on the planned approach, we expect no meaningful production from North Goonyella for three or more years. In 2020, we are commencing a commercial process for North Goonyella in conjunction with the existing mine development. The process comes in response to expressions of interest from potential strategic partners and other producers. Commercial outcomes could include a strategic financial partner, joint venture structure or complete sale of North Goonyella. Based on the success of discussions with QMI and/or progression of the commercial process being launched, we will determine the appropriate level, if any, and timing of capital expenditures. If after exploring all reasonable mine-planning steps focused on resuming mining activities at the North Goonyella Mine and other commercial outcomes, we determine that we are unable to extract coal from the southern panels of the mine, our results of operations, financial condition and cash flows could be materially and adversely impacted. In addition, the costs that may be incurred to return the mine to active operations (if the mine returns to active operations) are uncertain and could be significant. Refer to Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information regarding our North Goonyella Mine.
If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal may be diminished.
Transportation costs represent a significant portion of the total cost of coal use and the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs and the lack of sufficient rail and port capacity could lead to reduced coal sales.
We depend upon rail, barge, trucking, overland conveyor and ocean-going vessels to deliver coal to our customers. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, underperformance of the port and rail infrastructure, congestion and balancing systems which are imposed to manage vessel queuing and demurrage, non-performance or delays by co-shippers, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations.
A decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability.
Our mining operations require a reliable supply of mining equipment, replacement parts, fuel, explosives, tires, steel-related products (including roof control materials), lubricants and electricity. There has been some consolidation in the supplier base providing mining materials to the coal industry, such as with suppliers of explosives in the U.S. and both surface and underground equipment globally, that has limited the number of sources for these materials. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases and to ensure security of supply. If the cost of any of these inputs increased significantly, or if a source for these supplies or mining equipment were unavailable to meet our replacement demands, our profitability could be reduced or we could experience a delay or halt in our production.
Take-or-payCompany’s take-or-pay arrangements within the coal industry could unfavorably affect ourits profitability.
We haveThe Company has substantial take-or-pay arrangements with its port access and rail transportation providers, predominately in Australia, totaling $1.1$1.4 billion, with terms ranging up to 2320 years, that commit usthe Company to pay a minimum amount for rail and port commitments for the delivery of coal even if those commitments go unused. The take-or-pay provisions in these contracts sometimes allow usthe Company to apply amounts paid for subsequent deliveries, but these provisions have limitations and wethe Company may not be able to apply all such amounts so paid in all cases. Also, wethe Company may not be able to utilize the amount of capacity for which we haveit has previously paid. Additionally, coal companies, including us,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.
We have contract-based intangible liabilities primarily consisting of unutilized capacity under port and rail take-or-pay contracts. Future unutilized capacity and the amortization periods related to the take-or-pay contract intangible liabilities are based upon estimates of forecasted usage. We anticipate that the amortization of the intangible liability, which is classified as a reduction to “Operating costs and expenses,” will extend through 2043.
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Peabody Energy Corporation | 2019 Form 10-K | 29 |
An inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us could reduce our profitability.
In conducting our trading, brokerage and mining operations, we utilize third-party sources of coal production and transportation, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Employee relations at mines that use contractors are the responsibility of the contractor.
Our profitability or exposure to loss on transactions or relationships is dependent upon the reliability (including financial viability) and price of the third-party suppliers; our obligation to supply coal to customers in the event that weather, flooding, natural disasters or adverse geologic mining conditions restrict deliveries from our suppliers; our willingness to participate in temporary cost increases experienced by our third-party coal suppliers; our ability to pass on temporary cost increases to our customers; the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market and the ability of our freight sources to fulfill their delivery obligations. Market volatility and price increases for coal or freight on the international and domestic markets could result in non-performance by third-party suppliers under existing contracts with us, in order to take advantage of the higher prices in the current market. Such non-performance could have an adverse impact on our ability to fulfill deliveries under our coal supply agreements.
WeThe Company may not recover ourits investments in ourits mining, exploration and other assets, which may require usthe Company to recognize impairment charges related to those assets.
The value of ourthe Company’s assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond ourits control, including unfavorable changes in the economic environments in which we operate,it operates; declining coal-fired electricity generation; lower-than-expected coal pricing,pricing; technical and geological operating difficulties,difficulties; an inability to economically extract ourits coal reserves and resources; and unanticipated increases in operating costs. During the year ended December 31, 2019, the Company recorded $270.2 million of impairment charges related to such factors, as further described in Note 5. “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 ourthe Company’s results of operations.
Because of the volatile and cyclical nature of U.S. and international coal markets, it is reasonably possible that ourthe Company’s current estimates of projected future cash flows from ourits mining assets may change in the near term, which may result in the need for adjustments to the carrying value of ourits assets.
OurThe Company’s ability to operate our company effectively could be impaired if we loseit loses key personnel or failfails to attract qualified personnel.
We manage ourPeabody manages its business with a number of key personnel, the loss of whom could have a material adverse effect on us,the Company, absent the completion of an orderly transition. In addition, we believethe Company believes that ourits future success will depend greatly on ourits continued ability to attract and retain highly skilled and qualified personnel in tight labor markets, particularly personnel with mining experience. WePeabody cannot provide assurance that key personnel will continue to be employed by usthe Company or that weit will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.the Company.
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Peabody Energy Corporation | 2022 Form 10-K | 30 |
The Company could be negatively affected if we failit fails to maintain satisfactory labor relations.
As of December 31, 2019, we2022, the Company had approximately 6,6005,500 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 5,0004,300 hourly employees. We areThe Company is party to labor agreements with various labor unions that represent certain of ourits employees. Such labor agreements are negotiated periodically, and, therefore, we arethe Company is subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 42%34% of ourits hourly employees were represented by organized labor unions and generated approximately 19%16% of ourits coal production for the year ended December 31, 2019.2022. Relations with ourits employees and, where applicable, organized labor are important to ourthe Company’s success. If some or all of ourits current non-union operations were to become unionized, wethe Company could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we failthe Company fails to maintain good relations or successfully negotiate contracts with ourits employees who are represented by unions, wethe Company could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact ourits profitability.
WeThe Company could be adversely affected if we failit fails to appropriately provide financial assurances for ourits obligations.
U.S. federal and state laws and Australian laws require usthe Company to provide financial assurances related to requirements to reclaim lands used for mining,mining; to pay federal and state workers’ compensation, such as black lung liabilities; to provide financial assurances for coal lease obligationsobligations; and to satisfy other miscellaneous obligations. The primary methods we usethe Company uses to meet those obligations are to provide a third-party surety bond or provide a letter of credit. As of December 31, 2019, we2022, the Company had $1,609.2$1,376.8 million of outstanding surety bonds and $200.5$569.6 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.guarantees, in addition to collateral for sureties.
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Peabody Energy Corporation | 2019 Form 10-K | 30 |
OurThe 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 us,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 may be furtherhave been severely restricted or terminated in most of the regions where currently available. Ourits 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 us.it. That failure could result from a variety of factors including the following: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.credit; and
Our•lack of available fronting banks in certain countries where the Company must provide financial assurances but its primary surety providers are not licensed or admitted.
As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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 ourits mining permits and prevent mining operations from continuing, which would cast substantial doubt on our abilitycould result in its inability to continue as a going concern.
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Peabody Energy Corporation | 2022 Form 10-K | 31 |
The Company’s mining operations are extensively regulated, which imposes significant costs on us,it, and future regulations and developments could increase those costs or limit ourits 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 ourthe Company’s mines, ourits production and sale of coal would be disrupted and weit may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on ourthe Company’s financial condition, results of operations and cash flows.
The possibility exists that newNew legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect ourthe Company’s mining operations, ourits cost structure or ourits 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 usthe Company or ourits customers to change operations significantly or incur increased costs. Some of ourthe 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 ourthe Company’s financial condition and results of operations.
For additional information about the various regulations affecting us,the Company, see the sections entitled “Regulatory Matters —U.S.” and “Regulatory Matters — Australia”.Australia.”
OurThe Company’s operations may impact the environment or cause exposure to hazardous substances, and ourits properties may have environmental contamination, which could result in material liabilities to us.the Company.
OurThe 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., CERCLA and RCRA,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.
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Peabody Energy Corporation | 20192022 Form 10-K | 3132 |
WeThe Company may be unable to obtain, renew or maintain permits necessary for ourits operations, or wethe Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which we run ourit runs its operations, which would reduce ourits production, cash flows and profitability.
Numerous governmental and tribal 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 we applythe Company applies for permits and approvals, we areit 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 ourthe 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 ourthe Company’s ability to efficiently and economically conduct ourits mining activities, any of which would materially reduce ourits production, cash flows and profitability.
The Corps regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies like us to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. In recent years, the Section 404 permitting process has been subject to increasingly stringent regulatory and administrative requirements as well as a series of court challenges, which have resulted in increased costs and delays in the permitting process. Additionally, increasingly stringent requirements governing coal mining also are being considered or implemented under the SMCRA, the National Pollution Discharge Elimination System permit process and various other environmental programs. Potential future laws, regulations and policies could result in material adverse impacts on our operations, financial condition or cash flows, in view of the significant uncertainty surrounding each of these potential future laws, regulations and policies.
Our mining operations are subject to extensive forms of taxation, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal competitively.
Federal, state, provincial or local governmental authorities in nearly all countries across the global coal mining industry impose various forms of taxation, including production taxes, sales-related taxes, royalties, environmental taxes, mining profits taxes and income taxes. If new legislation or regulations related to various forms of coal taxation, which increase our costs or limit our ability to compete in the areas in which we sell our coal, are adopted, our business, financial condition or results of operations could be adversely affected.
If the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated.
Our 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. Our management and engineers periodically review these estimates. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our 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 our assumptions, which could have a material adverse effect on our results of operations and financial condition.
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Peabody Energy Corporation | 2019 Form 10-K | 32 |
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.
Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Moreover, the amount of proven and probable coal reserves described in Part I, Item 2. “Properties” involves the use of certain estimates and those estimates could be inaccurate. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include geological conditions, historical production from the area compared with production from other producing areas, the assumed effects of regulations and taxes by governmental agencies and assumptions governing future prices and future operating costs. Actual production, revenues and expenditures with respect to our coal reserves may vary materially from estimates.
Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties and infrastructure. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our 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, 2019, we leased a total of 47,272 acres from the federal government subject to those limitations.
Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, in order to develop our reserves, we must also own the rights to the related surface property and receive various governmental permits. We cannot predict whether we will continue to receive the permits or appropriate land access necessary for us to operate profitably in the future. We 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 or maintain our 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, we have experienced litigation with lessors of our coal properties and with royalty holders. In addition, from time to time, our permit applications and federal and state coal leases have been challenged, causing production delays.
To the extent that our existing sources of liquidity are not sufficient to fund our planned mine development projects and reserve acquisition activities, we may require access to capital markets, which may not be available to us or, if available, may not be available on satisfactory terms. If we are unable to fund these activities, we may not be able to maintain or increase our existing production rates and we could be forced to change our business strategy, which could have a material adverse effect on our financial condition, results of operations and cash flows.
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Peabody Energy Corporation | 2019 Form 10-K | 33 |
We face numerous uncertainties in estimating our economically recoverable coal reserves and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
Coal is economically recoverable when the price at which our 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 our coal is economically recoverable varies based on the mine. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our reserve information on engineering, economic and geological data assembled and analyzed by our staff and third parties, which includes various engineers and geologists. The reserve estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves 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, including many factors beyond our control. Estimates of economically recoverable coal reserves 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 our experience in areas we currently mine;
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.
As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. Thus, these estimates may not accurately reflect our actual reserves. Any material inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially and adversely affect our business, results of operations, financial position and cash flows.
Our global operations increase our exposure to risks unique to international mining and trading operations.
Our international platform increases our exposure to country risks, international regulatory requirements and the effects of changes in currency exchange rates. Some of our international activities are in developing countries where the economic strength, business practices and counterparty reputations may not be as well developed as in our U.S. or Australian operations. We are exposed to various business, political and sovereign risks, including political instability, heightened levels of corruption or fraud in certain markets, the potential for expropriation of assets, costs associated with the repatriation of earnings and the potential for unexpected changes in regulatory requirements. Despite our efforts to perform due diligence, screening, training and auditing of internal and external business agents, vendors, partners and customers to mitigate these risks, our results of operations, financial position or cash flows could be adversely affected by these activities.
Our proposed joint venture with Arch may not be completed.
On June 18, 2019, we entered into a definitive implementation agreement with Arch to establish a joint venture that will combine the respective Powder River Basin and Colorado mining operations of Peabody and Arch.
The closing of our proposed joint venture with Arch is subject to various conditions to closing, including the termination or expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of certain other required regulatory approvals and the absence of injunctions or other legal restraints preventing the formation of the joint venture. These closing conditions may not be satisfied, and in that circumstance we may be unable or unwilling to complete this joint venture. If the closing has not occurred on or prior to June 18, 2020 and all required regulatory approvals have not been obtained, the Implementation Agreement may be terminated by either Peabody or Arch no later than June 29, 2020 following written notice and the payment by the terminating party to the non-terminating party of a termination fee of $40 million; provided, however, that the non-terminating party may elect to extend the Implementation Agreement until September 18, 2020. If the non-terminating party exercises this option to extend, the termination fee payable to the non-terminating party by the terminating party if the closing does not occur on or prior to September 18, 2020 will be reduced to $25 million.
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Peabody Energy Corporation | 2019 Form 10-K | 34 |
Joint ventures, partnerships or non-managed operations may not be successful and may not comply with our operating standards.
We participate in several joint venture and partnership arrangements and may enter into others, all of which necessarily involve risk. Whether or not we hold majority interests or maintain operational control in our joint ventures, our partners may, among other things, (1) have economic or business interests or goals that are inconsistent with, or opposed to, ours; (2) seek to block actions that we believe are in our 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 our results of operations and our liquidity or impair our ability to recover our investments.
Where our joint ventures are jointly controlled or not managed by us, we may provide expertise and advice but have limited control over compliance with our operational standards. We also utilize contractors across our mining platform, and may be similarly limited in our ability to control their operational practices. Failure by non-controlled joint venture partners or contractors to adhere to operational standards that are equivalent to ours could unfavorably affect safety results, operating costs and productivity and adversely impact our results of operations and reputation.
The benefits that are expected to result from the proposed joint venture with Arch will depend, in part, on our ability to realize the anticipated cost synergies in the transaction, our and Arch’s ability to successfully integrate our Powder River Basin and Colorado mining operations, and our and Arch’s ability to successfully manage the joint venture on a going-forward basis. It is not certain that we will realize these benefits at all, and if we do, it is not certain how long it will take to achieve these benefits. If, for example, we are unable to achieve the anticipated cost savings, or if there are unforeseen integration costs, or if we and Arch are unable to operate the joint venture smoothly in the future, the financial performance of the joint venture may be negatively affected.
We may undertake further repositioning plans that would require additional charges.
As a result of our continuing review of our business or changing demand, we may choose to further modify our portfolio of operations and/or reduce our workforce in the future. These actions may result in further restructuring charges, cash expenditures and the consumption of management resources, any of which could cause our operating results to decline and may fail to yield the expected benefits.
We could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if we sustain cyber-attacks or other security breaches that disrupt our operations or result in the dissemination of proprietary or confidential information about us, our employees, our customers or other third-parties.
We use digital technology to conduct our business operations and engage with our customers, vendors, employees, financial institutions and other partners. Our business depends on the reliable and secure operation of computer systems, network infrastructure, digital communication technologies and other information technology. Problems may arise in both our internally managed systems and those of third parties. We have implemented security protocols and systems with the intent of maintaining the physical security of our operations and protecting our and our counterparties’ confidential information and information related to identifiable individuals against unauthorized access. Despite such efforts, we may be subject to security breaches which could result in unauthorized access to our facilities or the information we are trying to protect. Unauthorized physical access to one of our facilities or electronic access to our information systems could result in, among other things, unfavorable publicity, litigation by affected parties, damage to sources of competitive advantage, disruptions to our operations, loss of customers, financial obligations for damages related to the theft or misuse of such information and costs to remediate such security vulnerabilities, any of which could have a substantial impact on our results of operations, financial condition or cash flows.
Our expenditures for postretirement benefit obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
We provide postretirement health and life insurance benefits to eligible employees. Our total accumulated postretirement benefit obligation related to such benefits was a liability of $625.7 million as of December 31, 2019, of which $32.3 million was classified as a current liability.
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Peabody Energy Corporation | 2019 Form 10-K | 35 |
These liabilities are actuarially determined. We use 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. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities. A decrease in the discount rate used to determine our 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. We have made assumptions related to future trends for medical care costs in the estimates of retiree health care obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes or changes in healthcare benefits provided by the government could increase our obligation to satisfy these or additional obligations. We develop our actuarial determinations of liabilities using actuarial mortality tables we believe best fit our population’s actual results. In deciding which mortality tables to use, we periodically review our population’s actual mortality experience and evaluate results against our 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 our year end valuations. If our mortality tables do not anticipate our population’s mortality experience as accurately as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Additionally, our reported defined benefit pension funding status may be affected, and we may be required to increase employer contributions, due to increases in our defined benefit pension obligation or poor financial performance in asset markets in future years.
Our defined benefit pension plans are subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). It is implicit in our underlying assumptions that those plans continue to operate in the normal course of business. However, the Pension Benefit Guaranty Corporation (PBGC) may terminate our plans under certain circumstances pursuant to ERISA, including in the event that the PBGC concludes that its risk may increase unreasonably if such plans continue to operate based on its assessment of the plans’ funded status, our financial condition or other factors. Termination of the plans would require us to provide immediate funding or other financial assurance to the PBGC for all or a substantial portion of the underfunded amounts, as determined by the PBGC based on its own assumptions. Those assumptions may differ from our own. Any of those consequences could have a material adverse effect on our results of operations, financial conditions or available liquidity.
Concerns about the impacts of coal combustion on global climate are increasingly leading to consequencesconditions that have affected and could continue to affect demand for ourthe Company’s products or ourits securities and ourits ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.
Global climate issues continue to attract public and scientific attention. Numerous reports, such asincluding 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 mines or coal-fueled power stations could adversely impact the global supply and demand for coal.coal in the future. The potential financial impact on usPeabody 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. Similarly, higher-efficiencyHigher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including some 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, wethe 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 that we make significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on ourthe Company’s operations, financial condition or cash flows. We do not believe that suchSuch analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on ourthe Company’s results of operations, financial condition or cash flows.
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Peabody Energy Corporation | 20192022 Form 10-K | 3633 |
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 ourthe 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 been to makemade it more costly and difficult to maintain ourthe Company’s business. These cost increases and/or a substantial or extended declinedeclines in the prices we receivethe Company receives for ourits coal due to these or other factors could reduce ourits revenue and profitability, cash flows, liquidity, and value of ourits coal reserves and resources, and could result in material losses.
Risks Related to Our Indebtedness and Capital Structure
Our financial performance could be adversely affected by our indebtedness.
As of December 31, 2019, we had approximately $1.3 billion of indebtedness outstanding, excluding finance leases and debt issuance costs.
The degreeCompany’s trading and hedging activities do not cover certain risks and may expose it to which we are leveraged could have important consequences, including, but not limited to:
making it more difficult for us to pay interestearnings volatility and satisfy our debt obligations;
increasing the cost of borrowing;
increasing our vulnerability to general adverse economic and industry or regulatory conditions;
requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development or other general corporate requirements;
limiting our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements;
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 our flexibility in planning for, or reacting to, changes in our business and in the coal industry;
causing a decline in our credit ratings; and
placing us at a competitive disadvantage compared to less leveraged competitors.risks.
In addition our indebtedness subjects us 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 has entered into certain restrictive covenants. Failurehedging arrangements to address these risks, and may continue in the future to enter into hedging arrangements, including economic hedging arrangements, to manage these risks or other exposures. Since the Company’s existing hedging arrangements do not receive cash flow hedge accounting treatment, all changes in fair value are reflected in current earnings.
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 useach 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 comply withreclaim the disturbed acreage and the timing of these covenantscash 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 result in an event of default that,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 not cured or waived,actual amounts change significantly from its assumptions, which could have a material adverse effect on usits 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, revenue and expenditures with respect to its coal reserves and resources may vary materially from estimates.
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Peabody Energy Corporation | 2022 Form 10-K | 34 |
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, 2022, 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 amounts outstanding thereundersignificant 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 immediately duematerially 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 payable.resources, the Company must also own the rights to the related surface property and receive various governmental permits. The termsCompany 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 our indebtedness provideits 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 we cannot meet our debt service obligations,available, may not be available on satisfactory terms. If the lenders could foreclose against the assets securing their borrowingsCompany is unable to fund these activities, it may not be able to maintain or increase its existing production rates and we could be forced into bankruptcy or liquidation.to change its business strategy, which could have a material adverse effect on its financial condition, results of operations and cash flows.
A downgradeThe Company faces numerous uncertainties in our credit ratings or other unfavorable indicatorsestimating its coal reserves and resources and inaccuracies in its estimates could result in lower than expected revenue, 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 matters, additionalthings, 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 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.
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 financial assurancespermits;
•employee health and safety; and
•historical production from the area compared with production from other producing areas.
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Peabody Energy Corporation | 2022 Form 10-K | 35 |
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 revenue 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 our reclamation bonding requirements, a requirement to post additional collateral on derivative trading instruments that we may enter into, the lossits reserves and resources could result in lower than expected revenue, higher than expected costs or decreased profitability which could materially and adversely affect its business, results of trading counterparties for corporate hedgingoperations, financial position and trading and brokerage activitiescash flows.
Joint ventures, partnerships or an increase in the cost of, or a limit on our access to, various forms of credit used in operating our business.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measuresnon-managed operations may not be successful and may not permit uscomply 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, meet our scheduled debtthe 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 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 $172.5 million as of December 31, 2022, of which $16.0 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, demographic assumptions and expected 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. Our indebtednessIts 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 restrictbe 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.
Inflation could result in higher costs and decreased profitability
Recent inflation, increasing the usecost of materials, labor, equipment, freight, fuel and other cost categories, has adversely impacted the Company and could be a sustained trend. The Company’s efforts to recover inflation-based cost increases from its customers may be hampered as a result of the proceeds from any such sales. We may not be able to complete those salesstructure of its contracts and the proceedscontract bidding process as well as the competitive industries, economic conditions and countries in which the Company operates. Accordingly, substantial inflation may not be adequate to meet any debt service obligations then due.result in a material adverse impact on the Company’s costs, profitability and financial results.
During the year ended December 31, 2022, the Company estimates that the impact of inflation increased operating costs and expenses by approximately $230 million over the prior year.
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Peabody Energy Corporation | 20192022 Form 10-K | 36 |
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 global coronavirus (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 restrictions and covenants under its debt and surety bonding obligations.
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 chain 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.
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.
Peabody is exposed to risks associated with political or international conflicts such as the ongoing conflict between Russia and Ukraine.
Political or international conflicts can result in worldwide geopolitical and macroeconomic uncertainty, as has been the case with the ongoing conflict between Russia and Ukraine. The Company is unable to predict the ultimate impacts related to such conflicts. If a conflict continues for a significant time or expands to other countries, it could have adverse effects on macroeconomic conditions, including but not limited to, turbulent coal pricing and trade flow disruptions resulting from sanctions imposed on coal imports; supply chain disruptions; increased costs; and decreased business spending. Furthermore, political or international conflicts could give rise to disruptions to Peabody or its business partners’ global technology infrastructure, including through cyber attack or cyber intrusion; adverse changes in international trade policies and relations; regulatory enforcement; Peabody’s ability to implement and execute its business strategy; terrorist activities; Peabody’s exposure to foreign currency fluctuations; and constraints, volatility, or disruption in the capital markets, any of which could have a material adverse effect on the Company’s business, results of operations, cash flows and financial condition.
Peabody could be exposed to significant liability, reputational harm, loss of revenue, increased costs or other risks if it sustains cyber attacks or other security breaches that disrupt its operations or result in the dissemination of proprietary or confidential information about the Company, its customers or other third-parties.
Peabody has implemented security protocols and systems with the intent of maintaining the physical security of its operations and protecting the Company’s and its counterparties’ confidential information and information related to identifiable individuals against unauthorized access. Despite such efforts, the Company may be subject to security breaches which could result in unauthorized access to its facilities or the information it is trying to protect. Unauthorized physical access to one of the Company’s facilities or electronic access to its information systems could result in, among other things, unfavorable publicity, litigation by affected parties, damage to sources of competitive advantage, disruptions to its operations, loss of customers, financial obligations for damages related to the theft or misuse of such information and costs to remediate such security vulnerabilities, any of which could have a substantial impact on the Company’s results of operations, financial condition or cash flows.
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Peabody Energy Corporation | 2022 Form 10-K | 37 |
The Company is subject to various general operating risks which may be fully or partially outside of its control.
Despite our indebtedness, weThe Company’s results of operations, financial position or cash flows could be adversely impacted by various general operating risks which may still be ablefully 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 incur substantially more debt,financial instruments, and their ability to perform under contracts;
•inability of suppliers and other counterparties, including secured debt, which could further increasethose related to transportation, contract mining, service provision, and coal trading and brokerage, to fulfil the risksterms 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;
•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; and
•uncertainties associated with our indebtedness.the Company’s global operating platform, including country and political risks, international regulatory requirements, and foreign currency rates.
We may be ableRisks Related to incur substantial additional indebtedness in the future, including additional secured debt. Although covenants under the indenture governing our senior secured notes and the agreements governing our other indebtedness, including our credit facility, revolver and finance leases limit our 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 substantial. In addition, the indenture governing the senior secured notes and the agreements governing our other indebtedness do not limit us from incurring obligations that do not constitute indebtedness as defined therein.Peabody’s Capital Structure
The terms of our indenture governing our senior secured notes and the agreements and instruments governing our other indebtednessthe Company’s debt and surety bonding obligations impose restrictions that may limit ourits operating and financial flexibility.
The indenture governing our senior secured notes and the agreements governing our other indebtednessthe Company’s debt and surety bonding obligations contain certain restrictions and covenants which restrict ourits 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 ourthe Company’s ability to operate ourits business, as well as significantly affect ourits liquidity, and therefore could adversely affect ourits results of operations. Our credit facility also contains a mandatory prepayment provision providing that certain amounts of excess cash flow (as defined in the agreements governing the facility) must be utilized to make payments on the outstanding balance under that facility.
These restrictions and covenants limit, among other things, ourthe 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 ourits assets; and
place restrictions on the ability of subsidiaries to pay•receive dividends or make other payments to us.from subsidiaries in certain cases.
OurThe Company’s ability to comply with these restrictions or covenants may be affected by events beyond ourits control and wethe Company may need to refinance existing debt in the future. A breach of any of these restrictions or covenants together with the expiration of any cure period, if applicable, could result in a default under our senior secured notes.default. If any such default occurs, subject to applicable grace periods, the holderholders of our senior secured notesthe Company’s indebtedness may elect to declare all outstanding senior secured notes,such indebtedness, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If thesuch obligations under our senior secured notes were to be accelerated, ourthe Company’s financial resources may be insufficient to repay the notesdebt and any other indebtednessobligations becoming due in full.full as a result of certain cross default provisions.
In addition, if we breachIf the covenants in the indentures governing the senior secured notes and do not cure such breach within the applicable time periods specified therein, we would cause an event ofCompany experiences a default under the indenture governing the senior secured notes and a cross-default to certainterms of our other indebtedness and the lendersits debt or holders thereunder could accelerate their obligations. If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our indebtedness is in defaultsurety bonding obligations for any reason, ourits business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenantssuch terms may make it more difficult for usthe Company to successfully execute ourits business strategy and compete against companies who are not subject to such restrictions.
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Peabody Energy Corporation | 2022 Form 10-K | 38 |
The number and quantity of viable financing and insurance alternatives available to usthe 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 ourits efforts with respect to environmental and social matters and related governance considerations could harm the perception of our companythe Company by certaina significant number of investors or result in the exclusion of ourits securities from consideration by those investors.
Global climate issues, including with respect to greenhouse gases such as carbon dioxide and methane and the relationship that greenhouse gases have with climate change, continue to attract significant public and scientific attention.
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Peabody Energy Corporation | 2019 Form 10-K | 38 |
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, which alsocoal. 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 corporateenvironmental, social and governance related to environmental and social 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.
These efforts may have adverse consequences, including, but not limited to:
•restricting ourthe Company’s ability to access capital and financial markets in the future;
•reducing the demand and price for ourits equity securities;
•increasing the cost of borrowing;
•causing a decline in ourthe Company’s credit ratings;
•reducing the availability, and/or increasing the cost of, third-party insurance;
•increasing ourthe 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 ourthe Company’s flexibility in business development activities such as mergers, acquisitions and divestures.divestitures.
Risks Related to Ownership of OurPeabody’s Securities
The price of ourPeabody’s securities may be volatile.
The price of ourPeabody’s common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of ourits Common Stock regardless of ourits operating performance, including, among others:
•actual or anticipated fluctuations in ourPeabody’s quarterly and annual results and those of other public companies in ourits 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 usPeabody or to accurately predict the results weit actually achieve;achieves;
•changes in accounting principles;
•announcements concerning usPeabody or ourits competitors;
•the purchase and sale of shares of its Common Stock by significant shareholders;
•lack of or excess of trading liquidity; and
•the general statevolatility of the securities market.markets.
In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of our Common Stock, regardless of our actual operating performance. As a result of all of these factors, investors in ourPeabody’s Common Stock may not be able to resell their stock at or above the price they paid or at all. Further, wePeabody 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 ourits results of operation.
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Peabody Energy Corporation | 2022 Form 10-K | 39 |
Peabody’s Common Stock is subject to dilution and may be subject to further dilution in the future.
OurPeabody’s Common Stock is subject to dilution from ourits convertible senior debt and its long-term incentive plan. In addition, in the future, wePeabody may issuecontinue issuing equity securities in connection with future investments, acquisitions 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.
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Peabody Energy Corporation | 2019 Form 10-K | 39 |
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 ourthe Company’s other stakeholders. A significant stockholder may exert substantial influence over usthe Company to cause usthe 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 usPeabody 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 usPeabody or other holders of ourits Common Stock or debt instruments.
A significant stockholder may also sell shares of our Common Stock into the market from time to time, and we cannot predict the effect, if any, that suchThe future sales may have on the market price of our Common Stock.
The payment of dividends on ourPeabody’s stock or future repurchases of ourits stock is dependent on a number of factors and future payments and repurchases cannot be assured.
RestrictiveAs 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 ourthe Company’s credit facility and in the indenture governing our senior secured notessurety agreements limit ourits ability to pay cash dividends and repurchase shares. Other debt instruments to which we or our subsidiaries are, or may be, a party, also contain restrictive covenants that may limit our ability to pay dividends or for us to receive dividends from our subsidiaries, any of whichSuch restrictions may negatively impact the trading price of the Common Stock. In addition, holders of capital stock will only be entitled to receive such cash dividends as our Board of Directors may declare out of funds legally available for such payments, and our Board of Directors may only authorize us to repurchase shares of our capital stock with funds legally available for such repurchases. The payment of future cash dividends and future repurchases will depend upon ourthese restrictions, as well as Peabody’s earnings, economic conditions, liquidity and capital requirements, and other factors, including ourits leverage and other financial ratios. Accordingly, wethe Company cannot make any assurance that future dividends will be paid or future repurchases will be made.
Other Business RisksGeneral Risk Factors
WeThe Company may not be able to fully utilize ourits deferred tax assets.
We areThe Company is subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2019, we2022, the Company had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $2,208.1$1,587.0 million and $140.2$81.7 million, respectively, as described further in Note 12.8. “Income Taxes” to the accompanying consolidated financial statements. At that date, wethe Company also had recorded a valuation allowance of $2,068.4 million, substantially comprised of a full valuation allowance against our net deferred tax asset positions in the U.S. and Australia driven by recent cumulative book losses, as determined by considering all sources of available income (including items classified as discontinued operations or recorded directly to “Accumulated other comprehensive income”), which limited our ability to look to future taxable income in assessing the likelihood of realizing those assets.$1,451.0 million.
The Company’s ability to use its net operating lossU.S. NOL carryforwards may be limited if it experiences an “ownership change” as defined in Section 382 (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.
There is no assurance thatAlthough the Company will not experience a future ownership change under Section 382 that may significantly limit or possibly eliminate its ability to use its net operating loss carryforwards. Potential future transactions involving the sale or issuance of our Common Stock, including the exercise of conversion options under the terms of any convertible debt that Peabody may issue in the future, the repurchase of such debt with Common Stock, any issuance of Common Stock for cash and the acquisition or disposition of such stock by a stockholder owning 5% or more of our Common Stock, or a combination of such transactions, may increase the possibility that the Company will experience a future ownership change under Section 382.
Under Section 382, a future ownership change would subject the Company to additional annual limitations that apply to the amount of pre-ownership change net operating losses that may be used to offset post-ownership change taxable income. This limitation is generally determined by multiplying the value of a corporation’s stock immediately before the ownership change by the applicable long-term tax-exempt rate. Any unused annual limitation may, subject to certain limits, be carried over to later years, and the limitation may under certain circumstances be increased by built-in gains in the assets held by such corporation at the time of the ownership change. This limitation could cause the Company’s U.S. federal income taxes to be greater, or to be paid earlier, than they otherwise would be, and could cause all or a portion of the Company’s net operating loss carryforwards to expire unused. Similar rules and limitations may apply for state income tax purposes. The Company’s ability to use its net operating loss carryforwards will also depend on the amount of taxable income it generates in future periods. Its net operating loss carryforwards may expire before the Company can generate sufficient taxable income to use them in full.
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Peabody Energy Corporation | 2019 Form 10-K | 40 |
Although we may be able to utilize some or all of those deferred tax assets in the future if we haveit 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 weit will be able to do so. Further, we arethe 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 ourits operations in those jurisdictions to support the realization of the related net deferred tax asset positions. OurThe Company’s results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.
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Peabody Energy Corporation | 2022 Form 10-K | 40 |
Acquisitions and divestitures are a potentially important part of ourthe Company’s long-term strategy, subject to ourits investment criteria, and involve a number of risks, any of which could cause usthe Company not to realize the anticipated benefits.
WeThe Company may engage in acquisition or divestiture activity based on ourits set of investment criteria to produce outcomes that increase shareholder value. As it relates to divestitures, we may dispose of certain assets within our portfolio if we determine thatvalue or provide potential strategic benefits. If the price received is more beneficial to us than keeping the assets within our portfolio. Conversely, acquisitions are a potentially important part of our long-term strategy, and we may pursue acquisition opportunities. If we failCompany 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 properties we acquire, ourassets it acquires, its business, financial condition or results of operations could be negatively affected. Moreover, any transactions we pursuethe Company pursues could materially impact ourits liquidity and an acquisition could increase capital resource needs and may require usit to incur indebtedness, seek equity capital or both. WeThe 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 ourits assuming significant long-term liabilities, including potentially unknown liabilities, relative to the value of the acquisitions.
In addition to the above, any acquisition would be accompanied by risks associated with integrating and assimilating the operations and personnel of any acquired companies, failure to realize the anticipated synergies and maximize the financial and strategic position of the combined enterprise and inability to maintain uniform standards, policies and controls across the organization. Additionally, the acquired companies, assets or properties may have unknown liabilities which could be significant.
OurPeabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in ourPeabody’s certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us,it, even if doing so might be beneficial to ourits stockholders. Provisions of ourPeabody’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 ourits Common Stock and may have the effect of delaying or preventing a change in control.
Diversity in interpretation and application of accounting literature in the mining industry may impact ourthe Company’s reported financial results.
The mining industry has limited industry-specific accounting literature and, as a result, we understandthe 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, wethe Company may need to restate ourits reported results if the resulting interpretations differ from ourits current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of ourthe Company’s significant accounting policies.
Item 1B. Unresolved Staff Comments.
None.
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Peabody Energy Corporation | 2019 Form 10-K | 41 |
Item 2. Properties.
Coal Reserves and Resources
We controlled an estimated 4.1 billion tonsInformation concerning the Company’s mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of proven and probable coal reserves assubpart 1300 of Regulation S-K, which first became applicable to the Company for the year ended December 31, 2019. An estimated 3.6 billion tons2021. These requirements differ significantly from the previously applicable disclosure requirements of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 1.5% of our U.S. proven and probable coal reserves, or 53 million tons, are metallurgical coking coal. The remainder of our U.S. coal reserves consists of thermal coal. Approximately 55% of our Australian proven and probable coal reserves, or 269 million tons, are metallurgical coal, comprised of approximately 143 million and 126 million tons of coking coal and low-volatile pulverized coal injection (LV PCI) coals, respectively. The remainder of our Australian coal reserves consists of thermal coal. We own approximately 24% of these reserves and leased property comprises the remaining 76%. Approximately 70% of our reserves, or 2.8 billion tons, are compliance coal and 30% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). Compliance coal is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
Below is a table summarizing the locations and proven and probable coal reserves of our major mining segments.
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| | | | Proven and Probable Reserves as of December 31, 2019 (1) |
| | | | Owned Tons | | Leased Tons | | Total Tons |
Mining Segment | | Locations | | | |
| | | | (Tons in millions) |
Seaborne Thermal Mining | | New South Wales | | — |
| | 250 |
| | 250 |
|
Seaborne Metallurgical Mining | | Queensland, New South Wales and Alabama | | — |
| | 297 |
| | 297 |
|
Powder River Basin Mining | | Wyoming | | — |
| | 2,309 |
| | 2,309 |
|
Midwestern U.S. Mining | | Illinois, Indiana and Kentucky | | 927 |
| | 228 |
| | 1,155 |
|
Western U.S. Mining | | Arizona, New Mexico and Colorado | | 32 |
| | 7 |
| | 39 |
|
Total Proven and Probable Coal Reserves | | 959 |
|
| 3,091 |
|
| 4,050 |
|
| | | | | | | | |
Total United States | | 959 |
| | 2,597 |
| | 3,556 |
|
Total Australia | | — |
| | 494 |
| | 494 |
|
Total Proven and Probable Coal Reserves | | 959 |
| | 3,091 |
| | 4,050 |
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(1)
| Estimated proven and probable coal reserves have been adjusted to account for estimated process dilutions and losses during mining and processing involved in producing a saleable coal product. |
Reserves are defined by SEC Industry Guide 77. Among other differences, subpart 1300 of Regulation S-K requires disclosure of mineral resources, in addition to mineral reserves, both in the aggregate and for each of the Company��s 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 depositresource, which couldincludes 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 and legally extracted or produced at the timeviable project. The conversion of the reserve determination. Proven and probable coalreported mineral resources to mineral reserves are defined by SEC Industry Guide 7 as follows:
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• | Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
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• | Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
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Our estimates of proven and probable coal reserves are established within these guidelines. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density.
should not be assumed.
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Peabody Energy Corporation | 20192022 Form 10-K | 4241 |
Our guidelines for geologic assurance surroundingCoal resources are estimated proven and probable U.S. and Australian coal reserves generally follow the respective industry-accepted practices of those countries. In the U.S., our estimated proven coal reserves lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas, while our estimated probable coal reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. In Australia, our estimated proven coal reserves generally lie within 250 meters of a point of observation, while our estimated probable coal reserves may lie more than 250 meters, but less than 500 meters, from a point of observation. For some of our Australian coal reserves, the distance between points of observation is determined by a geostatistical study.
The preparation of our coal reserve estimates is completed in accordance with our prescribed internal control procedures, which include verification of input data into a coal reserve forecasting and economic evaluation software system, as well as multi-functional management review. Our reserve estimates are prepared by our staff of experienced geologists and engineers. Our corporate Geological Services group is responsible for tracking changes in reserve estimates, supervising our other geologists and coordinating periodic third-party reviews of our reserve estimates by qualified mining consultants.
Our coal reserve estimates are predicated on information obtainedgeological models constructed from an extensive historical database of drill holes and information obtained from ourthe Company’s ongoing drilling program. We compile dataData from individual drill holes is compiled in a computerized drill-hole database, from whichincluding the depth, thickness and, where core drilling is used, the quality of the coal is determined. Theobserved. For coal deposits, the density of a drill pattern determinesis one of the important factors which determine whether the related coal reserves will be classified as provenmeasured, indicated, or probable. Our coal reserve estimatesinferred.
Mineral resource classifications are then input into our computerized land management system, which overlays thatdifferentiated 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 dataconfidence; quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with data on ownership or controla 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 surface interestsinferred 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.
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 extentgeologic confidence based on historical experience with a specific coal deposit. Resources are further evaluated using a set of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantitystructure and quality (where available)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 reserves,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 well as production data,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 ownership, lease paymentsresource is considered a proven coal reserve and other information relating to ourhas 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 land holdings. We periodically update our coal reserve estimates to reflect productionhave a moderate degree of coal from those reserves and new drilling or other data received. Accordingly, our coal reserve estimates will change from time to time to reflect the effects of our mining activities, analysis of new engineering and geological data, changes in coal reserve holdings, modification of mining methods and other factors.
Our estimate of the economic recoverability of our coal reserves is generally based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to expected market prices for the quality of coal expected to be mined and take into consideration typical contractual sales agreements for the region and product. Where possible, we also review coal production by competitors in similar mining areas. Only coal reserves expected to be mined economically are included in our reserve estimates. Finally, our coal reserve estimates consider dilutions and losses during mining and processing for recoverability factors to estimate a saleable product. Factors impacting our 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 estimates are also impacted by decreases resulting from current year production and increases resulting from information obtained from additional drilling. Our estimation as of December 31, 2019 reflected a net reduction compared to the prior year of 841 million tons of coal reserves. The decrease was driven by production, changes to our estimatesassurance of economic recoverability to reflect current market conditions, mine plan changes and new drilling.
We periodically engage independent mining and geological consultants and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability. There was no audit conducted in 2019, and in coming years we plan to complete additional audits of our reserve estimates on a cyclical basis for each of our major operating regions.
With respect to the accuracy of our coal reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification.viability.
For each mine or future mine, wethe Company develops Life-of-Mine (LOM) plans which employ a market-driven, risk adjustedrisk-adjusted capital allocation process to guide long-term mine planning of active operations and development projectsprojects. QPs rely on LOM planning as an integral process for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning.coal reserve and resource estimates. The LOM plan projects,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.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 recoverableviable coal in the LOM plan.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 the Company’s 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.
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Peabody Energy Corporation | 20192022 Form 10-K | 4342 |
Pricing
The pricing information usedCompany is party to establish our reserves includes internal, proprietary price forecasts and existing contract economics, in each case on a mine-by-mine and product-by-product basis. In general, our 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 steel demand, 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 us to confirm the conclusions reached through our analytical processes, and our 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 we evaluate in developing our 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 our price forecasts and realized factors could cause actual pricing to differ from our 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 reserve 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 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 individual 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.
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Peabody Energy Corporation | 2019 Form 10-K | 44 |
Costs
The cost estimates we use to establish our reserves are generally estimated 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. Our 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 cost at our various operations include:
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• | Geological settings. The geological characteristics of each mine are among the most important factors that determine the mining cost. Our geology department conducts the exploration program and provides 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.
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• | Scale of operations and the equipment sizes. For surface mines, our dragline systems generally have a lower unit cost than truck-and-shovel systems for overburden removal. The longwall operations generally are more cost effective than room-and-pillar operations for underground mines.
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• | 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 bolts represents a significant cost. Forecasted commodity prices are used to project those costs in the financial models we use to establish our reserves.
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• | Target product quality. By targeting a premium quality product, our 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 our mine plans, the product qualities are estimated to correspond to existing contracts and forecasted market demands.
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• | Transportation costs. Transportation costs vary by region. Most of our U.S. thermal operations sell coal at mine loadouts. Therefore, no transportation expenses are included in our U.S. thermal cost estimates. Our seaborne operations typically sell coal at designated ports. The estimated costs for our seaborne operations include rail and barge transportation and related fees at ports.
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• | Royalty costs. Our 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.
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• | Exchange rates. Costs related to our Australian production are predominantly denominated in Australian dollars, while the Australian coal that we export is sold in U.S. dollars. As a result, Australian/U.S. dollar exchange rates impact the U.S. dollar cost of Australian production.
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Based on our mine-by-mine and product-by-product evaluations of the estimated prices for our coal, and the costs and expenses of mining and selling our coal, we have concluded our reserves were economically recoverable as of December 31, 2019.
On October 31, 2018, the SEC voted to adopt amendments to modernize the property disclosure requirements for mining registrants and related guidance under the Securities Act of 1933 and the Securities Exchange Act of 1934. The final rules provide a three-year transition period, thus, we will be required to begin to comply with the new rules for the fiscal year beginning on January 1, 2021 (reported in the Annual Report on Form 10-K for the year ended December 31, 2021). We are in the process of assessing the impact the new rules will have on our disclosures.
We have 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 ourPeabody’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 our 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, 2019, we2022, the Company leased 1,610 acres of federal land in Alabama, 6,1073,480 acres in Colorado, 640282 acres in New Mexico and 38,915 acres in Wyoming, for a total of 47,27244,287 acres nationwide subject to those limitations.
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Peabody Energy Corporation | 2019 Form 10-K | 45 |
Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 64,783 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We 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 usthe 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 our 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 reservescoal properties may expire or these leases may be renewed periodically.
Mining and exploration in Australia isare 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.
Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reservesPricing
The pricing information used in support of the lessors or grantorsCompany’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 and economic activity, 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 boundariescost of our leased properties are not completely verified until we prepare to mine those reserves.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.
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Peabody Energy Corporation | 20192022 Form 10-K | 4643 |
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.
The following charts provideMetallurgical. 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 summary, by mining complex, of production (in descending order by mining segment) for the years ended December 31, 2019, 2018 and 2017, tonnagemanufacturing input. Competition from other types of coal reservesis 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 assignedcontractually passed on to our active operating mines, our property interestcustomers in those reserves and other characteristics of the facilities.
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SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES |
(Tons in millions) |
| | | | | | | | | | Sulfur Content of Assigned Reserves as of December 31, 2019 (1) | | |
| | | | | | | | | | <1.2 lbs. | | >1.2 to 2.5 lbs. | | >2.5 lbs. | | As |
| | Production | | | | Sulfur | | Sulfur | | Sulfur | | Received |
| | Year Ended December 31, | | Type of | | Dioxide per | | Dioxide per | | Dioxide per | | Btu per |
Segment/Mining Complex | | 2019 | | 2018 | | 2017 | | Coal | | Million Btu | | Million Btu | | Million Btu | | pound (2) |
Seaborne Thermal Mining: | | | | | | | | | | | | | | | | |
Wilpinjong | | 14.1 |
| | 14.1 |
| | 13.4 |
| | T | | 104 |
| | — |
| | — |
| | 10,000 |
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Wambo (3) | | 5.6 |
| | 5.2 |
| | 5.9 |
| | T/C | | 146 |
| | — |
| | — |
| | 11,300 |
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Total | | 19.7 |
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| 19.3 |
|
| 19.3 |
|
|
|
| 250 |
|
| — |
|
| — |
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Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | |
Coppabella | | 2.4 |
| | 2.7 |
| | 2.8 |
| | P | | 24 |
| | — |
| | — |
| | 12,600 |
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Shoal Creek | | 1.9 |
| | 0.2 |
| | — |
| | C | | 53 |
| | — |
| | — |
| | 12,700 |
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Moorvale | | 1.7 |
| | 2.1 |
| | 1.8 |
| | C/P/T | | 8 |
| | — |
| | — |
| | 12,500 |
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Metropolitan | | 1.5 |
| | 1.7 |
| | 1.0 |
| | C/P/T | | 18 |
| | — |
| | — |
| | 12,600 |
|
Millennium | | 0.6 |
| | 1.9 |
| | 3.3 |
| | C/P | | — |
| | — |
| | — |
| | 12,600 |
|
North Goonyella | | — |
| | 1.4 |
| | 3.4 |
| | C | | 82 |
| | — |
| | — |
| | 12,700 |
|
Middlemount (4) | | — |
| | — |
| | — |
| | C/P | | 22 |
| | — |
| | — |
| | 12,400 |
|
Total | | 8.1 |
| | 10.0 |
| | 12.3 |
| | | | 207 |
|
| — |
|
| — |
| | |
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Powder River Basin Mining: | | | | | | | | | | | | | | | | |
North Antelope Rochelle | | 85.3 |
| | 98.3 |
| | 101.6 |
| | T | | 1,610 |
| | — |
| | — |
| | 8,800 |
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Caballo | | 12.6 |
| | 11.3 |
| | 11.1 |
| | T | | 447 |
| | 6 |
| | — |
| | 8,400 |
|
Rawhide | | 10.1 |
| | 9.5 |
| | 10.4 |
| | T | | 200 |
| | 46 |
| | — |
| | 8,300 |
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Total | | 108.0 |
| | 119.1 |
| | 123.1 |
| | | | 2,257 |
| | 52 |
| | — |
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Midwestern U.S. Mining: | | | | | | | | | | | | | | | | |
Bear Run | | 6.8 |
| | 6.9 |
| | 7.3 |
| | T | | 4 |
| | 25 |
| | 205 |
| | 10,900 |
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Gateway North | | 3.0 |
| | 3.1 |
| | 2.5 |
| | T | | — |
| | — |
| | 52 |
| | 10,900 |
|
Wild Boar | | 2.5 |
| | 2.7 |
| | 2.7 |
| | T | | — |
| | — |
| | 30 |
| | 11,100 |
|
Francisco Underground | | 2.0 |
| | 2.2 |
| | 2.2 |
| | T | | — |
| | — |
| | 14 |
| | 11,370 |
|
Wildcat Hills Underground (5) | | 1.4 |
| | 1.3 |
| | 1.5 |
| | T | | — |
| | — |
| | — |
| | 12,100 |
|
Somerville Central | | 1.2 |
| | 2.0 |
| | 2.2 |
| | T | | — |
| | — |
| | 3 |
| | 11,000 |
|
Cottage Grove (6) | | 0.1 |
| | 0.4 |
| | 0.3 |
| | T | | — |
| | — |
| | — |
| | — |
|
Total | | 17.0 |
| | 18.6 |
| | 18.7 |
| | | | 4 |
| | 25 |
| | 304 |
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Western U.S. Mining: | | | | | | | | | | | | | | | | |
El Segundo/Lee Ranch | | 5.5 |
| | 5.5 |
| | 4.9 |
| | T | | 4 |
| | 23 |
| | 7 |
| | 9,100 |
|
Kayenta (7) | | 3.8 |
| | 6.5 |
| | 6.2 |
| | T | | — |
| | — |
| | — |
| | 10,600 |
|
Twentymile | | 2.6 |
| | 3.1 |
| | 3.8 |
| | T | | 5 |
| | — |
| | — |
| | 11,200 |
|
Total | | 11.9 |
| | 15.1 |
| | 14.9 |
| | | | 9 |
| | 23 |
| | 7 |
| | |
Total Assigned | | 164.7 |
|
| 182.1 |
|
| 188.3 |
|
|
|
| 2,727 |
|
| 100 |
|
| 311 |
| | |
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
certain commercial relationships.
|
| | | | | | | |
Peabody Energy Corporation | 20192022 Form 10-K | 4744 |
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: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ASSIGNED RESERVES (8) | | | | |
AS OF DECEMBER 31, 2019 | | | | |
(Tons in millions) | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | Attributable Ownership | | 100% Project Basis | | Modifying Factors (9) |
| | | | Proven and Probable Reserves | | | | | | | | | | Proven and Probable Reserves | | | | | | | | | | | | |
Segment/Mining Complex | | Interest | | | Owned | | Leased | | Surface | | Underground | | | Owned | | Leased | | Surface | | Underground | | ROM Factor | | Yield |
Seaborne Thermal Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Wilpinjong | | 100% | | 104 |
| | — |
| | 104 |
| | 104 |
| | — |
| | 104 |
| | — |
| | 104 |
| | 104 |
| | — |
| | 104 | % | | 90 | % |
Wambo (3) | | (a) | | 146 |
| | — |
| | 146 |
| | 36 |
| | 110 |
| | 179 |
| | — |
| | 179 |
| | 69 |
| | 110 |
| | 99 | % | | 73 | % |
Total | | | | 250 |
| | — |
| | 250 |
| | 140 |
| | 110 |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Coppabella | | 73.3% | | 24 |
| | — |
| | 24 |
| | 24 |
| | — |
| | 33 |
| | — |
| | 33 |
| | 33 |
| | — |
| | 93 | % | | 77 | % |
Shoal Creek | | 100% | | 53 |
| | — |
| | 53 |
| | — |
| | 53 |
| | 53 |
| | — |
| | 53 |
| | — |
| | 53 |
| | 102 | % | | 56 | % |
Moorvale | | 73.3% | | 8 |
| | — |
| | 8 |
| | 8 |
| | — |
| | 11 |
| | — |
| | 11 |
| | 11 |
| | — |
| | 117 | % | | 80 | % |
Metropolitan | | 100% | | 18 |
| | — |
| | 18 |
| | — |
| | 18 |
| | 18 |
| | — |
| | 18 |
| | — |
| | 18 |
| | 117 | % | | 78 | % |
Millennium | | 100% | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 95 | % | | 79 | % |
North Goonyella | | 100% | | 82 |
| | — |
| | 82 |
| | — |
| | 82 |
| | 82 |
| | — |
| | 82 |
| | — |
| | 82 |
| | 76 | % | | 82 | % |
Middlemount (4) | | 50% | | 22 |
| | — |
| | 22 |
| | 22 |
| | — |
| | 44 |
| | — |
| | 44 |
| | 44 |
| | — |
| | 85 | % | | 77 | % |
Total | | | | 207 |
| | — |
| | 207 |
| | 54 |
| | 153 |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Powder River Basin Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
North Antelope Rochelle | | 100% | | 1,610 |
| | — |
| | 1,610 |
| | 1,610 |
| | — |
| | 1,610 |
| | — |
| | 1,610 |
| | 1,610 |
| | — |
| | 92 | % | | 100 | % |
Caballo | | 100% | | 453 |
| | — |
| | 453 |
| | 453 |
| | — |
| | 453 |
| | — |
| | 453 |
| | 453 |
| | — |
| | 90 | % | | 100 | % |
Rawhide | | 100% | | 246 |
| | — |
| | 246 |
| | 246 |
| | — |
| | 246 |
| | — |
| | 246 |
| | 246 |
| | — |
| | 93 | % | | 100 | % |
Total | | | | 2,309 |
| | — |
| | 2,309 |
| | 2,309 |
| | — |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Midwestern U.S. Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Bear Run | | 100% | | 234 |
| | 104 |
| | 130 |
| | 234 |
| | — |
| | 234 |
| | 104 |
| | 130 |
| | 234 |
| | — |
| | 106 | % | | 73 | % |
Gateway North | | 100% | | 52 |
| | 51 |
| | 1 |
| | — |
| | 52 |
| | 52 |
| | 51 |
| | 1 |
| | — |
| | 52 |
| | 70 | % | | 62 | % |
Wild Boar | | 100% | | 30 |
| | 11 |
| | 19 |
| | 30 |
| | — |
| | 30 |
| | 11 |
| | 19 |
| | 30 |
| | — |
| | 104 | % | | 80 | % |
Francisco Underground | | 100% | | 14 |
| | 3 |
| | 11 |
| | — |
| | 14 |
| | 14 |
| | 3 |
| | 11 |
| | — |
| | 14 |
| | 71 | % | | 65 | % |
Wildcat Hills Underground (5) | | 100% | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — | % | | — | % |
Somerville Central | | 100% | | 3 |
| | 3 |
| | — |
| | 3 |
| | — |
| | 3 |
| | 3 |
| | — |
| | 3 |
| | — |
| | 103 | % | | 68 | % |
Cottage Grove (6) | | 100% | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — | % | | — | % |
Total | | | | 333 |
| | 172 |
| | 161 |
| | 267 |
| | 66 |
| |
| |
| |
| |
| |
| | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Western U.S. Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
El Segundo/Lee Ranch | | 100% | | 34 |
| | 29 |
| | 5 |
| | 34 |
| | — |
| | 34 |
| | 29 |
| | 5 |
| | 34 |
| | — |
| | 87 | % | | 100 | % |
Kayenta (7) | | 100% | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — | % | | — | % |
Twentymile | | 100% | | 5 |
| | 3 |
| | 2 |
| | — |
| | 5 |
| | 5 |
| | 3 |
| | 2 |
| | — |
| | 5 |
| | 119 | % | | 67 | % |
Total | | | | 39 |
| | 32 |
| | 7 |
| | 34 |
| | 5 |
| |
| |
| |
| |
| |
| | | | |
Total Assigned | | | | 3,138 |
|
| 204 |
|
| 2,934 |
|
| 2,804 |
|
| 334 |
| |
| |
| |
| |
| |
| | | | |
•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 2.4 billion tons of coal reserves and 2.4 billion tons of coal resources as of December 31, 2022. 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 | 20192022 Form 10-K | 4845 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (8) |
AS OF DECEMBER 31, 2019 |
(Tons in millions) |
| | | | | | | | | | | | | | | | | | | | |
| | Attributable Ownership | | 100% Project Basis |
| | | | | | Proven and | | | | | | | | | | Proven and | | | | |
| | Total Tons | | Probable | | | | | | Total Tons | | Probable | | | | |
Coal Seam Location | | Assigned | | Unassigned | | Reserves | | Proven | | Probable | | Assigned | | Unassigned | | Reserves | | Proven | | Probable |
Seaborne Thermal Mining (New South Wales) | | 250 |
| | — |
| | 250 |
| | 203 |
| | 47 |
| | 283 |
| | — |
| | 283 |
| | 211 |
| | 72 |
|
| | | | | | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | | | | | |
Alabama | | 53 |
| | — |
| | 53 |
| | 52 |
| | 1 |
| | 53 |
| | — |
| | 53 |
| | 52 |
| | 1 |
|
New South Wales | | 18 |
| | — |
| | 18 |
| | 2 |
| | 16 |
| | 18 |
| | — |
| | 18 |
| | 2 |
| | 16 |
|
Queensland | | 136 |
| | 90 |
| | 226 |
| | 184 |
| | 42 |
| | 170 |
| | 120 |
| | 290 |
| | 232 |
| | 58 |
|
Total | | 207 |
| | 90 |
| | 297 |
| | 238 |
| | 59 |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Powder River Basin Mining (Wyoming) | | 2,309 |
| | — |
| | 2,309 |
| | 2,202 |
| | 107 |
| | 2,309 |
| | — |
| | 2,309 |
| | 2,202 |
| | 107 |
|
| | | | | | | | | | | | | | | | | | | | |
Midwestern U.S. Mining: | | | | | | | | | | | | | | | | | | | | |
Illinois | | 52 |
| | 719 |
| | 771 |
| | 333 |
| | 438 |
| | 52 |
| | 719 |
| | 771 |
| | 333 |
| | 438 |
|
Indiana | | 281 |
| | 6 |
| | 287 |
| | 208 |
| | 79 |
| | 281 |
| | 6 |
| | 287 |
| | 208 |
| | 79 |
|
Kentucky (10) | | — |
| | 97 |
| | 97 |
| | 44 |
| | 53 |
| | — |
| | 97 |
| | 97 |
| | 44 |
| | 53 |
|
Total | | 333 |
| | 822 |
| | 1,155 |
| | 585 |
| | 570 |
| |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | | | | | |
Western U.S. Mining: | | | | | | | | | | | | | | | | | | | | |
Arizona (7) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
New Mexico | | 34 |
| | — |
| | 34 |
| | 34 |
| | — |
| | 34 |
| | — |
| | 34 |
| | 34 |
| | — |
|
Colorado | | 5 |
| | — |
| | 5 |
| | 5 |
| | — |
| | 5 |
| | — |
| | 5 |
| | 5 |
| | — |
|
Total | | 39 |
| | — |
| | 39 |
| | 39 |
| | — |
| |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | | | | | |
Total Proven and Probable | | 3,138 |
|
| 912 |
|
| 4,050 |
|
| 3,267 |
|
| 783 |
| |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SUMMARY COAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2022 (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)(4) | | | | | | | | | | Tons | | %Ash | | %Sulfur | | Kcal/kg(6) | | Tons | | %Ash | | %Sulfur | | Kcal/kg(6) | | Tons | | %Ash | | %Sulfur | | Kcal/kg(6) | | |
Wilpinjong | | AUS | | NSW | | P | | S | | T | | 63 | | | 24.2 | | | 0.5 | | | 5,953 | | | 4 | | | 30.4 | | | 0.4 | | | 5,422 | | | 67 | | | 24.5 | | | 0.5 | | | 5,924 | | | 100 | % |
Wambo Opencut (9) | | AUS | | NSW | | P | | S | | T | | 29 | | | 10.9 | | | 0.3 | | | 6,448 | | | 2 | | | 10.6 | | | 0.3 | | | 6,478 | | | 31 | | | 10.9 | | | 0.3 | | | 6,450 | | | 50 | % |
Wambo Underground | | AUS | | NSW | | P | | U | | T | | 2 | | | 13.7 | | | 0.4 | | | 6,473 | | | 3 | | | 12.2 | | | 0.4 | | | 6,588 | | | 5 | | | 12.9 | | | 0.4 | | | 6,534 | | | 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 | | | | | | | | | | | | 94 | | | | | | | | | 83 | | | | | | | | | 177 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining:(3)(4) | | | | | | | | | | Tons | | %Ash | | %Sulfur | | VM%(7) | | Tons | | %Ash | | %Sulfur | | VM%(7) | | Tons | | %Ash | | %Sulfur | | VM%(7) | | |
Shoal Creek | | USA | | AL | | P | | U | | C | | 15 | | | 10.0 | | | 0.7 | | | 30.2 | | | 2 | | | 10.0 | | | 0.7 | | | 30.2 | | | 17 | | | 10.0 | | | 0.7 | | | 30.2 | | | 100 | % |
Coppabella | | AUS | | QLD | | P | | S | | P | | 6 | | | 9.3 | | | 0.2 | | | 9.9 | | | 4 | | | 9.8 | | | 0.2 | | | 8.5 | | | 10 | | | 9.5 | | | 0.2 | | | 9.3 | | | 73.3 | % |
Moorvale | | AUS | | QLD | | P | | S | | C/P/T | | 4 | | | 11.4 | | | 0.3 | | | 16.5 | | | — | | | — | | | — | | | — | | | 4 | | | 11.4 | | | 0.3 | | | 16.5 | | | 73.3 | % |
Metropolitan | | AUS | | NSW | | P | | U | | C/T | | 3 | | | 13.9 | | | 0.4 | | | 18.6 | | | 7 | | | 13.8 | | | 0.4 | | | 18.7 | | | 10 | | | 13.8 | | | 0.4 | | | 18.6 | | | 100 | % |
North Goonyella | | AUS | | QLD | | D | | 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 | | P | | S | | C/P | | 3 | | | 11.1 | | | 0.4 | | | 18.4 | | | 2 | | | 9.8 | | | 0.4 | | | 17.4 | | | 5 | | | 10.6 | | | 0.4 | | | 18.0 | | | 73.3 | % |
Middlemount (9) | | AUS | | QLD | | P | | S | | C/P | | 25 | | | 10.3 | | | 0.4 | | | 18.0 | | | 9 | | | 10.3 | | | 0.4 | | | 18.0 | | | 34 | | | 10.3 | | | 0.4 | | | 18.0 | | | 50.0 | % |
Total | | | | | | | | | | | | 102 | | | | | | | | | 48 | | | | | | | | | 150 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | | 1,316 | | | 4.4 | | | 0.2 | | | 8,889 | | | 107 | | | 4.5 | | | 0.2 | | | 8,965 | | | 1,423 | | | 4.4 | | | 0.2 | | | 8,895 | | | 100 | % |
Caballo | | USA | | WY | | P | | S | | T | | 274 | | 5.1 | | | 0.3 | | | 8,517 | | | 68 | | 5.6 | | | 0.3 | | | 8,313 | | | 342 | | 5.2 | | | 0.3 | | | 8,476 | | | 100 | % |
Rawhide | | USA | | WY | | P | | S | | T | | 115 | | 5.6 | | | 0.4 | | | 8,278 | | | 2 | | 5.2 | | | 0.3 | | | 8,362 | | | 117 | | 5.6 | | | 0.4 | | | 8,279 | | | 100 | % |
Total | | | | | | | | | | | | 1,705 | | | | | | | | | 177 | | | | | | | | | 1,882 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | | 84 | | | 10.6 | | | 3.1 | | | 11,058 | | | 52 | | | 10.0 | | | 2.5 | | | 11,045 | | | 136 | | | 10.4 | | | 2.9 | | | 11,055 | | | 100 | % |
El Segundo/Lee Ranch | | USA | | NM | | P | | S | | T | | 13 | | | 15.8 | | | 0.9 | | | 9,249 | | | 1 | | | 12.3 | | | 0.7 | | | 9,526 | | | 14 | | | 15.6 | | | 0.9 | | | 9,266 | | | 100 | % |
Gateway North | | USA | | IL | | P | | U | | T | | 38 | | | 8.9 | | | 2.9 | | | 10,888 | | | 5 | | | 9.0 | | | 3.0 | | | 10,874 | | | 43 | | | 8.9 | | | 2.9 | | | 10,886 | | | 100 | % |
Twentymile | | USA | | CO | | P | | U | | T | | 10 | | | 10.7 | | | 0.5 | | | 11,280 | | | 1 | | | 10.2 | | | 0.5 | | | 11,230 | | | 11 | | | 10.6 | | | 0.5 | | | 11,272 | | | 100 | % |
Wild Boar | | USA | | IN | | P | | S | | T | | 7 | | | 8.3 | | | 2.4 | | | 11,010 | | | 8 | | | 8.4 | | | 2.7 | | | 11,470 | | | 15 | | | 8.4 | | | 2.6 | | | 11,265 | | | 100 | % |
Francisco Underground | | USA | | IN | | P | | U | | T | | 3 | | | 8.7 | | | 2.9 | | | 11,500 | | | 4 | | | 9.0 | | | 3.3 | | | 11,455 | | | 7 | | | 8.9 | | | 3.1 | | | 11,480 | | | 100 | % |
Total | | | | | | | | | | | | 155 | | | | | | | | | 71 | | | | | | | | | 226 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Grand total | | | | | | | | | | | | 2,056 | | | | | | | | | 379 | | | | | | | | | 2,435 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | 20192022 Form 10-K | 4946 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD |
AS OF DECEMBER 31, 2019 |
(Tons in millions) |
| | | | | | | | | | | | | | | | |
| | Attributable Ownership | | 100% Project Basis |
| | Reserve Control | | Mining Method | | Reserve Control | | Mining Method |
Coal Seam Location | | Owned | | Leased | | Surface | | Underground | | Owned | | Leased | | Surface | | Underground |
Seaborne Thermal Mining (New South Wales) | | — |
| | 250 |
| | 140 |
| | 110 |
| | — |
| | 283 |
| | 173 |
| | 110 |
|
| | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | |
Alabama | | — |
| | 53 |
| | — |
| | 53 |
| | — |
| | 53 |
| | — |
| | 53 |
|
New South Wales | | — |
| | 18 |
| | — |
| | 18 |
| | — |
| | 18 |
| | — |
| | 18 |
|
Queensland | | — |
| | 226 |
| | 60 |
| | 166 |
| | — |
| | 290 |
| | 96 |
| | 194 |
|
Total | | — |
| | 297 |
| | 60 |
| | 237 |
| | | | | | | | |
| | | | | | | | | | | | | | | | |
Powder River Basin Mining (Wyoming) | | — |
| | 2,309 |
| | 2,309 |
| | — |
| | — |
| | 2,309 |
| | 2,309 |
| | — |
|
| | | | | | | | | | | | | | | | |
Midwestern U.S. Mining: | | | | | | | | | | | | | | | | |
Illinois | | 770 |
| | 1 |
| | — |
| | 771 |
| | 770 |
| | 1 |
| | — |
| | 771 |
|
Indiana | | 124 |
| | 163 |
| | 274 |
| | 13 |
| | 124 |
| | 163 |
| | 274 |
| | 13 |
|
Kentucky (10) | | 33 |
| | 64 |
| | — |
| | 97 |
| | 33 |
| | 64 |
| | — |
| | 97 |
|
Total | | 927 |
| | 228 |
| | 274 |
| | 881 |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | |
Western U.S. Mining: | | | | | | | | | | | | | | | | |
Arizona (7) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
New Mexico | | 29 |
| | 5 |
| | 34 |
| | — |
| | 29 |
| | 5 |
| | 34 |
| | — |
|
Colorado | | 3 |
| | 2 |
| | — |
| | 5 |
| | 3 |
| | 2 |
| | — |
| | 5 |
|
Total | | 32 |
| | 7 |
| | 34 |
| | 5 |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | |
Total Proven and Probable | | 959 |
|
| 3,091 |
|
| 2,817 |
|
| 1,233 |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SUMMARY COAL RESOURCES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2022 (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(6) | Tons | | %Ash | %Sulfur | Kcal/kg(6) | | Tons | | %Ash | %Sulfur | Kcal/kg(6) | | Tons | | %Ash | %Sulfur | Kcal/kg(5) | | |
Wilpinjong | AUS | | NSW | | P | | S | | T | | 103 | | | 23.0 | | | 0.5 | | | 6,055 | | | 25 | | | 25.4 | | | 0.5 | | | 5,860 | | | 128 | | | 23.5 | | | 0.5 | | | 6,017 | | | 6 | | | 27.3 | | | 0.5 | | | 5,698 | | | 100 | % |
Wambo Opencut (9) | AUS | | NSW | | P | | S/U | | T | | 191 | | | 21.6 | | | 0.4 | | | 5,731 | | | 154 | | | 21.5 | | | 0.4 | | | 5,764 | | | 345 | | | 21.6 | | | 0.4 | | | 5,746 | | | 259 | | | 19.9 | | | 0.4 | | | 5,864 | | | 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 | | | | | | | | | | | | 513 | | | | | | | | | 262 | | | | | | | | | 775 | | | | | | | | | 312 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | | 14 | | | 18.5 | | | 0.3 | | | 16.7 | | | 14 | | | 17.2 | | | 0.3 | | | 16.6 | | | 28 | | | 17.9 | | | 0.3 | | | 16.7 | | | 5 | | | 15.9 | | | 0.3 | | | 16.7 | | | 73.3 | % |
Moorvale South | AUS | | QLD | | P | | 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 | | | | | | | | | | | | 369 | | | | | | | | | 351 | | | | | | | | | 720 | | | | | | | | | 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 | | 15 | | | 5.3 | | | 0.4 | | | 8,218 | | | 65 | | | 5.2 | | | 0.4 | | | 8,211 | | | 80 | | | 5.2 | | | 0.4 | | 8,212 | | | 1 | | | 5.5 | | | 0.4 | | 8,263 | | | 100 | % |
Rawhide | | USA | | WY | | P | | S | | T | | 1 | | | 5.4 | | | 0.4 | | | 8,277 | | | 95 | | | 5.2 | | | 0.3 | | | 8,356 | | | 96 | | | 5.2 | | | 0.3 | | | 8,355 | | | 7 | | | 5.7 | | | 0.4 | | | 8,252 | | | 100 | % |
Total | | | | | | | | | | | | 16 | | | | | | | | | 160 | | | | | | | | | 176 | | | | | | | | | 8 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | | 18 | | | 14.6 | | | 3.5 | | | 10,860 | | | 51 | | | 16.8 | | | 3.5 | | | 10,450 | | | 69 | | | 16.3 | | | 3.5 | | | 10,550 | | | 37 | | | 16.3 | | | 3.5 | | | 10,545 | | | 100 | % |
El Segundo/Lee Ranch | | USA | | NM | | P | | S | | T | | 1 | | | 17.1 | | | 1.1 | | | 9,491 | | | 5 | | | 16.5 | | | 1.0 | | | 9,475 | | | 6 | | | 16.6 | | | 1.0 | | | 9,478 | | | 2 | | | 17.4 | | | 1.2 | | | 9,280 | | | 100 | % |
Wild Boar | USA | | IN | | P | | S | | T | | — | | | — | | | — | | | — | | | 3 | | | 12.9 | | | 6.1 | | | 10,940 | | | 3 | | | 12.9 | | | 5.4 | | | 11,020 | | | 1 | | | 12.9 | | | 5.9 | | | 10,960 | | | 100 | % |
Total | | | | | | | | | | | 19 | | | | | | | | | 59 | | | | | | | | | 78 | | | | | | | | | 40 | | | | | | | | | |
Grand total | | | | | | | | | | 917 | | | | | | | | | 832 | | | | | | | | | 1,749 | | | | | | | | | 614 | | | | | | | | | |
|
| | | | | | | |
Peabody Energy Corporation | 20192022 Form 10-K | 5047 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT |
AS OF DECEMBER 31, 2019 |
(Tons in millions) |
| | | | | | | | | | | | | | | | |
| | | | Attributable Ownership | | 100% Project Basis | | |
| | | | Sulfur Content (1) | | Sulfur Content (1) | | |
| | | | <1.2 lbs. | | >1.2 to 2.5 lbs. | | >2.5 lbs. | | <1.2 lbs. | | >1.2 to 2.5 lbs. | | >2.5 lbs. | | As |
| | | | Sulfur Dioxide | | Sulfur Dioxide | | Sulfur Dioxide | | Sulfur Dioxide | | Sulfur Dioxide | | Sulfur Dioxide | | Received |
| | Type of | | per | | per | | per | | per | | per | | per | | Btu |
Coal Seam Location | | Coal | | Million Btu | | Million Btu | | Million Btu | | Million Btu | | Million Btu | | Million Btu | | per Pound (2) |
Seaborne Thermal Mining (New South Wales) | | T/C | | 250 |
| | — |
| | — |
| | 283 |
| | — |
| | — |
| | 10,700 |
|
| | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | |
Alabama | | C | | 53 |
| | — |
| | — |
| | 53 |
| | — |
| | — |
| | 12,700 |
|
New South Wales | | C/P/T | | 18 |
| | — |
| | — |
| | 18 |
| | — |
| | — |
| | 12,600 |
|
Queensland | | C/P/T | | 226 |
| | — |
| | — |
| | 290 |
| | — |
| | — |
| | 12,400 |
|
Total | | | | 297 |
| | — |
| | — |
| | | | | | | | |
| | | | | | | | | | | | | | | | |
Powder River Basin Mining (Wyoming) | | T | | 2,257 |
| | 52 |
| | — |
| | 2,257 |
| | 52 |
| | — |
| | 8,700 |
|
| | | | | | | | | | | | | | | | |
Midwestern U.S. Mining: | | | | | | | | | | | | | | | | |
Illinois | | T | | — |
| | — |
| | 771 |
| | — |
| | — |
| | 771 |
| | 10,800 |
|
Indiana | | T | | 4 |
| | 25 |
| | 258 |
| | 4 |
| | 25 |
| | 258 |
| | 11,000 |
|
Kentucky (10) | | T | | — |
| | — |
| | 97 |
| | — |
| | — |
| | 97 |
| | 11,800 |
|
Total | | | | 4 |
| | 25 |
| | 1,126 |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | |
Western U.S. Mining: | | | | | | | | | | | | | | | | |
Arizona (7) | | T | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
New Mexico | | T | | 4 |
| | 23 |
| | 7 |
| | 4 |
| | 23 |
| | 7 |
| | 9,150 |
|
Colorado | | T | | 5 |
| | — |
| | — |
| | 5 |
| | — |
| | — |
| | 11,200 |
|
Total | | | | 9 |
| | 23 |
| | 7 |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | |
Total Proven and Probable | | | | 2,817 |
|
| 100 |
|
| 1,133 |
| |
| |
| |
| |
|
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
|
| | | | |
Peabody Energy Corporation(1) | 2019 Form 10-K | 51 |
| |
(1) (2) | ComplianceThe moisture condition for Seaborne Thermal Mining segment coal quality is defined by Phase II of the CAA as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coalon an air-dry basis, except for Wambo Opencut, which is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal. |
| estimated on an as-shipped basis for reserves, and an in-situ moisture basis for resources. |
(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) | (2)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.
|
As-received (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, except for Wambo Opencut which is estimated as gross calorific value. |
(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 the coal on an as-sold basis. The range of variability of the moisture content in coal across a given region may affect the actual shipped Btu contentcontent. |
(9) | Reserve and resource data is maintained and provided by joint venture managing partners utilizing the Australasian Code for Reporting of current production from assigned reserves.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 revenue, 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, strategic priorities, the regulatory environment, capital expansion plans, and the long-term pricing outlook. 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 also assesses material changes in the material properties mainly on the basis of the amount of reserves and resources over a period of three years. The Company concluded that, as of December 31, 2022, its material mining operations had no material changes. The Company will update its assessment of individually material mines on an annual basis.
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 studies 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. The changes from the previous year are not material and no updates for TRS are included in this filing. Other technical details regarding the individual properties should be referred to the previously disclosed TRS.
| | | | | | | | |
(3)Peabody Energy Corporation
| Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas.2022 Form 10-K | 48 |
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, 2022, all required licenses and permits were in place for the operations of NARM.
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.
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.
The property, plant, equipment and mine development assets of NARM had a net book value of approximately $417 million at December 31, 2022. 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.
| | | | | | | | |
(4)Peabody Energy Corporation
| Represents our 50% interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. Because that entity is accounted for as an unconsolidated equity affiliate, 2019, 2018 and 2017 tons produced by Middlemount have been excluded from the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table. Middlemount produced 2.9 million tons, 4.2 million tons, and 4.3 million tons of coal in 2019, 2018 and 2017, respectively (on a 100% basis).2022 Form 10-K | 49 |
The table below presents NARM coal reserve estimates at December 31, 2022, along with comparative quantities at December 31, 2021. NARM did not hold any coal resources as of December 31, 2022. 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NARM - SUMMARY OF RESERVES (1) |
(Tons in millions) |
| | | | | | | | | | | | |
| | December 31, 2022 | | December 31, 2021 |
Coal Reserves (2)(3)(4) | | Tons | | %Ash | | %Sulfur | | Btu | | % Mine Yield(5) | | Tons |
Proven | | 1,316 | | | 4.4 | | | 0.2 | | | 8,889 | | | 100 | % | | 1,378 | |
Probable | | 107 | | | 4.5 | | | 0.2 | | | 8,965 | | | 100 | % | | 106 | |
Total | | 1,423 | | | | | | | | | | | 1,484 | |
| | | | | | | | | | | | |
Year-over-year decrease | | (4) | % | | | | | | | | | | |
The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
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(5) (1) | Economic recoverability is based upon an estimated average sales price per ton of $14.64 for the five-year period ending December 31, 2027 and assumed escalation of 2.0% per annum during the subsequent period through the end of the LOM plan. |
(2) | The Company’s Wildcat Hills Underground 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. |
(5) | Mine ceased production in December 2019. The shipmentyield is the ratio of finalestimated saleable product coal over ROM coal tons, is expected in 2020.with processing loss considered. |
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(6)Peabody Energy Corporation
| The Company’s Cottage Grove Mine closed during July 2019.2022 Form 10-K | 50 |
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, 2022, all required licenses and permits were in place for the operations of the Shoal Creek Mine.
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.
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.
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(7)Peabody Energy Corporation
| The Company’s Kayenta Mine closed during August 2019 upon termination of its coal supply agreement with the Navajo Generating Station in Arizona.2022 Form 10-K | 51 |
The property, plant, equipment and mine development assets of Shoal Creek Mine had a net book value of approximately $287 million at December 31, 2022. 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.
The tables below present Shoal Creek Mine’s estimated coal reserves and resources at December 31, 2022, along with comparative quantities at December 31, 2021. 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.
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SHOAL CREEK MINE - SUMMARY OF RESERVES AND RESOURCES (1) |
(Tons in millions) |
| | | | | | | | | | | | |
| | December 31, 2022 | | December 31, 2021 |
Coal Reserves (2)(4)(5)(6) | | Tons | | %Ash | | %Sulfur | | %VM | | % Mine Yield (7) | | Tons |
Proven | | 15 | | | 10.0 | | | 0.7 | | | 30.2 | | | 36 | % | | 16 | |
Probable | | 2 | | | 10.0 | | | 0.7 | | | 30.2 | | | 36 | % | | 2 | |
Total | | 17 | | | | | | | | | | | 18 | |
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Year-over-year decrease | | (6) | % | | | | | | | | | | |
| | | | | | | | | | | | |
| | December 31, 2022 | | | | December 31, 2021 |
Coal Resources (2)(3)(4)(5) | | Tons | | %Ash | | %Sulfur | | VM% | | | | Tons |
Measured | | 40 | | | 9.6 | | | 0.7 | | | 25.1 | | | | | 40 | |
Indicated | | 35 | | | 9.9 | | | 0.7 | | | 24.1 | | | | | 35 | |
Measured and indicated | | 75 | | | 9.8 | | | 0.7 | | | 24.6 | | | | | 75 | |
Inferred | | 7 | | | 10.2 | | | 0.7 | | | 24.0 | | | | | 7 | |
Total | | 82 | | | | | | | | | | | 82 | |
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The year-over-year decrease in coal reserves reflects 2022 production depletion.
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(8) (1) | Assigned reserves represent recoverableEconomic recoverability is based upon an estimated average sales price per ton of $159.45 for the five-year period ending December 31, 2027 and assumed escalation of 2.0% per annum during the subsequent period through the end of the LOM plan. |
(2) | The quality of coal reserves thatand resources are controlledestimated 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 accessible at active operationsprocessing. |
(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 of December 31, 2019. Unassigned reserves represent coal at currently non-producing locations that would require significant new mine development, mining equipment or plant facilities before operations could beginthe main criteria for the resource boundary based on the property. |
| mine’s actual performance in the last two decades. |
(9) (6) | The modifying factors reflect the assumptions which are utilized to convertquantity of coal quantities and qualities as in ground to run of mine (ROM) coal after mining, and eventually toreserves is estimated on a saleable product coal after processing. Coal reserves are reported as an estimation of the final saleable quantity,basis, which takes into account any losses and dilutionsconsideration of unmined coal (pillars, etc.), 20% coal loss during mining and processing. We generally keep trackprocessing, and additional washing recovery. The results from the LOM planning process demonstrate the economic recoverability of coal reserves through in place coal, ROM coal and product coal. In place coal for U.S. underground reserves excludes planned barrier pillars, but includes regular pillars from projected underground extractions. In place coal for Australian underground reserves is exclusive of all planned pillars. The difference is due to historic practice and software used by each country. The ROM factor represents the estimated ROM coal in relation to the coal in place with considerations of coal losses, dilutions and remaining pillars during mining processes. Thereserve estimate. |
(7) | Mine yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. |
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(10)Peabody Energy Corporation
| All coal reserves in Kentucky are leased to third parties.2022 Form 10-K | 52 |
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 contractor 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 has secured three exploration licenses of 3,186 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 and the third was granted in May 2022 for an initial term of 6 years. As of December 31, 2022, all required licenses and permits were in place for the operations of Wilpinjong.
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.
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.
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(a)Peabody Energy Corporation
| In2022 Form 10-K | 53 |
The property, plant, equipment and mine development assets of Wilpinjong Mine had a net book value of approximately $342 million at December 31, 2022. 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 by providing access to an additional 55 million tonnes of coal reserves. The Company capitalized approximately $62 million related to the project through December 31, 2022 and expects the total cost to reach approximately $76 million.
The tables below present Wilpinjong Mine’s estimated coal reserves and resources at December 31, 2022, along with comparative quantities at December 31, 2021. 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.
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WILPINJONG MINE - SUMMARY OF RESERVES AND RESOURCES (1) |
(Tons in millions) |
| | | | | | | | | | | | |
| | December 31, 2022 | | December 31, 2021 |
Coal Reserves (5)(6) | | Tons | | %Ash | | %Sulfur | | Kcal/kg | | % Mine Yield(7) | | Tons |
Proven | | 63 | | | 24.2 | | | 0.5 | | | 5,953 | | | 82 | % | | 71 | |
Probable | | 4 | | | 30.4 | | | 0.4 | | | 5,422 | | | 82 | % | | 5 | |
Total | | 67 | | | | | | | | | | | 76 | |
| | | | | | | | | | | | |
Year-over-year decrease | | (12) | % | | | | | | | | | | |
| | | | | | | | | | | | |
| | December 31, 2022 | | | | December 31, 2021 |
Coal Resources (2)(3)(4) | | Tons | | %Ash | | %Sulfur | | Kcal/kg | | | | Tons |
Measured | | 103 | | | 23.0 | | | 0.5 | | | 6,055 | | | | | 103 | |
Indicated | | 25 | | | 25.4 | | | 0.5 | | | 5,860 | | | | | 25 | |
Measured and indicated | | 128 | | | 23.5 | | | 0.5 | | | 6,017 | | | | | 128 | |
Inferred | | 6 | | | 27.3 | | | 0.5 | | | 5,698 | | | | | 6 | |
Total | | 134 | | | | | | | | | | | 134 | |
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The year-over-year decrease in the quantity of coal reserves was driven by production depletion.
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(1) | Economic recoverability is based upon product-specific estimated average sales prices per ton of $51.99 for the five-year period ending December 2019, after receiving31, 2027 and assumed escalation of 2.0% to 3.0% per annum during the requisite regulatory and permitting approvals,subsequent period through the Company formed an unincorporated joint venture with Glencore, in which the Company holds a 50% interest, to combine the existing operationsend of the Company’s Wambo Open-Cut MineLOM plan. |
(2) | The quality of coal resources is on an in Australia withsitu, 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 adjacentresults 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 Glencore’s United Mine. The Wambo reservecoal reserves is estimated for our 50% interest in United Wambo Joint Ventureon a saleable product basis, which takes into consideration of mining and 100% interest in Wambo Underground processing loss. The economic results from the LOM planning process demonstrate the economic viability of the coal reserve estimate. |
(7) | Mine areas.yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. |
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Peabody Energy Corporation | 2022 Form 10-K | 54 |
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. During 2022, the Moorvale Mine substantially completed development of, and began production from, its Moorvale South pit. 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. The development of the Moorvale South pit made a portion of the Vermont seam economically mineable. 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 40%, depending upon the realized revenue per tonne. 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 Moorvale South pit 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.
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. The Moorvale Mine utilizes only diesel hydraulic excavators for overburden removal. All CMJV 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.
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Peabody Energy Corporation | 2022 Form 10-K | 55 |
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.
The property, plant, equipment and mine development assets of CMJV had a net book value of approximately $173 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.
The tables below present estimates of the CMJV coal reserves and resources as of December 31, 2022, along with comparative quantities at December 31, 2021. 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.
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CMJV - SUMMARY OF RESERVES AND RESOURCES (1) |
(Tons in millions) |
| | | | | | | | | | | | |
| | December 31, 2022 | | December 31, 2021 |
Coal Reserves (5)(6) | | Tons | | %Ash | | %Sulfur | | %VM | | % Mine Yield (7) | | Tons |
Proven | | 13 | | | 10.4 | | | 0.3 | | | 13.9 | | | 74 | % | | 14 | |
Probable | | 6 | | | 9.8 | | | 0.3 | | | 11.5 | | | 76 | % | | 6 | |
Total | | 19 | | | | | | | | | | | 20 | |
| | | | | | | | | | | | |
Year-over-year decrease | | (5) | % | | | | | | | | | | |
| | | | | | | | | | | | |
| | December 31, 2022 | | | | December 31, 2021 |
Coal Resources (2)(3)(4) | | Tons | | %Ash | | %Sulfur | | VM% | | | | Tons |
Measured | | 30 | | | 17.3 | | | 0.3 | | | 15.3 | | | | | 34 | |
Indicated | | 69 | | | 15.3 | | | 0.3 | | | 14.1 | | | | | 69 | |
Measured and indicated | | 99 | | | 15.9 | | | 0.3 | | | 14.5 | | | | | 103 | |
Inferred | | 84 | | | 15.6 | | | 0.3 | | | 12.9 | | | | | 84 | |
Total | | 183 | | | | | | | | | | | 187 | |
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Year-over-year decrease | | (2) | % | | | | | | | | | | |
| | | | | | | | | | | | |
The decrease in reserves reflects 2022 production depletion, partially offset by the reclassification of certain mine areas to reserves; the decrease in resources reflects this reclassification.
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Peabody Energy Corporation | 2022 Form 10-K | 56 |
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(1) | Economic recoverability is based upon product-specific estimated average sales prices per ton of $122.75 for the five-year period ending December 31, 2027 and assumed escalation of 2% to 3% per annum during the subsequent period through the end of the LOM plan. |
(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. |
(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.
Item 3. Legal Proceedings.
See Note 26.21. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of ourPeabody’s pending legal proceedings, which information is incorporated herein by reference.
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Peabody Energy Corporation | 2022 Form 10-K | 57 |
Item 4. Mine Safety Disclosures.
OurPeabody’s “Safety a Way of Lifeand Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and healthenvironmental stewardship across ourthe Company’s business. It aligns to the National Mining Association’s CORESafety® framework and encompasses three fundamental areas: leadership and organization, safety and health risk management and assurance. WePeabody also partnerpartners with other companies and certain governmental agencies to pursue new technologies that have the potential to improve ourits safety performance and provide better safety protection for employees.
WePeabody continually monitor ourmonitors 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.
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Peabody Energy Corporation | 2019 Form 10-K | 52 |
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
OurPeabody’s Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 18, 202017, 2023 there were 137173 holders of ourthe Company’s Common Stock, as determined by counting ourits record holders and the number of participants reflected in a security position listing provided to usthe Company by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of ourPeabody’s Common Stock on behalf of their customers, we dothe Company does not know the actual number of unique shareholders represented by these record holders.
Dividend PolicyDividends
The paymentAs more fully described within “Liquidity and Capital Resources” of dividends is subject to certain limitations, as set forth in our debt agreements. Such limitations on dividends are discussed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.Operations,” We declared and paid quarterly dividends every quarter in 2019, and a supplemental dividend was declared and paid during the firstfourth quarter of 2019. We are suspending dividends in 2020, and our Board of Directors will continue to evaluate the declaration andCompany 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 also limit the future and the amount of those dividends will depend on our results of operations, financial condition,Company's ability to pay cash requirements, future prospects, any limitations imposed by our debt covenants and other factors that our Board of Directors may deem relevant to such evaluations.dividends.
Share Relinquishments
WeThe Company routinely allowallows 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 ourits equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of ourthe Company’s Common Stock on the dates of the respective relinquishments.
Share Repurchase ProgramsProgram
TheOn August 1, 2017, the Company announced that its Board of Directors authorized a share repurchase program as amended, to allow repurchases of up to $1.5 billion$500 million of the then outstanding shares of the Company’sits common stock and/or preferred stock (Repurchase Program). Repurchases may be made from time, which was eventually expanded to time at the Company’s discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time.$1.5 billion during 2018. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2019, we2022, the Company has repurchased 41.5 million shares of ourits 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. Limitations on
Similar to the payment of dividends as described above, the same agreements with the Company’s surety bond providers prohibit share repurchases imposedthrough the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by ourthe parties to the agreements. Additionally, restrictive covenants in its credit facility also limit the Company’s ability to repurchase shares. Future repurchases will be made at the Company’s discretion. The specific timing, price and size of purchases will depend upon the share price, general market and economic conditions and other considerations, including compliance with various debt instrumentsagreements in effect at the time any repurchases are discussedmade.
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Peabody Energy Corporation | 2022 Form 10-K | 58 |
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. No sales were made under this at-the-market equity offering program during the year ended December 31, 2022, leaving approximately 7.7 million shares available for sale.
On March 7, 2022, the Company entered into an at-the-market equity offering program pursuant to which the Company could offer and sell shares of its common stock having an aggregate gross sales price of up of $225 million. 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 a prospectus supplement dated March 7, 2022 relating to the offer and sale of the shares. During the year ended December 31, 2022, the Company sold approximately 10.1 million shares for net proceeds of $222.0 million, thereby concluding this at-the-market equity offering program.
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 Part II, Item 7. “Management’s Discussionwhich 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 Analysis$21.6 million aggregate principal amount of Financial Conditionthe 2024 Peabody Notes. No such bilateral transactions were completed during the year ended December 31, 2022. The issuance of shares of common stock in exchange for the 2022 Notes, the 2025 Notes and Resultsthe 2024 Peabody Notes was made in reliance on the exemption from registration provided in Section 3(a)(9) under the Securities Act of Operations.” We suspended share repurchases1933, based in 2019part 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 additional repurchases are planned.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, 2019:2022:
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| | | | | | | | | | | | | | |
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, 2019 | | 2,024,905 |
| | $ | 14.68 |
| | 2,024,500 |
| | $ | 160.5 |
|
November 1 through November 30, 2019 | | 1,085 |
| | 9.10 |
| | — |
| | 160.5 |
|
December 1 through December 31, 2019 | | 912 |
| | 9.09 |
| | — |
| | 160.5 |
|
Total | | 2,026,902 |
| | 14.67 |
| | 2,024,500 |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
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, 2022 | | — | | | $ | — | | | — | | | $ | 160.5 | |
November 1 through November 30, 2022 | | — | | | — | | | — | | | 160.5 | |
December 1 through December 31, 2022 | | — | | | — | | | — | | | 160.5 | |
Total | | — | | | — | | | — | | | |
(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program Repurchase Program.
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Peabody Energy Corporation | 2019 Form 10-K | 53 |
Mandatory Conversion of Preferred Shares
Each share of our Series A Convertible Preferred Stock (Convertible Preferred Stock) that was previously outstanding was subject to mandatory automatic conversion into a number of shares of Common Stock if the volume weighted average price of the Common Stock exceeded $32.50 for at least 45 trading days in a 60 consecutive trading day period, including each of the last 20 days in such 60 consecutive trading day period. On January 31, 2018, the requirements for such a mandatory conversion were met and the then outstanding 13.2 million shares of Convertible Preferred Stock were automatically converted into 24.8 million shares of Common Stock. As a result of this mandatory conversion, we recorded a non-cash preferred dividend charge of $102.5 million during the year ended December 31, 2018. After the mandatory conversion, no shares of Convertible Preferred Stock are issued or outstanding and all rights of the prior holders of Convertible Preferred Stock have terminated.
Stock Performance Graph
The following performance graph compares the cumulative total return on ourPeabody’s common stock from April 4, 2017, the date our common stock began trading following the effective date of our Plan, through December 31, 2019, with the cumulative total return of the following indices: (i) the S&P MidCap 400 Stock Index and (ii) aCustom Composite Index (a peer group comprised of Arch Coal,Resources, Inc., Hallador Energy Co., and Warrior Met Coal, Inc. (Custom Composite Index)). The Custom Composite Index reflects publicly listed U.S. companies within the coal industry of similar size or product type. Cloud Peak Energy Inc. was removed from our updated Custom Composite Index as it was delisted by the New York Stock Exchange on March 26, 2019. Master Limited Partnerships were excluded.
The graph assumes that the value of the investment in BTU and each index 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 MarchDecember 31, 2017, for the S&P Midcap 400 Index.2017. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2019.
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Peabody Energy Corporation | 2019 Form 10-K | 54 |
2022. 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.
Item 6. Selected Financial Data.
This item presents selected financial and other data about us for the most recent five fiscal years.
The table that follows and the discussion of our results of operations in 2019 and 2018 in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and 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 our segments’ operating performance. We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. Adjusted EBITDA is defined as income (loss) from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segments’ operating performance, as displayed in the reconciliation. A reconciliation of (loss) income from continuing operations, net of income taxes to Adjusted EBITDA is included on page 58 of this report. Adjusted EBITDA is not intended to serve as an alternative to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.
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Peabody Energy Corporation | 20192022 Form 10-K | 5559 |
The selected financial data for all periods presented reflect the classification as discontinued operations of certain operations previously divested (by sale or otherwise).
We have derived the selected historical financial data as of and for the years ended December 31, 2019, 2018, 2017, 2016 and 2015 from our audited financial statements, adjusted retrospectively for items subsequently classified as discontinued operations and the implementation of certain accounting literature. Also, all share and per share data have been retroactively restated to reflect the September 30, 2015 1-for-15 reverse stock split. The following table should be read in conjunction with the accompanying consolidated financial statements, including the related notes to those financial statements, and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”6. Reserved.
References to “Successor” are in reference to reporting dates on or after April 2, 2017; references to “Predecessor” are in reference to reporting dates through April 1, 2017, which include the impact of the Plan provisions and the application of fresh start reporting.Not applicable.
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Peabody Energy Corporation | 2019 Form 10-K | 56 |
The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, Part I, Item 1A. “Risk Factors” of this report includes a discussion of risk factors that could impact our future results of operations.
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| | | | | | | | | | | | | | | | | | | | | | |
| Successor | Predecessor |
| Year Ended December 31, | | April 2 through December 31, 2017 | January 1 through April 1, 2017 | | Year Ended December 31, |
| 2019 | | 2018 | |
| 2016 |
| 2015 |
| (In millions, except per share data) |
Results of Operations Data | | | | | | |
| | |
| | |
|
Total revenues | $ | 4,623.4 |
| | $ | 5,581.8 |
| | $ | 4,252.6 |
| $ | 1,326.2 |
| | $ | 4,715.3 |
| | $ | 5,609.2 |
|
Costs and expenses | 4,561.7 |
| | 4,920.2 |
| | 3,588.8 |
| 1,113.7 |
| | 4,935.1 |
| | 6,995.0 |
|
Operating profit (loss) | 61.7 |
| | 661.6 |
| | 663.8 |
| 212.5 |
| | (219.8 | ) | | (1,385.8 | ) |
Interest expense, net | 117.2 |
| | 117.7 |
| | 135.0 |
| 30.2 |
| | 322.4 |
| | 525.5 |
|
Net periodic benefit costs, excluding service cost | 19.4 |
| | 18.1 |
| | 21.9 |
| 14.4 |
| | 57.1 |
| | 79.0 |
|
Net mark-to-market adjustment on actuarially determined liabilities | 67.4 |
| | (125.5 | ) | | (45.2 | ) | — |
| | — |
| | — |
|
Reorganization items, net | — |
| | (12.8 | ) | | — |
| 627.2 |
| | 159.0 |
| | — |
|
(Loss) income from continuing operations before income taxes | (142.3 | ) | | 664.1 |
| | 552.1 |
| (459.3 | ) | | (758.3 | ) | | (1,990.3 | ) |
Income tax provision (benefit) | 46.0 |
| | 18.4 |
| | (161.0 | ) | (263.8 | ) | | (94.5 | ) | | (207.1 | ) |
(Loss) income from continuing operations, net of income taxes | (188.3 | ) | | 645.7 |
| | 713.1 |
| (195.5 | ) | | (663.8 | ) | | (1,783.2 | ) |
Income (loss) from discontinued operations, net of income taxes | 3.2 |
| | 18.1 |
| | (19.8 | ) | (16.2 | ) | | (57.6 | ) | | (175.0 | ) |
Net (loss) income | (185.1 | ) | | 663.8 |
| | 693.3 |
| (211.7 | ) | | (721.4 | ) | | (1,958.2 | ) |
Less: Series A Convertible Preferred Stock dividends | — |
| | 102.5 |
| | 179.5 |
| — |
| | — |
| | — |
|
Less: Net income attributable to noncontrolling interests | 26.2 |
| | 16.9 |
| | 15.2 |
| 4.8 |
| | 7.9 |
| | 7.1 |
|
Net (loss) income attributable to common stockholders | $ | (211.3 | ) | | $ | 544.4 |
| | $ | 498.6 |
| $ | (216.5 | ) | | $ | (729.3 | ) | | $ | (1,965.3 | ) |
| | | | | | | | | | |
Basic EPS - (Loss) income from continuing operations | $ | (2.07 | ) | | $ | 4.35 |
| | $ | 3.85 |
| $ | (10.93 | ) | | $ | (36.72 | ) | | $ | (98.65 | ) |
Diluted EPS - (Loss) income from continuing operations | $ | (2.07 | ) | | $ | 4.28 |
| | $ | 3.81 |
| $ | (10.93 | ) | | $ | (36.72 | ) | | $ | (98.65 | ) |
Weighted average shares used in calculating basic EPS | 103.7 |
| | 119.3 |
| | 101.1 |
| 18.3 |
| | 18.3 |
| | 18.1 |
|
Weighted average shares used in calculating diluted EPS | 103.7 |
| | 121.0 |
| | 102.5 |
| 18.3 |
| | 18.3 |
| | 18.1 |
|
Dividends declared per share | $ | 2.410 |
| | $ | 0.485 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 0.075 |
|
Other Data | | | | | | |
| | | | |
|
Tons produced | 164.7 |
| | 182.1 |
| | 142.7 |
| 45.6 |
| | 175.6 |
| | 208.7 |
|
Tons sold | 165.5 |
| | 186.7 |
| | 145.4 |
| 46.1 |
| | 186.8 |
| | 228.8 |
|
Net cash provided by (used in) continuing operations: | | | | | | |
| | | | |
|
Operating activities | $ | 705.4 |
| | $ | 1,516.9 |
| | $ | 832.2 |
| $ | (804.8 | ) | | $ | 33.6 |
| | $ | 69.7 |
|
Investing activities | (261.3 | ) | | (517.3 | ) | | (93.4 | ) | 15.1 |
| | (244.1 | ) | | (290.0 | ) |
Financing activities | (701.3 | ) | | (1,025.2 | ) | | (745.4 | ) | 952.3 |
| | 907.9 |
| | 267.7 |
|
Adjusted EBITDA | 837.1 |
| | 1,379.3 |
| | 1,145.3 |
| 341.3 |
| | 532.0 |
|
| 432.4 |
|
Balance Sheet Data (at period end) | | | | | | |
| | | | |
|
Total assets | $ | 6,542.8 |
| | $ | 7,423.7 |
| | $ | 8,181.2 |
| $ | 8,266.9 |
| | $ | 11,777.7 |
| | $ | 10,946.9 |
|
Total long-term debt (including financing leases) | 1,310.8 |
| | 1,367.0 |
| | 1,460.8 |
| 1,881.4 |
| | 7,791.4 |
| | 6,241.2 |
|
Total stockholders’ equity | 2,672.5 |
| | 3,451.6 |
| | 3,655.8 |
| 3,131.9 |
| | 181.5 |
| | 751.7 |
|
|
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Peabody Energy Corporation | 2019 Form 10-K | 57 |
Adjusted EBITDA is calculated as follows:
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| | | | | | | | | | | | | | | | | | | | | | |
| Successor | Predecessor |
| Year Ended December 31, | | April 2 through December 31, 2017 | January 1 through April 1, 2017 | | Year Ended December 31, |
| 2019 | | 2018 | | 2016 | | 2015 |
| (Dollars in millions) |
(Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | | $ | 645.7 |
| | $ | 713.1 |
| $ | (195.5 | ) | | $ | (663.8 | ) | | $ | (1,783.2 | ) |
Depreciation, depletion and amortization | 601.0 |
| | 679.0 |
| | 521.6 |
| 119.9 |
| | 465.4 |
| | 572.2 |
|
Asset retirement obligation expenses | 58.4 |
| | 53.0 |
| | 41.2 |
| 14.6 |
| | 41.8 |
| | 45.5 |
|
Selling and administrative expenses related to debt restructuring | — |
| | — |
| | — |
| — |
| | 21.5 |
| | — |
|
Gain on formation of United Wambo Joint Venture | (48.1 | ) | | — |
| | — |
| — |
| | — |
| | — |
|
Asset impairment | 270.2 |
| | — |
| | — |
| 30.5 |
| | 247.9 |
| | 1,277.8 |
|
Provision for North Goonyella equipment loss | 83.2 |
| | 66.4 |
| | — |
| — |
| | — |
| | — |
|
North Goonyella insurance recovery - equipment | (91.1 | ) | | — |
| | — |
| — |
| | — |
| | — |
|
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (18.8 | ) | | (18.3 | ) | | (17.3 | ) | (5.2 | ) | | (7.5 | ) | | 3.9 |
|
Interest expense | 144.0 |
| | 149.3 |
| | 119.7 |
| 32.9 |
| | 298.6 |
| | 465.4 |
|
Loss on early debt extinguishment | 0.2 |
| | 2.0 |
| | 20.9 |
| — |
| | 29.5 |
| | 67.8 |
|
Interest income | (27.0 | ) | | (33.6 | ) | | (5.6 | ) | (2.7 | ) | | (5.7 | ) | | (7.7 | ) |
Net mark-to-market adjustment on actuarially determined liabilities | 67.4 |
| | (125.5 | ) | | (45.2 | ) | — |
| | — |
| | — |
|
Reorganization items, net | — |
| | (12.8 | ) | | — |
| 627.2 |
| | 159.0 |
| | — |
|
Gain on disposal of reclamation liability | — |
| | — |
| | (31.2 | ) | — |
| | — |
| | — |
|
Gain on disposal of Burton Mine assets | — |
| | — |
| | (52.2 | ) | — |
| | — |
| | — |
|
Break fees related to terminated asset sales | — |
| | — |
| | (28.0 | ) | — |
| | — |
| | — |
|
Unrealized (gains) losses on economic hedges | (42.2 | ) | | (18.3 | ) | | 23.0 |
| (16.6 | ) | | 39.8 |
| | (2.2 | ) |
Unrealized (gains) losses on non-coal trading derivative contracts | (1.2 | ) | | 0.7 |
| | 1.5 |
| — |
| | — |
| | — |
|
Fresh start coal inventory revaluation | — |
| | — |
| | 67.3 |
| — |
| | — |
| | — |
|
Fresh start take-or-pay contract-based intangible recognition | (16.6 | ) | | (26.7 | ) | | (22.5 | ) | — |
| | — |
| | — |
|
Income tax provision (benefit) | 46.0 |
| | 18.4 |
| | (161.0 | ) | (263.8 | ) | | (94.5 | ) | | (207.1 | ) |
Adjusted EBITDA | $ | 837.1 |
| | $ | 1,379.3 |
| | $ | 1,145.3 |
| $ | 341.3 |
| | $ | 532.0 |
| | $ | 432.4 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
OurThe Company’s discussion and analysis of the year ended December 31, 20192022 compared to the year ended December 31, 20182021 is included herein. For discussion and analysis of the year ended December 31, 20182021 compared to the year ended December 31, 2017,2020, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in ourPeabody’s Annual Report on Form 10-K for the year ended December 31, 2018,2021, which was filed with the SEC on February 27, 201918, 2022 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 and Total Reporting Segment Costs, which are financial measures 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 and allocate resources. Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments’ operating performance.
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Peabody Energy Corporation | 2022 Form 10-K | 60 |
Also included in the following discussion of Peabody’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment. These metrics are used by management to measure each of its reporting segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting 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. 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 2019, we2022, Peabody produced and sold 164.7122.9 million and 165.5123.7 million tons of coal, respectively, from continuing operations.
As of December 31, 2019, we report our results of operations primarily through2022, the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, Midwestern U.S. Mining, Western U.S. Mining and Corporate and Other.
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Peabody Energy Corporation | 2019 Form 10-K | 58 |
During the year ended December 31, 2019, the Cottage Grove Mine in the Midwestern U.S. Mining segment and the Kayenta Mine in the Western U.S. Mining segment shipped their final tons. We also announced the closures of the Wildcat HiIls Underground and Somerville Central Mines in the Midwestern U.S. Mining segment, with both of those operations expecting to ship their final tons in 2020. Due to these changes, we will update our reportable segments beginning in the first quarter of 2020 to combine the Midwestern U.S. Mining segment with the Western U.S. Mining segment, which reflects the manner in which our CODM views our businesses going forward for purposes of reviewing performance, allocating resources and assessing future prospects and strategic execution. Beginning the first quarter of 2020, we will report ourCompany 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 ourthe Company’s seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of ourits thermal and metallurgical coal sold within Australia. Generally, revenuesrevenue 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. We classify ourThe 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, wethe Company may market some of ourits metallurgical coal products as a thermal coal product from time to time depending on market conditions.
OurThe 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.
OurThe Company’s Seaborne Metallurgical Mining operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama.Alabama, USA. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal (low-sulfur, high Btu coal).coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and PCIpulverized coal injection coal.
The principal business of ourthe Company’s thermal miningoperating 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. OurThe Company’s Powder River Basin Mining operations consist of ourits 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). Our MidwesternThe Company’s Other U.S. Thermal Mining operations include ourreflect the aggregation of its Illinois, Indiana, New Mexico and IndianaColorado mining operations, whichoperations. 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). Our Western U.S. Mining operations historically reflectGeologically, the aggregation of our New Mexico, Arizona and Colorado mining operations. The mines in that segment are characterized by a mix of surface and underground mining extraction processes and coal with a mid-range sulfur content and Btu. Geologically, ourCompany’s Powder River Basin Mining operations mine sub-bituminous coal deposits our Midwesternand its Other U.S. Mining operations mine bituminous coal deposits and our Western U.S.Thermal Mining operations mine both bituminous and sub-bituminous coal deposits.
OurThe Company’s Corporate and Other segment includes selling and administrative expenses, including our technical and shared services functions, results from equity affiliates, corporate hedging activities, trading and brokerage activities, certain mining and export/transportation joint ventures, restructuring charges and activities associated with the optimization of our coal reserve and real estate holdings, minimum charges on certain transportation-related contracts, the closure of inactive mining sites and certain commercial matters.
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Peabody Energy Corporation | 2022 Form 10-K | 61 |
Resource Management. As of December 31, 2019, we2022, Peabody controlled approximately 4.12.4 billion tons of proven and probable coal reserves, 2.4 billion tons of resources and approximately 500,000360,000 acres of surface property through ownership and lease agreements. We haveThe Company has an ongoing asset optimization program whereby ourits 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 we havePeabody has completed post-mining reclamation. In addition, we generatethe 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.contracts and lease income from surface lands under contracts with renewable energy ventures.
Middlemount Mine. We ownPeabody owns a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and LV PCIlow-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, 2019, 20182022 and 2017,2021, the mine sold 2.9 million, 4.21.6 million and 4.22.0 million tons of coal, respectively (on a 100%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 index 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, 2022 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, 2022 due to quality differentials and a portion 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, with spot, index and quarterly sales arrangements also utilized. The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a 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, 2022 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, 2022 | | February 17, 2023 |
Premium HCC (1) | | $ | 670.50 | | | $ | 188.00 | | | $ | 363.45 | | | $ | 294.50 | | | $ | 390.00 | |
Premium PCI coal (1) | | $ | 655.00 | | | $ | 180.50 | | | $ | 330.81 | | | $ | 284.50 | | | $ | 344.00 | |
Newcastle index thermal coal (1) | | $ | 452.81 | | | $ | 201.54 | | | $ | 362.78 | | | $ | 398.50 | | | $ | 187.27 | |
API 5 index thermal coal (1) | | $ | 284.20 | | | $ | 109.66 | | | $ | 176.44 | | | $ | 133.38 | | | $ | 117.72 | |
PRB 8,800 Btu/Lb coal (2) | | $ | 27.50 | | | $ | 15.50 | | | $ | 18.03 | | | $ | 15.50 | | | $ | 14.80 | |
Illinois Basin 11,500 Btu/Lb coal (2) | | $ | 196.00 | | | $ | 88.00 | | | $ | 149.32 | | | $ | 134.00 | | | $ | 83.00 | |
(1) Prices expressed per metric tonne.
(2) Prices expressed per short ton.
Within the global coal industry, supply and demand for its products and the supplies used for mining have been impacted by the ongoing Russian-Ukrainian conflict and the COVID-19 pandemic. Furthermore, inflationary pressures and supply chain constraints have contributed to rising costs and may continue to impact future periods. As future developments related to the Russian-Ukrainian conflict, the COVID-19 pandemic and rising inflation are unknown, the global coal industry data for the year ended December 31, 2022 presented herein may not be indicative of their ultimate impacts.
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| | | | | | | |
Peabody Energy Corporation | 20192022 Form 10-K | 5962 |
Within the seaborne metallurgical coal market, the year ended December 31, 2022 was characterized by significant volatility as a weakened global macroeconomic environment was counteracted by tight coal supply and continued trade flow disruptions following sanctions imposed on Russian coal imports. Steel prices trended lower during the year ended December 31, 2022, causing some steelmakers to implement small-scale output cuts. The reduction in steel output is partially influencing short-term incremental metallurgical coal demand in some markets; however, it is being more than offset by transitioning demand from many steelmakers removing exposure to Russian coal by seeking additional volumes from other regions such as Australia, the U.S. and Canada. This is particularly so for PCI, where Russia typically accounts for approximately 35% of global traded volumes. In early January 2023, China partially restarted imports of Australian coal for the first time in two years, providing additional market depth and further support for prices. The Company believes energy shortages and the global inflationary environment present a risk to industrial activity in some markets, but the underlying market fundamentals remain constructive with continuing themes of supply tightness, resilient and improving demand in some markets and further economic stimulus in China and elsewhere.
North Goonyella Mine
Our North Goonyella Mine in Queensland, Australia experienced a fire in a portion ofWithin the mine during September 2018 and mining operationsseaborne thermal coal market, global thermal coal prices ended the year at elevated levels, fueled by broader energy supply security concerns. These concerns have been suspended since then. No mine personnel were physically harmeddriven by the September 2018 events. On November 13, 2018,Russian-Ukrainian conflict and the QMI initiated an investigation intosubsequent ban of Russian coal by European countries, as well as limited supply response out of Australia and Columbia due to weather and labor issues. In China, domestic coal production and renewable generation have been strong during the events that occurred atyear ended December 31, 2022, which has lowered import demand. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent as supply remains tight and European coal importers look to replace Russian coal.
In the mineUnited States, overall electricity demand increased more than 3% year-over-year, positively impacted by weather and economic activity. Through the year ended December 31, 2022, electricity generation from thermal coal has declined year-over-year due to determinecoal conservation by utilities, transportation issues impacting coal deliveries and stronger renewable generation. Coal’s share of electricity generation has declined to approximately 19% for the causeyear ended December 31, 2022, while wind and solar’s combined generation share has increased to 15%. Coal inventories have continued to decline since December 2021, with a decline of approximately 6% or 5 million tons. During the event, assessyear ended December 31, 2022, utility consumption of PRB coal declined approximately 5% compared to the response to it and make recommendations to reduce the possibility of future incidents and improve response.prior year period.
Financing Transactions
During the first quarter of 2019, we completed segmenting2022, Peabody issued convertible senior unsecured notes and used the proceeds of the mine into multiple zonesoffering to facilitate a phased reventilationretire nearer term higher cost senior secured debt. This both lowered the Company’s borrowing rates and re-entry of the mine. We commenced reventilation of the first zone of the mine during the second quarter of 2019extended debt maturities to 2028. Throughout 2022, Peabody continued to reduce its outstanding debt, and subsequently re-entered the area in the third quarter. Following these activities and a detailed review and assessment of North Goonyella, we determined that due to the time, cost and required regulatory approach to ventilate and re-enter the rest of the mine, we will not pursue attempts to access certain portions of the mine through existing mine workings, but instead will move to the southern panels. We are currently in discussions with the QMI regarding ventilation and re-entry of the second zone of the current mine configuration. In 2020, we are commencing a commercial process for North Goonyella in conjunction with the existing mine development. The process comes in response to expressions of interest from potential strategic partners and other producers. Commercial outcomes could include a strategic financial partner, a joint venture structure or the complete sale of North Goonyella. Alternatively, the commercial process could be abandoned in the absence of an acceptable outcome. Based on the success of discussions with QMI and/or progression of the commercial process being launched, we will determine the appropriate level, if any, and timing of capital expenditures. We anticipate annual holding costs of approximately $24 million per year in relation to North Goonyella, excluding $16 million in take-or-pay commitments, which we are in discussions to reduce.
During the year endedat December 31, 2018, we recorded $58.02022, all senior secured debt had been retired.
High demand and tight supply for coal globally has resulted in a substantial rise in seaborne thermal coal prices during 2022, which has been amplified by the Russian-Ukrainian conflict, resulting in unprecedented upward volatility in Newcastle coal pricing since late February 2022. As a result, Peabody posted additional cash margin of $125.4 million in containment and idling costs related to the events at North Goonyella and a provision of $66.4 million for expected equipment losses. As work progressed and more information became available, we recorded an additional $111.5 million in containment and idling costs and an additional provision of $83.2 million related to equipment losses during the year ended December 31, 2019.2022 to satisfy the margin requirements for its derivative contracts.
Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of these financing and liquidity transactions.
North Goonyella Redevelopment
During the third quarter of 2022, the Company initiated the redevelopment of its North Goonyella Mine, a premium hard-coking coal longwall operation in Australia with over 70 million tons of coal reserves. The combined provision includes $50.7project will utilize substantial existing infrastructure and equipment at the mine, including a new 300-meter longwall system, a coal handling preparation plant, a dedicated rail loop for transport to the Dalrymple Bay Coal Terminal and an accommodation village with housing and service amenities for more than 400 workers. North Goonyella is anticipated to increase the Company’s production in its Seaborne Metallurgical Mining segment.
The Company’s board of directors has approved redevelopment expenditures of $120 million for 2023, which include ventilation, equipment, conveyance and infrastructure updates in anticipation of reaching development coal, subject to regulatory approvals, in the estimated costfirst quarter of 2024. Cash flow from operations is expected to replace leased equipment, $45.6 million relatedfund all redevelopment costs as the Company continues to strengthen its balance sheet. Future decisions about the redevelopment of North Goonyella may be impacted by Queensland’s increased royalty tiers. Development costs in addition to the costcurrent approved amount are estimated to be $240 million, with longwall operations expected to commence in 2026.
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 63 |
Other
In March 2019, we2022, the Company entered into a joint venture with unrelated partners to form R3 Renewables LLC (R3). R3 was formed with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage. During 2022, R3 has advanced efforts with potential customers, finalized its management team and commenced site evaluations with project developer Treaty Oak Clean Energy, LLC. The Company’s interest in R3 is accounted for as an insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policyequity method investment. The Company contributed $10.9 million to R3 and recorded an equity loss of $3.9 million from its operations during the year ended December 31, 2022.
In March 2022, Peabody Investments Corp., a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amountwholly owned subsidiary of the recovery.
On April 30, 2019, Peabody (Bowen) Pty LtdCompany, entered into a commitment agreement relating to one of its qualified pension plans (the Plan) with an option exerciseinsurer. Under the commitment agreement, the Plan purchased a buy-in group annuity contract for approximately $500 million and release agreement with Yancoal Technology Development Pty Ltd pursuantthe insurer will reimburse the Plan for benefit payments to which Peabody (Bowen) Pty Ltd exercised an optionbe made to acquire from Yancoal Technology Development Pty Ltd the longwall mining equipment used under license atPlan’s participants. Under the North Goonyella Mine for $54.2 million, which was consistent with our provision for equipment lossesterms of this transaction, the Plan continues to administer and pay the retirement benefits of Plan participants and is reimbursed by the insurer for the related impaired assets.payment of all benefits covered by the group annuity contract. In May 2022, the board of directors of Peabody Investments Corp. approved the termination of the Plan effective July 31, 2022. Refer to Note 14. “Pension and Savings Plans” to the accompanying consolidated financial statements for a further discussion of this transaction.
Results of Operations
Non-GAAP Financial Measures
The following discussion of our results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. GAAP. Adjusted EBITDA is used by management as the primary metric to measure each of our segments’ operating performance.
Also included in the following discussion of our 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 our 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. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include 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 our discussion of liquidity and capital resources, we include references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations.
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| | |
Peabody Energy Corporation | 2019 Form 10-K | 60 |
We believe non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our 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.
Year Ended December 31, 20192022 Compared to Year Ended December 31, 2018
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, 2019 is set forth in the table below. Pricing for our Western U.S. Mining segment is not included as there is no similar spot or prompt pricing data available.2021
The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2019 due to quality differentials and the majority of our seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. Our typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a 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 we realized during the year ended December 31, 2019 since we generally sell 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 coal producers may also impact our realized pricing.
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| | | | | | | | | | | | | | | | |
| | High | | Low | | Average | | December 31, 2019 |
Premium HCC (1) | | $ | 215.80 |
| | $ | 127.30 |
| | $ | 176.66 |
| | $ | 136.10 |
|
Premium PCI coal (1) | | $ | 129.85 |
| | $ | 85.50 |
| | $ | 110.50 |
| | $ | 86.65 |
|
Newcastle index thermal coal (1) | | $ | 99.78 |
| | $ | 62.32 |
| | $ | 77.74 |
| | $ | 66.55 |
|
API 5 thermal coal (1) | | $ | 62.87 |
| | $ | 48.00 |
| | $ | 54.41 |
| | $ | 51.30 |
|
PRB 8,800 Btu/Lb coal (2) | | $ | 12.60 |
| | $ | 12.05 |
| | $ | 12.22 |
| | $ | 12.10 |
|
Illinois Basin 11,500 Btu/Lb coal (2) | | $ | 47.50 |
| | $ | 33.50 |
| | $ | 38.83 |
| | $ | 33.65 |
|
| |
(1)
| Prices expressed per tonne. |
| |
(2)
| Prices expressed per ton. |
With respect to seaborne metallurgical coal, global steel production increased approximately 3% through the year ended December 31, 2019 as compared to the prior year period. India imports increased approximately 5% through the year ended December 31, 2019, as compared to the prior year, amid domestic steel production growth of approximately 3% year-over-year. Steel production in China increased approximately 7% through the year ended December 31, 2019 as compared to the prior year, resulting in an approximate 15% increase in coking coal imports during the same period. China’s steel production continues to be fueled by infrastructure spending. China’s seaborne demand will remain dependent upon the country’s import policies.
Seaborne thermal coal demand and pricing was subdued due to restrictions in China and low gas prices coupled with elevated stockpiles in Europe, despite robust demand from India and other Asian regions. Chinese thermal coal imports increased by approximately 8 million tonnes through the year ended December 31, 2019 as compared to the prior year. Despite constraints by heightened mine safety inspections, China’s domestic production registered a 4.2% increase through the year ended December 31, 2019, as compared to the prior year period, supported by new mine approvals. India’s domestic production declined approximately 1% through the year ended December 31, 2019, which was not sufficient to meet growing demand from its industrial and power sectors. As a result, India’s thermal coal imports have increased by approximately 6% or 10 million tonnes year-over-year through December 31, 2019. Demand from countries comprising the Association of Southeast Asian Nations (ASEAN) increased 23 million tonnes through the year ended December 31, 2019 as compared to the prior year, primarily led by Vietnam.
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Peabody Energy Corporation | 2019 Form 10-K | 61 |
In the United States, overall electricity demand was down year-over-year through the year ended December 31, 2019. Continued coal plant retirements, growth in natural gas and renewable generation and weak natural gas prices have negatively impacted coal demand. For the year ended December 31, 2019, utility consumption of PRB coal fell approximately 16% as compared to the prior year due to ongoing pressure from retirements, wind generation and regional natural gas prices that continue to trade at a discount to quoted Henry Hub natural gas spot prices.
Our revenues for the year ended December 31, 2019 decreased as compared to the same period in 2018 ($958.4 million) primarily due to lower sales volumes and realized prices. Our Seaborne Metallurgical Mining segment was adversely impacted by the events at our North Goonyella Mine described above, as well as other production factors, partially offset by the incremental volume provided by our Shoal Creek Mine. Our Powder River Basin Mining segment was adversely impacted by lower demand and delays in rail shipments caused by severe flooding during the first half of 2019.
Resultsincome from continuing operations, net of income taxes for the year ended December 31, 2019 decreased as2022 compared to the same period in the prior year2021 ($834.0970.0 million) was primarily driven by higher revenue ($1,663.6 million) due to higher realized prices and a 20% increase in metallurgical sales volumes; improved results from equity affiliates ($49.1 million); and lower interest expense ($43.1 million). The decrease was driven by the unfavorable revenue variances described above, as well as asset impairment charges recorded in the current period ($270.2 million), the impact of a net mark-to-market loss on actuarially determined liabilities as compared to a gain in the prior year ($192.9 million) and approximately $20 million of expense in the current year related to the Monto litigation. These unfavorablefavorable variances were partially offset by reducedhigher operating costs and expenses owing largely to($737.7 million), which reflect increased sales price sensitive costs, the sales volume decline as well as production efficienciesimpacts of challenging weather conditions and other cost improvementsinflationary pressures for commodities, materials, services, repairs and labor; and net losses on early debt extinguishments in the current year ($534.8 million) and an insurance recovery related to the events at our North Goonyella Mine ($125.091.1 million).
The decrease in net results attributable to common stockholders during the year ended December 31, 2019 as compared to the same period in 2018 was partially offset by dividends ($102.5 million) recorded in the prior year period related to the convertible preferred stock issued in connection with our reorganization. Adjusted EBITDA for the year ended December 31, 20192022 reflected a 101% year-over-year decreaseincrease of $542.2$928.0 million.
As of December 31, 2019, our available liquidity was approximately $1.3 billion. Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of factors affecting our available liquidity.
Tons Sold
The following table presents tons sold by operating segment:
|
| | | | | | | | | | | |
| Successor | | Increase (Decrease) |
| Year Ended December 31, | | to Volumes |
| 2019 | | 2018 | | Tons | | % |
| (Tons in millions) | | |
Seaborne Thermal Mining | 19.5 |
| | 19.1 |
| | 0.4 |
| | 2.1 | % |
Seaborne Metallurgical Mining | 8.1 |
| | 11.0 |
| | (2.9 | ) | | (26.4 | )% |
Powder River Basin Mining | 108.1 |
| | 120.3 |
| | (12.2 | ) | | (10.1 | )% |
Midwestern U.S. Mining | 16.0 |
| | 18.9 |
| | (2.9 | ) | | (15.3 | )% |
Western U.S. Mining | 11.9 |
| | 14.7 |
| | (2.8 | ) | | (19.0 | )% |
Total tons sold from mining segments | 163.6 |
| | 184.0 |
| | (20.4 | ) | | (11.1 | )% |
Corporate and Other | 1.9 |
| | 2.7 |
| | (0.8 | ) | | (29.6 | )% |
Total tons sold | 165.5 |
| | 186.7 |
| | (21.2 | ) | | (11.4 | )% |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | (Decrease) Increase |
| Year Ended December 31, | | to Volumes |
| 2022 | | 2021 | | Tons | | % |
| (Tons in millions) | | |
Seaborne Thermal Mining | 15.6 | | | 17.3 | | | (1.7) | | | (9.8) | % |
Seaborne Metallurgical Mining | 6.6 | | | 5.5 | | | 1.1 | | | 20.0 | % |
Powder River Basin Mining | 82.6 | | | 88.4 | | | (5.8) | | | (6.6) | % |
Other U.S. Thermal Mining | 18.4 | | | 16.9 | | | 1.5 | | | 8.9 | % |
Total tons sold from operating segments | 123.2 | | | 128.1 | | | (4.9) | | | (3.8) | % |
Corporate and Other | 0.5 | | | 2.0 | | | (1.5) | | | (75.0) | % |
Total tons sold | 123.7 | | | 130.1 | | | (6.4) | | | (4.9) | % |
|
| | | | | | | |
Peabody Energy Corporation | 20192022 Form 10-K | 6264 |
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) |
| 2022 | | 2021 | | $ | | % |
| | | | | | | |
Revenue per Ton - Mining Operations (1) | | | | | | | |
Seaborne Thermal | $ | 86.07 | | | $ | 54.09 | | | $ | 31.98 | | | 59.1 | % |
Seaborne Metallurgical | 243.78 | | | 131.83 | | | 111.95 | | | 84.9 | % |
Powder River Basin | 12.89 | | | 10.99 | | | 1.90 | | | 17.3 | % |
Other U.S. Thermal | 51.82 | | | 40.75 | | | 11.07 | | | 27.2 | % |
Costs per Ton - Mining Operations (1) (2) | | | | | | | |
Seaborne Thermal | $ | 44.65 | | | $ | 33.64 | | | $ | 11.01 | | | 32.7 | % |
Seaborne Metallurgical | 125.92 | | | 99.55 | | | 26.37 | | | 26.5 | % |
Powder River Basin | 12.06 | | | 9.46 | | | 2.60 | | | 27.5 | % |
Other U.S. Thermal | 38.63 | | | 31.04 | | | 7.59 | | | 24.5 | % |
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) | | | | | | | |
Seaborne Thermal | $ | 41.42 | | | $ | 20.45 | | | $ | 20.97 | | | 102.5 | % |
Seaborne Metallurgical | 117.86 | | | 32.28 | | | 85.58 | | | 265.1 | % |
Powder River Basin | 0.83 | | | 1.53 | | | (0.70) | | | (45.8) | % |
Other U.S. Thermal | 13.19 | | | 9.71 | | | 3.48 | | | 35.8 | % |
|
| | | | | | | | | | | | | | |
| Successor | | | | |
| Year Ended December 31, | | (Decrease) Increase |
| 2019 | | 2018 | | $ | | % |
| | | | | | | |
Revenues per Ton - Mining Operations (1) | | | | | | | |
Seaborne Thermal | $ | 49.69 |
| | $ | 57.58 |
| | $ | (7.89 | ) | | (13.7 | )% |
Seaborne Metallurgical | 127.62 |
| | 141.06 |
| | (13.44 | ) | | (9.5 | )% |
Powder River Basin | 11.37 |
| | 11.84 |
| | (0.47 | ) | | (4.0 | )% |
Midwestern U.S. | 41.90 |
| | 42.44 |
| | (0.54 | ) | | (1.3 | )% |
Western U.S. | 53.48 |
| | 40.20 |
| | 13.28 |
| | 33.0 | % |
Costs per Ton - Mining Operations (1) (2) | | | | | | | |
Seaborne Thermal | $ | 32.84 |
| | $ | 33.90 |
| | $ | (1.06 | ) | | (3.1 | )% |
Seaborne Metallurgical (3) | 110.30 |
| | 100.97 |
| | 9.33 |
| | 9.2 | % |
Powder River Basin | 9.32 |
| | 9.47 |
| | (0.15 | ) | | (1.6 | )% |
Midwestern U.S. | 33.72 |
| | 34.75 |
| | (1.03 | ) | | (3.0 | )% |
Western U.S. | 34.19 |
| | 30.33 |
| | 3.86 |
| | 12.7 | % |
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) | | | | | | | |
Seaborne Thermal | $ | 16.85 |
| | $ | 23.68 |
| | $ | (6.83 | ) | | (28.8 | )% |
Seaborne Metallurgical (3) | 17.32 |
| | 40.09 |
| | (22.77 | ) | | (56.8 | )% |
Powder River Basin | 2.05 |
| | 2.37 |
| | (0.32 | ) | | (13.5 | )% |
Midwestern U.S. | 8.18 |
| | 7.69 |
| | 0.49 |
| | 6.4 | % |
Western U.S. | 19.29 |
| | 9.87 |
| | 9.42 |
| | 95.4 | % |
(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. | |
(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; provision for North Goonyella equipment loss and related insurance recovery; amortization of fresh start reporting adjustments related to take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. |
| |
(3)
| Includes the events at the North Goonyella Mine resulting in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton for Seaborne Metallurgical of $9.59 and $5.27 for the years ended December 31, 2019 and 2018, respectively. |
Revenues(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.
Revenue
The following table presents revenuesrevenue by reporting segment:
| | | Successor | | (Decrease) Increase | | | | Increase |
| Year Ended December 31, | | to Revenues | | Year Ended December 31, | | to Revenue |
| 2019 | | 2018 | | $ | | % | | 2022 | | 2021 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 971.7 |
| | $ | 1,099.2 |
| | $ | (127.5 | ) | | (11.6 | )% | Seaborne Thermal Mining | $ | 1,345.6 | | | $ | 934.0 | | | $ | 411.6 | | | 44.1 | % |
Seaborne Metallurgical Mining | 1,033.1 |
| | 1,553.0 |
| | (519.9 | ) | | (33.5 | )% | Seaborne Metallurgical Mining | 1,616.9 | | | 727.7 | | | 889.2 | | | 122.2 | % |
Powder River Basin Mining | 1,228.7 |
| | 1,424.8 |
| | (196.1 | ) | | (13.8 | )% | Powder River Basin Mining | 1,065.5 | | | 971.2 | | | 94.3 | | | 9.7 | % |
Midwestern U.S. Mining | 669.7 |
| | 801.0 |
| | (131.3 | ) | | (16.4 | )% | |
Western U.S. Mining | 639.7 |
| | 592.0 |
| | 47.7 |
| | 8.1 | % | |
Other U.S. Thermal Mining | | Other U.S. Thermal Mining | 952.2 | | | 689.1 | | | 263.1 | | | 38.2 | % |
Corporate and Other | 80.5 |
| | 111.8 |
| | (31.3 | ) | | (28.0 | )% | Corporate and Other | 1.7 | | | (3.7) | | | 5.4 | | | 145.9 | % |
Revenues | $ | 4,623.4 |
| | $ | 5,581.8 |
| | $ | (958.4 | ) | | (17.2 | )% | |
Revenue | | Revenue | $ | 4,981.9 | | | $ | 3,318.3 | | | $ | 1,663.6 | | | 50.1 | % |
Seaborne Thermal Mining. The decreaseincrease in our Seaborne Thermal Mining segment revenues forrevenue during the year ended December 31, 20192022 compared to the prior year was primarily driven by unfavorabledue to favorable realized coal pricingprices ($131.9540.4 million), partially offset by favorable volumeunfavorable volumes ($128.8 million) which were impacted by wet weather in the current year and mix variances ($4.4 million).
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Peabody Energy Corporation | 2019 Form 10-K | 63 |
Seaborne Metallurgical Mining. Segment revenues decreasedrevenue increased during the year ended December 31, 20192022 compared to the same period in the prior year primarily due to unfavorable volumes (2.9 million tons, $441.1favorable realized prices at the Australian operations ($583.1 million). The unfavorable volume variance resulting from, the transition to highwall miningresumption of sales at our Millennium Mine in September 2018, an extended longwall move at our Metropolitan Mine and various mine sequencing impacts (3.2 million tons, $424.4 million) and no current year volume from our North Goonyella Mine (1.7 million tons, $337.6 million) was partially offset by incremental volume provided by ourthe Shoal Creek Mine acquired in December 2018 (2.0 million tons, $320.9($236.6 million) and favorable volume and mix variances at the Australian operations ($69.5 million). Segment revenues were further impactedSales volumes increased by lower realized pricing ($78.8 million).20% from the prior year.
Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year due to lower volume primarily attributable to lower demand and railroad closures and delays that resulted from severe flooding across the upper Great Plains during the first half of 2019 ($157.9 million) and unfavorable realized pricing ($57.9 million). These unfavorable variances were partially offset by a favorable contract settlement with a PRB customer ($19.7 million).
Midwestern U.S. Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to lower demand-based volume ($124.0 million) and unfavorable realized pricing ($7.3 million).
Western U.S. Mining. Segment revenuesrevenue increased during the year ended December 31, 20192022 compared to the same period in the prior year due to revenues associated with the final commercial negotiations for the Kayenta Minefavorable realized prices ($127.8168.5 million), offset by an unfavorable volume and mix variancevolumes ($75.774.2 million) resulting from rail performance issues.
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Peabody Energy Corporation | 2022 Form 10-K | 65 |
Other U.S. Thermal Mining. The increase in segment revenue during the year ended December 31, 2022 compared to the prior year was due to favorable realized prices ($209.2 million) and unfavorable realized pricingfavorable volumes ($4.453.9 million).
Corporate and Other. Segment revenues decreasedrevenue increased during the year ended December 31, 20192022 compared to the same period in the prior year primarily due to lower net unrealized mark-to-market losses on derivative contracts related to forecasted coal sales ($79.3 million), offset by lower results from trading activities ($74.5 million) due to net realized losses on economic hedges.derivative contracts related to forecasted coal sales exceeding the higher margins recognized on the physical sale of coal.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of ourthe Company’s reporting segments:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) to |
| Year Ended December 31, | | Adjusted EBITDA |
| 2022 | | 2021 | | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 647.6 | | | $ | 353.1 | | | $ | 294.5 | | | 83.4 | % |
Seaborne Metallurgical Mining | 781.7 | | | 178.2 | | | 603.5 | | | 338.7 | % |
Powder River Basin Mining | 68.2 | | | 134.9 | | | (66.7) | | | (49.4) | % |
Other U.S. Thermal Mining | 242.4 | | | 164.2 | | | 78.2 | | | 47.6 | % |
Corporate and Other | 104.8 | | | 86.3 | | | 18.5 | | | 21.4 | % |
Adjusted EBITDA (1) | $ | 1,844.7 | | | $ | 916.7 | | | $ | 928.0 | | | 101.2 | % |
|
| | | | | | | | | | | | | | |
| Successor | | (Decrease) Increase to |
| Year Ended December 31, | | Adjusted EBITDA |
| 2019 | | 2018 | | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 329.4 |
| | $ | 452.0 |
| | $ | (122.6 | ) | | (27.1 | )% |
Seaborne Metallurgical Mining | 140.2 |
| | 441.4 |
| | (301.2 | ) | | (68.2 | )% |
Powder River Basin Mining | 221.2 |
| | 284.5 |
| | (63.3 | ) | | (22.2 | )% |
Midwestern U.S. Mining | 130.7 |
| | 145.2 |
| | (14.5 | ) | | (10.0 | )% |
Western U.S. Mining | 230.7 |
| | 145.4 |
| | 85.3 |
| | 58.7 | % |
Corporate and Other | (215.1 | ) | | (89.2 | ) | | (125.9 | ) | | (141.1 | )% |
Adjusted EBITDA (1) | $ | 837.1 |
| | $ | 1,379.3 |
| | $ | (542.2 | ) | | (39.3 | )% |
| |
(1)(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.
| 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 decreasedincreased during the year ended December 31, 20192022 compared to the same period in the prior year as a result of lowerhigher realized prices net coal pricingof sales sensitive costs ($121.7 million) and unfavorable mine sequencing impacts and higher equipment maintenance costs among our thermal surface mines ($48.1 million), offset by improved longwall performance at our Wambo Underground Mine ($30.2495.5 million) and favorable foreign currency impacts ($24.125.2 million). The increases were offset by unfavorable operational costs ($119.8 million) resulting from the impacts of wet weather, COVID-19-related staffing shortages, the longwall move at the Wambo Underground Mine in the first half of 2022 and inflationary pressures on supplies and outside services; lower volumes ($64.7 million); higher port and demurrage costs ($21.7 million) and higher commodity pricing ($18.6 million).
Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreasedincreased during the year ended December 31, 20192022 compared to the same period in the prior year due to unfavorable volume variances described abovehigher realized prices net of sales sensitive costs at the Australian operations ($231.9466.9 million). The impact, favorable volumes from the resumption of the negative volumessales at our Australian mines ($356.8 million) was partially offset by the incremental volume provided by our Shoal Creek Mine ($124.9 million). The decrease in Segment Adjusted EBITDA was further impacted by lower realized net coal pricing ($71.6 million), mine sequencing impacts among our metallurgical surface operations ($62.6111.6 million) and the net containment and holding costs at our North Goonyella Mine ($19.6 million). These negative variances were partially offset by favorable foreign currency impacts ($50.536.3 million).
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Peabody Energy Corporation | 2019 Form 10-K | 64 |
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 20192022 compared to the same period in the prior year as a result of increased overburden removal costs as the workforce focused on preparatory efforts in light of rail performance issues ($63.3 million); higher costs for materials, services, repairs and labor ($55.3 million) due in part to increased repairs for an aging equipment fleet and inflationary pressures on materials and services; the unfavorable impacts of higher commodity pricing ($53.9 million); and lower volumes ($19.9 million) resulting from rail performance issues. These decreases were offset by higher realized prices net of sales sensitive costs ($146.7 million).
Other U.S. Thermal Mining. Segment Adjusted EBITDA increased during the year ended December 31, 2022 compared to the same period in the prior year due to the impacthigher realized prices net of lower volumesales sensitive costs ($78.7 million) described above, lower realized net coal pricing ($10.7210.4 million) and unfavorable mine sequencing impactsfavorable volumes ($10.019.2 million), partially. These increases were offset by the net impact of the favorable contract settlement with a PRB customer ($24.0 million) and lower lease expenses due to early lease buyouts ($8.6 million).
Midwestern U.S. Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to the impact of lower volume ($18.7 million) and lower realized net coal pricing ($2.0 million), partially offset by lowerhigher costs for materials, services, repairs and labor ($104.8 million) due in part to increased equipment repairs ($4.2 million) and lowerheadcount resulting from increasing volume demands and inflationary pressures on materials and services; and the unfavorable impacts of higher commodity pricing for fuel and explosives ($3.244.2 million).
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Peabody Energy Corporation | 2022 Form 10-K | 66 |
Western U.S. Mining. Table of ContentsSegment Adjusted EBITDA increased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to the net impact associated with the final commercial negotiations for the Kayenta Mine ($83.3 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 |
| 2022 | | 2021 | | $ | | % |
| (Dollars in millions) | | |
Middlemount (1) | $ | 132.8 | | | $ | 48.2 | | | $ | 84.6 | | | 175.5 | % |
Resource management activities (2) | 29.3 | | | 6.9 | | | 22.4 | | | 324.6 | % |
Selling and administrative expenses | (88.8) | | | (84.9) | | | (3.9) | | | (4.6) | % |
Other items, net (3) | 31.5 | | | 116.1 | | | (84.6) | | | (72.9) | % |
Corporate and Other Adjusted EBITDA | $ | 104.8 | | | $ | 86.3 | | | $ | 18.5 | | | 21.4 | % |
|
| | | | | | | | | | | | | | |
| Successor | | (Decrease) Increase |
| Year Ended December 31, | | to Income |
| 2019 | | 2018 | | $ | | % |
| (Dollars in millions) | | |
Middlemount (1) | $ | (9.8 | ) | | $ | 51.1 |
| | $ | (60.9 | ) | | (119.2 | )% |
Resource management activities (2) | 8.2 |
| | 44.7 |
| | (36.5 | ) | | (81.7 | )% |
Selling and administrative expenses | (145.0 | ) | | (158.1 | ) | | 13.1 |
| | 8.3 | % |
Restructuring charges | (24.3 | ) | | (1.2 | ) | | (23.1 | ) | | (1,925.0 | )% |
Transaction costs related to business combinations and joint ventures | (21.6 | ) | | (7.4 | ) | | (14.2 | ) | | (191.9 | )% |
Other items, net (3) | (22.6 | ) | | (18.3 | ) | | (4.3 | ) | | (23.5 | )% |
Corporate and Other Adjusted EBITDA | $ | (215.1 | ) | | $ | (89.2 | ) | | $ | (125.9 | ) | | (141.1 | )% |
| |
(1)(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 $25.1 million and $46.8 million during the years ended December 31, 2019 and 2018, respectively. |
| |
(2)
| Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. |
| |
(3)
| Includes trading and brokerage activities, costs associated with post mining activities, certain coal royalty expenses, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts and expenses related to our other commercial activities. |
The decrease 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 $62.7 million and $42.0 million during the years ended December 31, 2022 and 2021, respectively.
(2)Includes gains (losses) on certain surplus coal reserve, resource and surface land sales and property management costs and revenue.
(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.
Corporate and Other Adjusted EBITDA benefited during the year ended December 31, 20192022 compared to the same period in the prior year was primarily driven by an unfavorable variancefrom favorable variances in Middlemount’s results due to the temporary suspensionimpact of operationshigher sales pricing ($84.6 million) and gains on various land sales in both the U.S. and Australia ($20.0 million). This benefit was offset by unfavorable trading results ($61.6 million) and a significant change to the mine plan following a highwall failure mid-2019; resource management gains recordedgain recognized in the prior year period related toon the sale of surplus land assets in Queensland’s Bowen Basin ($20.6 million) and the sale of surplus coal resources associated with theCompany’s Millennium Mine ($20.526.1 million); restructuring charges recorded as discussed in the current year for workforce reductions resulting from actions taken at the the North Goonyella Mine, U.S. mine closures and reductions in overhead and support functions; and increased transaction costs in the current year period related to the PRB Colorado joint venture with Arch. These unfavorable results were partially offset by lower selling and administrative expenses primarily related to outside services and incentive compensation.Note 17. “Other Events.”
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Peabody Energy Corporation | 2019 Form 10-K | 65 |
(Loss) Income From Continuing Operations, Net of Income Taxes
The following table presents (loss) income from continuing operations, net of income taxes:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) to Income |
| Year Ended December 31, | |
| 2022 | | 2021 | | $ | | % |
| (Dollars in millions) | | |
Adjusted EBITDA (1) | $ | 1,844.7 | | | $ | 916.7 | | | $ | 928.0 | | | 101.2 | % |
Depreciation, depletion and amortization | (317.6) | | | (308.7) | | | (8.9) | | | (2.9) | % |
Asset retirement obligation expenses | (49.4) | | | (44.7) | | | (4.7) | | | (10.5) | % |
Restructuring charges | (2.9) | | | (8.3) | | | 5.4 | | | 65.1 | % |
| | | | | | | |
| | | | | | | |
Asset impairment | (11.2) | | | — | | | (11.2) | | | n.m. |
| | | | | | | |
| | | | | | | |
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | 2.3 | | | 33.8 | | | (31.5) | | | (93.2) | % |
Interest expense | (140.3) | | | (183.4) | | | 43.1 | | | 23.5 | % |
Net (loss) gain on early debt extinguishment | (57.9) | | | 33.2 | | | (91.1) | | | (274.4) | % |
Interest income | 18.4 | | | 6.5 | | | 11.9 | | | 183.1 | % |
Net mark-to-market adjustment on actuarially determined liabilities | 27.8 | | | 43.4 | | | (15.6) | | | (35.9) | % |
| | | | | | | |
Unrealized losses on derivative contracts related to forecasted sales | (35.8) | | | (115.1) | | | 79.3 | | | 68.9 | % |
Unrealized losses on foreign currency option contracts | (2.3) | | | (7.5) | | | 5.2 | | | 69.3 | % |
Take-or-pay contract-based intangible recognition | 2.8 | | | 4.3 | | | (1.5) | | | (34.9) | % |
Income tax benefit (provision) | 38.8 | | | (22.8) | | | 61.6 | | | 270.2 | % |
Income from continuing operations, net of income taxes | $ | 1,317.4 | | | $ | 347.4 | | | $ | 970.0 | | | 279.2 | % |
(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.
|
| | | | | | | | | | | | | | |
| Successor | | (Decrease) Increase to Income |
| Year Ended December 31, | |
| 2019 | | 2018 | | $ | | % |
| (Dollars in millions) | | |
Adjusted EBITDA (1) | $ | 837.1 |
| | $ | 1,379.3 |
| | $ | (542.2 | ) | | (39.3 | )% |
Depreciation, depletion and amortization | (601.0 | ) | | (679.0 | ) | | 78.0 |
| | 11.5 | % |
Asset retirement obligation expenses | (58.4 | ) | | (53.0 | ) | | (5.4 | ) | | (10.2 | )% |
Gain on formation of United Wambo Joint Venture | 48.1 |
| | — |
| | 48.1 |
| | n.m. |
|
Asset impairment | (270.2 | ) | | — |
| | (270.2 | ) | | n.m. |
|
Provision for North Goonyella equipment loss | (83.2 | ) | | (66.4 | ) | | (16.8 | ) | | (25.3 | )% |
North Goonyella insurance recovery - equipment | 91.1 |
| | — |
| | 91.1 |
| | n.m. |
|
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | 18.8 |
| | 18.3 |
| | 0.5 |
| | 2.7 | % |
Interest expense | (144.0 | ) | | (149.3 | ) | | 5.3 |
| | 3.5 | % |
Loss on early debt extinguishment | (0.2 | ) | | (2.0 | ) | | 1.8 |
| | 90.0 | % |
Interest income | 27.0 |
| | 33.6 |
| | (6.6 | ) | | (19.6 | )% |
Net mark-to-market adjustment on actuarially determined liabilities | (67.4 | ) | | 125.5 |
| | (192.9 | ) | | (153.7 | )% |
Reorganization items, net | — |
| | 12.8 |
| | (12.8 | ) | | (100.0 | )% |
Unrealized gains on economic hedges | 42.2 |
| | 18.3 |
| | 23.9 |
| | 130.6 | % |
Unrealized gains (losses) on non-coal trading derivative contracts | 1.2 |
| | (0.7 | ) | | 1.9 |
| | 271.4 | % |
Fresh start take-or-pay contract-based intangible recognition | 16.6 |
| | 26.7 |
| | (10.1 | ) | | (37.8 | )% |
Income tax provision | (46.0 | ) | | (18.4 | ) | | (27.6 | ) | | (150.0 | )% |
(Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | | $ | 645.7 |
| | $ | (834.0 | ) | | (129.2 | )% |
| | | | | | | | |
(1)Peabody Energy Corporation
| 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.2022 Form 10-K | 67 |
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment:
|
| | | | | | | | | | | | | | |
| Successor | | (Decrease) Increase |
| Year Ended December 31, | | to Income |
| 2019 | | 2018 | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | (90.7 | ) | | $ | (88.4 | ) | | $ | (2.3 | ) | | (2.6 | )% |
Seaborne Metallurgical Mining | (125.3 | ) | | (129.8 | ) | | 4.5 |
| | 3.5 | % |
Powder River Basin Mining | (148.5 | ) | | (183.4 | ) | | 34.9 |
| | 19.0 | % |
Midwestern U.S. Mining | (94.1 | ) | | (121.5 | ) | | 27.4 |
| | 22.6 | % |
Western U.S. Mining | (134.1 | ) | | (147.3 | ) | | 13.2 |
| | 9.0 | % |
Corporate and Other | (8.3 | ) | | (8.6 | ) | | 0.3 |
| | 3.5 | % |
Total | $ | (601.0 | ) | | $ | (679.0 | ) | | $ | 78.0 |
| | 11.5 | % |
|
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Peabody Energy Corporation | 2019 Form 10-K | 66 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | (Decrease) Increase |
| Year Ended December 31, | | to Income |
| 2022 | | 2021 | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | (114.4) | | | $ | (107.7) | | | $ | (6.7) | | | (6.2) | % |
Seaborne Metallurgical Mining | (88.8) | | | (73.3) | | | (15.5) | | | (21.1) | % |
Powder River Basin Mining | (42.5) | | | (41.5) | | | (1.0) | | | (2.4) | % |
Other U.S. Thermal Mining | (62.2) | | | (67.4) | | | 5.2 | | | 7.7 | % |
Corporate and Other | (9.7) | | | (18.8) | | | 9.1 | | | 48.4 | % |
Total | $ | (317.6) | | | $ | (308.7) | | | $ | (8.9) | | | (2.9) | % |
Additionally, the following table presents a summary of ourthe Company’s weighted-average depletion rate per ton for active mines in each of our miningits operating segments:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 |
Seaborne Thermal Mining | $ | 2.61 | | | $ | 2.19 | |
Seaborne Metallurgical Mining | 2.55 | | | 1.18 | |
Powder River Basin Mining | 0.32 | | | 0.25 | |
Other U.S. Thermal Mining | 1.23 | | | 1.15 | |
|
| | | | | | | |
| Successor |
| Year Ended December 31, |
| 2019 | | 2018 |
Seaborne Thermal Mining | $ | 1.84 |
| | $ | 1.79 |
|
Seaborne Metallurgical Mining | 3.09 |
| | 0.94 |
|
Powder River Basin Mining | 0.80 |
| | 0.81 |
|
Midwestern U.S. Mining | 1.05 |
| | 0.89 |
|
Western U.S. Mining | 1.72 |
| | 2.29 |
|
Depreciation, depletion and amortization expense decreased during the year ended December 31, 2019 as compared to the same period in the prior year primarily due to lower amortization of the fair value of certain U.S. coal supply agreements ($65.9 million), decreased expense at our North Goonyella Mine after the fire due to lower sales volumes and asset impairments ($19.2 million) and decreased expense related to the closures of the Kayenta and Cottage Grove Mines during the third quarter of 2019 ($23.7 million). The acquisition of the Shoal Creek Mine in the fourth quarter of 2018 partly offset the decrease in depreciation, depletion and amortization ($41.0 million) and was the driver of the year-over-year increase in the weighted-average depletion rate per ton for the Seaborne MetallurgicalThermal Mining segment.
Gain on Formation of United Wambo Joint Venture. Duringsegment during the year ended December 31, 2019, we recognized a $48.1 million gain upon the formation of the United Wambo Joint Venture. Refer to Note 22. “Other Events”2022 compared to the accompanying consolidated financial statements for further information regardingsame period in the calculationprior year reflects the impact of volume and mix variances across the gain, which information is incorporated herein by reference.segment. The increase in the Seaborne Metallurgical Mining segment during the year ended December 31, 2022 compared to the same period in the prior year reflects the resumption of sales at the Shoal Creek Mine.
Asset Impairment. WeThe Company recognized $270.2$11.2 million in aggregate asset impairment charges during the year ended December 31, 2019.2022 related to the sale of certain land interests and an investment in equity securities. Refer to Note 5.3. “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.
Provision for North Goonyella Equipment Loss. Provisions for equipment losses relatedChanges in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to the events at our North Goonyella Mine were recorded during the years ended December 31, 2019 and 2018 as discussed in Note 22. “Other Events” to the accompanying consolidated financial statements. The current year provision is incremental to the provisions recorded during 2018 and represents the best estimate of potential loss associated with these events based on assessments made to date.
North Goonyella Insurance Recovery - Equipment.Equity Affiliates. During the year ended December 31, 2019, we entered into an insurance claim settlement agreement with our insurance providers2021, the Company released a valuation allowance of approximately $33 million previously recorded on Middlemount’s deferred tax assets as a result of taxable income generated during 2021. As of December 31, 2021, no valuation allowance remained related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussedMiddlemount’s deferred tax assets so there is no release reflected in 2022. The current year income activity relates only to the amortization of basis differences which is comparable to prior periods. Refer to Note 22. “Other Events”5. “Equity Method Investments” to the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicablestatements for further information regarding these changes, which information is incorporated herein by reference.
Interest Expense. The decrease in interest expense during the year ended December 31, 2022 compared to total equipment losses recognized at the timeprior year primarily reflects debt retirements completed by the Company during 2022 and 2021 and prior year fees related to a series of refinancing transactions completed by the insurance recovery settlement, which consistedCompany as further described in Note 10. “Long-term Debt” to the accompanying consolidated financial statements.
Net (Loss) Gain on Early Debt Extinguishment. The net loss (gain) on early debt extinguishment was primarily related to the redemption of $24.7 million and $66.4 million recognizedexisting notes during the years ended December 31, 20192022 and 2018, respectively. The remaining $33.9 million, applicable2021, as further discussed in Note 10. “Long-term Debt” to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019.accompanying consolidated financial statements.
Interest Income. The decreaseincrease in interest income during the year ended December 31, 2019 as2022 compared to the prior year was driven by lowerprimarily due to higher cash balances.balances and interest rates in the current year.
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Peabody Energy Corporation | 2022 Form 10-K | 68 |
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The expensegain recorded during the year ended December 31, 20192022 was driven by decreasesincreases to the discount rates for all actuarially determined liabilities ($137.6190.1 million) and the favorable impacts of changes for the postretirement benefit plans related to updated claims experience ($28.6 million). These increases were offset by mark-to-market losses on pension and postretirement benefit plan assets ($162.1 million); the unfavorable impact of the premium paid for the purchase of a buy-in group annuity contract for a qualified pension plan ($17.6 million) and the unfavorable impactimpacts of changes related to claims and an update to our census datamedical trend updates for the postretirement benefitsbenefit plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.515.7 million).
The gain recorded during the year ended December 31, 20182021 was driven by increases to the discount rates for actuarially determined liabilities ($46.237.6 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 changes related to claims ($54.2 million), updates to the Medicare law ($20.0 million) and an update to ourthe Company’s census data ($7.7 million) for the postretirement benefit plans. The impact on our pension plans was small as actuarialactuarially determined liabilities ($10.3 million). These increases were offset by mark-to-market losses on pension and postretirement benefit plan assets were largely offset by an increase in discount rates.
Reorganization Items, Net. The reorganization items recorded during the year ended December 31, 2018 were impacted by a favorable adjustment to our former bankruptcy claims accrual due to settlement of claims.($43.1 million).
Unrealized GainsLosses on Economic Hedges.Derivative Contracts Related to Forecasted Sales. Unrealized gainslosses primarily relate to mark-to-market activity from economic hedge activities intendedon derivative contracts related to hedge futureforecasted coal sales. For additional information, refer to Note 9.6. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
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Peabody Energy Corporation | 2019 Form 10-K | 67 |
Fresh Start Take-or-Pay Contract-Based Intangible RecognitionUnrealized Losses on Foreign Currency Option Contracts.. Included in the fresh start reporting adjustments were contract-based intangible liabilities for port and rail take-or-pay Unrealized losses primarily relate to mark-to-market activity on foreign currency option contracts. During the years ended December 31, 2019 and 2018 we ratably recognized these contract-based intangible liabilities. For additional details,information, refer to Note 10. “Intangible Contract Assets6. “Derivatives and Liabilities”Fair Value Measurements” to the accompanying consolidated financial statements.
Income Tax ProvisionBenefit (Provision). The increase in the income tax provisionbenefit recorded during the year ended December 31, 2019 as compared to the prior year period2022 was primarily related to the tax impact of the gain on formation of the United Wambo Joint Venture recognized during the fourth quarter of 2019, the year-over-year change in the benefit recorded in continuing operations under the exception provisions within ASC 740-20-45-7 and the prior year tax benefit relateddue to the release of valuation allowance on refundable alternative minimum tax credits .related to Australian NOLs, partially offset by year-over-year increases in pretax income. Refer to Note 12.8. “Income Taxes” to the accompanying consolidated financial statements for additional information.
Net (Loss) Income Attributable to Common Stockholders
The following table presents net (loss) income attributable to common stockholders:
|
| | | | | | | | | | | | | | |
| Successor | | (Decrease) Increase to |
| Year Ended December 31, | | to Income |
| 2019 | | 2018 | | $ | | % |
| (Dollars in millions) | | |
(Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | | $ | 645.7 |
| | $ | (834.0 | ) | | (129.2 | )% |
Income from discontinued operations, net of income taxes | 3.2 |
| | 18.1 |
| | (14.9 | ) | | (82.3 | )% |
Net (loss) income | (185.1 | ) | | 663.8 |
| | (848.9 | ) | | (127.9 | )% |
Less: Series A Convertible Preferred Stock dividends | — |
| | 102.5 |
| | (102.5 | ) | | (100.0 | )% |
Less: Net income attributable to noncontrolling interests | 26.2 |
| | 16.9 |
| | 9.3 |
| | 55.0 | % |
Net (loss) income attributable to common stockholders | $ | (211.3 | ) | | $ | 544.4 |
| | $ | (755.7 | ) | | (138.8 | )% |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) |
| Year Ended December 31, | | to Income |
| 2022 | | 2021 | | $ | | % |
| (Dollars in millions) | | |
Income from continuing operations, net of income taxes | $ | 1,317.4 | | | $ | 347.4 | | | $ | 970.0 | | | 279.2 | % |
Income from discontinued operations, net of income taxes | 1.7 | | | 24.0 | | | (22.3) | | | (92.9) | % |
Net income | 1,319.1 | | | 371.4 | | | 947.7 | | | 255.2 | % |
| | | | | | | |
Less: Net income attributable to noncontrolling interests | 22.0 | | | 11.3 | | | 10.7 | | | 94.7 | % |
Net income attributable to common stockholders | $ | 1,297.1 | | | $ | 360.1 | | | $ | 937.0 | | | 260.2 | % |
Income from Discontinued Operations, Net of Income Taxes. The decrease in income from discontinued operations, net of income taxes during the year ended December 31, 2019 as2022 compared to the prior year period was primarily driven by smaller actuarial gains associated with black lung liabilities.
Series A Convertible Preferred Stock Dividends. The convertible preferred stock dividends for the prior year ended December 31, 2018 were comprisedgain of $24.6 million recognized on the sale of the deemed dividends granted for all remaining shares of convertible preferred stock shares that were convertedWilkie Creek Mine as of January 31, 2018.discussed in Note 17. “Other Events” to the accompanying consolidated financial statements.
Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests during the year ended December 31, 20192022 compared to the prior year period was primarily driven by the gain on formationdue to stronger financial results of the United Wambo Joint Venture recognized during the fourth quarter of 2019.Peabody’s majority-owned mines in which there is an outside non-controlling interest.
Diluted EPS
The following table presents diluted EPS:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) to |
| Year Ended December 31, | | EPS |
| 2022 | | 2021 | | $ | | % |
Diluted EPS attributable to common stockholders: | | | | | | | |
Income from continuing operations | $ | 8.29 | | | $ | 3.00 | | | $ | 5.29 | | | 176.3 | % |
Income from discontinued operations | 0.02 | | | 0.22 | | | (0.20) | | | (90.9) | % |
Net income attributable to common stockholders | $ | 8.31 | | | $ | 3.22 | | | $ | 5.09 | | | 158.1 | % |
|
| | | | | | | | | | | | | | |
| Successor | | Decrease to |
| Year Ended December 31, | | EPS |
| 2019 | | 2018 | | $ | | % |
Diluted EPS attributable to common stockholders: | | | | | | | |
(Loss) income from continuing operations | $ | (2.07 | ) | | $ | 4.28 |
| | $ | (6.35 | ) | | (148.4 | )% |
Income from discontinued operations | 0.03 |
| | 0.15 |
| | (0.12 | ) | | (80.0 | )% |
Net (loss) income attributable to common stockholders | $ | (2.04 | ) | | $ | 4.43 |
| | $ | (6.47 | ) | | (146.0 | )% |
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 69 |
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 103.7157.2 million and 121.0112.0 million for the years ended December 31, 20192022 and 2018,2021, respectively.
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Peabody Energy Corporation | 2019 Form 10-K | 68 |
Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization and reorganization items, net.amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of ourits segment’s operating performance, as displayed in the reconciliations below.
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | |
| (Dollars in millions) |
Income from continuing operations, net of income taxes | $ | 1,317.4 | | | $ | 347.4 | | | |
Depreciation, depletion and amortization | 317.6 | | | 308.7 | | | |
Asset retirement obligation expenses | 49.4 | | | 44.7 | | | |
Restructuring charges | 2.9 | | | 8.3 | | | |
| | | | | |
| | | | | |
Asset impairment | 11.2 | | | — | | | |
| | | | | |
| | | | | |
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (2.3) | | | (33.8) | | | |
Interest expense | 140.3 | | | 183.4 | | | |
Net loss (gain) on early debt extinguishment | 57.9 | | | (33.2) | | | |
Interest income | (18.4) | | | (6.5) | | | |
Net mark-to-market adjustment on actuarially determined liabilities | (27.8) | | | (43.4) | | | |
| | | | | |
Unrealized losses on derivative contracts related to forecasted sales | 35.8 | | | 115.1 | | | |
Unrealized losses on foreign currency option contracts | 2.3 | | | 7.5 | | | |
Take-or-pay contract-based intangible recognition | (2.8) | | | (4.3) | | | |
Income tax (benefit) provision | (38.8) | | | 22.8 | | | |
Adjusted EBITDA | $ | 1,844.7 | | | $ | 916.7 | | | |
Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its segments’ operating performance, as displayed in the reconciliations below:
| | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
| 2022 | | 2021 | | | |
| (Dollars in millions) |
Operating costs and expenses | $ | 3,290.8 | | | $ | 2,553.1 | | | | | |
Unrealized losses on foreign currency option contracts | (2.3) | | | (7.5) | | | | | |
Take-or-pay contract-based intangible recognition | 2.8 | | | 4.3 | | | | | |
| | | | | | | |
Net periodic benefit credit, excluding service cost | (49.0) | | | (38.3) | | | | | |
Total Reporting Segment Costs | $ | 3,242.3 | | | $ | 2,511.6 | | | | | |
The following table presents Total Reporting Segment Costs by reporting segment:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | |
| (Dollars in millions) |
Seaborne Thermal Mining | $ | 698.0 | | | $ | 580.9 | | | |
Seaborne Metallurgical Mining | 835.2 | | | 549.5 | | | |
Powder River Basin Mining | 997.3 | | | 836.3 | | | |
Other U.S. Thermal Mining | 709.8 | | | 524.9 | | | |
Corporate and Other | 2.0 | | | 20.0 | | | |
Total Reporting Segment Costs | $ | 3,242.3 | | | $ | 2,511.6 | | | |
|
| | | | | | | |
| Successor |
| Year Ended December 31, |
| 2019 | | 2018 |
| (Dollars in millions) |
(Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | | $ | 645.7 |
|
Depreciation, depletion and amortization | 601.0 |
| | 679.0 |
|
Asset retirement obligation expenses | 58.4 |
| | 53.0 |
|
Gain on formation of United Wambo Joint Venture | (48.1 | ) | | — |
|
Asset impairment | 270.2 |
| | — |
|
Provision for North Goonyella equipment loss | 83.2 |
| | 66.4 |
|
North Goonyella insurance recovery - equipment | (91.1 | ) | | — |
|
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (18.8 | ) | | (18.3 | ) |
Interest expense | 144.0 |
| | 149.3 |
|
Loss on early debt extinguishment | 0.2 |
| | 2.0 |
|
Interest income | (27.0 | ) | | (33.6 | ) |
Net mark-to-market adjustment on actuarially determined liabilities | 67.4 |
| | (125.5 | ) |
Reorganization items, net | — |
| | (12.8 | ) |
Unrealized gains on economic hedges | (42.2 | ) | | (18.3 | ) |
Unrealized (gains) losses on non-coal trading derivative contracts | (1.2 | ) | | 0.7 |
|
Fresh start take-or-pay contract-based intangible recognition | (16.6 | ) | | (26.7 | ) |
Income tax provision | 46.0 |
| | 18.4 |
|
Adjusted EBITDA | $ | 837.1 |
| | $ | 1,379.3 |
|
Revenues | | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 70 |
Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenuesrevenue by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to RevenuesRevenue per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:
|
| | | | | | | |
| Successor |
| Year Ended December 31, |
| 2019 | | 2018 |
| (Dollars in millions) |
Operating costs and expenses | $ | 3,536.6 |
| | $ | 4,071.4 |
|
Unrealized gains (losses) on non-coal trading derivative contracts | 1.2 |
| | (0.7 | ) |
Fresh start take-or-pay contract-based intangible recognition | 16.6 |
| | 26.7 |
|
North Goonyella insurance recovery - cost recovery and business interruption | (33.9 | ) | | — |
|
Net periodic benefit costs, excluding service cost | 19.4 |
| | 18.1 |
|
Restructuring charges | 24.3 |
| | 1.2 |
|
Total Reporting Segment Costs | $ | 3,564.2 |
| | $ | 4,116.7 |
|
|
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Peabody Energy Corporation | 2019 Form 10-K | 69 |
The following table presents Reporting Segment Costs by reporting segment:
|
| | | | | | | |
| Successor |
| Year Ended December 31, |
| 2019 | | 2018 |
| (Dollars in millions) |
Seaborne Thermal Mining | $ | 642.3 |
| | $ | 647.2 |
|
Seaborne Metallurgical Mining | 892.9 |
| | 1,111.6 |
|
Powder River Basin Mining | 1,007.5 |
| | 1,140.3 |
|
Midwestern U.S. Mining | 539.0 |
| | 655.8 |
|
Western U.S. Mining | 409.0 |
| | 446.6 |
|
Corporate and Other | 73.5 |
| | 115.2 |
|
Total Reporting Segment Costs | $ | 3,564.2 |
| | $ | 4,116.7 |
|
Ton.The following tables present tons sold, revenues,revenue, Total Reporting Segment Costs and Adjusted EBITDA by reportingoperating segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Other U.S. Thermal Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 15.6 | | | 6.6 | | | 82.6 | | | 18.4 | |
| | | | | | | |
Revenue | $ | 1,345.6 | | | $ | 1,616.9 | | | $ | 1,065.5 | | | $ | 952.2 | |
Total Reporting Segment Costs | 698.0 | | | 835.2 | | | 997.3 | | | 709.8 | |
Adjusted EBITDA | $ | 647.6 | | | $ | 781.7 | | | $ | 68.2 | | | $ | 242.4 | |
| | | | | | | |
Revenue per Ton | $ | 86.07 | | | $ | 243.78 | | | $ | 12.89 | | | $ | 51.82 | |
Costs per Ton | 44.65 | | | 125.92 | | | 12.06 | | | 38.63 | |
Adjusted EBITDA Margin per Ton | $ | 41.42 | | | $ | 117.86 | | | $ | 0.83 | | | $ | 13.19 | |
|
| | | | | | | | | | | | | | | | | | | |
| Successor |
| Year Ended December 31, 2019 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Midwestern U.S. Mining | | Western U.S. Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 19.5 |
| | 8.1 |
| | 108.1 |
| | 16.0 |
| | 11.9 |
|
| | | | | | | | | |
Revenues | $ | 971.7 |
| | $ | 1,033.1 |
| | $ | 1,228.7 |
| | $ | 669.7 |
| | $ | 639.7 |
|
Reporting Segment Costs | 642.3 |
| | 892.9 |
| | 1,007.5 |
| | 539.0 |
| | 409.0 |
|
Adjusted EBITDA | 329.4 |
| | 140.2 |
| | 221.2 |
| | 130.7 |
| | 230.7 |
|
| | | | | | | | | |
Revenues per Ton | $ | 49.69 |
| | $ | 127.62 |
| | $ | 11.37 |
| | $ | 41.90 |
| | $ | 53.48 |
|
Costs per Ton | 32.84 |
| | 110.30 |
| | 9.32 |
| | 33.72 |
| | 34.19 |
|
Adjusted EBITDA Margin per Ton | 16.85 |
| | 17.32 |
| | 2.05 |
| | 8.18 |
| | 19.29 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Successor |
| Year Ended December 31, 2018 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Midwestern U.S. Mining | | Western U.S. Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 19.1 |
| | 11.0 |
| | 120.3 |
| | 18.9 |
| | 14.7 |
|
| | | | | | | | | |
Revenues | $ | 1,099.2 |
| | $ | 1,553.0 |
| | $ | 1,424.8 |
| | $ | 801.0 |
| | $ | 592.0 |
|
Reporting Segment Costs | 647.2 |
| | 1,111.6 |
| | 1,140.3 |
| | 655.8 |
| | 446.6 |
|
Adjusted EBITDA | 452.0 |
| | 441.4 |
| | 284.5 |
| | 145.2 |
| | 145.4 |
|
| | | | | | | | | |
Revenues per Ton | $ | 57.58 |
| | $ | 141.06 |
| | $ | 11.84 |
| | $ | 42.44 |
| | $ | 40.20 |
|
Costs per Ton | 33.90 |
| | 100.97 |
| | 9.47 |
| | 34.75 |
| | 30.33 |
|
Adjusted EBITDA Margin per Ton | 23.68 |
| | 40.09 |
| | 2.37 |
| | 7.69 |
| | 9.87 |
|
|
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Peabody Energy Corporation | 2019 Form 10-K | 70 |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | |
Revenue | $ | 934.0 | | | $ | 727.7 | | | $ | 971.2 | | | $ | 689.1 | |
Total Reporting Segment Costs | 580.9 | | | 549.5 | | | 836.3 | | | 524.9 | |
Adjusted EBITDA | $ | 353.1 | | | $ | 178.2 | | | $ | 134.9 | | | $ | 164.2 | |
| | | | | | | |
Revenue 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 | |
Free Cash Flow is defined as net cash provided by 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, | | |
| 2022 | | 2021 | |
| (Dollars in millions) |
Net cash provided by operating activities | $ | 1,173.6 | | | $ | 420.0 | | | |
Net cash used in investing activities | (28.7) | | | (131.5) | | | |
| | | | | |
Free Cash Flow | $ | 1,144.9 | | | $ | 288.5 | | | |
|
| | | | | | | |
| Successor |
| Year Ended December 31, |
| 2019 | | 2018 |
| (Dollars in millions) |
Net cash provided by operating activities | $ | 677.4 |
| | $ | 1,489.7 |
|
Net cash used in investing activities | (261.3 | ) | | (517.3 | ) |
Add back: Amount attributable to acquisition of Shoal Creek Mine | 2.4 |
| | 387.4 |
|
Free Cash Flow | $ | 418.5 |
| | $ | 1,359.8 |
|
Outlook
As part of its normal planning and forecasting process, Peabody utilizes a broad approach to develop macroeconomic assumptions for key variables, including country-level gross domestic product (GDP), industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections for key demand centers for coal, electricity generation and steel. Specific to the U.S., the Company evaluates individual plant needs, including expected retirements, on a plant by plant basis in developing its demand models. Supply models and cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates.
Our estimates involve risks and uncertainties and are subject to change based on various factors as described more fully in the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Annual Report on Form 10-K.
Our near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in our long-term outlook.
Near-Term Outlook
Seaborne Thermal Coal. Demand growth continues to be led by the Asia-Pacific region. Continued urbanization trends in Vietnam led to the country approximately doubling its 2019 imports over the prior year and contributed to total ASEAN imports rising some 23 million tonnes. Even with record Chinese domestic coal production, Chinese thermal coal imports rose approximately 4% year-over-year on increased domestic power consumption. In addition, India thermal coal imports increased 6% to 177 million tonnes. As expected, demand in Europe declined as the region continues to shift away from coal-fueled generation.
On the supply side, lower-quality Indonesian and Russian exports rose 29 and 12 million tonnes, respectively, in 2019 over the prior year primarily in response to increased demand from China, India and Vietnam. Australian thermal coal exports rose modestly, while U.S. thermal coal exports declined 25% given unfavorable economics on delivered coal pricing.
Looking ahead, Peabody expects growth from the Asia-Pacific region to mitigate impacts of declines in the Atlantic. Indonesia, Australia and Russia will continue to serve as the major sources of seaborne thermal supply.
Seaborne Metallurgical Coal. Supply and demand balance remains favorable as modest demand growth was met with limited supply growth. Limited new sources of metallurgical coal supply are expected to be largely offset by natural depletion. In 2019, Chinese metallurgical coal imports rose approximately 10 million tonnes on increased pig iron production. India’s metallurgical coal imports continued to rise, growing 5% in 2019 compared to the prior year as the country lacks the domestic quantity and quality to meet its steelmaking needs. Increased steel production from ASEAN nations also continued to support seaborne metallurgical coal demand.
Supply growth was muted in 2019 with rising metallurgical exports from Russia and Australia largely offset by declines in U.S. exports. Looking ahead, Peabody anticipates demand growth to be led by India.
U.S. Thermal Coal. Within the U.S., substantial plant retirements, unfavorable weather conditions, low natural gas prices and continued growth in other available energy sources resulted in an estimated 95 million ton decline in total electric power sector demand in 2019. Coal’s share of the total U.S. electricity generation mix fell to 23% in 2019, compared to 27% in 2018. Declining coal capacity, along with natural gas prices and the availability of other sources of electricity generation are expected to continue to impact total U.S. coal demand.
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Peabody Energy Corporation | 2019 Form 10-K | 71 |
Long-Term Outlook
Seaborne Fundamentals. Peabody anticipates that seaborne metallurgical coal demand will continue to grow as India increases steel production and China continues to have a significant influence on seaborne balances. On the supply side, we expect Australia to maintain its leading metallurgical coal export position, followed by other key seaborne suppliers - U.S., Canada and Russia, among others.
For seaborne thermal, Peabody expects demand to remain relatively stable as demand growth from ASEAN nations helps offset demand decline elsewhere, including, notably, in the Atlantic markets. Over 80% of seaborne thermal coal demand is projected to come from the Asia-Pacific region as Europe’s coal generation continues its secular decline. Seaborne thermal coal will continue to be sourced primarily from seaborne exporters Indonesia and Australia, along with Russia, Colombia, South Africa and the U.S., among others.
U.S. Fundamentals. Coal is expected to remain an important piece of the U.S. electric generation mix, albeit declining from current levels. Peabody expects coal-fueled plant retirements to continue to negatively impact future coal demand. The combination of fluctuations in natural gas prices, growth in renewable generation and other competing fuels, and policy and regulations, among other things, are expected to continue to be a key determinant of future U.S. coal demand.
Liquidity and Capital Resources
Overview
OurThe Company’s primary source of cash is proceeds from the sale of ourits coal production to customers. We haveThe Company has also generated cash from the sale of non-strategic assets, including coal reserves, resources and surface lands, borrowings under our credit facilities and, from time to time, borrowings under its credit facilities and the issuance of securities. OurThe Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, financecapital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining retirementreclamation obligations, collateral and margining requirements, and selling and administrative expenses. We haveRecently, the Company has also used cash for early debt retirements, and, historically, it has also used cash for dividends and share repurchases and early debt retirements. We believe that our capital structure allows us to satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations and cash on hand.repurchases.
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 71 |
Any future determinations to return capital to stockholders, such as dividends or share repurchases will be at the discretion of our Board of Directors and will depend on a variety of factors, including the restrictions set forth under ourthe Company’s debt and surety agreements, ourits 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. OurThe Company’s ability to declare dividends or repurchase shares or early retire debt in the future will depend on ourits future financial performance, which in turn depends on the successful implementation of ourits 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 ourits industry, many of which are beyond ourthe Company’s control.
Total Indebtedness. Our total indebtedness 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 December 31, 2019 and 2018 consisted of the following:
|
| | | | | | | |
| December 31, |
| 2019 | | 2018 |
| (Dollars in millions) |
6.000% Senior Secured Notes due March 2022 | $ | 459.0 |
| | $ | 500.0 |
|
6.375% Senior Secured Notes due March 2025 | 500.0 |
| | 500.0 |
|
Senior Secured Term Loan due 2025, net of original issue discount | 392.1 |
| | 395.9 |
|
Finance lease and other obligations | 15.2 |
| | 40.0 |
|
Less: Debt issuance costs | (55.5 | ) | | (68.9 | ) |
| 1,310.8 |
| | 1,367.0 |
|
Less: Current portion of long-term debt | 18.3 |
| | 36.5 |
|
Long-term debt | $ | 1,292.5 |
| | $ | 1,330.5 |
|
Refer to Note 14. “Long-term Debt” to the accompanying consolidated financial statements for further information regarding our indebtedness.
|
| | |
Peabody Energy Corporation | 2019 Form 10-K | 72 |
Equity Securities.”
Liquidity
As of December 31, 2019, our available liquidity was $1,275.8 million, which was comprised of cash and cash equivalents and availability under our revolving credit facility and receivables securitization program described below. As of December 31, 2019, our2022, the Company’s cash balances totaled $732.2$1,307.3 million, including approximately $644.9$412 million held by U.S. entities, $62.8subsidiaries, approximately $863 million held by Australian subsidiaries, and the remaining balanceremainder held by other foreign subsidiaries.subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by ourthe Company’s foreign subsidiaries is in accounts domiciled in the U.S. and denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. During 2019, we repatriatedFrom time to time, the Company may repatriate excess cash from its foreign subsidiaries to the U.S. During the year ended December 31, 2022, the Company repatriated approximately $420 million previously held by foreign subsidiaries.$1.3 billion. If we repatriate additional foreign-held cash is repatriated in the future, we dothe Company does not expect restrictions or potential taxes towill have a material effect to its near-term liquidity.
The Company’s available liquidity increased from $995.9 million as of December 31, 2021 to $1,317.8 million as of December 31, 2022. Available liquidity was comprised of the following:
| | | | | | | | | | | | | |
| | | December 31, |
| | | 2022 | | 2021 |
| | | (Dollars in millions) |
Cash and cash equivalents | | | $ | 1,307.3 | | | $ | 954.3 | |
Credit facility availability | | | 3.5 | | | 15.3 | |
Accounts receivable securitization program availability | | | 7.0 | | | 26.3 | |
Total liquidity | | | $ | 1,317.8 | | | $ | 995.9 | |
Collateral Requirements
In November 2020, the Company entered into an agreement with the providers of its surety bond portfolio to resolve previous collateral demands. In accordance with the agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit. The Company subsequently granted second liens on our overall$200.0 million of certain mining equipment and is further required to post an additional $25.0 million of collateral per year from 2021 through 2024 for the benefit of the surety providers. The collateral postings further increase to the extent the Company generates more than $100.0 million of free cash flow (as defined in the surety agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement. Based upon the Company’s free cash flow since entering into the surety agreement, additional collateral of $102.4 million was posted during the year ended December 31, 2022 and $74.4 million was posted in January 2023, in the form of cash-collateralized letters of credit. The Company is unable to accurately estimate future additional collateral postings due to the sensitivity of free cash flow to external market factors such as coal pricing.
Under the agreement, the relevant surety providers agreed to a standstill through December 31, 2025, during which time, the surety providers will not demand collateral incremental to that described above, 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.
The Company is currently in negotiations with its surety providers to amend the existing agreement, including a modification to permit shareholder returns.
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 72 |
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, expected to primarily support reclamation bonding requirements. 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 variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At December 31, 2022, letters of credit of $103.3 million were outstanding under the agreement, which were collateralized by cash of $111.0 million, which includes interest earned on deposits.
Margin Requirements
From time to time, the Company enters into hedging arrangements, including economic hedging arrangements, to manage various risks, including coal price volatility. Most hedging arrangements require the Company to post margin with its clearing broker based on the value of the related instruments and other credit factors. If the fair value of its exchange-cleared hedge portfolio moves significantly, the Company could be required to post additional margin, which could negatively impact its liquidity.
During 2022, the Company’s margin requirements have been driven primarily by coal derivative contracts entered into in the first half of 2021 related to 1.9 million metric tons of production at the Wambo Underground Mine in the Company’s Seaborne Thermal Mining segment. Based on planned production, the contracts were expected to settle at a rate of 1.2 million metric tons in 2022 and 0.7 million metric tons in 2023.
High demand and tight supply for coal globally during 2022 has resulted in a substantial rise in seaborne thermal coal prices, which has been amplified by the Russian-Ukrainian conflict resulting in unprecedented upward volatility in Newcastle coal pricing since late February 2022. The Newcastle financial price reached over $450 per metric ton during 2022, compared to approximately $166 per metric ton on December 31, 2021. As a result, the Company’s total initial and variation margin requirements reached approximately $750 million during March 2022. Margin is returned to the Company upon reductions in the underlying market coal price or, absent such reductions, cash is recovered as the Company delivers coal into the market at spot prices.
In order to meet its near-term liquidity requirements, particularly with respect to cash margin, the Company entered into a $150 million unsecured revolving credit facility in March 2022. Concurrently with this agreement, the Company entered into an agreement for at-the-market equity offerings of up to $225.0 million of the Company’s common stock. During the three months ended March 31, 2022, the Company borrowed and repaid $225.0 million under the revolving credit facility using net proceeds of $222.0 million from at-the-market issuances of 10.1 million shares of common stock and available cash. The Company made no additional borrowings and terminated the facility prior to its scheduled 2025 maturity, on August 4, 2022.
To reduce exposure to additional margin requirements, during 2022, the Company converted 0.8 million metric tons of financial hedges into fixed price physical sales. As of December 31, 2022, 0.6 million metric tons remain outstanding and are projected to settle during the first half of 2023.
On December 31, 2022, the Company had $255.5 million of margin posted. On February 17, 2023, the Company had $80.5 million of margin posted. For additional information regarding the Company’s coal derivative contracts, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 73 |
Indebtedness
The Company’s total indebtedness as of December 31, 2022 and 2021 is presented in the table below.
| | | | | | | | | | | |
| December 31, |
Debt Instrument (defined below, as applicable) | 2022 | | 2021 |
| (Dollars in millions) |
6.000% Senior Secured Notes due March 2022 (2022 Notes) | $ | — | | | $ | 23.1 | |
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 | |
Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) | — | | | 322.8 | |
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) | 320.0 | | | — | |
| | | |
Finance lease obligations | 23.6 | | | 29.3 | |
Less: Debt issuance costs | (9.8) | | | (34.8) | |
| 333.8 | | | 1,137.8 | |
Less: Current portion of long-term debt | 13.2 | | | 59.6 | |
Long-term debt | $ | 320.6 | | | $ | 1,078.2 | |
As further described below, during 2021, the Company completed a significant debt restructuring to extend maturities on its existing debt and obtain covenant relief. Subsequent to these restructuring activities, the Company utilized various methods allowable or required under its relevant debt agreements to retire all of its senior secured long-term debt by December 31, 2022, as only the 2028 Convertible Notes, which are further described below, and finance lease obligations remain outstanding.
The Company’s remaining indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at December 31, 2022, of approximately $25 million in 2023, $16 million in 2024, $14 million in 2025, $13 million in 2026, $11 million in 2027 and $322 million thereafter.
Cash interest payments amounted to $118.5 million, $174.9 million and $126.9 million during the years ended December 31, 2022, 2021, and 2020, respectively.
2021 Debt Restructuring
During the first quarter of 2021, the Company completed a series of financing transactions to provide the Company with maturity extensions and covenant relief, while allowing it to maintain near-term operating liquidity. These transactions included a senior notes exchange, a revolving credit facility exchange, various amendments to the Company’s existing debt agreements and a support agreement with the Company’s surety bond providers. These transactions were preceded by an organizational realignment in which the Company formed certain wholly-owned subsidiaries (the Co-Issuers) to indirectly own and conduct the operations of the Company’s Wilpinjong Mine in Australia and the designation of such entities as unrestricted subsidiaries under the Company’s then-existing credit agreement (Credit Agreement) and senior notes’ indenture.
The senior notes exchange involved the tender of $398.7 million aggregate principal amount of the Company’s 2022 Notes for aggregate consideration consisting of (a) $193.9 million aggregate principal amount of new 2024 Co-Issuer Notes, (b) $195.1 million aggregate principal amount of new 2024 Peabody Notes issued by the Company and (c) a cash payment of approximately $9.4 million.
Concurrently with the senior notes exchange, the Company solicited consents from holders of the 2022 Notes to certain proposed amendments to its existing senior notes’ indenture to (i) eliminate substantially all of the restrictive covenants, certain events of default applicable to the 2022 Notes and certain other provisions contained in their indenture and (ii) release the collateral securing the 2022 Notes and eliminate certain other related provisions. The Company received the requisite consents from holders of the 2022 Notes and entered into a supplemental indenture to reflect such amendments.
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 74 |
The Company also restructured $216.0 million of existing revolving loans under the Credit Agreement by (i) paying down $10.0 million aggregate principal amount of such loans, (ii) compelling the Co-Issuers to incur $206.0 million of Co-Issuer Term Loans under a separate credit agreement, (iii) entering into a letter of credit facility (the Company LC Agreement) and (iv) amending the Credit Agreement.
Under the Company LC Agreement, 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. 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. The Company LC Agreement was subsequently amended during 2022 to mandatorily reduce its capacity by approximately $22 million to make allowable certain previously restricted payments for joint venture investments. The amendment creates an investment basket which allows payments of $30.0 million per year specifically limited to investment in renewable energy-related projects. The Company has no contractual commitment for such project investment. Unused portions of the basket carryover from year-to-year, and the total amount of investment will further reduce the credit facility capacity by a like amount, or a minimum of $10.0 million per year, through the maturity of the credit facility. In February 2023, the Company LC Agreement was further amended to reduce its capacity by an additional $65.0 million, accelerate its expiration date to December 31, 2023 from December 31, 2024, and eliminate the prepayment premium due upon any reduction of commitments thereunder prior to July 29, 2023.
The Company expects to utilize its collateralized letter of credit agreement to offset reductions in the capacity of the Company LC Agreement.
Completion of the 2021 debt restructuring transactions allowed the Company to finalize the surety transaction support agreement described above.
2021 Debt Retirements
During the remainder of 2021, the Company retired $293.3 million of debt principal for cash at an aggregate cost of $250.3 million, and $106.1 million of debt principal in exchange for 10.0 million shares of its common stock, as further described below.
In March 2021, as a requirement of the senior notes exchange, the Company purchased $22.4 million of the 2024 Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest.
In June 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. During the year ended December 31, 2021, the Company sold approximately 24.8 million shares for net cash proceeds of $269.8 million. Such proceeds were utilized, in part, for the retirement of debt as described below.
During the year ended December 31, 2019, we2021, 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.
Also during the year ended December 31, 2021, the Company completed multiple bilateral transactions with note holders 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.
2022 Debt Retirements
During 2022, the Company retired $1,143.8 million of debt principal for cash at an aggregate cost of $1,172.0 million, as further described below. Such amounts exclude the $225.0 million principal amount borrowed and repaid under the now-terminated revolving facility described above.
On March 31, 2022, the Company retired the remaining principal balance of 2022 Notes upon maturity for $23.1 million.
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 75 |
During the three months ended March 31, 2022, $62.5 million principal amount of the 2024 Peabody Notes was retired using proceeds from the offering of 2028 Convertible Notes, as further described below, and the remaining $0.1 million principal amount was retired through a mandatory repurchase offer required under the terms of their indenture and the Company LC Agreement. Such mandatory repurchase offers were required when the Company made open market repurchases of its debt. In general, the repurchase offers equated to 25% of the principal amount of priority lien debt repurchased in the preceding quarter at a price equal to the weighted average repurchase price paid dividendsover that quarter. In addition to the $0.1 million principal amount of $258.12024 Peabody Notes repurchased through such offers, the Company repurchased $42.2 million of aggregate priority lien obligations under the Company LC Agreement during 2022 at approximately 95%. The repurchases of Company LC Agreement commitments were effected by the posting of $40.1 million of collateral with the administrative agent and did not reduce the availability under the facility.
In March 2022, $257.4 million principal amount of the 2025 Notes was retired using proceeds from the offering of 2028 Convertible Notes, as further described below. The remaining 2025 Notes were retired through an open market repurchase of $11.4 million principal amount at 98.00% in September 2022 and, in accordance with the notes’ indenture, a voluntary prepayment of $66.1 million principal amount at 101.59% in December 2022.
The Senior Secured Term Loan was retired through various open market purchases of $44.1 million principal amount throughout 2022 at an aggregate cost of $42.1 million, scheduled quarterly principal amortization payments of $3.0 million, and, in accordance with the terms of the Credit Agreement, a voluntary prepayment of $276.2 million principal amount at par in December 2022.
The 2024 Co-Issuer Notes and the Co-Issuer Term Loans were subject to mandatory prepayment offers at the end of each six-month period, beginning with June 30, 2021, whereby the Excess Cash Flow (as defined in the 2024 Co-Issuer Notes indenture) generated by the Wilpinjong Mine during each such period could be applied to the principal of such notes and loans on a pro rata basis, provided that the liquidity attributable to the Wilpinjong Mine would not fall below $60.0 million. Such prepayments could be accepted or declined at the option of the debt holders. Based upon the Wilpinjong Mine’s results for the six-month periods ended December 31, 2021 and June 30, 2022 and the resultant mandatory prepayment offers, during 2022, the Company prepaid $18.5 million principal amount of 2024 Co-Issuer Notes at an aggregate cost of $19.2 million and $17.2 million principal amount of Co-Issuer Term Loans at par.
Voluntary repurchases of Co-Issuer Term Loans were permissible through various methods, including a modified Dutch auction process in which the Company could solicit acceptable prices from holders. During the year ended December 31, 2022, the Company solicited bids from all holders of Co-Issuer Term Loans at various dates for the repurchase of the remaining outstanding principal amount, resulting in the valid tender and purchase of $185.9 million principal amount at an aggregate cost of $195.8 million.
The underlying terms of the 2024 Co-Issuer Notes and Co-Issuer Term Loans required parity between the holders of Co-Issuer Term Loans and holders of the 2024 Co-Issuer Notes with respect to repurchase offers such as those undertaken through the auction processes described above. As such, the Company solicited commensurate bids from all holders of 2024 Co-Issuer Notes at various dates during the year ended December 31, 2022 for the repurchase of the remaining outstanding principal amount, resulting in the valid tender and purchase of $147.3 million principal amount at an aggregate cost of $154.1 million.
Subsequent to the modified Dutch auction processes and related transactions, during the fourth quarter of 2022, the Company voluntarily prepaid the remaining $28.1 million principal amount of 2024 Co-Issuer Notes and $2.9 million principal amount of Co-Issuer Term Loans at an aggregate cost of $32.8 million, including $200certain make whole premium amounts.
3.250% Convertible Senior Notes due 2028
On March 1, 2022, through a private offering, the Company issued $320.0 million for a supplemental dividend, made stock repurchases totaling $329.9 million,in aggregate principal amount of 3.250% Convertible Senior Notes due 2028 (the 2028 Convertible Notes). The 2028 Convertible Notes are senior unsecured obligations of the Company and made open-market purchasesare governed under an indenture.
The Company used the proceeds of $41.0the offering of the 2028 Convertible Notes to redeem the remaining $62.5 million of our senior secured notes for $39.9its outstanding 2024 Peabody Notes and, together with available cash, approximately $257.4 million plus accrued interest. No additional dividendsof its outstanding 2025 Notes, and to pay related premiums, fees and expenses relating to the offering of the 2028 Convertible Notes and the redemptions.
The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or stock repurchases are currently planned.
Our ability to maintain adequate liquidity depends on the successful operation of our business and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changesrepurchased in these and other factors.
Debt Financing
Asaccordance with their terms, as described in Note 14.10. “Long-term Debt” of the accompanying consolidated financial statements, during 2017, we entered into an indenture related to the issuancestatements. The 2028 Convertible Notes will bear interest at a rate of $500.0 million of 6.000% senior secured notes due3.250% per year payable semi-annually in arrears on March 2022 and $500.0 million of 6.375% senior secured notes due March 2025. We make semi-annual interest payments on the senior notes each March 311 and September 30 until maturity. Also1 of each year.
| | | | | | | | |
Peabody Energy Corporation | 2022 Form 10-K | 76 |
During the fourth quarter of 2022, the Company’s reported common stock prices reached levels which prompted the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes are convertible at the option of the holders during 2017, we entered into a credit agreementthe first quarter of 2023. The Company cannot currently satisfy the conversion obligation in cash because the terms of the Credit Agreement generally prohibit the Company from retiring unsecured debt with cash. It is the Company’s current intent and relatedpolicy to settle any conversions of notes through shares of its common stock. Through February 17, 2023, the Company has not received any conversion requests and does not anticipate receiving any conversion requests in the near term loanas the market value of the 2028 Convertible Notes exceeds their conversion value.
Covenant Compliance
The Company was compliant with all relevant covenants under its debt agreements at December 31, 2022, including the minimum aggregate liquidity requirement under the Company LC Agreement which we originally borrowed $950.0requires the Company’s restricted subsidiaries to maintain minimum aggregate liquidity of $125.0 million and have repaid $557.0 millionat the end of each quarter through December 31, 2019.2023. 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.
We also entered into a revolving credit facility allowable under our credit agreement during 2017 for an aggregate commitment of $350.0 million for general corporate purposes. In September 2019, we entered into an amendment to the credit agreement which increased the aggregate commitment amount under the revolver to $565.0 million and, beginning in 2020, makes applicable interest rates and fees dependent upon our periodically-determined first lien leverage ratio, as defined in the credit agreement. To date, we have only utilized this revolving credit facility for letters of credit which incur combined fees of 3.375%, while unused capacity bears a commitment fee of 0.5%. As of December 31, 2019, such letters of creditCompany’s restricted subsidiaries’ relevant liquidity amounted to $66.4 million and were primarily in support of our reclamation obligations. Availability under the revolver was $498.6$1,250.4 million at December 31, 2019.
Our debt agreements impose various restrictions and limits on certain categories of payments that we may make, such as those for dividends, investments, and stock repurchases. We are also subject to customary affirmative and negative covenants. We were in compliance with all such restrictions and covenants at December 31, 2019.
As described in the “Overview” section contained within Item 1. Business, the September 2019 amendment to our credit facility removed that agreement’s restrictions pertaining to the formation of the PRB Colorado joint venture with Arch. We are currently considering alternatives for addressing similar restrictions contained within the indenture underlying our senior secured notes. Our ability to accomplish this objective is subject to market conditions and other factors, including financing options that may be available to us from time to time and conditions in the credit and debt capital markets generally.2022.
Accounts Receivable Securitization Program
As described in Note 25.20. “Financial Instruments, Guarantees With Off-Balance-Sheet Risk and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, wethe Company entered into an amended accounts receivable securitization program during 2017 which currently expires2017. The securitization program was amended in 2022. The program provides for upJanuary 2022 to extend its maturity to January 2025 and reduce the available funding capacity from $250.0 million in funding,to $175.0 million. 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 providedutilized for letters of credit in support of other obligations. At December 31, 2019, we2022, the Company had no outstanding borrowings and $132.7$168.0 million of letters of credit providedoutstanding under the program. The letters of credit areprogram, which were primarily in support of portions of our obligations forthe Company’s reclamation workers’ compensation and postretirement benefits. Availabilityobligations. The Company had no cash collateral posted under the program, which is adjusted for certain ineligible receivables, was $45.0 millionSecuritization Program at December 31, 20192022.
The securitization program was amended again in February 2023 to increase the available funding capacity to $225.0 million and there was noadjust the relevant interest rate for borrowings to a secured overnight financing rate (SOFR).
Capital Expenditures
For 2023, the Company is targeting total capital expenditures of approximately $325 million. Approximately $200 million of such amount is appropriated to major projects and growth capital expenditures, including approximately $120 million for the initial redevelopment of the Company’s North Goonyella mine.
Other Requirements
The Company will incur significant future cash collateral requirement.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 $235 million in 2023, $100 million in 2024, $110 million in 2025, $100 million in 2026, $100 million in 2027 and $1,685 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 $100 million in 2023, $110 million in 2024, $105 million in 2025, $100 million in 2026, $100 million in 2027 and $875 million thereafter.
The Company’s operating lease commitments, excluding potential contingent rental amounts, will require cash payments of approximately $19 million in 2023, $7 million in 2024 and $4 million thereafter.
|
| | | | | | | |
Peabody Energy Corporation | 20192022 Form 10-K | 7377 |
Capital Requirements
Additions to Property, Plant, Equipment and Mine Development. For 2020, we are targeting capital expenditures of approximately $250 million, which includes approximately $100 million for ongoing extension projects related to our Seaborne Thermal Mining segment, and approximately $150 million in sustaining capital across our portfolio of mines. We plan to consider other growth and development projects across our global platform beyond 2020 and will continue to evaluate the timing associated with those projects based on changes in global coal supply and demand. We have no substantial future payment requirements under U.S. federal coal reserve leases.
Pension and Postretirement Benefit Contributions. Annual contributions to qualified pension plans are made in accordance with minimum funding standards and our agreement with the Pension Benefit Guaranty Corporation. Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). Subsequent to the Effective Date, we no longer sponsor any non-qualified plans. During 2019, we made discretionary contributions of $20.0 million to our qualified pension plans and $17.0 million to our postretirement benefit plans. Based upon our current funding status, we have no minimum funding requirement for 2020. From time to time, Peabody may make discretionary contributions to its qualified pension and postretirement benefit plans.
Historical Cash Flows and Free Cash Flow
The following table summarizes ourthe Company’s cash flows for the yearyears ended December 31, 20192022 and 2018,2021, as reported in the accompanying consolidated financial statements: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.
| | | Successor | | | | | | | | | | | |
| Year Ended December 31, | | Year Ended December 31, | |
| 2019 | | 2018 | | 2022 | | 2021 | |
| (Dollars in millions) | | (Dollars in millions) |
Net cash provided by operating activities | $ | 677.4 |
| | $ | 1,489.7 |
| Net cash provided by operating activities | $ | 1,173.6 | | | $ | 420.0 | | |
Net cash used in investing activities | (261.3 | ) | | (517.3 | ) | Net cash used in investing activities | (28.7) | | | (131.5) | | |
Net cash used in financing activities | (701.3 | ) | | (1,025.2 | ) | Net cash used in financing activities | (681.6) | | | (43.4) | | |
Net change in cash, cash equivalents and restricted cash | (285.2 | ) | | (52.8 | ) | Net change in cash, cash equivalents and restricted cash | 463.3 | | | 245.1 | | |
Cash, cash equivalents and restricted cash at beginning of period | 1,017.4 |
| | 1,070.2 |
| Cash, cash equivalents and restricted cash at beginning of period | 954.3 | | | 709.2 | | |
Cash, cash equivalents and restricted cash at end of period | $ | 732.2 |
| | $ | 1,017.4 |
| Cash, cash equivalents and restricted cash at end of period | $ | 1,417.6 | | | $ | 954.3 | | |
| | | | | | | | |
Net cash provided by operating activities | $ | 677.4 |
| | $ | 1,489.7 |
| Net cash provided by operating activities | $ | 1,173.6 | | | $ | 420.0 | | |
Net cash used in investing activities | (261.3 | ) | | (517.3 | ) | Net cash used in investing activities | (28.7) | | | (131.5) | | |
Add back: Acquisition of Shoal Creek Mine | 2.4 |
| | 387.4 |
| |
| Free Cash Flow | $ | 418.5 |
| | $ | 1,359.8 |
| Free Cash Flow | $ | 1,144.9 | | | $ | 288.5 | | |
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 ourthe 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.
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 ourits active mining operations, wethe Company generally groupgroups 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 ourits development and exploration properties and portfolio of surface land and coal reserve and resource holdings, we considerthe 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.