We believe we have good relationships with U.S. and Australian rail carriers and port and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators. Refer to the table in the foregoing “Mining Locations” section for a summary of transportation methods by mine.
In situations where we have elected to concentrate a large portion of our 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 our mining equipment also allows us to benefit from fleet standardization, which in turn improves asset utilization by facilitating the development of common maintenance practices across our global platform, enhancing our flexibility to move equipment between mines and reduce working capital through inventory optimization.
Surface and underground mining equipment demand and lead times have remained steady in recent periods. We consistently use our global leverage with major suppliers to ensure security of supply to meet the requirements of our active mines.
Demand for coal and the prices that we will be able to obtain for our coal are highly competitive and influenced by factors beyond our 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; taxes and environmental regulations imposed by the U.S. and foreign governments.
Internationally, thermal coal also competes with alternative forms of electricity generation. The competitiveness and availability of natural gas, oil, nuclear, hydro, wind, solar and biomass varies by country and region. Seaborne thermal coal consumption is also impacted by the competitiveness of delivered seaborne thermal coal supply from key exporting countries such as Indonesia, Australia, Russia, Colombia, the U.S. and South Africa, among others. In addition, seaborne thermal coal import demand can be significantly impacted by the availability of domestic coal production, particularly in the two leading coal import countries, China and India, among others.
In addition to our alternative fuel source competitors, our principal U.S. direct coal supply competitors (listed alphabetically) are other large coal producers, including Alliance Resource Partners, American Consolidated Natural Resources, Inc., Arch Resources, Inc., CONSOL Energy, Eagle Specialty Materials LLC, MurrayForesight Energy, CorporationHallador Energy, Kiewit, and Navajo Transitional Energy Company LLC, among others. Major international direct coal supply competitors (listed alphabetically) include Adaro Energy, Anglo American plc, BHP, Bumi Resources, China Shenhua Energy, Coal India Limited, Drummond Company, Glencore, PT Adaro Energy Tbk,South32, SUEK, Whitehaven Coal Limited and Yancoal Australia Ltd, among others.
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.
Major international direct competitors (listed alphabetically) include Anglo American, Arch Resources, Inc., BHP, Glencore, Jellinbah, KRU, Shanxi Coking Coal Group, Teck Resources, Warrior Met Coal, Whitehaven Coal Limited and Yancoal Australia Ltd, and , among others.
We use digital technology to conduct our business operations and engage with our customers, vendors and partners. As we implement newer technologies such as cloud, analytics, automation and “internet of things”,things,” the threats to our business operations from cyber intrusions, denial of service attacks, manipulation and other cyber misconduct increase. To address the risk, we continue to evolve our risk management approach in an effort to continually assess and improve our cybersecurity risk detection, deterrence and recovery capabilities. Our cybersecurity strategy emphasizes reduction of cyber risk exposure and continuous improvement of our 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.”
EmployeesHuman Capital
We had approximately 6,6004,600 employees as of December 31, 2019,2020, including approximately 5,0003,500 hourly employees. Additional information on our employees and related labor relations matters is contained in Note 24.22. “Management — Labor Relations” to the accompanying consolidated financial statements, which information is incorporated herein by reference. During the year ended December 31, 2020, we reduced our global headcount by nearly 2,000 employees, in both operational and non-operational positions, representing approximately 30% of our workforce. The reductions were made in connection with our cost repositioning efforts to appropriately align our cost structure and optimize our coal production relative to prevailing market conditions.
As of December 31, 2020, approximately 2,900 of our employees are located in the U.S., with the remainder primarily located in Australia. About 92% of our team members work for mine operations in the U.S. and Australia, while the remaining are employed at our global headquarters in St. Louis or other business offices. We strive to create a strong, united workforce with a commitment to safety as a way of life. In 2020, we achieved a global safety incidence rate of 1.67 incidents per 200,000 hours worked, which was 43% better than the 2019 U.S. industry average incidence rate of 2.93 incidents per 200,000 hours worked per the Mine Safety and Health Administration (MSHA).
We offer an inclusive work environment and engage, recognize and develop employees. We seek a workforce that is comprised of diverse backgrounds, thoughts and experiences. Our company strives to attract and retain the best people, develop their potential and align their skills to important initiatives and activities. We believe in fostering an inclusive work environment built on mutual trust, respect and engagement. We invest in our employees through health and wellness programs, competitive total rewards and development opportunities.
The typical Peabody employee has approximately nine years of experience with the company, and more than 60% of all Peabody employees remain employed with the company for more than five years. We offer a variety of learning events, including mentoring and development programs to aid our employees in their career growth. During the past five years, approximately 36% of open positions and 70% 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 our executive officers. Executive officers are appointed by, and hold office at the discretion of, our Board of Directors, subject to the terms of any employment agreements.
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Name | | Age (1) | | Position (1) |
Glenn L. Kellow | | 5253 | | President and Chief Executive Officer |
Mark A. Spurbeck | | 4647 | | Interim Chief Financial Officer |
A. Verona Dorch | | 52 | | Executive Vice President and Chief Financial Officer |
Scott T. Jarboe | | 47 | | Chief Legal Officer Governmental Affairs and Corporate Secretary |
Charles F. MeintjesDarren R. Yeates | | 5760 | | Executive Vice President and Chief Operating Officer |
Paul V. Richard | | 6061 | | Senior Vice President and Chief Human Resources Officer |
Marc E. Hathhorn | | 4950 | | President - Australian Operations |
Kemal Williamson | | 6061 | | President - U.S. Operations |
(1) As of February 18, 2020.16, 2021.
Glenn L. Kellow was named our President and Chief Operating Officer in August 2013; our President, Chief Executive Officer-elect and a director in January 2015; and our President and Chief Executive Officer in May 2015. Mr. Kellow’s career 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, Australia and South America. Mr. Kellow has held chief executive leadership, operating and financial roles in global business in the coal, copper, nickel, aluminum, steel, oil and gas sectors. He serves as Chairman of the World Coal Association, a director and executive committee memberVice Chairman of the U.S. National Mining Association and the Vicea director and former Chairman of the International Energy AgencyWorld Coal Industry Advisory Board.Association. Mr. Kellow is a graduate of the Advanced Management Program at the University of Pennsylvania’s Wharton School of Business and holds a Master of Business Administration Degree and a Bachelor’s Degree in Commerce from the University of Newcastle. He also holds an honorary Doctor of Science degree from the South Dakota School of Mines and Technology.
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Peabody Energy Corporation | 2020 Form 10-K | 9 |
Mark A. Spurbeck was named our InterimExecutive 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 and investor relations and corporate communications. 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 DorchScott T. Jarboe was named our Executive Vice President, Chief Legal Officer Governmental Affairs and Corporate Secretary in August 2015.March 2020. In this role, shehe 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. DorchMr. Jarboe joined Peabody in 2010 and 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,roles. He most recently serving as Chief Legal Officer, Chief Compliance Officerled the Litigation, Disputes and Corporate Secretary. She also has experience in corporateLabor & Employment activities for Peabody. Prior to joining Peabody, Mr. Jarboe practiced law with Husch Blackwell LLP 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. DorchBryan Cave LLP. Mr. Jarboe holds a Bachelor’sBachelor of Arts Degree from Dartmouth Collegethe University of Kansas, a Master’s Degree from the University of Missouri – Kansas City and a Juris Doctor degree from Harvard Law School.Washington University School of Law.
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Peabody Energy Corporation | 2019 Form 10-K | 9 |
Charles F. MeintjesDarren R. Yeates 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 improvementover 35 years of mining industry experience. From May 2018 to December 2019, Mr. Yeates served as Chief Operating Officer of MACH Energy Australia, a developer and information technology experiencesupplier of thermal coal to both the Australian domestic and Asian export markets. From January 2014 until June 2016, Mr. Yeates served as the Chief Executive Officer of GVK Hancock Coal, a joint venture developing the vast potential of the Galilee Basin in Central Queensland. Prior to that, he spent over 22 years with Rio Tinto, a global mining companies on three continents. He has also led financialgroup, including as Acting Managing Director and technical functions, large re-engineering programs, information technology system implementationsChief Operating Officer for Coal Australia, General Manager Ports and large industrial construction projects. He joined us in 2007,Infrastructure for Pilbara Iron and prior 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.General Manager Tarong Coal. Prior to joining us,Rio Tinto, Mr. Meintjes served asYeates worked for six years for BHP, a consultant to Exxaro Resources Limitedmining, metals and petroleum company, in South Africa,coal operations and metalliferous exploration. Mr. Yeates has a Bachelor of Engineering (Mining) from the University of Queensland, a Graduate Diploma in Management from the University of Central Queensland and a Graduate Diploma of Applied Finance and Investment from the Securities Institute of Australia. He has an Executive MBA from the Monash Mt Eliza Business School and is a former Executive Director and Board Member for Kumba Resources Limited in South Africa. He has senior management experience inFellow of the steel and the aluminum industries with Iscor and Alusaf in South Africa. Mr. Meintjes holds dual BachelorAustralian Institute 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.Company Directors.
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. Richard served as Vice President - Human Resources for Shaw Industries Group, Inc., a leading flooring materials producer and a subsidiary of Berkshire Hathaway, Inc. Prior to that, he served as a human resources leader for 19 years at Ferro Corporation, a global supplier of technology-based manufacturing, including four years as Vice President - Human Resources. Mr. Richard holds a Bachelor of Science Degree in Management and a Masters of Business Administration Degree from Louisiana Tech University.
Marc E. Hathhorn was named our President - Australian Operations in August 2019. He has executive responsibility for our Australian operating platform, which includes overseeing the areas of health and safety, operations, product delivery and support functions. Mr. Hathhorn has more than 30 years of experience in mining engineering and operations in North and South America. Mr. Hathhorn joined us 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 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.
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Peabody Energy Corporation | 2020 Form 10-K | 10 |
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 MidwestOther U.S. Thermal 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 | 2019 Form 10-K | 10 |
On March 22, 2017, a group of creditors (the Ad Hoc Committee) that held certain interests in the Company’s prepetition indebtedness appealed the Bankruptcy Court’s order confirming the Plan, requesting that the United States District Court for the Eastern District of Missouri (the District Court) reverse the Bankruptcy Court’s confirmation of the Plan and the order approving the Private Placement Agreement and Backstop Commitment Agreement. On December 29, 2017, the District Court entered an order dismissing the Ad Hoc Committee’s appeal, and, 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 stock at a discount. Oral argument on the appeal was held April 16, 2019, and the Eighth Circuit issued 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.
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 believe that we have obtained all permits currently required to conduct our present mining operations.
We endeavor to conduct our 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 are 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 provide additional details on MSHA compliance.
Black Lung (Coal Workers’ Pneumoconiosis)
Under the U.S. Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator who was the last to employ a claimant for a cumulative year of employment, with the last day worked for the operator after July 1, 1973, must pay federal black lung benefits and medical expenses to claimants whose claims for benefits are allowed. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, very few of the miners who sought federal black lung benefits were awarded these benefits; however, the approval rate has increased following implementation of black lung provisions contained in the Affordable Care Act. The 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 $53.3 million, $31.4 million $78.6 million, $60.9 million and $20.1$78.6 million for the years ended December 31, 2020, 2019 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017, respectively.
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Peabody Energy Corporation | 2020 Form 10-K | 11 |
The Affordable Care Act includes 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 a material impact on our costs expended in association with the federal black lung program.
Environmental Laws and Regulations
We are subject to various federal, state, local and tribal environmental laws and regulations. These laws and regulations place substantial requirements on our coal mining operations, and require regular inspection and monitoring of our mines and other facilities to ensure compliance. We are also affected by various other federal, state, local and tribal environmental laws and regulations that impact our customers.
Temporary Enforcement Policy. On March 26, 2020, the United States Environmental Protection Agency (EPA) announced a temporary policy regarding EPA enforcement of environmental legal obligations as a result of the COVID-19 pandemic. (COVID-19 Implications for EPA’s Enforcement and Compliance Assurance Program). Under the temporary policy, the EPA exercised enforcement discretion for certain noncompliance events that occurred during the period of time that the temporary policy was in effect and that resulted from the COVID-19 pandemic. The EPA’s temporary policy did not provide leniency for intentional criminal violations of law and imposed conditions on any violation that may result in “acute risk or an imminent threat to human health or the environment.” The policy also did not apply to activities that were carried out under Superfund and Resource Conservation and Recovery Act (RCRA) Corrective Action enforcement instruments. The EPA's temporary policy became effective on March 13, 2020 and remained in effect until August 31, 2020.
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 have active mining operations have achieved primacy control of enforcement through federal authorization. In Arizona, where we minewill be performing reclamation work on tribal lands, andwe are 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.
Our total reclamation bonding requirements in the U.S. were $1,263.9$1,139.3 million as of December 31, 2019.2020. 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. Our asset retirement obligations calculated in accordance with generally accepted accounting principles for our U.S. operations were $527.9$502.8 million as of December 31, 2019.2020. The bond requirement amount for our 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.
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 our 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.
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Peabody Energy Corporation | 2020 Form 10-K | 12 |
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 is $0.28 and $0.12 per ton of surface-mined and underground-mined coal, respectively. We recognized expense related to the fees of $28.4 million, $36.5 million $40.9 million, $31.6 million and $10.3$40.9 million for the years ended December 31, 2020, 2019 and 2018, the period April 2 through December 31, 2017 and the period January 1 through April 1, 2017, 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 our U.S. coal mining operations both directly and indirectly.
Direct impacts on coal mining and processing operations may occur through the CAA permitting requirements and/or emission control requirements relating to particulate matter (PM), nitrogen dioxide, ozone and sulfur dioxide (SO2). In recent years, the United States Environmental Protection Agency (EPA)EPA has adopted more stringent national ambient air quality standards (NAAQS) for PM, nitrogen oxide, ozone and SO2. It is possible that these modifications, as well as future modifications to NAAQS, could directly or indirectly impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, serving as a basis for changes in vehicle and/or engine emission standards or prompting additional local control measures pursuant to state implementation plans required to address revised NAAQS.
In 2009, the EPA adopted revised rules to add more stringent PM emissions limits for coal preparation and processing plants constructed or modified after April 28, 2008. 74 Fed. Reg. 51,950 (Oct. 8, 2009). The PM NAAQS was thereafter revised and made more stringent in 2012. In 2015, the EPA issued a final rule setting the ozone NAAQS at 70 parts per billion (ppb). (80 Fed. Reg. 65,292 (Oct. 25, 2015)). The primary ozone standard was upheld by the United States Court of Appeals for the D.C. Circuit (D.C. Circuit) in Murray Energy v. EPA, (D.C. Cir. 2019), Slip Op. 15-1385. The court, however, remanded the secondary ozone NAAQS standard to the EPA and vacated a “grandfathering” provision concerning the use of the prior ozone NAAQS in certain permitting actions.
The Clean Air Act requires the EPA to review NAAQS every five years to determine whether revision to current standards are appropriate. 42 U.S.C. §7409(d). As part of this recurring review process, the EPA proposed to retain the ozone standards promulgated in 2015, including current secondary standards. 85 Fed. Reg. 49,830 (Aug. 14, 2020).
The EPA is additionally considering revisionsalso proposed to retain the 2015 PM NAAQS as part of the periodic review process required by the CAA, with any revisions to the standards projected for latepromulgated in 2012 (85 Fed. Reg. 24,094 (Apr. 30, 2020)). On December 18, 2020, the same timeframe as it contemplates possible revisionsEPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5) and the 2015primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. On December 31, 2020, the EPA issued a final rule to retain the current primary and secondary ozone NAAQS. standards. 85 Fed. Reg. 87,256 (Dec. 31, 2020).
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 oxide and SO2 although the EPA promulgated a final rule on March 18, 2019 (84 Fed. Reg. 9866) that retains, without revision, the existing NAAQS for SO2 of 75 ppb averaged over an hour.
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, 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.
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Peabody Energy Corporation | 2020 Form 10-K | 13 |
This rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for carbon dioxide of 1,400 lb carbon dioxide per megawatt-hour gross output (CO2/MWh-gross). The standard (known as the Best System of Emission Reduction (BSER)) is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed units must implement the most efficient generating technology based on the size of the unit (supercritical steam conditions for larger units, to meet a standard of 1,800 lb CO2/MWh-gross, and subcritical conditions for smaller units to meet a standard of 2,000 lb CO2/MWh-gross).
Numerous legal challenges to the final rule were filed in the D.C. Circuit. Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports. Thus, the NSPS remains in effect.
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Peabody Energy Corporation | 2019 Form 10-K | 13 |
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 proposed rule. On January 13, 2021, the EPA promulgated a final rule concluded on February 19, 2019.which did not address BSER, but rather finalized a pollutant-specific significant contribution determination for greenhouse gas emissions from EGUs of 3%. Thus, the NSPS remains in effect. (86 Fed. Reg. 2,542 (Jan. 13, 2021)).
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 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 proposed to repeal the CPP. (82 Fed. Reg. 48,035 (Oct. 16, 2017)). 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)). On June 19, 2019, the EPA issued a combined package that finalizesfinalized the CPP repeal rule as well as the replacement rule, ACE. Repeal(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.
84 Fed. Reg. 32,520 (July 8, 2019)). The final ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on usinga determination that efficiency heat rate improvements as “Best System of Emission Reduction” measures.constitute the BSER. The EPA’s final rule also revises 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 of the ACE proposal were separated, and the EPA indicated that it intends to take final action on the proposed NSR program reforms at a later date.
Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C. Circuit matter seeking review of CPP, including Peabody, filed a motion to dismiss, which the court granted in September 2019. Meanwhile, challengers to
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Peabody Energy Corporation | 2020 Form 10-K | 14 |
Numerous petitions for review challenging the ACE Rule havewere filed petitions for judicial review,in the D.C. Circuit and consolidated in American Lung Association v. EPA (No. 19-1140 (D.C. Cir.)). This litigation has been fully briefed and oral argument before a 3-judge panel of the D.C. Circuit was held on October 8, 2020. The oral argument was organized around four issue areas concerning the EPA’s repeal of the CPP, the EPA’s authority to regulate power plants under the CAA, whether the ACE rule properly interpreted and applied the CAA and the treatment of biomass in the ACE Rule. On January 19, 2021, the panel held that new litigation is expectedthe ACE Rule and its repeal of the CPP were to continue into 2020.be vacated and remanded to the EPA. It also vacated amendments to the implementing regulations that extended the compliance timeline.
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, 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, 2016, the EPA published the final CSAPR Update Rule to address implementation of the 2008 ozone NAAQS. This rule imposed further reductions in nitrogen oxides emissions 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 Rule was subsequently remanded to the EPA to address the court’s holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. Wisconsin v. EPA, No. 16-1406 (D.C. Cir. 2019). At this time, it is unknown whether rehearing will be sought.16-1406. On September 13, 2019, the D.C. Circuit held that the CSAPR Update Rule did not comply with provisions of the Clean Air Act requiring upwind states to address air pollution which significantly interferes with the ability of a downwind state or states to attain NAAQS by relevant compliance dates. The court thus remanded the CSAPR Update Rule to the EPA in order for the Agency to address the court’s decision.
In 2018, the EPA also issued a finalanother determination that the existing CSAPR Update Rule fully addressed 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. This determination was also challenged in the D.C. Circuit (No. 19-1019). On October 1, 2019, the D.C. Circuit issued a judgment vacating this rule on the basis of the court’s decision in Wisconsin v. EPA. At this time, it is unknown whether rehearing will be sought.Additional litigation concerning the interstate transport of air pollution and the EPA’s response under the Clean Air Act continues. In Maryland v. EPA (No. 18-1285), the D.C. Circuit upheld EPA determinations that upwind states had not met their burden in seeking relief from transported air pollution under the same Clean Air Act provisions at issue in Wisconsin. In New York v. EPA, No. 19-1231 (D.C. Cir., July 14, 2020), the D.C. Circuit vacated the EPA’s denial of a Clean Air Act section 126 petition requesting that the Agency find approximately 350 sources of nitrogen oxides in nine States were contributing significantly to nonattainment in the New York Metropolitan Area. The court remanded the denial to the EPA for further proceedings consistent with the court’s opinion.
EPA has proposed a rule to address the court’s remand in Wisconsin as well as NOx emissions in 21 states targeted by the CSAPR Update Rule. 85 Fed. Reg. 68,964 (Oct. 30, 2020). The proposed rule would find that 9 of the states identified do not significantly contribute to downwind nonattainment and/or maintenance issues and therefore do not need additional emission reductions. For the 12 other states, EPA has proposed to adjust state NOx budgets downward and create a new emission trading program.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16, 2012. The MATS rule revised the NSPS for nitrogen oxides, SO2 and PM for new and modified coal-fueled electricity generating plants, and imposed 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.
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Peabody Energy Corporation | 2020 Form 10-K | 15 |
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, the EPA issued a final supplemental finding that largely tracked its proposed finding. Several states, companies and industry groups 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 in this litigation has concluded, the case remains in abeyance.
On December 27, 2018, the EPA issued a proposed revised Supplemental Cost Finding for the MATS rule that would revoke the determination that regulating HAPs from coal-fired power plants is “appropriate and necessary” under Section 112(n)(1)(A) of the CAA. The new proposed finding was based on an EPA assessment that health and environmental benefits from the MATS rule that arewere not directly related to mercury pollution and should not be included in the benefit portion of the analysis. In the new proposed cost-benefit analysis, the EPA found the costs “grossly outweigh” any possible benefits. The comment period for this proposed rule closed in spring 2019 with over a half million public comments filed. TheA final rule reversing EPA’s 2016 Supplemental Finding and determining, in lieu, that it is not “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired power plants was expectedpromulgated in May 2020. 85 Fed. Reg. 31,286 (May 22, 2020). This rule also finalized residual risk and technology review standards for the coal- and oil-fired EGU source category. Both actions have been challenged 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.
TheD.C. Circuit. See American Academy of Pediatrics et al. v. Wheeler, No. 20-1221 (D.C. Cir.), Air Alliance Houston, et al v. EPA Science Advisory Board, made up of non-EPA scientists and experts who review the EPA’s basis for regulatory decisions, recommended in December 2019 that the EPA conduct a new risk assessment concerning the rule.
The plan would leave the emissions standards of the MATS rule in effect but would repeal the statutorily required finding that it was "appropriate and necessary" to originally issue the standards. Many argue this could lead to industry lawsuits aimed at fully eliminating the standards., No. 20-1268 (D.C. Cir.).
Federal Coal Leasing Moratorium. Moratorium. President Trump’s 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 in courtprior NEPA violations. Environmental groups have since amended their complaint to challenge the Environmental Assessment and defended againstFONSI, and the freeze possibly being reinstated. This litigation is ongoing.remains pending.
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,June 1, 2020, the EPA issued a proposedfinal rule intended to clarify the scope of the state or tribal regulators’ authority that if adopted in its current form, wouldcould in effect limit state and tribal regulators’ authority by allowing the EPA to certify projects over state or tribal regulator objections.objections in some circumstances.
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New Source Review (NSR). The Clean Air Act imposes permitting requirements when a new source undergoes construction or when an existing source is reconstructed or undergoes a major modification. These requirements are contained in the Clean Air Act’s PSD and Nonattainment New Source Review programs, generally referred to as NSR. On March 25, 2020, the EPA released a draft guidance document that would allow power plants, refineries and other sources of emissions to begin certain construction activities while still awaiting a permit under the NSR program. Under the EPA’s revised interpretation, a source owner or operator may, prior to obtaining a NSR permit, undertake physical on-site activities, including activities that may significantly alter the site and/or are permanent in nature, provided that those activities do not constitute physical construction on an emissions unit. The comment period on the draft memo ended May 11, 2020. On August 4, 2020, the EPA released a guidance memorandum concerning implementation of plantwide applicability limitations (PALs) (Guidance on Plantwide Applicability Limitation Provisions Under the New Source Review Regulations). PALs allow sources to make physical and operational changes under a plantwide emission limit without “triggering” NSR.
The EPA has also taken action on a number of different rules and guidance affecting the interpretation and application of NSR. In a final rule (83 Fed. Reg. 57,324 (Nov. 15, 2018)), the EPA completed reconsideration of a 2009 petition to clarify when certain actions must be “aggregated” for this proposed rule closedpurposes of determining whether these actions are part of a single project to which NSR applies. The EPA has additionally published guidance on October 21, 2019.the definition of “ambient air” (Revised Policy on Exclusions from “Ambient Air,” Dec. 2, 2019) and guidance concerning when multiple air pollution-emitting activities may be considered to be “adjacent” so that they should be considered to be a single source (Interpreting “Adjacent” for New Source Review and Title V Source Determinations in All Industries Other Than Oil and Gas, Nov. 26, 2019). Additional memorandum and applicability determinations have also been made that address other NSR issues. These rules, guidance and memorandum may therefore affect the construction, reconstruction and modification of sources and the level of pollution control requirements that will be necessary on a case-by-case basis.
CWA Definition of “Waters of the United States”. A final rule defining the scope of waters protected under the CWA (commonly called the 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 2015 WOTUS Rule.Rule, and eventually that rule was preliminarily enjoined in over half of the country. On October 22, 2019, the EPA and the Corps jointly published a final rule, which became effective on December 23, 2019, repealing the 2015 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. On 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. The final rule will become effective 60 days after publicationA federal district judge in Colorado preliminarily enjoined the Navigable Waters Protection Rule in the Federal Register. Once effective, it replacesState of Colorado on June 19, 2020. The new rule took effect in all other states on June 22, 2020, but the pre-2015 definitions apply in Colorado. Litigation over both the 2019 repeal rule published on October 22, 2019.and the 2020 Navigable Waters Protection Rule remains pending in several federal district courts.
Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. On September 30, 2015, the EPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. On 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,The EPA has not yet determined how to address the vacated portions of the 2015 rule following the Fifth Circuit’s decision. Separately, on 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. The comment period for this proposed rule closed on January 21, 2020. IfAs 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.
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. We must provide information to agencies when we propose 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. The final rule seeks to reduce unnecessary paperwork, burdens and delays, promote better coordination among agency decision makers, and clarify scope of Proposed Rulemaking in June 2018 seeking comment on a number of ways to streamlineNEPA reviews, among other things. States and improveenvironmental groups have filed several lawsuits challenging the NEPA process. The comment period closed in August��2018. It is unclear how far reaching the changes will be and if they will be able to withstand expected court challenges.final rule.
Resource Conservation and Recovery Act (RCRA). RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.
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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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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. The EPA expects to issue a final rule around May 2021. Separately, on August 28, 2020, the EPA finalized certain amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. The EPA is still deciding how to further revise the 2015 rule to address the remainder of the court decision, and the EPA expects to issue a proposed rule in the summer of 2021. Generally, EPA-imposed requirements will increase the cost of CCR management, but not as much as if the rule had regulated CCR as hazardous.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). Although generally not a prominent environmental law in the coal mining sector, CERCLA, which was enacted in 1980, nonetheless may affect U.S. coal mining operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others, regardless of fault.
Toxic Release Inventory. Arising out of the passage of the Emergency Planning and Community Right-to-Know Act in 1986 and the Pollution Prevention Act passed in 1990, the EPA’s Toxic Release Inventory program requires companies to report the use, manufacture or processing of listed toxic materials that exceed established thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
Endangered Species Act (ESA). The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on our costs or our ability to mine some of our properties in accordance with our current mining plans. The Department of the Interior issued three proposed rules in 2018 aiming to streamline and update the ESA. The three final rules became effective on September 26, 2019.2019 and are currently the subject of a pending legal challenge filed in the U.S. District Court for the Northern District of California by a coalition of 18 states.
Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur 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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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.
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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 Title and Cultural Heritage. Since 1992, the Australian courts have recognized that native title to lands and water, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the federal Native Title Act which recognizes and protects native title, and under which a national register of native title claims has been established. Native title rights do not extend to minerals; however, native title rights can be affected by mining activities unless those rights have previously been extinguished, thereby requiring negotiation with the traditional owners (and potentially the payment of compensation) prior to the grant of certain mining tenements. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.
Following the May 2020 destruction of caves at the Juukan Gorge in the Pilbara region of Western Australia by an iron ore mining operation, the Federal Government established a Senate Inquiry. The Inquiry’s terms of reference include 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. The Inquiry was due to finalize its report by December 9, 2020. The reporting deadline for the final report has been extended to October 2021 and instead the Joint Standing Committee released its interim report in December 2020. The interim report focused specifically on Western Australia but the next phase of the Inquiry will be expanded to encompass other Australian states and territories, both with a view to address particular issues and to develop a nationally consistent response to heritage protection. The Inquiry’s findings and resultant legislation, if any, could potentially impact the Company’s mining permits or existing mine plans in an effort to mitigate against adverse impacts to such sites.
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.
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Peabody Energy Corporation | 2020 Form 10-K | 19 |
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 our 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 | 2019 Form 10-K | 18 |
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.
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Peabody Energy Corporation | 2020 Form 10-K | 20 |
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.
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 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. Our 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 our credit facility and accounts receivable securitization program. We operate in both the Queensland and New South Wales state jurisdictions.
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Peabody Energy Corporation | 2019 Form 10-K | 19 |
Our reclamation bonding requirements in Australia were $243.9$312.6 million as of December 31, 2019.2020. The bond requirements represent the 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 Australian asset retirement obligations are calculated in accordance with generally accepted accounting principles and were $224.4$225.4 million as of December 31, 2019.2020. The total bonding requirements for our 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 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.
Under significant reforms proposed by the NSW Resources Regulator in October 2020, all new and existing mines in NSW will be regulated by new standard rehabilitation conditions. The conditions will apply to all new and existing mining leases and focus on transparently requiring progressive mine site rehabilitation throughout the life of the mine. The draft Mining Amendment (Standard Conditions of Mining Leases - Rehabilitation) Regulation 2020 has been released for consultation. The new conditions would apply to all new mining leases and would be introduced into existing mining leases over a 12 to 24 month transition period. The conditions require (amongst other things) that the leaseholder must rehabilitate land and water in the mining area that is disturbed by activities under the mining lease as soon as reasonably practicable after the disturbance occurs. The proposed rehabilitation management plan for the mining area which must be prepared for large mines is intended to replace the current approach of preparing a mining operation plan.
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Peabody Energy Corporation | 2020 Form 10-K | 21 |
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 we will move each of our 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 are of the view that there will not be a need to seek any further regulatory approvals for any of the NUMAs at any of our Queensland mines.
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 and the Company continue to consult with the government on the proposed residual risk payment regime.
Federal Reclamation. InIn February 2017, the Australian Senate established a Committee of Inquiry into the rehabilitation of mining and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protection and Biodiversity Conservation Act 1999. The Committee released their report in March 2019. The Committee was unable to reach unanimous agreement on a set of recommendations. It is unclear the extent to which the report will impact policy reform at a federal government level.
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Peabody Energy Corporation | 2019 Form 10-K | 20 |
Occupational Health and Safety. State legislation requires us 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 mg/m3 for coal dust (to apply from October 2022) and 0.05 mg/m3 for silica.
Since August 2017,silica (to apply as soon as possible). In Queensland, the Workers’ Compensationnew workplace exposure standard for respirable crystalline silica (eight hour time-weighted average airborne concentration of 0.05 milligrams per cubic meter (mg/m3)) took effect from July 1, 2020. In New South Wales, the new respirable crystalline silica workplace exposure standard of 0.05 mg/m3 commenced on July 1, 2020. The respirable coal dust workplace exposure standard of 2.5 mg/m3 will be reduced to 1.5 mg/m3 commencing 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 will 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 Mining Safety and Health Act 1999 concerning, among other things, dutiesNSW Resources Regulator from this commencement date. NSW will be the first mining jurisdiction in Australia to implement an exposure standard for diesel particulate matter with the exposure standard 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 powers0.1 mg/m3 to suspend or cancel an individual’s statutory certificatealso commence on February 1, 2021
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Peabody Energy Corporation | 2020 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, 2021.
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 our 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 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 March 2019 with the effect that all current reported covered emissions baselines will expire on June 30, 2020, and there will be alternatives for setting new baselines, including by reference to default emissions intensity values.
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 contribute to a Resource Community Infrastructure Fund (the Fund) over this three-year period. The Government contributes $30 million Australian dollars towards the Fund, with companies voluntarily contributing $70 million Australian dollars. Peabody’s contribution to the State of Queensland at a rate of 12.5% on coal prices over $100Fund was approximately $713,000 Australian dollars per tonnefor the 2019-20 financial year and upis expected to $150 Australian dollars per tonnedecrease in years two and 15.0%three based on pricing over $150 Australian dollars per tonne. The rate is 7.0% for coal sold below $100 Australian dollars per tonne. The periodic impact of these royalty rates is dependent upon the volume of tonnes producedan expected reduction in production 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 interpretation of the laws that impose royalties and provide guidance on how royalty rates should be calculated.mines.
New South Wales Royalty. In New South Wales, the royalty applicable to coal is charged as a percentage of the value of production (total revenue less allowable deductions). This is equal to 6.2% for deep underground mines (coal extracted at depths greater than 400 meters below ground surface), 7.2% for underground mines and 8.2% for open-cut mines.
Sydney Water Catchment Areas. In November 2017, the New South Wales government established an independent expert panel (Panel) to advise the Department of Planning, Industry and Environment (DPIE) on the impact of underground mining activities in Sydney’s water catchment areas, including at our 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 makes findings and recommendations concerning mining activities and effects across the catchment as a whole.
The Panel’s reports acknowledge the major effort at the Metropolitan 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 on groundwater and surface water. The reports endorse the government taking an incremental approach to mining approvals that provides for considering existing and emerging information and knowledge gaps. The Panel concluded 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 evidence 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 beDPIE considered by the Panel, including the cumulative impacts of flow losses and the relative significance of these for water supplies as well as the practicalities associated with establishing a robust regional water balance model.
The DPIE will now consider the recommendations in the Panel’s final report and has saidin April 2020 announced that it had accepted all 50 recommendations in the meantime noPanel’s report, and that it has established an interagency taskforce to implement a detailed action plan during 2020. The action plan includes: ensuring there is a net gain for the metropolitan water supply by requiring more offsetting from mining companies; establishing a new developmentindependent expert panel to advise on future mining applications forin 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 the catchment will be determined. We do not currently have any such applications awaiting determination. The latest extraction plans for the Metropolitan Mine are progressing on an incremental basis and we continue to conduct robust monitoring, data collection and reporting and have been actively consultingline with the government on Metropolitan’s approval processesbest available science; introducing a licensing regime to properly account for any water losses; and undertaking further research into mine designclosure planning to ensure that operational impacts are appropriately managed and minimized as far as possible.
reduce potential long-term impacts.
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Peabody Energy Corporation | 20192020 Form 10-K | 2223 |
Global Climate
In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no such legislation has been signed into law. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA is undertakinghas taken steps to regulate greenhouse gas emissions pursuant to the CAA. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” In particular, in 2015, the EPA announced final rules (known as the CPP) for regulating carbon dioxide emissions from existing and new fossil fuel-fired EGUs. Twenty-seven states and governmental entities, as well as utilities, industry groups, trade associations, coal companies (including Peabody), and other entities, challenged the CPP in federal court. Implementation of the CPP was stayed by the U.S. Supreme Court pending resolution of its legal challenges. In October 2017, the EPA proposed to change its legal interpretation of section 111(d) of the CAA, the authority that the agency relied on for the original CPP. The EPA relied on the proposed reinterpretation until August 2018, when it proposed the Affordable Clean Energy Rule (the ACE Rule) to replace the CPP with a system where states would develop emissions reduction plans using BSER measures (essentially efficiency heat rate improvements), and the EPA would approve the state plans if they use EPA-approved candidate technologies. Changes in the NSR program were also proposed to allow efficiency improvements to be made without triggering NSR requirements. In September 2019, the ACE Rule, which provides states with the flexibility to regulate on a plant-by-plant basis with a focus on coal-fired EGUs, became effective and the CPP was repealed. Proposed revisions to the regulations under the NSR program that were part of the ACE proposal were separated and the EPA indicated that it intends to take final action on the proposed NSR program reforms at a later date. Following the effectiveness of the ACE Rule, the case challenging the CPP in federal court was dismissed as being moot. The ACE Rule is being challenged inOn January 19, 2021, the D.C. Circuit Court of Appeals held that the ACE Rule and its ultimate impact will depend on state implementation plan requirementsrepeal of the CPP were to be vacated and remanded to the outcome of associated legal challenges.EPA. It also vacated amendments to the implementing regulations that extended the compliance timeline.
At the same time, a number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGGI) in 2005, which 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 gas emissions and create economic opportunities in ways not limited to cap-and-trade programs.
Several other U.S. states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.
Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.
We participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and we regularly disclose in our annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by us in the U.S. The vast majority of our emissions are generated by the operation of heavy machinery to extract and transport material at our 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 | 20192020 Form 10-K | 2324 |
The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gas emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. In December 2012, Australia signed on to the second commitment period. During the UNFCCC conference in Paris, France in late 2015, an agreement was adopted calling for voluntary emissions reductions contributions after the second commitment period ends in 2020 (the Paris Agreement). The agreement was entered into force on November 4, 2016 after ratification and execution by more than 55 countries, including Australia, that account for at least 55% of global greenhouse gas emissions. 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, the Australian Federal Government released a plan aimed at delivering an affordable and reliable energy system that meets Australia’s international commitments to emissions reduction. The plan was referred to as the National Energy Guarantee (NEG) and was aimed at changing the National Electricity Market and associated legislative framework. The NEG was abandoned by the Australian government in September 2018. Following the outcome of the federal election in May 2019, the federal government confirmed it will not revive the former NEG policy. Instead, the government will pursue a new energy and climate change policy, which includes a $2 billion Australian dollars investment in projects to bring down Australia's greenhouse gas emissions. The Climate Solutions Fund is an extension of the former Emissions Reduction Fund. The government has confirmed that it remains committed to meeting Australia’s Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices.
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 file or furnish 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 our website (www.peabodyenergy.com) as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information included on our 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 our filings will be made available, free of charge, upon request by telephone at (314) 342-7900 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, St. Louis, Missouri 63101-1826, attention: Investor Relations.
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Peabody Energy Corporation | 2020 Form 10-K | 25 |
Item 1A. Risk Factors.
We operate 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 our business, financial condition, prospects, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with our business. New factors may emerge or changes to these risks could occur that could materially affect our 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 Our Operations
Our profitability depends upon the prices we receive for our coal.
We operate in a competitive and highly regulated industry that has previously experienced strong headwinds. Current pricing levels of both seaborne and domestic coal products may not be sustainable in the future. IfDepressed coal prices decreasehave reduced our revenues, and sustained prices at current levels or further declines in coal prices will adversely affect our operating results and profitability andfinancial condition. Further declines in coal prices will adversely affect the value of our coal reserves could be materially and adversely affected.reserves.
Coal prices are dependent upon factors beyond our 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 our metallurgical coal contracts;
•weather patterns, severe weather and natural disasters;
•regulatory, administrative and judicial decisions, including those affecting future mining permits and leases; 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 our coal sales by volume during 20192020 and 2018.2019. The vast majority of our 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; and (v) the coal inventories of utilities. Gas-fueled generation has displaced and is expected to 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 have also reduced the number of new power plants being built. These trends have reduced demand for our coal and the related prices. Any further reduction in the amount of coal consumed by electric power generators could reduce the volume and price of coal that we mine and sell.
Lower demand for metallurgical coal by steel producers would reduce our revenues and could further reduce the price of our metallurgical coal. We produce metallurgical coal that is used in the global steel industry. Metallurgical coal accounted for approximately 22%17% and 28%22% of our revenues in 20192020 and 2018,2019, respectively. Changes in governmental policies and regulations and changes in the steel industry, including the demand for steel, could reduce the demand for our metallurgical coal. Lower demand for metallurgical coal in international markets could reduce the amount of metallurgical coal that we sell and the prices that we receive for it, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.
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Peabody Energy Corporation | 2020 Form 10-K | 26 |
The balance between coal demand and supply, factoring in demand and supply of closely related and competing segments such as natural gas, both domestically and internationally, could materially reduce coal prices and therefore materially reduce our revenues and profitability. In the U.S., weWe compete with other fuel sources used for electricity generation, such as natural gas and renewables. Our 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 our coal, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
If a substantial number of our long-term coal supply agreements, including those with our largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.
Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract, particularly in the U.S. For the year ended December 31, 2020, we derived 32% of our revenues from coal supply agreements from our five largest customers. Those five customers were supplied primarily from 28 coal supply agreements (excluding trading and brokerage transactions) expiring at various times from 2021 to 2026.
Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We 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. We may experience reductions in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us 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 we amend the agreements to allow for such variation. Most of our coal supply agreements contain provisions requiring us 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 our customers to terminate their contracts in the event of changes in regulations affecting our 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 |
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 us under long-term supply agreements.
The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other contract provisions may increase our exposure to short-term coal price volatility provided by those contracts.volatility. 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 discuss 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 us under long-term supply agreements. If a number of these customers significantly reduce their purchases of coal from us, or if we are unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially. In addition, our 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 |
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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 | 20192020 Form 10-K | 27 |
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 our business, and events and conditions that could occur during the course of our mining operations could have a material adverse impact on us.
Our mining operations are subject to conditions that can impact the safety of our 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;
•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 our longwall equipment;
•unexpected maintenance problems; and
•unforeseen delays in implementation of mining technologies that are new to our operations.
We maintain 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 our 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-paytake-or-pay arrangements within the coal industry could unfavorably affect our profitability.
We have substantial take-or-pay arrangements, predominately in Australia, totaling $1.1$1.2 billion, with terms ranging up to 2322 years, that commit us 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 us to apply amounts paid for subsequent deliveries, but these provisions have limitations and we may not be able to apply all such amounts so paid in all cases. Also, we may not be able to utilize the amount of capacity for which we have previously paid. Additionally, coal companies, including us,we 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.
We may not recover our investments in our mining, exploration and other assets, which may require us to recognize impairment charges related to those assets.
The value of our assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond our control, including unfavorable changes in the economic environments in which we operate,operate; declining coal-fired electricity generation; lower-than-expected coal pricing,pricing; technical and geological operating difficulties,difficulties; an inability to economically extract our coal reservesreserves; and unanticipated increases in operating costs. During the yearyears ended December 31, 2020 and 2019, the Company recorded $1,487.4 million and $270.2 million of impairment charges related to such factors, as further described in Note 5.3. “Asset Impairment” to the accompanying consolidated financial statements. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.
Because of the volatile and cyclical nature of U.S. and international coal markets, it is reasonably possible that our current estimates of projected future cash flows from our mining assets may change in the near term, which may result in the need for adjustments to the carrying value of our assets.
Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.
We manage our business with a number of key personnel, the loss of whom could have a material adverse effect on us, absent the completion of an orderly transition. In addition, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel, particularly personnel with mining experience. We cannot provide assurance that key personnel will continue to be employed by us or that we 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.
We could be negatively affected if we fail to maintain satisfactory labor relations.
As of December 31, 2019,2020, we had approximately 6,6004,600 employees (excluding employees that were employed at operations classified as discontinued), which included approximately 5,0003,500 hourly employees. We are party to labor agreements with various labor unions that represent certain of our employees. Such labor agreements are negotiated periodically, and, therefore, we are subject to the risk that these agreements may not be able to be renewed on reasonably satisfactory terms. Approximately 42%29% of our hourly employees were represented by organized labor unions and generated approximately 19%18% of our coal production for the year ended December 31, 2019.2020. Relations with our employees and, where applicable, organized labor are important to our success. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations or successfully negotiate contracts with our employees who are represented by unions, we could potentially experience labor disputes, strikes, work stoppages, slowdowns or other disruptions in production that could negatively impact our profitability.
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Peabody Energy Corporation | 2020 Form 10-K | 28 |
We could be adversely affected if we fail to appropriately provide financial assurances for our obligations.
U.S. federal and state laws and Australian laws require us to provide financial assurances related to requirements to reclaim lands used for mining, to pay federal and state workers’ compensation, to provide financial assurances for coal lease obligations and to satisfy other miscellaneous obligations. The primary methods we use to meet those obligations are to provide a third-party surety bond or provide a letter of credit. As of December 31, 2019,2020, we had $1,609.2$1,633.6 million of outstanding surety bonds and $200.5$437.6 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.
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Peabody Energy Corporation | 2019 Form 10-K | 30 |
Our 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, 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.our mines reside. Our 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. That failure could result from a variety of factors including the following:
•lack of availability, higher expense or unfavorable market terms of new surety bonds, bank guarantees or letters of credit; and
•inability to provide or fund collateral for current and future third-party issuers of surety bonds, bank guarantees or letters of credit.
As further described in “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the Company reached a surety transaction support agreement with the providers of 99% of its surety bond portfolio to resolve approximately $800 million in additional collateral demands made by the sureties. The sureties have agreed to a standstill through December 31, 2024, during which time, the sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves, or cancel any existing surety bond. Our failure to provide adequate collateral, or abide by other terms in the agreement, could invalidate the agreement and materially and adversely affect our business and results of operations.
Our failure to maintain adequate bonding would invalidate our mining permits and prevent mining operations from continuing, which would cast substantial doubt oncould result in our abilityinability to continue as a going concern.
Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our 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 our mines, our production and sale of coal would be disrupted and we may be required to incur cash outlays to re-open the mine. Any of these actions could have a material adverse effect on our financial condition, results of operations and cash flows.
The possibility exists that new | | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 29 |
New legislation, regulations or orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure or our 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 us or our customers to change operations significantly or incur increased costs. Some of our 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 our financial condition and results of operations.
For additional information about the various regulations affecting us, see the sections entitled “Regulatory Matters —U.S.” and “Regulatory Matters — Australia”.Australia.”
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. A number of laws, including in the U.S., CERCLA and RCRA, 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 | 2019 Form 10-K | 31 |
We may be unable to obtain, renew or maintain permits necessary for our operations, or we may be unable to obtain, renew or maintain such permits without conditions on the manner in which we run our operations, which would reduce our 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 apply for permits and approvals, we are 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, our operations may be affected by sites within or near mining areas deemed to have cultural heritage significance to indigenous peoples, and our mining permits may be rescinded or modified, or our 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 our 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 our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flows and profitability.
The Corps regulates certain activities affecting navigable watersConcerns about the impacts of coal combustion on global climate are increasingly leading to consequences that have affected and waterscould continue to affect demand for our products or our securities and our ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the 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.
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Peabody Energy Corporation | 2020 Form 10-K | 30 |
The enactment of future laws, the passage of regulations, or other executive orders regarding emissions from the use of coal by the U.S., including wetlands. Section 404some of the CWA requires mining companies like usits states or other countries, or other actions to obtain Corps permitslimit such emissions, could result in electricity generators switching from coal to place material in streamsother fuel sources. Further, policies limiting available financing for the purposedevelopment of creating slurry ponds, water impoundments, refuse areas, valley fillsnew coal mines or coal-fueled power stations could adversely impact the global supply and demand for coal. The potential financial impact on us of such future laws, regulations or other mining activities. In recent years,policies will depend upon the Section 404 permitting process has been subjectdegree to increasingly stringent regulatorywhich 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 administrative requirementsdeployment of CCUS technologies as well as a seriesacceptance of court challenges,CCUS technologies to meet regulations and the alternative uses for coal. Similarly, 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 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, 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 have resulted in increased costs and delayssometimes show that if implemented in the permitting process. Additionally, increasingly stringent requirements governing coal mining also are being considered or implemented undermanner assumed by the SMCRA,analyses, the National Pollution Discharge Elimination System permit process and various other environmental programs. Potential futurepotential laws, regulations and policies could result in material adverse impacts on our operations, financial condition or cash flows, in view offlows. We do not believe that such analyses reasonably predict the significant uncertainty surrounding each of these potentialquantitative impact that future laws, regulations and policies.
Our miningor other policies may have on our results of 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 cash flows.
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 our future financial results, liquidity and growth prospects.
Several non-governmental organizations have undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation in the U.S. and across the globe. In an effort to stop or delay coal mining activities, activist groups have brought lawsuits challenging the issuance of individual coal leases, and challenging the federal coal leasing program more broadly. Other lawsuits challenge historical and pending regulatory approvals, permits and processes that are necessary to conduct coal mining operations or to operate coal-fueled power plants, including so-called “sue and settle” lawsuits where regulatory authorities in the past have reached private agreements with environmental activists that often involve additional regulatory restrictions or processes being implemented without formal rulemaking.
The effect of these and other similar developments has made it more costly and difficult to maintain our business. These cost increases and/or substantial or extended declines in the prices we receive for our coal due to these or other factors could reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and could result in material losses.
Our trading and hedging activities do not cover certain risks and may expose us to earnings volatility and other risks.
In addition to coal price volatility, we are currently subject to price volatility on diesel fuel utilized in our mining operations and the Australian dollar. We may in the future enter into hedging arrangements to manage these risks, or other exposures.
Some of these hedging instruments may 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 adversely affected.required to post additional margin, which could negatively impact our liquidity.
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Peabody Energy Corporation | 2020 Form 10-K | 31 |
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, 2019,2020, we leased a total of 47,27244,645 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 | 20192020 Form 10-K | 3332 |
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 Additionally, 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 reputationsreserve estimates 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 combinein 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 paymentfuture 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, 2020SEC’s recent rule amendments revising property disclosure requirements for publicly-traded mining companies. We will be reducedrequired to $25 million.
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Peabody Energy Corporation | 2019 Form 10-K | 34 |
comply with these new rules in 2021.
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.
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Peabody Energy Corporation | 2020 Form 10-K | 33 |
Our business, results of operations, financial condition and prospects could be exposedmaterially and adversely affected by the recent COVID-19 pandemic and the related effects on public health.
Our operations are susceptible to significant liability, reputational harm, losswidespread outbreaks of revenue, increased costsillness or other risks if we sustain cyber-attacks or other security breaches that disruptpublic health issues, such as the continuing global COVID-19 pandemic. The COVID-19 pandemic could have a material adverse effect on our business, results of operations, or resultfinancial condition and prospects, including our ability to comply with covenants under our debt agreements.
The COVID-19 pandemic has caused governments around the world, including in the disseminationU.S. and Australia, to implement quarantines, travel bans and shutdowns, which have significantly restricted the movement of proprietary or confidential information aboutpeople and goods. The continuing spread of COVID-19 has contributed to adverse changes in general domestic and global economic conditions and disrupted domestic and international credit markets. Within the global coal industry, supply and demand disruptions resulting from the COVID-19 pandemic have been widespread and have adversely impacted us and our customers, as further described in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Governmental mandates, and our efforts to act in the best interests of our employees, our customers, orsuppliers, vendors and joint venture and other third-parties.
We use digital technologybusiness partners, have affected and are continuing to conductaffect our business and operations, and engage withcausing us to modify a number of our customers, vendors, employees, financial institutionsnormal business practices. Additional governmental mandates could require forced shutdowns of our mines and other partners. Our business depends on the reliablefacilities for extended or indefinite periods and secure operation of computer systems, network infrastructure, digital communication technologies and other information technology. Problems may arisewidespread outbreaks 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, disruptionslocations significant to our operations losscould adversely affect our workforce, resulting in serious health issues and absenteeism. In addition, the COVID-19 pandemic may cause supply chains and distribution channels to be interrupted, slowed or rendered inoperable. If our operations are curtailed, we may need to seek alternate sources of customers, financial obligationssupply for damages relatedcommodities, services and labor, which may be more expensive. Alternate sources may not be available or may result in delays in shipments to our customers. Further, if our customers’ businesses are similarly affected, they might delay, reduce or cancel purchases from us. Adverse changes in the theftgeneral domestic and global economic conditions and disrupted domestic and international credit markets, could negatively affect our customers’ ability to pay us as well as our ability to access capital that could negatively affect our liquidity.
Despite our efforts to manage these realized and potential impacts, their ultimate impact also depends on factors beyond our knowledge or misusecontrol, including the duration and severity of such informationthe COVID-19 pandemic as well as third-party actions taken to contain its spread and mitigate its public health effects. While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may further negatively affect both demand and prices for our products. We also face disruption to supply chain and distribution channels, potentially increasing costs of production, storage and distribution, and potential adverse effects to remediate such security vulnerabilities, anyour workforce, each of which could have a substantial impactmaterial adverse effect on our business, financial condition, results of operations financial condition or cash flows.and prospects.
Our expenditures for postretirement benefit obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
We providepay postretirement health and life insurance benefits to eligible employees.retirees. Our total accumulated postretirement benefit obligation related to such benefits was a liability of $625.7$442.9 million as of December 31, 2019,2020, of which $32.3$29.7 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.
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Peabody Energy Corporation | 2020 Form 10-K | 34 |
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 impactsWe are subject to various general operating risks which may be fully or partially outside of coal combustion on global climate are increasingly leading to consequences that have affected and could continue to affect demand for our products or our securities and our ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators.control.
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 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. 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. Similarly, 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 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, 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 flows. We do not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on ourOur results of operations, financial conditionposition or cash flows.flows could be adversely impacted by various general operating risks which may be fully or partially outside of our control. Such risks stem from internal and external sources and include:
•global economic recessions and/or credit market disruptions;
•deterioration of the creditworthiness of our customers or counterparties to financial instruments, and their ability to perform under contracts; |
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Peabody Energy Corporation | 2019 Form 10-K | 36 |
•decreases in the availability or increases in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
Numerous activist groups are devoting substantial resources•disruption to, anti-coal activitiesor increased costs within, the transportation chain for coal, including rail, barge, trucking, overland conveyor, ports and ocean-going vessels;
•failure to minimize or eliminateattract and retain skilled and qualified personnel, particularly as the useprevalence of coal as a source ofcoal-fired electricity generation domesticallydeclines;
•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 internationally, thereby further reducing the demandincome taxes;
•uncertainties associated with our global operating platform, including country and pricing for coal,political risks, international regulatory requirements, and potentially materiallyforeign currency rates; and adversely impacting
•cyber-attacks or other security breaches that disrupt our future financial results, liquidity and growth prospects.
Several non-governmental organizations have undertaken campaigns to minimizeoperations or eliminate the use of coal as a source of electricity generationresult in the U.S. and across the globe. In an effort to stopdissemination of proprietary 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 make it more costly and difficult to maintainconfidential information about us, our business. These cost increases and/or a substantial or extended decline in the prices we receive foremployees, our coal due to thesecustomers or other factors could reduce our revenue and profitability, cash flows, liquidity, and value of our coal reserves and could result in losses.third-parties.
Risks Related to Our Indebtedness and Capital Structure
Our financial performance could be adversely affected by our indebtedness.Indebtedness.
As of December 31, 2019,2020, we had approximately $1.3$1.5 billion of indebtednessIndebtedness outstanding, excluding finance leases and debt issuance costs.
As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in January 2021 we entered into a series of interrelated transactions with our surety bond providers, the revolving lenders under our credit agreement and certain holders of our senior secured notes to extend a significant portion of our near-term debt maturities to December 2024 and to stabilize collateral requirements for our existing surety bond portfolio. While our aggregate amount of Indebtedness did not materially change as a result of these transactions, our incremental cost of borrowing and cash paid for interest expenses will increase prospectively.
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Peabody Energy Corporation | 2020 Form 10-K | 35 |
The degree to which we are leveraged could have important consequences, including, but not limited to:
•making it more difficult for us to pay interest 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,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;
•limiting our ability to refinance or otherwise exchange existing debt at commercially acceptable rates;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing, particularly during periods in which credit markets are weak;
•limiting 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.
In addition, our indebtednessIndebtedness subjects us to certain restrictive covenants. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us and result in amounts outstanding thereunder to be immediately due and payable. The terms of our indebtednessIndebtedness provide that if we cannot meet our debt service obligations, the lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation.
A downgrade in our credit ratings or other unfavorable indicators could result in, among other matters, additional required financial assurances related to our reclamation bonding requirements, a requirement to post additional collateral on derivative trading instruments that we may enter into, the loss of trading counterparties for corporate hedging and trading and brokerage activities or an increase in the cost of, or a limit on 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.Indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our indebtednessIndebtedness may restrict the use of the proceeds from any such sales. We may not be able to complete those sales and the proceeds may not be adequate to meet any debt service obligations then due.
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Peabody Energy Corporation | 2019 Form 10-K | 37 |
Despite our indebtedness,Indebtedness, we may still be able to incur substantially more debt, including secured debt, which could further increase the risks associated with our indebtedness.Indebtedness.
We may be able to incur substantial additional indebtednessIndebtedness in the future, including additional secured debt.future. Although covenants under the indentureindentures governing our senior secured notes and the agreements governing our other indebtedness,Indebtedness, including our credit facility, revolver and finance leases, limit our ability to incur additional indebtedness,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.material. In addition, the indenture governing the senior secured notes and the agreements governing our other indebtednessIndebtedness do not limit us from incurring obligations that do not constitute indebtednessIndebtedness as defined therein.
The terms of our indenturethe indentures governing our senior secured notes and the agreements and instruments governing our other indebtednessIndebtedness and surety bonding obligations impose restrictions that may limit our operating and financial flexibility.
The indentureindentures governing our senior secured notes and the agreements governing our other indebtednessIndebtedness and surety bonding obligations contain certain restrictions and covenants which restrict our 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 our ability to operate our business, as well as significantly affect our liquidity, and therefore could adversely affect our results of operations. Our credit facility also contains a mandatory prepayment provision providing that certain amounts
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Peabody Energy Corporation | 2020 Form 10-K | 36 |
These covenants limit, among other things, our ability to:
•incur additional indebtedness;Indebtedness;
•pay dividends on or make distributions in respect of stock or make certain other restricted payments, orsuch as share repurchases;
•make capital 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 our assets; and
place restrictions on the ability of subsidiaries to pay•receive dividends or make other payments to us.from subsidiaries in certain cases.
Our ability to comply with these covenants may be affected by events beyond our control and we may need to refinance existing debt in the future. A breach of any of these covenants together with the expiration of any cure period, if applicable, could result in a default under our senior secured notes. If any such default occurs, subject to applicable grace periods, the holderholders of our senior secured notes may elect to declare all outstanding senior secured notes, together with accrued interest and other amounts payable thereunder, to be immediately due and payable. If the obligations under our senior secured notes were to be accelerated, our financial resources may be insufficient to repay the notes and any other indebtednessIndebtedness becoming due in full.
In addition, if we breach 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 of default under the indenture governing the senior secured notes and a cross-default to certain of our other indebtednessIndebtedness and the lenders or holders thereunder could accelerate their obligations. If our indebtednessIndebtedness is accelerated, we may not be able to repay our indebtednessIndebtedness 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 indebtednessIndebtedness is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
The number and quantity of viable financing and insurance alternatives available to us 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 our efforts with respect to environmental and social matters and related governance considerations could harm the perception of our company by certaina significant number of investors or result in the exclusion of our 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 our ability to access capital and financial markets in the future;
•reducing the demand and price for our equity securities;
•increasing the cost of borrowing;
•causing a decline in our credit ratings;
•reducing the availability, and/or increasing the cost of, third-party insurance;
•increasing our retention of risk through self-insurance;
•making it more difficult to obtain surety bonds, letters of credit, bank guarantees or other financing; and
•limiting our flexibility in business development activities such as mergers, acquisitions and divestures.divestitures.
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Peabody Energy Corporation | 2020 Form 10-K | 37 |
Risks Related to Ownership of Our Securities
The price of our securities may be volatile.volatile and could fall below the minimum allowed by New York Stock Exchange (NYSE) listing requirements.
The price of our common stock (Common Stock) may fluctuate due to a variety of market and industry factors that may materially reduce the market price of our Common Stock regardless of our operating performance, including, among others:
•actual or anticipated fluctuations in our quarterly and annual results and those of other public companies in our 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 us or to accurately predict the results we actually achieve;
•changes in accounting principles;
•announcements concerning us or our competitors;
•the purchase and sale of shares of our Common Stock by significant shareholders;
•lack 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 our Common Stock may not be able to resell their stock at or above the price they paid or at all. In the recent past, our closing stock price has fallen below $1.00 per share for a limited number of trading days. If our stock were to trade below $1.00 per share for 30 consecutive trading days, NYSE could commence suspension and delisting procedures. Further, we 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 our results of operation.
Our Common Stock is subject to dilution and may be subject to further dilution in the future.
Our Common Stock is subject to dilution from our long-term incentive plan. In addition, in the future, we may issue 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 our other stakeholders. A significant stockholder may exert substantial influence over us to cause us 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 us 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 us or other holders of our 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 such future sales may have on the market price of our Common Stock.
The payment of dividends on our stock or repurchases of our stock is dependent on a number of factors, and future payments and repurchases cannot be assured.
As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020, we entered into transaction support agreements with our surety bond providers which prohibit the payment of dividends on our stock or repurchases of our stock through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Restrictive covenants in our credit facility and in the indentureindentures governing our senior secured notes also limit our 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 these restrictions, as well as our earnings, economic conditions, liquidity and capital requirements, and other factors, including our leverage and other financial ratios. Accordingly, we cannot make any assurance that future dividends will be paid or future repurchases will be made.
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Peabody Energy Corporation | 2020 Form 10-K | 38 |
General Business Risks
We may not be able to fully utilize our deferred tax assets.
We are subject to income and other taxes in the U.S. and numerous foreign jurisdictions, most significantly Australia. As of December 31, 2019,2020, we had gross deferred income tax assets, including net operating loss (NOL) carryforwards, and liabilities of $2,208.1$2,311.6 million and $140.2$54.4 million, respectively, as described further in Note 12.10. “Income Taxes” to the accompanying consolidated financial statements. At that date, we 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.$2,287.3 million.
The Company’s ability to use its net operating lossNOL 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 that 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 have income of the appropriate character in those jurisdictions (subject to loss carryforward and tax credit expiry, in certain cases), there is no assurance that we will be able to do so. Further, we are presently unable to record tax benefits on future losses in the U.S. and Australia until such time as sufficient income is generated by our operations in those jurisdictions to support the realization of the related net deferred tax asset positions. Our results of operations, financial condition and cash flows may adversely be affected in future periods by these limitations.
Acquisitions and divestitures are a potentially important part of our long-term strategy, subject to our investment criteria, and involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We may engage in acquisition or divestiture activity based on our 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 that 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.value or provide potential strategic benefits. If we fail 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 propertiesassets we acquire, our business, financial condition or results of operations could be negatively affected. Moreover, any transactions we pursue could materially impact our liquidity and an acquisition could increase capital resource needs and may require us to incur indebtedness,Indebtedness, seek equity capital or both. We 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 our 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.
Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our 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 our 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 our reported financial results.
The mining industry has limited industry-specific accounting literature and, as a result, we understand diversity in practice exists in the interpretation and application of accounting literature to mining-specific issues. As diversity in mining industry accounting is addressed, we may need to restate our reported results if the resulting interpretations differ from our current accounting practices. Refer to Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements for a summary of our significant accounting policies.
Item 1B. Unresolved Staff Comments.
None.
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Peabody Energy Corporation | 20192020 Form 10-K | 4139 |
Item 2. Properties.
Coal Reserves
We controlled an estimated 4.13.0 billion tons of proven and probable coal reserves as of December 31, 2019.2020. An estimated 3.62.6 billion tons of our attributable proven and probable coal reserves are in the U.S., with the remainder in Australia. Approximately 1.5%2% of our U.S. proven and probable coal reserves, or 5352 million tons, are metallurgical coking coal. The remainder of our U.S. coal reserves consists of thermal coal. Approximately 55%56% of our Australian proven and probable coal reserves, or 269243 million tons, are metallurgical coal, comprised of approximately 143121 million and 126122 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%6% of these reserves and leased property comprises the remaining 76%94%. Approximately 70%88% of our reserves, or 2.82.7 billion tons, are compliance coal and 30%12% 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, 2020 (1) |
| | | | Owned Tons | | Leased Tons | | Total Tons |
Mining Segment | | Locations | | | |
| | | | (Tons in millions) |
Seaborne Thermal Mining | | New South Wales | | — | | | 211 | | | 211 | |
Seaborne Metallurgical Mining | | Queensland, New South Wales and Alabama | | — | | | 275 | | | 275 | |
Powder River Basin Mining | | Wyoming | | — | | | 2,223 | | | 2,223 | |
Other U.S. Thermal Mining | | Illinois, Indiana, Kentucky, New Mexico and Colorado | | 190 | | | 149 | | | 339 | |
Total Proven and Probable Coal Reserves | | 190 | | | 2,858 | | | 3,048 | |
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Total United States | | 190 | | | 2,424 | | | 2,614 | |
Total Australia | | — | | | 434 | | | 434 | |
Total Proven and Probable Coal Reserves | | 190 | | | 2,858 | | | 3,048 | |
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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 |
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Seaborne Metallurgical Mining | | Queensland, New South Wales and Alabama | | — |
| | 297 |
| | 297 |
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Powder River Basin Mining | | Wyoming | | — |
| | 2,309 |
| | 2,309 |
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Midwestern U.S. Mining | | Illinois, Indiana and Kentucky | | 927 |
| | 228 |
| | 1,155 |
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Western U.S. Mining | | Arizona, New Mexico and Colorado | | 32 |
| | 7 |
| | 39 |
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Total Proven and Probable Coal Reserves | | 959 |
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| 3,091 |
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| 4,050 |
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Total United States | | 959 |
| | 2,597 |
| | 3,556 |
|
Total Australia | | — |
| | 494 |
| | 494 |
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Total Proven and Probable Coal Reserves | | 959 |
| | 3,091 |
| | 4,050 |
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(1)(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.
| 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 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal 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. • — 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. |
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.
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Peabody Energy Corporation | 20192020 Form 10-K | 4240 |
Our guidelines for geologic assurance surrounding 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 GeologicalTechnical 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 obtained from an extensive historical database of drill holes and information obtained from our ongoing drilling program. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal is determined. The density of a drill pattern determines whether the related coal reserves will be classified as proven or probable. Our coal reserve estimates are then input into our computerized land management system, which overlays that geological data with data on ownership or control of the mineral and surface interests to determine the extent of our attributable coal reserves in a given area. Our land management system contains reserve information, including the quantity and quality (where available) of reserves, as well as production data, surface and coal ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our coal reserve estimates to reflect production 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, 20192020 reflected a net reduction compared to the prior year of 841 million1.0 billion tons of coal reserves. The decrease was driven by production, changes to our estimates 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 conductedOur December 31, 2020 reserve estimates for the Gateway North Mine and El Segundo Mine in 2019,the U.S. were audited by Weir International, Inc., independent mining and geological consulting firm, which included a review of the data, procedures and parameters employed by us in developing our reserve estimates. The audits found that the reserve estimates for the areas were (1) well documented, clearly and concisely reported and (2) prepared consistent with standard industry and geological practice, and in coming years weaccordance with United States Geological Survey Circular 891 requirements and SEC Industry Guide 7 guidelines. 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.
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Peabody Energy Corporation | 2020 Form 10-K | 41 |
For each mine or future mine, we employ a market-driven, risk adjusted capital allocation process to guide long-term mine planning of active operations and development projects for economically mineable coal. We refer to this process as Life-of-Mine (LOM) planning. The LOM plan projects, 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. 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 recoverable coal in the LOM plan.
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Peabody Energy Corporation | 2019 Form 10-K | 43 |
Pricing
The pricing information used 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 | 20192020 Form 10-K | 4442 |
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. •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. •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. •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. •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. •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. •. 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. |
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, 2019.2020.
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 our principal reserves in the Powder River Basin and other reserves 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, 2019,2020, we leased 1,610 acres of federal land in Alabama, 6,1073,480 acres in Colorado, 640 acres in New Mexico and 38,915 acres in Wyoming, for a total of 47,27244,645 acres nationwide subject to those limitations.
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Peabody Energy Corporation | 20192020 Form 10-K | 4543 |
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 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 us 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 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. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically.
Mining and exploration in Australia is 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 reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.
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Peabody Energy Corporation | 20192020 Form 10-K | 4644 |
The following charts provide a summary, by mining complex, of production (in descending order by mining segment) for the years ended December 31, 2020, 2019 2018 and 2017,2018, tonnage of coal reserves that are assigned to our active operating mines, our property interest in those reserves and other characteristics of the facilities.
| | SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES | SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES | SUMMARY OF COAL PRODUCTION AND SULFUR CONTENT OF ASSIGNED RESERVES |
(Tons in millions) | (Tons in millions) | (Tons in millions) |
| | | | | | | | Sulfur Content of Assigned Reserves as of December 31, 2019 (1) | | | | Sulfur Content of Assigned Reserves as of December 31, 2020 (1) | |
| | | | | | | | <1.2 lbs. | | >1.2 to 2.5 lbs. | | >2.5 lbs. | | As | | <1.2 lbs. | | >1.2 to 2.5 lbs. | | >2.5 lbs. | | As |
| | Production | | Sulfur | | Sulfur | | Sulfur | | Received | | Production | | Sulfur | | Sulfur | | Sulfur | | Received |
| | Year Ended December 31, | | Type of | | Dioxide per | | Dioxide per | | Dioxide per | | Btu per | | 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) | Segment/Mining Complex | | 2020 | | 2019 | | 2018 | | Coal | | Million Btu | | Million Btu | | Million Btu | | pound (2) |
Seaborne Thermal Mining: | | | | | | | | | | | | | | | Seaborne Thermal Mining: | | | | | | | | | | | | | | | | |
Wilpinjong | | 14.1 |
| | 14.1 |
| | 13.4 |
| | T | | 104 |
| | — |
| | — |
| | 10,000 |
| Wilpinjong | | 14.2 | | | 14.1 | | | 14.1 | | | T | | 93 | | | — | | | — | | | 10,000 | |
Wambo (3) | | 5.6 |
| | 5.2 |
| | 5.9 |
| | T/C | | 146 |
| | — |
| | — |
| | 11,300 |
| Wambo (3) | | 5.5 | | | 5.6 | | | 5.2 | | | T/C | | 118 | | | — | | | — | | | 11,300 | |
Total | | 19.7 |
|
| 19.3 |
|
| 19.3 |
|
| 250 |
|
| — |
|
| — |
| | | Total | | 19.7 | | | 19.7 | | | 19.3 | | | 211 | | | — | | | — | | |
| | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | Seaborne Metallurgical Mining: | |
Coppabella | | 2.4 |
| | 2.7 |
| | 2.8 |
| | P | | 24 |
| | — |
| | — |
| | 12,600 |
| Coppabella | | 2.2 | | | 2.4 | | | 2.7 | | | P | | 22 | | | — | | | — | | | 12,600 | |
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 |
| Moorvale | | 1.2 | | | 1.7 | | | 2.1 | | | C/P/T | | 6 | | | — | | | — | | | 12,500 | |
Metropolitan | | 1.5 |
| | 1.7 |
| | 1.0 |
| | C/P/T | | 18 |
| | — |
| | — |
| | 12,600 |
| Metropolitan | | 1.0 | | | 1.5 | | | 1.7 | | | C/P/T | | 16 | | | — | | | — | | | 12,600 | |
Millennium | | 0.6 |
| | 1.9 |
| | 3.3 |
| | C/P | | — |
| | — |
| | — |
| | 12,600 |
| |
Shoal Creek | | Shoal Creek | | 0.6 | | | 1.9 | | | 0.2 | | | C | | 52 | | | — | | | — | | | 12,700 | |
Millennium (4) | | Millennium (4) | | 0.1 | | | 0.6 | | | 1.9 | | | C/P | | — | | | — | | | — | | | — | |
North Goonyella | | — |
| | 1.4 |
| | 3.4 |
| | C | | 82 |
| | — |
| | — |
| | 12,700 |
| North Goonyella | | — | | | — | | | 1.4 | | | C | | 69 | | | — | | | — | | | 12,700 | |
Middlemount (4) | | — |
| | — |
| | — |
| | C/P | | 22 |
| | — |
| | — |
| | 12,400 |
| |
Middlemount (5) | | Middlemount (5) | | — | | | — | | | — | | | C/P | | 20 | | | — | | | — | | | 12,400 | |
Total | | 8.1 |
| | 10.0 |
| | 12.3 |
| | 207 |
|
| — |
|
| — |
| | | Total | | 5.1 | | | 8.1 | | | 10.0 | | | 185 | | | — | | | — | | |
| | | | | | | | | | | | | | | |
Powder River Basin Mining: | | | | | | | | | | | | | | | Powder River Basin Mining: | |
North Antelope Rochelle | | 85.3 |
| | 98.3 |
| | 101.6 |
| | T | | 1,610 |
| | — |
| | — |
| | 8,800 |
| North Antelope Rochelle | | 66.1 | | | 85.3 | | | 98.3 | | | T | | 1,546 | | | — | | | — | | | 8,800 | |
Caballo | | 12.6 |
| | 11.3 |
| | 11.1 |
| | T | | 447 |
| | 6 |
| | — |
| | 8,400 |
| Caballo | | 11.6 | | | 12.6 | | | 11.3 | | | T | | 435 | | | 6 | | | — | | | 8,400 | |
Rawhide | | 10.1 |
| | 9.5 |
| | 10.4 |
| | T | | 200 |
| | 46 |
| | — |
| | 8,300 |
| Rawhide | | 9.5 | | | 10.1 | | | 9.5 | | | T | | 192 | | | 44 | | | — | | | 8,300 | |
Total | | 108.0 |
| | 119.1 |
| | 123.1 |
| | 2,257 |
| | 52 |
| | — |
| | | Total | | 87.2 | | | 108.0 | | | 119.1 | | | 2,173 | | | 50 | | | — | | |
| | | | | | | | | | | | | | | |
Midwestern U.S. Mining: | | | | | | | | | | | | | | | |
Other U.S. Thermal Mining: | | Other U.S. Thermal Mining: | |
Bear Run | | 6.8 |
| | 6.9 |
| | 7.3 |
| | T | | 4 |
| | 25 |
| | 205 |
| | 10,900 |
| Bear Run | | 5.2 | | | 6.8 | | | 6.9 | | | T | | 4 | | | 25 | | | 201 | | | 10,900 | |
El Segundo/Lee Ranch | | El Segundo/Lee Ranch | | 4.6 | | | 5.5 | | | 5.5 | | | T | | 1 | | | 19 | | | 4 | | | 9,100 | |
Wild Boar | | Wild Boar | | 2.0 | | | 2.5 | | | 2.7 | | | T | | — | | | — | | | 27 | | | 11,100 | |
Gateway North | | 3.0 |
| | 3.1 |
| | 2.5 |
| | T | | — |
| | — |
| | 52 |
| | 10,900 |
| Gateway North | | 1.8 | | | 3.0 | | | 3.1 | | | T | | — | | | — | | | 46 | | | 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 |
| Francisco Underground | | 1.6 | | | 2.0 | | | 2.2 | | | T | | — | | | — | | | 8 | | | 11,370 | |
Wildcat Hills Underground (5) | | 1.4 |
| | 1.3 |
| | 1.5 |
| | T | | — |
| | — |
| | — |
| | 12,100 |
| |
Twentymile | | Twentymile | | 1.2 | | | 2.6 | | | 3.1 | | | T | | 4 | | | — | | | — | | | 11,200 | |
Somerville Central(6) | | 1.2 |
| | 2.0 |
| | 2.2 |
| | T | | — |
| | — |
| | 3 |
| | 11,000 |
| | 0.4 | | | 1.2 | | | 2.0 | | | T | | — | | | — | | | — | | | 11,000 | |
Cottage Grove (6) | | 0.1 |
| | 0.4 |
| | 0.3 |
| | T | | — |
| | — |
| | — |
| | — |
| |
Total | | 17.0 |
| | 18.6 |
| | 18.7 |
| | 4 |
| | 25 |
| | 304 |
| | | |
| | | | | | | | | | | | | | | |
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 |
| Kayenta (7) | | — | | | 3.8 | | | 6.5 | | | T | | — | | | — | | | — | | | — | |
Twentymile | | 2.6 |
| | 3.1 |
| | 3.8 |
| | T | | 5 |
| | — |
| | — |
| | 11,200 |
| |
Wildcat Hills Underground (8) | | Wildcat Hills Underground (8) | | — | | | 1.4 | | | 1.3 | | | T | | — | | | — | | | — | | | — | |
Cottage Grove (9) | | Cottage Grove (9) | | — | | | 0.1 | | | 0.4 | | | T | | — | | | — | | | — | | | — | |
Total | | 11.9 |
| | 15.1 |
| | 14.9 |
| | 9 |
| | 23 |
| | 7 |
| | | Total | | 16.8 | | | 28.9 | | | 33.7 | | | 9 | | | 44 | | | 286 | | |
Total Assigned | | 164.7 |
|
| 182.1 |
|
| 188.3 |
|
| 2,727 |
|
| 100 |
|
| 311 |
| | | Total Assigned | | 128.8 | | | 164.7 | | | 182.1 | | | 2,578 | | | 94 | | | 286 | | |
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
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Peabody Energy Corporation | 2020 Form 10-K | 45 |
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ASSIGNED RESERVES (10) | | | | |
AS OF DECEMBER 31, 2020 | | | | |
(Tons in millions) | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | Attributable Ownership | | 100% Project Basis | | Modifying Factors (11) |
| | | | 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% | | 93 | | | — | | | 93 | | | 93 | | | — | | | 93 | | | — | | | 93 | | | 93 | | | — | | | 104 | % | | 86 | % |
Wambo (3) | | (a) | | 118 | | | — | | | 118 | | | 33 | | | 85 | | | 151 | | | — | | | 151 | | | 66 | | | 85 | | | 100 | % | | 74 | % |
Total | | | | 211 | | | — | | | 211 | | | 126 | | | 85 | | | | | | | | | | | | | | | |
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Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Coppabella | | 73.3% | | 22 | | | — | | | 22 | | | 22 | | | — | | | 30 | | | — | | | 30 | | | 30 | | | — | | | 92 | % | | 78 | % |
Moorvale | | 73.3% | | 6 | | | — | | | 6 | | | 6 | | | — | | | 8 | | | — | | | 8 | | | 8 | | | — | | | 107 | % | | 79 | % |
Metropolitan | | 100% | | 16 | | | — | | | 16 | | | — | | | 16 | | | 16 | | | — | | | 16 | | | — | | | 16 | | | 109 | % | | 84 | % |
Shoal Creek | | 100% | | 52 | | | — | | | 52 | | | — | | | 52 | | | 52 | | | — | | | 52 | | | — | | | 52 | | | 102 | % | | 56 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
North Goonyella | | 100% | | 69 | | | — | | | 69 | | | — | | | 69 | | | 69 | | | — | | | 69 | | | — | | | 69 | | | 105 | % | | 82 | % |
Middlemount (5) | | 50% | | 20 | | | — | | | 20 | | | 20 | | | — | | | 40 | | | — | | | 40 | | | 40 | | | — | | | 86 | % | | 77 | % |
Total | | | | 185 | | | — | | | 185 | | | 48 | | | 137 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Powder River Basin Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
North Antelope Rochelle | | 100% | | 1,546 | | | — | | | 1,546 | | | 1,546 | | | — | | | 1,546 | | | — | | | 1,546 | | | 1,546 | | | — | | | 92 | % | | 100 | % |
Caballo | | 100% | | 441 | | | — | | | 441 | | | 441 | | | — | | | 441 | | | — | | | 441 | | | 441 | | | — | | | 90 | % | | 100 | % |
Rawhide | | 100% | | 236 | | | — | | | 236 | | | 236 | | | — | | | 236 | | | — | | | 236 | | | 236 | | | — | | | 93 | % | | 100 | % |
Total | | | | 2,223 | | | — | | | 2,223 | | | 2,223 | | | — | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Other U.S. Thermal Mining: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Bear Run | | 100% | | 230 | | | 108 | | | 122 | | | 230 | | | — | | | 230 | | | 108 | | | 122 | | | 230 | | | — | | | 106 | % | | 72 | % |
El Segundo/Lee Ranch | | 100% | | 24 | | | 23 | | | 1 | | | 24 | | | — | | | 24 | | | 23 | | | 1 | | | 24 | | | — | | | 87 | % | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Wild Boar | | 100% | | 27 | | | 11 | | | 16 | | | 27 | | | — | | | 27 | | | 11 | | | 16 | | | 27 | | | — | | | 107 | % | | 76 | % |
Gateway North | | 100% | | 46 | | | 44 | | | 2 | | | — | | | 46 | | | 46 | | | 44 | | | 2 | | | — | | | 46 | | | 64 | % | | 62 | % |
Francisco Underground | | 100% | | 8 | | | 2 | | | 6 | | | — | | | 8 | | | 8 | | | 2 | | | 6 | | | — | | | 8 | | | 64 | % | | 64 | % |
Twentymile | | 100% | | 4 | | | 2 | | | 2 | | | — | | | 4 | | | 4 | | | 2 | | | 2 | | | — | | | 4 | | | 117 | % | | 67 | % |
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Total | | | | 339 | | | 190 | | | 149 | | | 281 | | | 58 | | | | | | | | | | | | | | | |
Total Assigned | | | | 2,958 | | | 190 | | | 2,768 | | | 2,678 | | | 280 | | | | | | | | | | | | | | | |
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Peabody Energy Corporation | 20192020 Form 10-K | 46 |
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ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES (10) |
AS OF DECEMBER 31, 2020 |
(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) | | 211 | | | — | | | 211 | | | 146 | | | 65 | | | 244 | | | — | | | 244 | | | 176 | | | 68 | |
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Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | | | | | |
Alabama | | 52 | | | — | | | 52 | | | 51 | | | 1 | | | 52 | | | — | | | 52 | | | 51 | | | 1 | |
New South Wales | | 16 | | | — | | | 16 | | | 2 | | | 14 | | | 16 | | | — | | | 16 | | | 2 | | | 14 | |
Queensland | | 117 | | | 90 | | | 207 | | | 168 | | | 39 | | | 147 | | | 120 | | | 267 | | | 212 | | | 55 | |
Total | | 185 | | | 90 | | | 275 | | | 221 | | | 54 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Powder River Basin Mining (Wyoming) | | 2,223 | | | — | | | 2,223 | | | 2,108 | | | 115 | | | 2,223 | | | — | | | 2,223 | | | 2,108 | | | 115 | |
| | | | | | | | | | | | | | | | | | | | |
Other U.S. Thermal Mining: | | | | | | | | | | | | | | | | | | | | |
Illinois | | 46 | | | — | | | 46 | | | 15 | | | 31 | | | 46 | | | — | | | 46 | | | 15 | | | 31 | |
Indiana | | 265 | | | — | | | 265 | | | 195 | | | 70 | | | 265 | | | — | | | 265 | | | 195 | | | 70 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
New Mexico | | 24 | | | — | | | 24 | | | 24 | | | — | | | 24 | | | — | | | 24 | | | 24 | | | — | |
Colorado | | 4 | | | — | | | 4 | | | 4 | | | — | | | 4 | | | — | | | 4 | | | 4 | | | — | |
Total | | 339 | | | — | | | 339 | | | 238 | | | 101 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Total Proven and Probable | | 2,958 | | | 90 | | | 3,048 | | | 2,713 | | | 335 | | | | | | | | | | | |
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 47 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 |
| |
| |
| |
| |
| |
| | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD |
AS OF DECEMBER 31, 2020 |
(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) | | — | | | 211 | | | 126 | | | 85 | | | — | | | 244 | | | 159 | | | 85 | |
| | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | |
Alabama | | — | | | 52 | | | — | | | 52 | | | — | | | 52 | | | — | | | 52 | |
New South Wales | | — | | | 16 | | | — | | | 16 | | | — | | | 16 | | | — | | | 16 | |
Queensland | | — | | | 207 | | | 54 | | | 153 | | | — | | | 267 | | | 85 | | | 182 | |
Total | | — | | | 275 | | | 54 | | | 221 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Powder River Basin Mining (Wyoming) | | — | | | 2,223 | | | 2,223 | | | — | | | — | | | 2,223 | | | 2,223 | | | — | |
| | | | | | | | | | | | | | | | |
Other U.S. Thermal Mining: | | | | | | | | | | | | | | | | |
Illinois | | 44 | | | 2 | | | — | | | 46 | | | 44 | | | 2 | | | — | | | 46 | |
Indiana | | 121 | | | 144 | | | 257 | | | 8 | | | 121 | | | 144 | | | 257 | | | 8 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
New Mexico | | 23 | | | 1 | | | 24 | | | — | | | 23 | | | 1 | | | 24 | | | — | |
Colorado | | 2 | | | 2 | | | — | | | 4 | | | 2 | | | 2 | | | — | | | 4 | |
Total | | 190 | | | 149 | | | 281 | | | 58 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Total Proven and Probable | | 190 | | | 2,858 | | | 2,684 | | | 364 | | | | | | | | | |
|
| | | | | | | |
Peabody Energy Corporation | 20192020 Form 10-K | 48 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 |
| |
| |
| |
| |
| |
|
|
| | |
Peabody Energy Corporation | 2019 Form 10-K | 49 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
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 |
| |
| |
| |
| |
|
|
| | |
Peabody Energy Corporation | 2019 Form 10-K | 50 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
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 |
| |
| |
| |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT |
AS OF DECEMBER 31, 2020 |
(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 | | 211 | | | — | | | — | | | 244 | | | — | | | — | | | 10,700 | |
| | | | | | | | | | | | | | | | |
Seaborne Metallurgical Mining: | | | | | | | | | | | | | | | | |
Alabama | | C | | 52 | | | — | | | — | | | 52 | | | — | | | — | | | 12,700 | |
New South Wales | | C/P/T | | 16 | | | — | | | — | | | 16 | | | — | | | — | | | 12,600 | |
Queensland | | C/P/T | | 207 | | | — | | | — | | | 267 | | | — | | | — | | | 12,400 | |
Total | | | | 275 | | | — | | | — | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Powder River Basin Mining (Wyoming) | | T | | 2,173 | | | 50 | | | — | | | 2,173 | | | 50 | | | — | | | 8,700 | |
| | | | | | | | | | | | | | | | |
Other U.S. Thermal Mining: | | | | | | | | | | | | | | | | |
Illinois | | T | | — | | | — | | | 46 | | | — | | | — | | | 46 | | | 10,800 | |
Indiana | | T | | 4 | | | 25 | | | 236 | | | 4 | | | 25 | | | 236 | | | 11,000 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
New Mexico | | T | | 1 | | | 19 | | | 4 | | | 1 | | | 19 | | | 4 | | | 9,150 | |
Colorado | | T | | 4 | | | — | | | — | | | 4 | | | — | | | — | | | 11,200 | |
Total | | | | 9 | | | 44 | | | 286 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Total Proven and Probable | | | | 2,668 | | | 94 | | | 286 | | | | | | | | | |
T: Thermal
C: Coking
P: Pulverized Coal Injection Metallurgical
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| | | | | | | |
Peabody Energy Corporation | 20192020 Form 10-K | 5149 |
(1)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. Non-compliance coal 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.
| |
(2)As-received Btu per pound 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 content of current production from assigned reserves. (3)Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas. (4)The Company’s Millennium Mine ceased production in March 2020, with sales continuing throughout May 2020. (5)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, 2020, 2019 and 2018 tons produced by Middlemount have been excluded from the “Summary of Coal Production and Sulfur Content of Assigned Reserves” table. Middlemount produced 3.2 million tons, 2.9 million tons, and 4.2 million tons of coal in 2020, 2019 and 2018, respectively (on a 100% basis). (6)The Company’s Somerville Central Mine ceased production in December 2020, with sales continuing into January 2021. (7)The Company’s Kayenta Mine closed during August 2019 upon termination of its coal supply agreement with the Navajo Generating Station in Arizona. (8)The Company’s Wildcat Hills Underground Mine ceased production in December 2019, with sales continuing throughout April 2020. (9)The Company’s Cottage Grove Mine ceased production in May 2019, with sales continuing throughout July 2019. (10)Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2020. Unassigned reserves represent coal at currently non-producing locations that would require significant new mine development, mining equipment or plant facilities before operations could begin on the property. (11)The modifying factors reflect the assumptions which are utilized to convert coal quantities and qualities as in ground to run of mine (ROM) coal after mining, and eventually to saleable product coal after processing. Coal reserves are reported as an estimation of the final saleable quantity, which takes into account any losses and dilutions during mining and processing. We generally keep track 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. The yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. a.In December 2019, after receiving the requisite regulatory and permitting approvals, the Company formed an unincorporated joint venture with Glencore, in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The Wambo Open-Cut reserve is estimated for our 50% interest in United Wambo Joint Venture. (1)
| 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. Non-compliance coal 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. |
| |
(2)
| As-received Btu per pound 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 content of current production from assigned reserves. |
| |
(3)
| Includes the Wambo Open-Cut Mine and the Wambo Underground Mine areas. |
| |
(4)
| 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). |
| |
(5)
| The Company’s Wildcat Hills Underground Mine ceased production in December 2019. The shipment of final tons is expected in 2020. |
| |
(6)
| The Company’s Cottage Grove Mine closed during July 2019. |
| |
(7)
| The Company’s Kayenta Mine closed during August 2019 upon termination of its coal supply agreement with the Navajo Generating Station in Arizona. |
| |
(8)
| Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations 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 begin on the property. |
| |
(9)
| The modifying factors reflect the assumptions which are utilized to convert coal quantities and qualities as in ground to run of mine (ROM) coal after mining, and eventually to saleable product coal after processing. Coal reserves are reported as an estimation of the final saleable quantity, which takes into account any losses and dilutions during mining and processing. We generally keep track 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. The yield is the ratio of estimated saleable product coal over ROM coal tons with mainly processing loss considered. |
| |
(10)
| All coal reserves in Kentucky are leased to third parties. |
| |
(a)
| In December 2019, after receiving the requisite regulatory and permitting approvals, the Company formed an unincorporated joint venture with Glencore, in which the Company holds a 50% interest, to combine the existing operations of the Company’s Wambo Open-Cut Mine in Australia with the adjacent coal reserves of Glencore’s United Mine. The Wambo reserve is estimated for our 50% interest in United Wambo Joint Venture and 100% interest in Wambo Underground Mine areas. |
Item 3. Legal Proceedings.
See Note 26.24. “Commitments and Contingencies” to the accompanying consolidated financial statements for a description of our pending legal proceedings, which information is incorporated herein by reference.
Item 4. Mine Safety Disclosures.
Our “Safety a Way of Lifeand Sustainability Management System” has been designed to set clear and consistent expectations for safety, health and healthenvironmental stewardship across our 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. We also partner with other companies and certain governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protection for employees.
We continually monitor our 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 | 20192020 Form 10-K | 5250 |
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our Common Stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 18, 202016, 2021 there were 137140 holders of our Common Stock, as determined by counting our record holders and the number of participants reflected in a security position listing provided to us by the Depository Trust Company (DTC). Because such DTC participants are brokers and other institutions holding shares of our Common Stock on behalf of their customers, we do not know the actual number of unique shareholders represented by these record holders.
Dividend Policy
The payment 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.” We declared and paid quarterly dividends every quarter in 2019, and a supplemental dividend was declared and paid during the first quarter of 2019. We are suspendingsuspended dividends in 2020. As more fully described within “Liquidity and Capital Resources” of Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020, andwe entered into transaction support agreements with our Board of Directors will continue to evaluatesurety bond providers which prohibit the declaration and payment of dividends through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in our credit facility and in the future and the amount of those dividends will depend onindentures governing our results of operations, financial condition,senior secured notes also limit our 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
We routinely allow 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 our equity incentive plans. The value of Common Stock tendered by employees is determined based on the closing price of our Common Stock on the dates of the respective relinquishments.
Share Repurchase Programs
TheOn August 1, 2017, we announced that our 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’sour common stock and/or preferred stock (Repurchase Program). Repurchases may be made from timeOn April 25, 2018, we announced that the Board authorized the expansion of the Repurchase Program to time at$1.0 billion. On October 30, 2018, we announced that the Company’s discretion. The specific timing, price and sizeBoard authorized an additional expansion 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 timeRepurchase Program to time.$1.5 billion. The Repurchase Program does not have an expiration date and may be discontinued at any time. Through December 31, 2019,2020, we repurchased 41.5 million shares of our 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 share repurchases imposed by our debt instruments are discussed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
We suspended share repurchases in 2019, and no additionalsimilar to the payment of dividends as described above, the same agreements with our surety bond providers prohibit share repurchases are planned.through December 31, 2024, unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in our credit facility and in the indentures governing our senior secured notes also limit our ability to repurchase shares. Prior to the suspension, repurchases were made at the Company’s discretion. The specific timing, price and size of purchases depended upon the share price, general market and economic conditions and other considerations, including compliance with various debt agreements in effect at the time the repurchases were made.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended December 31, 2019:2020:
|
| | | | | | | | | | | | | | |
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, 2020 | | 276 | | | $ | 2.20 | | | — | | | $ | 160.5 | |
November 1 through November 30, 2020 | | — | | | — | | | — | | | 160.5 | |
December 1 through December 31, 2020 | | 443 | | | 1.99 | | | — | | | 160.5 | |
Total | | 719 | | | 2.07 | | | — | | | |
(1) Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not a part of the Repurchase Program.
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| | | | | | | |
Peabody Energy Corporation | 20192020 Form 10-K | 5351 |
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 our common stock from April 4, 2017, the date our common stock began trading following the effective date of our Plan,plan of reorganization, through December 31, 2019,2020, 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 was $100 at April 4, 2017 for BTU and the Custom Composite Index (Warrior Met Coal, Inc. began trading on the New York Stock Exchange on April 13, 2017) and at March 31, 2017, for the S&P Midcap 400 Index. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2019.
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Peabody Energy Corporation | 2019 Form 10-K | 54 |
2020.
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 | 20192020 Form 10-K | 5552 |
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.”
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.
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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 |
|
|
| | |
Peabody Energy Corporation | 2019 Form 10-K | 57 |
Adjusted EBITDA is calculated as follows:
|
| | | | | | | | | | | | | | | | | | | | | | |
| 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.
Our discussion and analysis of the year ended December 31, 2019 compared to the year ended December 31, 2018 is included herein. For discussion and analysis of the year ended December 31, 2018 compared to the year ended December 31, 2017, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 27, 2019 and is incorporated by reference herein.
Overview
In 2019,2020, we produced and sold 164.7128.8 million and 165.5132.6 million tons of coal, respectively, from continuing operations.
As of December 31, 2019, we report our results of operations primarily through 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 our 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 our seaborne operating platform is primarily export focused with customers spread across several countries, with a portion of our thermal and metallurgical coal sold within Australia. Generally, revenues from individual countries vary year by year based on electricity and steel demand, the strength of the global economy, governmental policies and several other factors, including those specific to each country. We classify our 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, we may market some of our metallurgical coal products as a thermal coal product from time to time depending on market conditions.
Our 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.
Our Seaborne Metallurgical Mining operations consist of mines in Queensland, Australia, one in New South Wales, Australia and one in Alabama. The mines in that segment utilize both surface and underground extraction processes to mine various qualities of metallurgical coal (low-sulfur, high Btu coal). The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coking coal and PCI coal.
The principal business of our thermal mining segments in the U.S. is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S. under long-term contracts, with a relatively small portion sold as international exports as conditions warrant. Our Powder River Basin Mining operations consist of our 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 MidwesternOther U.S. Thermal Mining operations includehistorically reflect the aggregation of our Illinois, Indiana, New Mexico, Colorado and IndianaArizona 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 reflect 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, our Powder River Basin Mining operations mine sub-bituminous coal deposits our Midwestern U.S. Mining operations mine bituminous coal deposits and our WesternOther U.S. Thermal Mining operations mine both bituminous and sub-bituminous coal deposits.
Our Corporate and Other segment includes selling and administrative expenses, including our technical and shared services functions,functions; results from equity affiliates,affiliates; corporate hedging activities,activities; trading and brokerage activities,activities; results from certain mining and export/transportation joint ventures, restructuring charges and activities associated with the optimization of our coal reserve and real estate holdings,ventures; minimum charges on certain transportation-related contracts,contracts; the closure of inactive mining sitessites; and certain commercial matters.
Resource Management. As of December 31, 2019,2020, we controlled approximately 4.13.0 billion tons of proven and probable coal reserves and approximately 500,000450,000 acres of surface property through ownership and lease agreements. We have an ongoing asset optimization program whereby our property management group regularly reviews these reserves and surface properties for opportunities to generate earnings and cash flow through the sale or exchange of non-strategic coal reserves and surface lands. These surface lands include acres where we have completed post-mining reclamation. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties and farm income from surface lands under third-party contracts.
Middlemount Mine. We own a 50% equity interest in Middlemount, which owns the Middlemount Mine in Queensland, Australia. The mine predominantly produces semi-hard coking coal and 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, 2020, 2019 2018 and 2017,2018, the mine sold 2.93.2 million, 4.22.9 million and 4.2 million tons of coal, respectively (on a 100% basis).
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Peabody Energy Corporation | 20192020 Form 10-K | 5953 |
Coronavirus (COVID-19) Pandemic
On March 11, 2020, the COVID-19 outbreak was declared a pandemic by the World Health Organization. The pandemic has resulted in governments around the world implementing stringent measures to help control the spread of the virus, including quarantines, “shelter in place” and “stay at home” orders, travel restrictions, business curtailments, school closures and other measures. In addition, governments and central banks in several parts of the world have enacted fiscal and monetary stimulus measures to counteract the impacts of the COVID-19 pandemic.
Coal mining in the U.S. and Australia has been designated as an essential business to support coal-fueled electric power generation and critical steelmaking needs. As part of Peabody’s commitment to the ongoing health and safety of our employees, vendors and communities, we are following advice from government authorities and taking precautions to manage the spread of COVID-19. Peabody operations have implemented rigorous protocols, control and prevention measures, including mandatory temperature and health checks; paid leave for recommended self-isolation periods; enhanced cleaning and sterilization practices; expanded use of personal protective equipment; social distancing; and working remotely when circumstances warrant. While our operations have been designated as essential, each operation will only continue to operate when it is safe and economic to do so.
The global impact on economic activity has severely curtailed demand for numerous commodities. Within the global coal industry, supply and demand disruptions have been widespread. The global economy is showing improvement in industrial production, even as the timing of a recovery varies across countries and sectors. However, in the seaborne metallurgical and thermal markets, demand remains below pre-pandemic levels. In the U.S., the impacts of COVID-19 have accelerated a multi-year decline in coal demand. During the year ended December 31, 2020, coal-fueled generation declined approximately 20% compared to the prior year period and now represents 19% of the overall generation mix. Additionally, we have faced limited disruption to supply chain and distribution channels and adverse effects to our workforce. Coal industry fundamentals, as well as known impacts specific to Peabody, are further addressed in the “Results of Operations” section contained within this Item 7.
While the ultimate impacts of the COVID-19 pandemic on our business are unknown, we expect continued interference with general commercial activity, which may negatively affect both demand and prices for our products. Given the uncertainties with respect to future COVID-19 developments, including the duration, severity and scope, as well as the necessary government actions to limit the spread, we are unable to estimate the full impact of the pandemic on our business, financial condition, results of operations or cash flows at this time.
On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (the CARES Act), a $2 trillion economic relief bill, was enacted in the U.S.. The CARES Act contained numerous income tax provisions, including a provision that provides for the acceleration of refunds of previously generated alternative minimum tax credits. Pursuant to the CARES Act, we received approximately $24 million of accelerated refunds from the Internal Revenue Service and adjusted our current and deferred tax asset balances accordingly. The CARES Act also contained a provision for deferred payment of 2020 employer payroll taxes after the date of enactment to future years. We deferred a portion of our remaining 2020 employer payroll taxes to subsequent years.
North Goonyella Mine
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. No mine personnel were physically harmed by the September 2018 events. On November 13, 2018, the QMI initiated an investigation into the events that occurred at the mine to determine the causeIn 2020, we commenced a review of the event, assess the response to it and make recommendations to reduce the possibility of future incidents and improve response.strategic alternatives for North Goonyella which is currently ongoing.
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 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 yearyears ended December 31, 2019 and 2018, we recorded $58.0provisions for equipment losses of $83.2 million in containment and idling costs$66.4 million, respectively, related to the events at North Goonyella and a provisionfire, representing the best estimate of $66.4 millionlosses to date. No additional provisions 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 were recorded during the year ended December 31, 2019. The combined provision includes $50.7 million for the estimated cost to replace leased equipment, $45.6 million related2020. We have also incurred containment and idling costs subsequent to the cost of Company-owned equipment, $39.7mine’s suspension which amounted to $32.3 million, related to unrecoverable longwall panel development$111.5 million and $13.6$58.0 million of other charges, which representsduring the best estimate of loss based on the assessments made atyears ended December 31, 2019.2020, 2019 and 2018, respectively.
In March 2019, we entered into an insurance claim settlement agreement with our insurers and various re-insurers under a combined property damage and business interruption policy and recorded a $125 million insurance recovery, the maximum amount available under the policy above a $50 million deductible. We have collected the full amount of the recovery.
On April 30, 2019, Peabody (Bowen) Pty Ltd entered into an option exercise and release agreement with Yancoal Technology Development Pty Ltd pursuant to which Peabody (Bowen) Pty Ltd exercised an option to acquire from Yancoal Technology Development Pty Ltd the longwall mining equipment used under license at the North Goonyella Mine for $54.2 million, which was consistent with our provision for equipment losses for the related impaired assets. | | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 54 |
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.generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segments’ operating performance. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to business combinations and joint ventures as management does not view these items as part of our normal operations.
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, 20192020 Compared to Year Ended December 31, 20182019
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, 2020 is set forth in the table below.
The seaborne pricing included in the table below is not necessarily indicative of the pricing we realized during the year ended December 31, 2020 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, 2020 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 fuel sources may also impact our realized pricing.
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| | High | | Low | | Average | | December 31, 2020 |
Premium HCC (1) | | $ | 163.40 | | | $ | 97.60 | | | $ | 124.11 | | | $ | 101.60 | |
Premium PCI coal (1) | | $ | 102.80 | | | $ | 65.75 | | | $ | 78.42 | | | $ | 91.50 | |
Newcastle index thermal coal (1) | | $ | 85.31 | | | $ | 47.99 | | | $ | 60.24 | | | $ | 83.72 | |
API 5 thermal coal (1) | | $ | 59.63 | | | $ | 35.16 | | | $ | 44.74 | | | $ | 55.00 | |
PRB 8,800 Btu/Lb coal (2) | | $ | 12.10 | | | $ | 11.55 | | | $ | 11.83 | | | $ | 11.85 | |
Illinois Basin 11,500 Btu/Lb coal (2) | | $ | 33.80 | | | $ | 27.75 | | | $ | 30.27 | | | $ | 29.75 | |
(1) Prices expressed per tonne.
(2) Prices expressed per ton.
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Peabody Energy Corporation | 2020 Form 10-K | 55 |
Within the global coal industry, supply and demand disruptions have been widespread as the COVID-19 pandemic has forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19. The global coal industry data for the year ended December 31, 2020 presented herein may not be indicative of the ultimate impacts of the COVID-19 pandemic given the various levels of response and unknown duration, and potential for continued weak demand for our products.
With respect to seaborne metallurgical coal, global steel production decreased approximately 1% during the year ended December 31, 2020 compared to the prior year, with significant declines in most regions due to the impacts of COVID-19, offset by another year of strong growth in China. Excluding China, steel production was down approximately 10%, while Chinese steel production increased approximately 5% from 2019. While global steel production remained lower year-over-year, there has been consistent improvement in steel production since July 2020 as COVID-19 related lockdown restrictions eased in key countries. Improved steel demand has enabled steelmakers, including Peabody customers, to restart capacity and increase output, resulting in improvements in seaborne metallurgical coal demand. For example, India seaborne metallurgical coal imports set a new all-time monthly volume record each month from October to December. Elsewhere, the recovery continues steadily with most countries operating at or just below pre-COVID-19 levels. A key risk to demand for Australian metallurgical coal in 2021 is China’s import policies, which have largely prohibited the buying of Australian products since October 2020 and an end date to the limitations is currently unclear.
Within the seaborne thermal coal market, demand has been below pre-pandemic levels in many key countries, and headwinds such as COVID-19, China import restrictions and competition from alternative fuel sources persist. China thermal imports were up 6 million tonnes through the year ended December 31, 2020. India has seen domestic power demand recover, but thermal imports are down by approximately 25 million tonnes through the year ended December 31, 2020 compared to the prior year.
In the United States, overall electricity demand has been negatively impacted year-over-year due to COVID-19 induced economic shutdowns and mild weather during the year ended December 31, 2020. The reduction in thermal coal demand during that period has exceeded the reduction in overall electricity demand as continued coal plant retirements, and growth in natural gas and renewable generation negatively impacted coal’s share of electricity generation. Lower total electricity demand driven by COVID-19 related curtailments has resulted in coal’s share of generation declining to approximately 19% for the year ended December 31, 2020, while natural gas and renewables increased. Through the year ended December 31, 2020 utility consumption of PRB coal fell approximately 20% compared to the prior year period.
Our revenues for the year ended December 31, 2020 decreased compared to the same period in 2019 ($1,742.3 million) primarily due to lower sales volumes which were affected by the COVID-19 pandemic and lower realized prices.
Results from continuing operations, net of income taxes for the year ended December 31, 2020 decreased compared to the same period in the prior year ($1,671.5 million). The decrease was driven by the unfavorable revenue variance described above, higher asset impairment charges recorded in the current period ($1,217.2 million) and a prior year insurance recovery related to the events at our North Goonyella Mine ($125.0 million). These unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements ($1,011.7 million) and lower depreciation, depletion and amortization ($255.0 million).
Adjusted EBITDA for the year ended December 31, 2020 reflected a year-over-year decrease of $624.2 million.
As of December 31, 2020, our available liquidity was approximately $729 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 7 for a further discussion of factors affecting our available liquidity.
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Peabody Energy Corporation | 2020 Form 10-K | 56 |
Tons Sold
The following table presents tons sold by operating segment:
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| | | (Decrease) Increase |
| Year Ended December 31, | | to Volumes |
| 2020 | | 2019 | | Tons | | % |
| (Tons in millions) | | |
Seaborne Thermal Mining | 19.0 | | | 19.5 | | | (0.5) | | | (2.6) | % |
Seaborne Metallurgical Mining | 5.6 | | | 8.1 | | | (2.5) | | | (30.9) | % |
Powder River Basin Mining | 87.2 | | | 108.1 | | | (20.9) | | | (19.3) | % |
Other U.S. Thermal Mining | 18.3 | | | 27.9 | | | (9.6) | | | (34.4) | % |
Total tons sold from mining segments | 130.1 | | | 163.6 | | | (33.5) | | | (20.5) | % |
Corporate and Other | 2.5 | | | 1.9 | | | 0.6 | | | 31.6 | % |
Total tons sold | 132.6 | | | 165.5 | | | (32.9) | | | (19.9) | % |
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
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| Year Ended December 31, | | (Decrease) Increase |
| 2020 | | 2019 | | $ | | % |
| | | | | | | |
Revenues per Ton - Mining Operations (1) | | | | | | | |
Seaborne Thermal | $ | 37.46 | | | $ | 49.69 | | | $ | (12.23) | | | (24.6) | % |
Seaborne Metallurgical | 86.33 | | | 127.62 | | | (41.29) | | | (32.4) | % |
Powder River Basin | 11.37 | | | 11.37 | | | — | | | — | % |
Other U.S. Thermal | 38.73 | | | 46.85 | | | (8.12) | | | (17.3) | % |
Costs per Ton - Mining Operations (1) (2) | | | | | | | |
Seaborne Thermal | $ | 28.87 | | | $ | 32.84 | | | $ | (3.97) | | | (12.1) | % |
Seaborne Metallurgical (3) | 109.44 | | | 110.30 | | | (0.86) | | | (0.8) | % |
Powder River Basin | 9.14 | | | 9.32 | | | (0.18) | | | (1.9) | % |
Other U.S. Thermal | 29.51 | | | 33.91 | | | (4.40) | | | (13.0) | % |
Adjusted EBITDA Margin per Ton - Mining Operations (1) (2) | | | | | | | |
Seaborne Thermal | $ | 8.59 | | | $ | 16.85 | | | $ | (8.26) | | | (49.0) | % |
Seaborne Metallurgical (3) | (23.11) | | | 17.32 | | | (40.43) | | | (233.4) | % |
Powder River Basin | 2.23 | | | 2.05 | | | 0.18 | | | 8.8 | % |
Other U.S. Thermal | 9.22 | | | 12.94 | | | (3.72) | | | (28.7) | % |
(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 take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.
(3)Costs incurred at the North Goonyella Mine from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred at the North Goonyella Mine during the year ended December 31, 2019 remain within the Seaborne Metallurgical Mining segment and resulted in additional Costs per Ton and lower Adjusted EBITDA Margin per Ton of $9.59.
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Peabody Energy Corporation | 2020 Form 10-K | 57 |
Revenues
The following table presents revenues by reporting segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Decrease |
| Year Ended December 31, | | to Revenues |
| 2020 | | 2019 | | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 711.8 | | | $ | 971.7 | | | $ | (259.9) | | | (26.7) | % |
Seaborne Metallurgical Mining | 486.5 | | | 1,033.1 | | | (546.6) | | | (52.9) | % |
Powder River Basin Mining | 991.1 | | | 1,228.7 | | | (237.6) | | | (19.3) | % |
Other U.S. Thermal Mining | 707.3 | | | 1,309.4 | | | (602.1) | | | (46.0) | % |
Corporate and Other | (15.6) | | | 80.5 | | | (96.1) | | | (119.4) | % |
Revenues | $ | 2,881.1 | | | $ | 4,623.4 | | | $ | (1,742.3) | | | (37.7) | % |
Seaborne Thermal Mining. The decrease in our Seaborne Thermal Mining segment revenues for the year ended December 31, 2020 compared to the prior year was driven by unfavorable realized coal pricing ($220.3 million) and unfavorable volume and mix variances ($39.6 million).
Seaborne Metallurgical Mining. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year due to unfavorable volume and mix variances ($340.8 million) resulting from demand-based volume decreases across our mines and unfavorable realized coal pricing ($205.8 million).
Powder River Basin Mining. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year period due to demand-based volume decreases ($244.3 million) and the prior year benefit of a contract settlement with a PRB customer ($19.7 million). These unfavorable variances were partially offset by favorable realized coal pricing ($26.4 million).
Other U.S. Thermal Mining. The decrease in segment revenues for the year ended December 31, 2020 compared to the same period in the prior year was primarily due to volume decreases ($453.6 million) which were driven by the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Wildcat Hills Underground Mine during the second quarter of 2020, the prior year benefit of revenues associated with the final commercial negotiations for the Kayenta Mine ($127.8 million) and unfavorable realized coal pricing ($20.7 million).
Corporate and Other. Segment revenues decreased during the year ended December 31, 2020 compared to the prior year due to lower results on economic hedge activities.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of our reporting segments:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | (Decrease) Increase to |
| Year Ended December 31, | | Adjusted EBITDA |
| 2020 | | 2019 | | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 163.2 | | | $ | 329.4 | | | $ | (166.2) | | | (50.5) | % |
Seaborne Metallurgical Mining | (130.2) | | | 140.2 | | | (270.4) | | | (192.9) | % |
Powder River Basin Mining | 194.8 | | | 221.2 | | | (26.4) | | | (11.9) | % |
Other U.S. Thermal Mining | 168.4 | | | 361.4 | | | (193.0) | | | (53.4) | % |
Corporate and Other | (137.4) | | | (169.2) | | | 31.8 | | | 18.8 | % |
Adjusted EBITDA (1) | $ | 258.8 | | | $ | 883.0 | | | $ | (624.2) | | | (70.7) | % |
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year as a result of lower realized net coal pricing ($202.4 million), unfavorable volume variances ($12.6 million) and the unfavorable impacts of a temporary shutdown at our Wambo Underground Mine ($12.2 million). The decrease was partially offset by favorable mine sequencing impacts and lower costs for materials, services and repairs at our thermal surface mines ($35.6 million) and lower pricing for fuel ($14.0 million).
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 58 |
Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year due to lower realized net coal pricing ($188.0 million), unfavorable volume variances ($138.7 million) and higher costs at our Shoal Creek Mine, including those related to a conveyor upgrade ($51.1 million). These negative variances were partially offset by the inclusion of North Goonyella Mine containment and holding costs within our Corporate and Other segment in the current year ($77.6 million) and lower pricing for fuel ($10.9 million).
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year due to the impact of lower volumes ($43.6 million), the prior year net benefit of a contract settlement with a PRB customer ($24.0 million) and unfavorable mine sequencing impacts ($22.2 million). These negative variances were partially offset by lower costs for materials, services, repairs and labor ($31.1 million), lower pricing for fuel and explosives ($23.5 million) and higher realized net coal pricing ($6.5 million).
Other U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2020 compared to the same period in the prior year primarily due to the impact of lower volumes ($135.4 million) as described above, the prior year net benefit associated with the final commercial negotiations for the Kayenta Mine ($83.3 million), lower realized net coal pricing ($37.8 million) and unfavorable mine sequencing impacts ($12.9 million). These unfavorable variances were partially offset by lower costs for materials, services, repairs and labor ($42.4 million) and lower pricing for fuel and explosives ($16.8 million).
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | (Decrease) Increase |
| Year Ended December 31, | | to Income |
| 2020 | | 2019 | | $ | | % |
| (Dollars in millions) | | |
Middlemount (1) | $ | (29.2) | | | $ | (9.8) | | | $ | (19.4) | | | (198.0) | % |
Resource management activities (2) | 15.3 | | | 8.2 | | | 7.1 | | | 86.6 | % |
Selling and administrative expenses | (99.5) | | | (145.0) | | | 45.5 | | | 31.4 | % |
Other items, net (3)(4) | (24.0) | | | (22.6) | | | (1.4) | | | (6.2) | % |
Corporate and Other Adjusted EBITDA | $ | (137.4) | | | $ | (169.2) | | | $ | 31.8 | | | 18.8 | % |
(1)Middlemount’s results are before the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference. Middlemount’s standalone results included (on a 50% attributable basis) aggregate amounts of depreciation, depletion and amortization, asset retirement obligation expenses, net interest expense and income taxes of $29.9 million and $25.1 million during the years ended December 31, 2020 and 2019, 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, 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 our other commercial activities.
(4)North Goonyella costs incurred from January 1, 2020 forward are included within the Corporate and Other segment. Costs incurred prior to January 1, 2020 remain within the Seaborne Metallurgical Mining segment.
The increase in Corporate and Other Adjusted EBITDA during the year ended December 31, 2020 compared to the same period in the prior year was due to lower selling and administrative expenses driven by lower personnel costs; the favorable impact of changes made to one of our postretirement health care benefit plans during the third quarter of 2020 ($14.9 million); resource management gains recorded in the current period ($14.8 million); and favorable corporate hedging results ($10.7 million). These favorable results were partially offset by current year containment and holding costs for our North Goonyella Mine ($32.3 million) and an unfavorable variance in Middlemount’s results due to the continuing impacts of lower sales pricing and a significant change to the mine plan following a highwall failure in mid-2019.
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 59 |
Loss From Continuing Operations, Net of Income Taxes
The following table presents loss from continuing operations, net of income taxes:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | (Decrease) Increase to Income |
| Year Ended December 31, | |
| 2020 | | 2019 | | $ | | % |
| (Dollars in millions) | | |
Adjusted EBITDA (1) | $ | 258.8 | | | $ | 883.0 | | | $ | (624.2) | | | (70.7) | % |
Depreciation, depletion and amortization | (346.0) | | | (601.0) | | | 255.0 | | | 42.4 | % |
Asset retirement obligation expenses | (45.7) | | | (58.4) | | | 12.7 | | | 21.7 | % |
Restructuring charges | (37.9) | | | (24.3) | | | (13.6) | | | (56.0) | % |
Transaction costs related to joint ventures | (23.1) | | | (21.6) | | | (1.5) | | | (6.9) | % |
Gain on formation of United Wambo Joint Venture | — | | | 48.1 | | | (48.1) | | | (100.0) | % |
Asset impairment | (1,487.4) | | | (270.2) | | | (1,217.2) | | | (450.5) | % |
Provision for North Goonyella equipment loss | — | | | (83.2) | | | 83.2 | | | 100.0 | % |
North Goonyella insurance recovery - equipment | — | | | 91.1 | | | (91.1) | | | (100.0) | % |
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (30.9) | | | 18.8 | | | (49.7) | | | (264.4) | % |
Interest expense | (139.8) | | | (144.2) | | | 4.4 | | | 3.1 | % |
| | | | | | | |
Interest income | 9.4 | | | 27.0 | | | (17.6) | | | (65.2) | % |
Net mark-to-market adjustment on actuarially determined liabilities | 5.1 | | | (67.4) | | | 72.5 | | | 107.6 | % |
| | | | | | | |
Unrealized (losses) gains on economic hedges | (29.6) | | | 42.2 | | | (71.8) | | | (170.1) | % |
Unrealized gains on non-coal trading derivative contracts | 7.1 | | | 1.2 | | | 5.9 | | | 491.7 | % |
Take-or-pay contract-based intangible recognition | 8.2 | | | 16.6 | | | (8.4) | | | (50.6) | % |
Income tax provision | (8.0) | | | (46.0) | | | 38.0 | | | 82.6 | % |
Loss from continuing operations, net of income taxes | $ | (1,859.8) | | | $ | (188.3) | | | $ | (1,671.5) | | | (887.7) | % |
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) |
| Year Ended December 31, | | to Income |
| 2020 | | 2019 | $ | | % |
| (Dollars in millions) | | |
Seaborne Thermal Mining | $ | (88.0) | | | $ | (90.7) | | | $ | 2.7 | | | 3.0 | % |
Seaborne Metallurgical Mining | (85.4) | | | (125.3) | | | 39.9 | | | 31.8 | % |
Powder River Basin Mining | (85.3) | | | (148.5) | | | 63.2 | | | 42.6 | % |
Other U.S. Thermal Mining | (72.1) | | | (228.2) | | | 156.1 | | | 68.4 | % |
Corporate and Other | (15.2) | | | (8.3) | | | (6.9) | | | (83.1) | % |
Total | $ | (346.0) | | | $ | (601.0) | | | $ | 255.0 | | | 42.4 | % |
Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 |
Seaborne Thermal Mining | $ | 1.90 | | | $ | 1.84 | |
Seaborne Metallurgical Mining | 2.30 | | | 3.09 | |
Powder River Basin Mining | 0.50 | | | 0.80 | |
Other U.S. Thermal Mining | 1.04 | | | 1.33 | |
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 60 |
Depreciation, depletion and amortization expense decreased during the year ended December 31, 2020 compared to the same period in the prior year primarily due to the closure of the Kayenta and Cottage Grove Mines during the third quarter of 2019 and the Millennium and Wildcat Hills Underground Mines during the second quarter of 2020 ($122.7 million), the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 ($52.6 million), decreased depletion driven by lower sales volumes ($22.5 million) and lower amortization of contract based intangibles ($21.8 million). The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the year ended December 31, 2020 compared to the same period in the prior year reflects the volume and mix variances which impacted our revenues as described above. The decrease in the weighted-average depletion rate per ton for the Powder River Basin Mining segment during the year ended December 31, 2020 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020.
Asset Retirement Obligation Expenses. Asset retirement obligation expenses decreased during the year ended December 31, 2020 compared to the same period in the prior year as the result of favorable revisions to the estimates for our closed mines.
Restructuring Charges. Restructuring charges increased during the year ended December 31, 2020 compared to the same period in the prior year as the result of workforce reductions made across the organization through the use of involuntary and voluntary reductions, as discussed in Note 1. “Summary of Significant Accounting Policies” to the accompanying consolidated financial statements.
Transaction Costs Related to Joint Ventures. The charges recorded during the current and prior year periods related to the proposed PRB Colorado joint venture with Arch Resources, Inc. as further described in Note 20. “Other Events” to the accompanying consolidated financial statements.
Gain on Formation of United Wambo Joint Venture. 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 20. “Other Events” to the accompanying consolidated financial statements for further information regarding the calculation of the gain, which information is incorporated herein by reference.
Asset Impairment. We recognized $1,487.4 million in aggregate asset impairment charges during the year ended December 31, 2020, primarily related to the fair value of our North Antelope Rochelle Mine in our Powder River Basin Mining segment. During the year ended December 31, 2019, we recognized $270.2 million in aggregate asset impairment charges primarily related to the El Segundo/Lee Ranch and Wildcat Hills Underground Mines in our Other U.S. Thermal Mining segment. Refer to Note 3. “Asset Impairment” to the accompanying consolidated financial statements for further information regarding the nature and composition of those charges, which information is incorporated herein by reference.
Provision for North Goonyella Equipment Loss. A provision for expected equipment losses related to the events at our North Goonyella Mine was recorded during the prior year as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements.
North Goonyella Insurance Recovery - Equipment. During the year ended December 31, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 20. “Other Events” to the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the years ended December 31, 2019 and 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019.
Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates. During the year ended December 31, 2020, we established a valuation allowance on Middlemount’s net deferred tax position of approximately $33 million. During the year ended December 31, 2019, we released a tax reserve of approximately $17 million. Refer to Note 6. “Equity Method Investments” to the accompanying consolidated financial statements for further information regarding these changes, which information is incorporated herein by reference
Interest Income. The decrease in interest income during the year ended December 31, 2020 compared to the prior year was driven by the conclusion of a contract during the fourth quarter of 2019 which contained an embedded financing element and by lower cash balances.
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Peabody Energy Corporation | 2020 Form 10-K | 61 |
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The gain recorded during the year ended December 31, 2020 was driven by gains on pension and postretirement benefit plan assets ($73.7 million), the favorable impacts of a mortality update for all actuarially determined liabilities ($39.5 million) and changes related to claims for the postretirement benefit plans ($21.2 million). These increases were offset by decreases to the discount rates for all actuarially determined liabilities ($116.5 million).
The expense recorded during the year ended December 31, 2019 was driven by decreases to the discount rates for all actuarially determined liabilities ($137.6 million) and the unfavorable impact of changes related to claims and an update to our census data for the postretirement benefits plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.5 million).
Unrealized (Losses) Gains on Economic Hedges. Unrealized (losses) gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 7. “Derivatives and Fair Value Measurements” to the accompanying consolidated financial statements.
Take-or-Pay Contract-Based Intangible Recognition. During the years ended December 31, 2020 and 2019, we ratably recognized contract-based intangible liabilities for port and rail take-or-pay contracts. For additional details, refer to Note 8. “Intangible Contract Assets and Liabilities” to the accompanying consolidated financial statements.
Income Tax Provision. The decrease in the income tax provision during the year ended December 31, 2020 compared to the prior year period was primarily due to year-over-year decreases in taxable income, partially offset by an increase in the provision related to the remeasurement of foreign income tax accounts. Refer to Note 10. “Income Taxes” to the accompanying consolidated financial statements for additional information.
Net Loss Attributable to Common Stockholders
The following table presents net loss attributable to common stockholders:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Decrease to |
| Year Ended December 31, | | to Income |
| 2020 | | 2019 | | $ | | % |
| (Dollars in millions) | | |
Loss from continuing operations, net of income taxes | $ | (1,859.8) | | | $ | (188.3) | | | $ | (1,671.5) | | | (887.7) | % |
(Loss) income from discontinued operations, net of income taxes | (14.0) | | | 3.2 | | | (17.2) | | | (537.5) | % |
Net loss | (1,873.8) | | | (185.1) | | | (1,688.7) | | | (912.3) | % |
| | | | | | | |
Less: Net (loss) income attributable to noncontrolling interests | (3.5) | | | 26.2 | | | (29.7) | | | (113.4) | % |
Net loss attributable to common stockholders | $ | (1,870.3) | | | $ | (211.3) | | | $ | (1,659.0) | | | (785.1) | % |
(Loss) Income from Discontinued Operations, Net of Income Taxes. The decrease in results from discontinued operations, net of income taxes during the year ended December 31, 2020 compared to the prior year period was primarily driven by decreases to the discount rates for black lung liabilities.
Net (Loss) Income Attributable to Noncontrolling Interests. The decrease in net results attributable to noncontrolling interests during the year ended December 31, 2020 compared to the prior year period was primarily due to lower results of our majority-owned mines in which there is an outside non-controlling interest.
Diluted EPS
The following table presents diluted EPS:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Decrease to | | |
| Year Ended December 31, | | EPS | | |
| 2020 | | 2019 | | $ | | % | | |
Diluted EPS attributable to common stockholders: | | | | | | | | | |
Loss from continuing operations | $ | (18.99) | | | $ | (2.07) | | | $ | (16.92) | | | (817.4) | % | | |
(Loss) income from discontinued operations | (0.15) | | | 0.03 | | | (0.18) | | | (600.0) | % | | |
Net loss attributable to common stockholders | $ | (19.14) | | | $ | (2.04) | | | $ | (17.10) | | | (838.2) | % | | |
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 97.7 million and 103.7 million for the years ended December 31, 2020 and 2019, respectively.
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 62 |
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Summary
Spot pricing for Premium HCC, 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.
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | |
|
| | | | | | | | | | | | | | | | |
| | 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. | |
(1)(2) Prices expressed per ton. | 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.
|
| | |
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 tradetraded 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.
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 63 |
Results from continuing operations, net of income taxes for the year ended December 31, 2019 decreased as compared to the same period in the prior year ($834.0 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 unfavorable variances were partially offset by reduced operating costs and expenses owing largely to the sales volume decline as well as production efficiencies and other cost improvements ($534.8 million) and an insurance recovery related to the events at our North Goonyella Mine ($125.0 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, 2019 reflected a year-over-year decrease of $542.2$504.9 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 | )% |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Increase (Decrease) to Tons Sold |
| Year Ended December 31, | |
| 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) | % |
Other U.S. Thermal Mining | 27.9 | | | 33.6 | | | (5.7) | | | (17.0) | % |
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) | % |
|
| | | | | | | |
Peabody Energy Corporation | 20192020 Form 10-K | 6264 |
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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) | % |
Other U.S. Thermal | 46.85 | | | | | | 41.46 | | | 5.39 | | | 13.0 | % |
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) | % |
Other U.S. Thermal | 33.91 | | | | | | 32.81 | | | 1.10 | | | 3.4 | % |
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) | % |
Other U.S. Thermal | 12.94 | | | | | | 8.65 | | | 4.29 | | | 49.6 | % |
|
| | | | | | | | | | | | | | |
| 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)(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 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. | 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
The following table presents revenues by reporting segment:
| | | Successor | | (Decrease) Increase | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | to Revenues | | Year Ended December 31, | | Decrease to Revenues |
| 2019 | | 2018 | | $ | | % | | 2019 | | 2018 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 971.7 |
| | $ | 1,099.2 |
| | $ | (127.5 | ) | | (11.6 | )% | Seaborne Thermal Mining | $ | 971.7 | | | $ | 1,099.2 | | | $ | (127.5) | | | (11.6) | % |
Seaborne Metallurgical Mining | 1,033.1 |
| | 1,553.0 |
| | (519.9 | ) | | (33.5 | )% | Seaborne Metallurgical Mining | 1,033.1 | | | 1,553.0 | | | (519.9) | | | (33.5) | % |
Powder River Basin Mining | 1,228.7 |
| | 1,424.8 |
| | (196.1 | ) | | (13.8 | )% | Powder River Basin Mining | 1,228.7 | | | 1,424.8 | | | (196.1) | | | (13.8) | % |
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 | 1,309.4 | | | 1,393.0 | | | (83.6) | | | (6.0) | % |
Corporate and Other | 80.5 |
| | 111.8 |
| | (31.3 | ) | | (28.0 | )% | Corporate and Other | 80.5 | | | 111.8 | | | (31.3) | | | (28.0) | % |
Revenues | $ | 4,623.4 |
| | $ | 5,581.8 |
| | $ | (958.4 | ) | | (17.2 | )% | Revenues | $ | 4,623.4 | | | $ | 5,581.8 | | | $ | (958.4) | | | (17.2) | % |
Seaborne Thermal Mining. The decrease in our Seaborne Thermal Mining segment revenues for the year ended December 31, 2019 compared to the prior year was primarily driven by unfavorable realized coal pricing ($131.9 million), partially offset by favorable volume and mix variances ($4.4 million).
|
| | |
Peabody Energy Corporation | 2019 Form 10-K | 63 |
Seaborne Metallurgical Mining. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to unfavorable volumes (2.9 million tons, $441.1 million). The unfavorable volume variance resulting from the transition to highwall mining 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 during 2019 (1.7 million tons, $337.6 million) was partially offset by incremental volume provided by our Shoal Creek Mine, acquired in December 2018 (2.0 million tons, $320.9 million). Segment revenues were further impacted by lower realized pricing ($78.8 million).
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 65 |
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).
MidwesternOther U.S. Thermal 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-basedunfavorable volume and mix variances ($124.0200.2 million) and unfavorable realized pricing ($7.311.2 million).
Western U.S. Mining. Segment revenues increased during the year ended December 31, 2019 compared to the same period in the prior year due to These unfavorable variances were partially offset by revenues associated with the final commercial negotiations for the Kayenta Mine ($127.8 million), offset by an unfavorable volume and mix variance ($75.7 million) and unfavorable realized pricing ($4.4 million).
Corporate and Other. Segment revenues decreased during the year ended December 31, 2019 compared to the same period in the prior year primarily due to lower results on economic hedges.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of our reporting segments:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | (Decrease) Increase to 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) | % |
Other U.S. Thermal Mining | 361.4 | | | 290.6 | | | 70.8 | | | 24.4 | % |
Corporate and Other | (169.2) | | | (80.6) | | | (88.6) | | | (109.9) | % |
Adjusted EBITDA (1) | $ | 883.0 | | | $ | 1,387.9 | | | $ | (504.9) | | | (36.4) | % |
|
| | | | | | | | | | | | | | |
| 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 decreased during the year ended December 31, 2019 compared to the same period in the prior year as a result of lower realized net coal pricing ($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 ($30.2 million) and favorable foreign currency impacts ($24.1 million).
Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2019 compared to the same period in the prior year due to unfavorable volume variances described above ($231.9 million). The impact of the negative volumes 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 ($62.6 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 ($50.5 million).
|
| | |
Peabody Energy Corporation | 2019 Form 10-K | 64 |
Powder River Basin Mining. Segment Adjusted EBITDA decreased during the year ended December 31, 2019 compared to the same period in the prior year due to the impact of lower volume ($78.7 million) described above, lower realized net coal pricing ($10.7 million) and unfavorable mine sequencing impacts ($10.0 million), partially 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).
MidwesternOther U.S. Thermal 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 lower costs for materials, services and repairs ($4.2 million) and lower pricing for fuel and explosives ($3.2 million).
Western U.S. Mining. Segment 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) and higher realized net coal pricing ($13.0 million), partially offset by the unfavorable impact of lower volume ($25.7 million).
| | | | | | | | |
Peabody Energy Corporation | 2020 Form 10-K | 66 |
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | (Decrease) Increase 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 | % |
Other items, net (3) | (22.6) | | | (18.3) | | | (4.3) | | | (23.5) | % |
Corporate and Other Adjusted EBITDA | $ | (169.2) | | | (80.6) | | | $ | (88.6) | | | (109.9) | % |
|
| | | | | | | | | | | | | | |
| 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)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. | |
(1)(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, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations and expenses related to our other commercial activities. | 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 Corporate and Other Adjusted EBITDA during the year ended December 31, 2019 compared to the same period in the prior year was primarily driven by an unfavorable variance in Middlemount’s results due to the temporary suspension of operations and a significant change to the mine plan following a highwall failure mid-2019;mid-2019 and resource management gains recorded in the prior year period related to the sale of surplus land assets in Queensland’s Bowen Basin ($20.6 million) and the sale of surplus coal resources associated with the Millennium Mine ($20.5 million); restructuring charges recorded 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.
lower personnel costs.
|
| | | | | | | |
Peabody Energy Corporation | 20192020 Form 10-K | 6567 |
(Loss) Income From Continuing Operations, Net of Income Taxes
The following table presents (loss) income from continuing operations, net of income taxes:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | (Decrease) Increase to Income |
| 2019 | | | | | 2018 | | $ | | % |
| (Dollars in millions) | | |
Adjusted EBITDA (1) | $ | 883.0 | | | | | | $ | 1,387.9 | | | $ | (504.9) | | | (36.4) | % |
Depreciation, depletion and amortization | (601.0) | | | | | | (679.0) | | | 78.0 | | | 11.5 | % |
Asset retirement obligation expenses | (58.4) | | | | | | (53.0) | | | (5.4) | | | (10.2) | % |
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) | % |
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 | (144.2) | | | | | | (151.3) | | | 7.1 | | | 4.7 | % |
| | | | | | | | | | |
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 | % |
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) | % |
|
| | | | | | | | | | | | | | |
| 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)(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. |
Depreciation, Depletion and Amortization.The following table presents a summary of depreciation, depletion and amortization expense by 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 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | (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 | % |
Other U.S. Thermal Mining | (228.2) | | | (268.8) | | | 40.6 | | | 15.1 | % |
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 | 20192020 Form 10-K | 6668 |
Additionally, the following table presents a summary of our weighted-average depletion rate per ton for active mines in each of our mining segments:
| | | Successor | | | | | | | | | | |
| Year Ended December 31, | | Year Ended December 31, |
| 2019 | | 2018 | | 2019 | | 2018 |
Seaborne Thermal Mining | $ | 1.84 |
| | $ | 1.79 |
| Seaborne Thermal Mining | $ | 1.84 | | | $ | 1.79 | |
Seaborne Metallurgical Mining | 3.09 |
| | 0.94 |
| Seaborne Metallurgical Mining | 3.09 | | | 0.94 | |
Powder River Basin Mining | 0.80 |
| | 0.81 |
| Powder River Basin Mining | 0.80 | | | 0.81 | |
Midwestern U.S. Mining | 1.05 |
| | 0.89 |
| |
Western U.S. Mining | 1.72 |
| | 2.29 |
| |
Other U.S. Thermal Mining | | Other U.S. Thermal Mining | 1.33 | | | 1.51 | |
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 Metallurgical Mining segment.
Restructuring Charges. Restructuring charges increased during the year ended December 31, 2019 compared to the same period in the prior year as the result of workforce reductions made during 2019 resulting from actions taken at the North Goonyella Mine, U.S. mine closures and reductions in overhead and support functions.
Transaction Costs Related to Business Combinations and Joint Ventures. The increase in transaction costs was primarily related to the proposed PRB Colorado joint venture with Arch Resources, Inc. as further described in Note 20. “Other Events” to the accompanying consolidated financial statements.
Gain on Formation of United Wambo Joint Venture.Venture. 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 22.20. “Other Events” to the accompanying consolidated financial statements for further information regarding the calculation of the gain, which information is incorporated herein by reference.
Asset Impairment. We recognized $270.2 million in aggregate asset impairment charges during the year ended December 31, 2019. 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 related to the events at our North Goonyella Mine were recorded during the years ended December 31, 2019 and 2018 as discussed in Note 22.20. “Other Events” to the accompanying consolidated financial statements. The current year provision isrecorded during 2019 was 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. During the year ended December 31, 2019, we entered into an insurance claim settlement agreement with our insurance providers related to North Goonyella equipment losses and recorded a $125.0 million insurance recovery, as discussed in Note 22.20. “Other Events” to the accompanying consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the years ended December 31, 2019 and 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the year ended December 31, 2019.
Interest Income. The decrease in interest income during the year ended December 31, 2019 as compared to the prior year was driven by lower cash balances.
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities. The expense recorded during the year ended December 31, 2019 was driven by decreases to the discount rates for all actuarially determined liabilities ($137.6 million) and the unfavorable impact of changes related to claims and an update to our census data for the postretirement benefits plans ($19.7 million). These decreases were partially offset by actuarial gains on pension assets ($94.5 million).
The gain recorded during the year ended December 31, 2018 was driven by increases to the discount rates ($46.2 million), the favorable impact of changes related to claims ($54.2 million), updates to the Medicare law ($20.0 million) and an update to our census data ($7.7 million) for the postretirement benefit plans. The impact on our pension plans was small as actuarial losses on pension assets were largely offset by an increase in discount rates.
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Peabody Energy Corporation | 2020 Form 10-K | 69 |
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.
Unrealized Gains on Economic Hedges. Unrealized gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge future coal sales. For additional information, refer to Note 9.7. “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 RecognitionRecognition.. Included in the fresh start reporting adjustments were contract-based intangible liabilities for port and rail take-or-pay contracts. During the years ended December 31, 2019 and 2018, we ratably recognized these contract-based intangible liabilities.liabilities for port and rail take-or-pay contracts. For additional details, refer to Note 10.8. “Intangible Contract Assets and Liabilities” to the accompanying consolidated financial statements.
Income Tax ProvisionProvision.. The increase in the income tax provision during the year ended December 31, 2019 as compared to the prior year period 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 related to the release of valuation allowance on refundable alternative minimum tax credits .credits. Refer to Note 12.10. “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 | | | | (Decrease) Increase to |
| Year Ended December 31, | | to Income | | Year Ended December 31, | | to Income |
| 2019 | | 2018 | | $ | | % | | 2019 | | 2018 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
(Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | | $ | 645.7 |
| | $ | (834.0 | ) | | (129.2 | )% | (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 | )% | 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 | )% | 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: 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 | % | 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 | )% | Net (loss) income attributable to common stockholders | $ | (211.3) | | | $ | 544.4 | | | $ | (755.7) | | | (138.8) | % |
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 as 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 year ended December 31, 2018 were comprised of the deemed dividends granted for all remaining shares of convertible preferred stock shares that were converted as of January 31, 2018.
Net Income Attributable to Noncontrolling InterestsInterests.. The increase in net income attributable to noncontrolling interests during the year ended December 31, 2019 was primarily driven by the gain on formation of the United Wambo Joint Venture recognized during the fourth quarter of 2019.
Diluted EPS
The following table presents diluted EPS:
| | | Successor | | Decrease to | | | | Decrease to | |
| Year Ended December 31, | | EPS | | Year Ended December 31, | | EPS | |
| 2019 | | 2018 | | $ | | % | | 2019 | | 2018 | | $ | | % | |
Diluted EPS attributable to common stockholders: | | | | | | | | Diluted EPS attributable to common stockholders: | | | | | | | | |
(Loss) income from continuing operations | $ | (2.07 | ) | | $ | 4.28 |
| | $ | (6.35 | ) | | (148.4 | )% | (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 | )% | 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 | )% | Net (loss) income attributable to common stockholders | $ | (2.04) | | | $ | 4.43 | | | $ | (6.47) | | | (146.0) | % | |
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 103.7 million and 121.0 million for the years ended December 31, 2019 and 2018, respectively.
respectively
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Peabody Energy Corporation | 20192020 Form 10-K | 6870 |
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, 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 segment’s operating performance, as displayed in the reconciliations below. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to business combinations and joint ventures as management does not view these items as part of our normal operations.
| | | Successor | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Year Ended December 31, |
| 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| (Dollars in millions) | | (Dollars in millions) |
(Loss) income from continuing operations, net of income taxes | $ | (188.3 | ) | | $ | 645.7 |
| (Loss) income from continuing operations, net of income taxes | $ | (1,859.8) | | | $ | (188.3) | | | $ | 645.7 | |
Depreciation, depletion and amortization | 601.0 |
| | 679.0 |
| Depreciation, depletion and amortization | 346.0 | | | 601.0 | | | 679.0 | |
Asset retirement obligation expenses | 58.4 |
| | 53.0 |
| Asset retirement obligation expenses | 45.7 | | | 58.4 | | | 53.0 | |
Restructuring charges | | Restructuring charges | 37.9 | | | 24.3 | | | 1.2 | |
Transaction costs related to business combinations and joint ventures | | Transaction costs related to business combinations and joint ventures | 23.1 | | | 21.6 | | | 7.4 | |
Gain on formation of United Wambo Joint Venture | (48.1 | ) | | — |
| Gain on formation of United Wambo Joint Venture | — | | | (48.1) | | | — | |
Asset impairment | 270.2 |
| | — |
| Asset impairment | 1,487.4 | | | 270.2 | | | — | |
Provision for North Goonyella equipment loss | 83.2 |
| | 66.4 |
| Provision for North Goonyella equipment loss | — | | | 83.2 | | | 66.4 | |
North Goonyella insurance recovery - equipment | (91.1 | ) | | — |
| 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 | ) | Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | 30.9 | | | (18.8) | | | (18.3) | |
Interest expense | 144.0 |
| | 149.3 |
| Interest expense | 139.8 | | | 144.2 | | | 151.3 | |
Loss on early debt extinguishment | 0.2 |
| | 2.0 |
| |
| Interest income | (27.0 | ) | | (33.6 | ) | Interest income | (9.4) | | | (27.0) | | | (33.6) | |
Net mark-to-market adjustment on actuarially determined liabilities | 67.4 |
| | (125.5 | ) | Net mark-to-market adjustment on actuarially determined liabilities | (5.1) | | | 67.4 | | | (125.5) | |
Reorganization items, net | — |
| | (12.8 | ) | Reorganization items, net | — | | | — | | | (12.8) | |
Unrealized gains on economic hedges | (42.2 | ) | | (18.3 | ) | |
Unrealized losses (gains) on economic hedges | | Unrealized losses (gains) on economic hedges | 29.6 | | | (42.2) | | | (18.3) | |
Unrealized (gains) losses on non-coal trading derivative contracts | (1.2 | ) | | 0.7 |
| Unrealized (gains) losses on non-coal trading derivative contracts | (7.1) | | | (1.2) | | | 0.7 | |
Fresh start take-or-pay contract-based intangible recognition | (16.6 | ) | | (26.7 | ) | |
Take-or-pay contract-based intangible recognition | | Take-or-pay contract-based intangible recognition | (8.2) | | | (16.6) | | | (26.7) | |
Income tax provision | 46.0 |
| | 18.4 |
| Income tax provision | 8.0 | | | 46.0 | | | 18.4 | |
Adjusted EBITDA | $ | 837.1 |
| | $ | 1,379.3 |
| Adjusted EBITDA | $ | 258.8 | | | $ | 883.0 | | | $ | 1,387.9 | |
Revenues per Ton and Adjusted EBITDA Margin per Ton are equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per Ton, and are reconciled to operating costs and expenses as follows:
|
| | | | | | | |
| 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 |
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
| 2020 | | 2019 | | 2018 | |
| (Dollars in millions) |
Operating costs and expenses | $ | 2,524.9 | | | $ | 3,536.6 | | | $ | 4,071.4 | | | |
Unrealized gains (losses) on non-coal trading derivative contracts | 7.1 | | | 1.2 | | | (0.7) | | | |
Take-or-pay contract-based intangible recognition | 8.2 | | | 16.6 | | | 26.7 | | | |
North Goonyella insurance recovery - cost recovery and business interruption | — | | | (33.9) | | | — | | | |
Net periodic benefit (credit) costs, excluding service cost | (1.8) | | | 19.4 | | | 18.1 | | | |
Total Reporting Segment Costs | $ | 2,538.4 | | | $ | 3,539.9 | | | $ | 4,115.5 | | | |
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Peabody Energy Corporation | 20192020 Form 10-K | 6971 |
The following table presents Reporting Segment Costs by reporting segment:
| | | Successor | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Year Ended December 31, |
| 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| (Dollars in millions) | | (Dollars in millions) |
Seaborne Thermal Mining | $ | 642.3 |
| | $ | 647.2 |
| Seaborne Thermal Mining | $ | 548.6 | | | $ | 642.3 | | | $ | 647.2 | |
Seaborne Metallurgical Mining | 892.9 |
| | 1,111.6 |
| Seaborne Metallurgical Mining | 616.7 | | | 892.9 | | | 1,111.6 | |
Powder River Basin Mining | 1,007.5 |
| | 1,140.3 |
| Powder River Basin Mining | 796.3 | | | 1,007.5 | | | 1,140.3 | |
Midwestern U.S. Mining | 539.0 |
| | 655.8 |
| |
Western U.S. Mining | 409.0 |
| | 446.6 |
| Western U.S. Mining | 538.9 | | | 948.0 | | | 1,102.4 | |
Corporate and Other | 73.5 |
| | 115.2 |
| Corporate and Other | 37.9 | | | 49.2 | | | 114.0 | |
Total Reporting Segment Costs | $ | 3,564.2 |
| | $ | 4,116.7 |
| Total Reporting Segment Costs | $ | 2,538.4 | | | $ | 3,539.9 | | | $ | 4,115.5 | |
The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by reportingmining segment:
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. Peabody is continuing to monitor the rapidly evolving COVID-19 pandemic and any impacts related to both our near-term and long-term outlook.
Our primary source of cash is proceeds from the sale of our coal production to customers. We have also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, borrowings under our credit facilities and, from time to time, the issuance of securities. Our 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, and selling and administrative expenses. We have also used cash for dividends, 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.
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 our debt and surety agreements, our 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. Our ability to declare dividends, repurchase shares, or early retire debt, declare dividends, or repurchase shares in the future will depend on our future financial performance, which in turn depends on the successful implementation of our 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 our industry, many of which are beyond our control.
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.