At times, the Company becomes a party to other disputes, including those related to contract miner performance, claims, lawsuits, arbitration proceedings, regulatory investigations and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that such other pending or threatened proceedings are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows. The Company reassesses the probability and estimability of contingent losses as new information becomes available.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
As used in this report, the terms “we,” “us,” “our,” and the “Company”“Peabody” or “the Company” refer to Peabody Energy Corporation andor its consolidated subsidiaries and affiliates, collectively, unlessapplicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to the context indicates otherwise. TheCompany’s continuing operations.
When used in this filing, the term “Peabody”“ton” refers to Peabody Energy Corporation and not its consolidated subsidiaries and affiliates.short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms).
Cautionary Notice Regarding Forward-Looking Statements
This report includes statements of ourPeabody’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or ourPeabody’s future financial performance, including, without limitation, the section captioned “Outlook” in this Item 2. We useperformance. The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements.
Without limiting the foregoing, all statements relating to ourPeabody’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believePeabody believes are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors are difficult to accurately predict and may be beyond ourthe Company’s control. Factors that could affect ourits results or an investment in ourits securities include, but are not limited to:
•the impact of assumptions and analyses developed by us which formed, in large part,Company’s profitability depends upon the basisprices it receives for its coal;
•if a substantial number of the Plan could be incorrect, also persisting or worsening adverse market conditions could affect our ability to successfully implement the Plan;
certain claims that may not ultimately be discharged in the Plan could have a material adverse effect on our financial condition and results of operation;
adjustments to our historical financial information, which as a result of our emergence from our Chapter 11 Cases, will not be indicative of our future financial performance and realization of assets and liquidation of liabilities are subject to uncertainty;
the impairment of certain of the tax assets of our Australian operations as a result of the consummation of the Plan;
our dependence on the prices we receive for ourCompany’s long-term coal which are dependent on factors beyond our control, including, the demand for electricity, the strength of the global economy, the relative price of natural gas and other energy sources used to generate electricity, the demand for electricity and the capacity utilization of electricity generating units (whether coal or non-coal), the demand for steel, which may lead to price fluctuations in the monthly and quarterly repricing of our metallurgical coal contracts, the global supply and production costs of thermal and metallurgical coal, changes in fuel consumption and dispatch patterns of electric power generators, weather patterns and natural disasters, competition within our industry and the availability, quality and price of alternative fuels, including natural gas, fuel oil, nuclear, hydroelectric, wind, biomass and solar power, the proximity, capacity and cost of transportation and terminal facilities, coal and natural gas industry output and capacity, governmental regulations and taxes,agreements, including those establishing air emission standards for coal-fueled power plantswith its largest customers, terminate, or mandatingif the pricing, volumes or subsidizing increased useother elements of electricity from renewable sources, regulatory, administrativethose agreements materially adjust, its revenues 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;
our abilityoperating profits could suffer if the Company is unable to find alternate buyers willing to purchase ourits coal on comparable terms to those in the event that a substantial number of our long-term coal supply agreements terminate, which could cause our revenues and operating profits to suffer;its contracts;
the loss of, or significant reduction in, purchases by our largest customers, which could adversely affect our revenues;
our trading and hedging activities that no longer cover certain risks, and which could expose us to earnings volatility and other risks, including increasing requirements to post collateral;
unfavorable economic and financial market conditions, which could adversely affect our operating results;
our ability to collect payments from our customers could be impaired if their creditworthiness or contractual performance deteriorates;
•risks inherent to mining such as fires and explosions from methane gas or coal dust, accidental mine water discharges, weather, flooding and natural disasters, unexpected maintenance problems, unforeseen delays in implementation of mining technologies that are new to our operations, key equipment failures, variations in coal seam thickness, variations in coal quality, variations in the amount of rock and soil overlying the coal deposit, variations in rock and other natural materials and variations in geologic conditions, could increase the cost of operating our business;the Company’s business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company;
any substantial increase in •the price or the unavailability of transportation of our coal for our customers, in which case our ability to sell coal could suffer;
any decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires, which could decrease our anticipated profitability;
impacts of any unfavorableCompany’s take-or-pay arrangements within could unfavorably affect its profitability;
•the coal industry on our profitability;
inability of trading, brokerage, mining or freight counterparties to fulfill the terms of their contracts with us, which could reduce our profitability;
impairment charges thatCompany may result from any failure tonot recover ourits investments in ourits mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets;
loss of key personnel or failure to attract qualified personnel may impact our ability to operate our company effectively;
our ability•the Company could be negatively affected if it fails to maintain satisfactory labor relations;
our ability•the Company could be adversely affected if it fails to appropriately provide financial assurances for our obligations, including land reclamation, federal and state workers’ compensation, coal leases and other obligations related to our operations;its obligations;
•the extensive regulation of ourCompany’s mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments which could impose significantincrease those costs on us andor limit ourits ability to produce coal;
our•the Company’s operations may impact the environment or cause exposure to hazardous substances, and ourits properties may have environmental contamination, which could result in material liabilities to us;the Company;
our ability•the Company may be unable to obtain, and renew or maintain permits necessary for ourits operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce ourits production, cash flows and profitability;
•concerns about the extensive formsimpacts of taxation of our mining operations, which imposes significant costscoal combustion on us,global climate are increasingly leading to consequences that have affected and future regulationscould continue to affect demand for the Company’s products or its securities and developments which could increase those costs or limit ourits ability to produce, including increased governmental regulation of coal competitively;combustion and unfavorable investment decisions by electricity generators;
accuracy•numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of ourcoal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting the Company’s future financial results, liquidity and growth prospects;
•the Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks;
•if the assumptions underlying ourthe Company’s asset retirement obligations for reclamation and mine closures whichare materially inaccurate, its costs could raise our costsbe significantly greater than anticipated if anticipated;
•the assumptions are materially inaccurate;
ourCompany’s future success depends upon its ability to continue to acquireacquiring and developdeveloping coal reserves that are economically recoverable;
•the Company faces numerous uncertainties in estimating ourits economically recoverable coal reserves whereand inaccuracies in ourits estimates could result in lower than expected revenues, higher than expected costs and decreased profitability;
increased exposure to risks unique to international mining and trading operations, such as country risks, international regulatory requirements and the effects of changes in currency exchange rates;
the success or failure of •joint ventures, partnerships or non-managed operations in which we participate,may not be successful and may not comply with the limited control over compliance with our operational standards that weCompany’s operating standards;
•the Company may exercise over such non-managed operations;
undertake further repositioning plans that we may undertake,would require additional charges;
•the Company’s business, results of operations, financial condition and associated additional charges;prospects could be materially and adversely affected by the coronavirus (COVID-19) pandemic and the related effects on public health;
significant liability, reputational harm, loss of revenue, increased costs or other risks that we may sustain as a result of cyber attacks or other security breaches that disrupt our operations or result in •the dissemination of proprietary or confidential information about us, our customers or other third parties;
accuracy of our assumptions underlying our predictedCompany’s expenditures for postretirement benefit and pension obligations;obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect;
concerns about •the environmental impactsCompany is subject to various general operating risks which may be fully or partially outside of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policiesits control;
•the Company’s financial performance could be adversely affected by government-backed lending institutions and development banks towardits funded indebtedness (Indebtedness);
•despite the financing of new overseas coal-fueled power plants and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities;
risks that could materially and adversely affect our business, including deterioration or other changes in economic conditions, changes in the industry, changes in customer demand for, and acceptance of, our coal, and increasing expenses;
dilution of our Common Stock;
our ability to pay dividends on our stock or to repurchase our stock, and our inability to assure future payments and repurchases;
our substantial indebtedness, which could adversely affect our financial performance. The degree to which we are leveraged could have important consequences, including, but not limited to, makeCompany’s Indebtedness, it more difficult for us to pay interest and satisfy our debt obligations, increase the cost of borrowing under our credit facilities, increase our vulnerability to general economic and industry conditions, require the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development or other general corporate requirements, limit our ability to obtain additional financing to fund future working capital, capital expenditures, business development or other general corporate requirements, limit our flexibility in planning for and reacting to changes in our business and in the coal industry, cause a decline in our credit ratings and place us at a competitive disadvantage to less leveraged competitors;
our and our subsidiaries’ abilitymay still be able to incur substantially more debt despite our and our subsidiaries’ level of indebtedness following the Plan Effective Date, including secured debt, which could further increase the risks associated with our substantial indebtedness;its Indebtedness;
any failure to generate sufficient cash to service all of our post-emergence indebtedness or other obligations;
restrictions imposed by •the terms of our indenturethe indentures governing the Senior Secured NotesCompany’s senior secured notes and the agreements and instruments governing ourits other post-emergence indebtedness, which mayIndebtedness and surety bonding obligations impose restrictions that may limit ourits operating and financial flexibility;
•the number and quantity of viable financing and insurance alternatives available to the Company may be significantly impacted by unfavorable lending and investment policies by financial institutions and insurance companies associated with concerns about environmental impacts of coal combustion, and negative views around its efforts with respect to environmental and social matters and related governance considerations could harm the perception of the Company by a significant number of investors or result in the exclusion of its securities from consideration by those investors;
•the price of Peabody’s securities may be volatile and could fall below the minimum allowed by New York Stock Exchange listing requirements;
52•Peabody’s common stock is subject to dilution and may be subject to further dilution in the future;
•there may be circumstances in which the interests of a significant stockholder could be in conflict with other stakeholders’ interests;
our ability•the payment of dividends on Peabody’s stock or repurchase of its stock is dependent on a number of factors, and future payments and repurchases cannot be assured;
•the Company may not be able to fully utilize ourits deferred tax assets;
provisions in our Certificate•acquisitions and divestitures are a potentially important part of Incorporationthe Company’s long-term strategy, subject to its investment criteria, and By-lawsinvolve a number of risks, any of which could cause the Company not to realize the anticipated benefits;
•Peabody’s certificate of incorporation and by-laws include provisions that may discourage a takeover attempt;
•diversity in interpretation and application of accounting literature in the mining industry that may impact ourthe Company’s reported financial results; and
volatility in the price of our securities;
conflicts of interest among our significant stockholders and other holders of our securities;
reports and projections published by analysts, including projections in those reports that exceed our actual results, which could adversely affect the price and trading volume of our securities;
sales of our common stock that could exert downward pressure on the market price of our common stock, and could encourage short selling that could exert further downward pressure; and
•other risks and factors detailed in this report, including, but not limited to, those discussed in “Legal Proceedings,” set forth in Part II, Item 1 and in “Risk Factors,” set forth in Part II, Item 1A of this Quarterly Report on Form 10-Q.
When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in ourthe Company’s other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect ourits results contained in Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of ourits Annual Report on Form 10-K for the year ended December 31, 2016, Exhibit 99.2 to our Current Report on Form 8-K2020 filed with the SEC on April 11, 2017, and in Amendment No. 1 to our Annual Report on Form 10-K/A for the year ended December 31, 2016 filed with the SEC on July 10, 2017.February 23, 2021. These forward-looking statements speak only as of the date on which such statements were made, and we undertakethe Company undertakes no obligation to update these statements except as required by federal securities laws.
Overview
We arePeabody is a leading coal producer. In 2020, the world’s largest private-sectorCompany produced and sold 128.8 million and 132.6 million tons of coal, company by volume. As of Septemberrespectively, from continuing operations. At June 30, 2017, we2021, the Company owned interests in 2317 active coal mining operations located in the United States (U.S.) and Australia. We have a majority interestIncluded in 22 of those mining operations and athat count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to ourits mining operations, we marketthe Company markets and brokerbrokers coal from other coal producers, both as principal and agent, and tradetrades coal and freight-related contracts.
In 2016, we produced 175.6 million tonsThe Company reports its results of coal and sold 186.8 million tons of coal from continuing operations. During that period, 76% of our total sales (by volume) were to U.S. electricity generators, 21% were to customers outsideoperations primarily through the U.S. and 3% were to the U.S. industrial sector, with approximately 86% of our worldwide sales (by volume) delivered under long-term contracts.
We conduct business through six operatingfollowing reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, Powder River Basin Mining, MidwesternOther U.S. Mining, Western U.S. Mining, Australian Metallurgical Mining, Australian Thermal Mining and TradingCorporate and Brokerage.Other. Refer to Note 20.18. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of ourits Corporate and Other segment.
Filing Under Chapter 11Financing and Surety Transactions
During the fourth quarter of 2020 and the first quarter of 2021, the Company entered into a series of interrelated agreements with its surety bond providers, the revolving lenders under its credit agreement and certain holders of its senior secured notes to extend a significant portion of its near-term debt maturities to December 2024 and to stabilize collateral requirements for its existing surety bond portfolio.
During the second quarter of 2021, and continuing into the third quarter of 2021, the Company completed a series of additional financing transactions intended to improve its capital structure. These transactions included at-the-market common stock issuances for cash proceeds, common stock issuances for the retirement of long-term debt and the retirement of long-term debt primarily through open market purchases.
Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of these financing and surety transactions.
Other
From time to time, the Company initiates restructuring activities in connection with its repositioning efforts to appropriately align its cost structure or optimize its coal production relative to prevailing market conditions. As further described in the “Results of Operations” section contained within this Item 2, the Company incurred restructuring charges of $2.1 million and $16.5 million during the three months ended June 30, 2021 and 2020, respectively, and $4.2 million and $23.0 million during the six months ended June 30, 2021 and 2020, respectively, related to workforce reductions made across the organization through both involuntary and voluntary reductions.
The Shoal Creek Mine remains idled as the Company continues activities to increase productivity, lower costs and improve yields from the operation in the future. The preparation plant upgrade project remains on schedule with completion expected in the middle of the United States Bankruptcy Codethird quarter of 2021. The Shoal Creek labor contract expired in April 2021, and negotiations with the workforce are ongoing.
On April 13, 2016 (the Petition Date), Peabody Energy CorporationThe Metropolitan Mine full workforce returned to the mine in early May. Development work at the mine has been ongoing and longwall production restarted late in the second quarter of 2021, with a majorityramp up to planned production levels in the third quarter of 2021. The underground workforce enterprise agreement expired in January 2021 and after a period of ongoing negotiation, an application was made to terminate the underground labor agreement. That application is pending.
Subsequent to June 30, 2021, the Company executed transactions to sell its wholly owned domestic subsidiaries as well as one international subsidiaryclosed Millennium and Wilkie Creek Mines to reduce its closed mine reclamation liabilities and associated costs. The Company is in Gibraltar (the Filing Subsidiaries, and together with Peabody,process of assessing the Debtors) filed voluntary petitions for reorganization (the Bankruptcy Petitions) under Chapter 11 of Title 11financial impacts of the U.S. Code (the Bankruptcy Code)sales, but anticipates recording cumulative gains of $40 million to $50 million in the United States Bankruptcy Court for the Eastern Districtthird quarter of Missouri (the Bankruptcy Court). The Company’s Australian operations and other international subsidiaries were not included in the filings. 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.). During the Chapter 11 Cases, the Debtors continued to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance2021, with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtors-in-possession, the Debtors were authorized under Chapter 11 to continue to operate as an ongoing business, but could not engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.minimal cash consideration received.
On January 27, 2017, the Debtors filed with the Bankruptcy Court the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (as further modified, the Plan) and the Second Amended Disclosure Statement with Respect to the Second Amended Joint Plan of Reorganization of Debtors and Debtors in Possession (previous versions of the Plan and Disclosure Statement were filed with the Bankruptcy Court on December 22, 2016, January 25, 2017 and January 27, 2017). Subsequently, the Debtors solicited votes on the Plan. On March 15, 2017, the Debtors filed a revised version of the Plan and on March 16, 2017, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 17, 2017, the Bankruptcy Court entered an order, Docket No. 2763 (the Confirmation Order), confirming 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.
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) (OCI). For additional details, refer to Note 1. “Basis of Presentation” and Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the unaudited condensed consolidated financial statements.
In connection with our emergence from the Chapter 11 Cases and the adoption of fresh start reporting, the results of operations for 2017 separately present a Successor period (for the period April 2, 2017 through September 30, 2017) and a Predecessor period (for the period January 1, 2017 through April 1, 2017). The results of operations for 2016 include Predecessor periods for the three and nine months ended September 30, 2016. 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. Although the 2017 Successor period and the 2017 Predecessor period are distinct reporting periods, the effects of emergence and fresh start reporting did not have a material impact on the comparability of our results of operations between the periods, unless otherwise noted below. Accordingly, references to 2017 results of operations for the nine months ended September 30, 2017 combine the two periods to enhance the comparability of such information to the prior year.
Results of Operations
Non-U.S. GAAPNon-GAAP Financial Measures
The following discussion of ourthe Company’s results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance with U.S. generally accepted accounting principles (GAAP)(U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of our segment’sits segments’ operating performance. We believe non-U.S. GAAP
Also included in the following discussion of the Company’s results of operations are references to Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each mining segment. These metrics are used by management to measure each of its mining segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2.
In its discussion of liquidity and capital resources, the Company includes references to Free Cash Flow which is also a non-GAAP measure. Free Cash Flow is used by management as a measure of its financial performance and its ability to generate excess cash flow from its business operations.
The Company believes non-GAAP performance measures are used by investors to measure ourits operating performance and lenders to measure ourits 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 segment’s operating performance, as displayed in the reconciliation below. Adjusted EBITDA is These measures are not intended to serve as an alternativealternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies.
A reconciliation Refer to the “Reconciliation of Adjusted EBITDANon-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to itsthe most comparable measuremeasures under U.S. GAAP is included in Note 20. “Segment Information” of the accompanying unaudited condensed consolidated financial statements.GAAP.
Also included in the following discussion of our results of operations are references to Revenues per Ton, Operating Costs per Ton and Gross Margin per Ton for each reporting segment which are all non-U.S. GAAP measures. Revenues per Ton and Gross Margin per Ton are approximately equal to revenues by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Operating Costs per Ton is equal to Revenues per Ton less Gross Margin per Ton.
Three and NineSix Months Ended SeptemberJune 30,, 20172021 Compared to the Three and NineSix Months Ended SeptemberJune 30,, 20162020
Summary
Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, and Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for Powder River Basin (PRB)PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended SeptemberJune 30, 20172021 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.
In the U.S., theThe seaborne pricing included in the table below is not necessarily indicative of the pricing wethe Company realized during the three months ended SeptemberJune 30, 20172021 due to quality differentials and the majority of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis.
In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended June 30, 2021 since wethe Company generally sellsells 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 producersfuel sources may also impact ourthe Company’s realized pricing.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | High | | Low | | Average | | June 30, 2021 | | | |
Premium HCC (1) | | $ | 194.00 | | | $ | 106.50 | | | $ | 137.84 | | | $ | 194.00 | | | | |
Premium PCI coal (1) | | 144.75 | | | 104.25 | | | 117.11 | | | 144.75 | | | | |
Newcastle index thermal coal (1) | | 132.42 | | | 90.89 | | | 107.79 | | | 132.42 | | | | |
API 5 thermal coal (1) | | 73.11 | | | 54.64 | | | 61.02 | | | 73.11 | | | | |
PRB 8,800 Btu/Lb coal (2) | | 12.50 | | | 11.95 | | | 12.06 | | | 12.50 | | | | |
Illinois Basin 11,500 Btu/Lb coal (2) | | 40.00 | | | 32.00 | | | 33.89 | | | 40.00 | | | | |
(1) Prices expressed per tonne.
(2) Prices expressed per ton.
Within the global coal industry, supply and demand disruptions were widespread as the COVID-19 pandemic forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19. The seaborne pricing included inglobal coal industry data for the table below is alsosix months ended June 30, 2021 presented herein may not necessarilybe indicative of the pricing we realized duringultimate impacts of the three months ended September 30, 2017 due to price discounts based on coal qualitiesCOVID-19 pandemic given the various levels of response and properties.unknown duration.
|
| | | | | | | | | | | | | | | | |
| | High | | Low | | Average | | September 30, 2017 |
Premium HCC | | $ | 211.00 |
| | $ | 151.50 |
| | $ | 188.78 |
| | $ | 187.25 |
|
Premium PCI coal | | $ | 128.55 |
| | $ | 102.35 |
| | $ | 116.75 |
| | $ | 124.80 |
|
Newcastle index thermal coal | | $ | 100.30 |
| | $ | 79.45 |
| | $ | 93.23 |
| | $ | 97.25 |
|
PRB 8,800 Btu/Lb coal | | $ | 11.90 |
| | $ | 11.20 |
| | $ | 11.62 |
| | $ | 11.50 |
|
Illinois Basin 11,500 Btu/Lb coal | | $ | 35.00 |
| | $ | 33.25 |
| | $ | 34.45 |
| | $ | 35.00 |
|
Seaborne thermal andWithin the seaborne metallurgical coal pricing remained wellmarket, record steel production and tight coal availability have driven Australian spot prices to the highest level in two years. China’s unofficial ban on Australian coal remains in place and continues to support delivered China prices above prior-year levels on continued strengththose of all other markets. This is incentivizing producers in Russia, the U.S. and Canada to supply China and overallwith additional volumes, providing opportunities for Australia to supply constraints.
With respectcustomers typically serviced by these countries. COVID-19 remains an ongoing risk to seaborne metallurgical coal global steel productiondemand and has risenrecently impacted import volumes to India and Japan.
Within the seaborne thermal coal market, tight supplies and elevated demand have driven Newcastle thermal coal pricing to levels not seen in over 10 years. China’s domestic thermal coal supply remains hampered by heightened safety inspections and mine suspensions. The relaxation of China’s import controls combined with tight domestic supply has pushed import demand higher. In addition, India’s thermal coal imports improved ahead of the monsoon season. However, supply response to elevated demand has been muted year-to-date, sending thermal coal prices higher.
In the United States, overall electricity demand increased 4% year-over-year, positively impacted by weather and the prior year economic impacts of COVID. Electricity generation from thermal coal has notably improved year-over-year as a result of higher natural gas prices and stronger overall electricity demand. This has positively impacted coal’s share of electricity generation, with a rise to approximately 5% during22% for the ninesix months ended SeptemberJune 30, 2017 as2021, while causing natural gas’s share to decline to approximately 36%. Stronger coal use has contributed to decreasing coal stockpile levels. Since December 2020, coal inventories have fallen by approximately 17 million tons. Through the six months ended June 30, 2021, utility consumption of PRB coal rose approximately 35% compared to the prior year period, led by record Chinese steel production. In addition, Chinese steel exports are down 30% year-to-date through September. Through the nine months ended September 30, 2017 metallurgical coal imports in China rose 9 million tonnes as compared to the prior year period on strong demand and curtailed domestic production.period.
Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand primarily in China and South Korea. Chinese thermal coal imports are up approximately 15 million tonnes year-to-date through September compared to the prior year period on strong electricity generation that exceeded domestic production growth. In addition, South Korean imports have strengthened approximately 15 million tonnes through September, a 23% increase year-over-year, as nuclear generation has been curtailed. While import demand from India has been sluggish on increased domestic coal usage, stockpiles are currently at multi-year lows, which is supportive of additional imports in the fourth quarter.
In the United States, demand was impacted by mild weather and weaker gas pricing in the third quarter of 2017. Even as overall electricity demand weakened year-over-year through September, utility consumption of Powder River Basin coal rose approximately 8% with natural gas consumption decreasing 12% compared to the prior year period (on 30% higher average natural gas prices year-over-year through September).
Net results of $230.0 million for the Successor three months ended September 30, 2017 includedThe Company’s revenues of $1,477.2 million, a tax benefit of $84.1 million and income from equity affiliates of $10.5 million. These were offset by operating costs of $1,044.9 million, depreciation, depletion and amortization of $194.5 million and interest expense of $42.4 million related to the new debt instruments for the Successor Company. Net income attributable to common stockholders of $201.4 million included dividends of $23.5 million related to the Series A Convertible Preferred Stock (Preferred Stock) issued by the Successor Company. Adjusted EBITDA for the three months ended SeptemberJune 30, 2017 was $411.3 million.
Net results2021 increased compared to the same period in 2020 ($96.7 million) primarily due to the impact of $328.7 millionhigher sales volumes and higher seaborne thermal pricing. Revenues for the Successorsix months ended June 30, 2021 decreased compared to the same period April 2 through Septemberin 2020 ($98.2 million) primarily due to lower realized prices and lower sales volumes.
Results from continuing operations, net of income taxes for the three months ended June 30, 2017 included revenues2021 increased compared to the same period in the prior year ($1,522.3 million) primarily due to the asset impairment charges recorded in the prior year period ($1,418.1 million) and the favorable revenue variance described above.
Results from continuing operations, net of $2,735.5 million, a tax benefit of $79.4 million and income from equity affiliates of $26.2 million. These were offset bytaxes for the six months ended June 30, 2021 increased compared to the same period in the prior year ($1,573.9 million) primarily due to the asset impairment charges recorded in the prior year period ($1,418.1 million), lower operating costs of $1,979.7 million,and expenses driven by the sales volume decline as well as production efficiencies and other cost improvements ($141.8 million) and lower depreciation, depletion and amortization of $342.8 million and interest expense of $83.8 million. Net income attributable to common stockholders of $181.2 million for the Successor period April 2 through September 30, 2017 was impacted by Preferred Stock dividends of $138.6 million. Adjusted EBITDA for the Successor period April 2 through September 30, 2017 was $729.1 million.
For the Predecessor period January 1 through April 1, 2017, net loss attributable to common stockholders of $216.5 million included revenues of $1,326.2 million, a tax benefit of $263.8 million and income from equity affiliates of $15.0 million.($48.9 million). These favorable variances were offset by operating costs of $963.7 million, depreciation, depletionthe unfavorable revenue variance described above and amortization of $119.9 million,increased interest expense ($30.4 million) primarily resulting from fees and higher borrowing rates related to new debt arrangements entered into during the first quarter of $32.9 million and reorganization items, net of $627.2 million which included the impact of the Plan provisions and the application of fresh start reporting. Adjusted EBITDA for the Predecessor period January 1 through April 1, 2017 was $341.3 million.2021.
During the three and nine months ended September 30, 2016, the Predecessor Company had net loss attributable to common stockholders of $137.6 million and $536.6 million, respectively. The three months ended September 30, 2016 had revenues of $1,207.1 million which were offset by operating costs of $1,064.8 million, depreciation, depletion and amortization of $117.8 million, selling and administrative expenses of $32.1 million, interest expense of $58.5 million, and reorganization items, net of $29.7 million. The nine months ended September 30, 2016 had revenues of $3,274.5 million, which were offset by operating costs of $2,981.2 million, depreciation, depletion and amortization of $345.5 million, selling and administrative expenses of $114.6 million, interest expense of $243.7 million and reorganization items, net of $125.1 million. The Adjusted EBITDA for the three and ninesix months ended SeptemberJune 30, 2016 was $130.22021 reflected a year-over-year increase of $98.7 million and $238.0$123.0 million, respectively.
As of SeptemberJune 30, 2017, our2021, the Company’s available liquidity was approximately $942.7$564 million. Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of factors affecting ourthe Company’s available liquidity.
Tons Sold
The following tables presenttable presents tons sold by operating segment:
|
| | | | | | | | | | | | |
Three Month Comparison | 2017 | | | 2016 | | | | |
| Successor | | | Predecessor | | Increase (Decrease) |
| Three Months Ended | | to Volumes |
| September 30 | | Tons | | % |
| (Tons in millions) | | |
Powder River Basin Mining | 33.7 |
| | | 33.0 |
| | 0.7 |
| | 2 | % |
Midwestern U.S. Mining | 4.9 |
| | | 4.9 |
| | — |
| | — | % |
Western U.S. Mining | 4.0 |
| | | 4.3 |
| | (0.3 | ) | | (7 | )% |
Australian Metallurgical Mining | 3.5 |
| | | 3.2 |
| | 0.3 |
| | 9 | % |
Australian Thermal Mining | 5.2 |
| | | 5.4 |
| | (0.2 | ) | | (4 | )% |
Total tons sold from mining segments | 51.3 |
| | | 50.8 |
| | 0.5 |
| | 1 | % |
Trading and Brokerage | 0.7 |
| | | 2.0 |
| | (1.3 | ) | | (65 | )% |
Total tons sold | 52.0 |
| | | 52.8 |
| | (0.8 | ) | | (2 | )% |
|
| | | | | | | | | | | | | | | | | | |
Nine Month Comparison | 2017 | | 2016 | | | | |
| Successor | | | Predecessor | | Combined | | Predecessor | | Increase (Decrease) |
| April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended | | to Volumes |
| | | | September 30 | | Tons | | % |
| (Tons in millions) | | |
Powder River Basin Mining | 62.2 |
| | | 31.0 |
| | 93.2 |
| | 80.0 |
| | 13.2 |
| | 17 | % |
Midwestern U.S. Mining | 9.5 |
| | | 4.5 |
| | 14.0 |
| | 13.8 |
| | 0.2 |
| | 1 | % |
Western U.S. Mining | 7.2 |
| | | 3.4 |
| | 10.6 |
| | 10.0 |
| | 0.6 |
| | 6 | % |
Australian Metallurgical Mining | 5.5 |
| | | 2.2 |
| | 7.7 |
| | 10.1 |
| | (2.4 | ) | | (24 | )% |
Australian Thermal Mining | 9.8 |
| | | 4.6 |
| | 14.4 |
| | 15.8 |
| | (1.4 | ) | | (9 | )% |
Total tons sold from mining segments | 94.2 |
| | | 45.7 |
| | 139.9 |
| | 129.7 |
| | 10.2 |
| | 8 | % |
Trading and Brokerage | 1.4 |
| | | 0.4 |
| | 1.8 |
| | 5.4 |
| | (3.6 | ) | | (67 | )% |
Total tons sold | 95.6 |
| | | 46.1 |
| | 141.7 |
| | 135.1 |
| | 6.6 |
| | 5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | (Decrease ) Increase to Volumes | | Six Months Ended June 30, | | (Decrease ) Increase to Volumes |
| 2021 | | 2020 | | Tons | | % | | 2021 | | 2020 | | Tons | | % |
| (Tons in millions) | | | | (Tons in millions) | | |
Seaborne Thermal Mining | 4.1 | | | 4.6 | | | (0.5) | | | (11) | % | | 8.2 | | | 9.2 | | | (1.0) | | | (11) | % |
Seaborne Metallurgical Mining | 1.4 | | | 1.1 | | | 0.3 | | | 27 | % | | 2.4 | | | 3.1 | | | (0.7) | | | (23) | % |
Powder River Basin Mining | 22.5 | | | 17.9 | | | 4.6 | | | 26 | % | | 43.2 | | | 41.4 | | | 1.8 | | | 4 | % |
Other U.S. Thermal Mining | 3.9 | | | 3.8 | | | 0.1 | | | 3 | % | | 7.8 | | | 8.7 | | | (0.9) | | | (10) | % |
Total tons sold from mining segments | 31.9 | | | 27.4 | | | 4.5 | | | 16 | % | | 61.6 | | | 62.4 | | | (0.8) | | | (1) | % |
Corporate and Other | 0.9 | | | 0.9 | | | — | | | — | % | | 1.4 | | | 1.5 | | | (0.1) | | | (7) | % |
Total tons sold | 32.8 | | | 28.3 | | | 4.5 | | | 16 | % | | 63.0 | | | 63.9 | | | (0.9) | | | (1) | % |
Supplemental Financial Data
The following tables presenttable presents supplemental financial data by operating segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Increase (Decrease) | | Six Months Ended June 30, | | Increase (Decrease) |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
Revenues per Ton - Mining Operations (1) |
Seaborne Thermal | $ | 46.92 | | | $ | 35.10 | | | $ | 11.82 | | | 34 | % | | $ | 45.15 | | | $ | 39.58 | | | $ | 5.57 | | | 14 | % |
Seaborne Metallurgical | 85.48 | | | 86.80 | | | (1.32) | | | (2) | % | | 86.31 | | | 92.61 | | | (6.30) | | | (7) | % |
Powder River Basin | 11.06 | | | 11.45 | | | (0.39) | | | (3) | % | | 11.04 | | | 11.40 | | | (0.36) | | | (3) | % |
Other U.S. Thermal | 40.70 | | | 39.81 | | | 0.89 | | | 2 | % | | 39.75 | | | 39.49 | | | 0.26 | | | 1 | % |
Costs per Ton - Mining Operations (1)(2) |
Seaborne Thermal | $ | 29.61 | | | $ | 29.19 | | | $ | 0.42 | | | 1 | % | | $ | 32.97 | | | $ | 30.56 | | | $ | 2.41 | | | 8 | % |
Seaborne Metallurgical | 104.24 | | | 120.72 | | | (16.48) | | | (14) | % | | 106.51 | | | 115.00 | | | (8.49) | | | (7) | % |
Powder River Basin | 9.04 | | | 9.26 | | | (0.22) | | | (2) | % | | 9.29 | | | 9.84 | | | (0.55) | | | (6) | % |
Other U.S. Thermal | 29.57 | | | 31.22 | | | (1.65) | | | (5) | % | | 29.47 | | | 31.31 | | | (1.84) | | | (6) | % |
Adjusted EBITDA Margin per Ton - Mining Operations (1)(2) |
Seaborne Thermal | $ | 17.31 | | | $ | 5.91 | | | $ | 11.40 | | | 193 | % | | $ | 12.18 | | | $ | 9.02 | | | $ | 3.16 | | | 35 | % |
Seaborne Metallurgical | (18.76) | | | (33.92) | | | 15.16 | | | 45 | % | | (20.20) | | | (22.39) | | | 2.19 | | | 10 | % |
Powder River Basin | 2.02 | | | 2.19 | | | (0.17) | | | (8) | % | | 1.75 | | | 1.56 | | | 0.19 | | | 12 | % |
Other U.S. Thermal | 11.13 | | | 8.59 | | | 2.54 | | | 30 | % | | 10.28 | | | 8.18 | | | 2.10 | | | 26 | % |
|
| | | | | | | | | | | | | | | |
Three Month Comparison | 2017 | | | 2016 | | | | |
| Successor | | | Predecessor | | |
| Three Months Ended | | (Decrease) Increase |
| September 30 | | $ | | % |
| | | | | | | | |
Revenues per Ton - Mining Operations | | | | | | | | |
Powder River Basin | $ | 12.48 |
| | | $ | 12.73 |
| | $ | (0.25 | ) | | (2 | )% |
Midwestern U.S. | 42.52 |
| | | 43.02 |
| | (0.50 | ) | | (1 | )% |
Western U.S. | 38.25 |
| | | 38.03 |
| | 0.22 |
| | 1 | % |
Australian Metallurgical | 119.55 |
| | | 71.34 |
| | 48.21 |
| | 68 | % |
Australian Thermal | 51.78 |
| | | 36.53 |
| | 15.25 |
| | 42 | % |
Operating Costs per Ton - Mining Operations (1) | | | | | | | | |
Powder River Basin | $ | 9.13 |
| | | $ | 8.97 |
| | $ | 0.16 |
| | 2 | % |
Midwestern U.S. | 32.39 |
| | | 30.96 |
| | 1.43 |
| | 5 | % |
Western U.S. | 29.77 |
| | | 30.00 |
| | (0.23 | ) | | (1 | )% |
Australian Metallurgical | 78.42 |
| | | 81.93 |
| | (3.51 | ) | | (4 | )% |
Australian Thermal | 32.72 |
| | | 27.50 |
| | 5.22 |
| | 19 | % |
Gross Margin per Ton - Mining Operations (1) | | | | | | | | |
Powder River Basin | $ | 3.35 |
| | | $ | 3.76 |
| | $ | (0.41 | ) | | (11 | )% |
Midwestern U.S. | 10.13 |
| | | 12.06 |
| | (1.93 | ) | | (16 | )% |
Western U.S. | 8.48 |
| | | 8.03 |
| | 0.45 |
| | 6 | % |
Australian Metallurgical | 41.13 |
| | | (10.59 | ) | | 51.72 |
| | 488 | % |
Australian Thermal | 19.06 |
| | | 9.03 |
| | 10.03 |
| | 111 | % |
(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) | Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; coal inventory revaluation; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities. |
(2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities.
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Month Comparison | 2017 | | 2016 | | | | |
| Successor | | | Predecessor | | Combined | | Predecessor | | |
| April 2 through September 30 |
|
| January 1 through April 1 | | Nine Months Ended | | (Decrease) Increase |
|
|
| | September 30 | | $ | | % |
| | | | | | | | | | | | |
Revenues per Ton - Mining Operations | | | | | | | | | | | | |
Powder River Basin | $ | 12.65 |
| | | $ | 12.70 |
| | $ | 12.67 |
| | $ | 13.28 |
| | $ | (0.61 | ) | | (5 | )% |
Midwestern U.S. | 42.57 |
| | | 42.96 |
| | 42.69 |
| | 43.45 |
| | (0.76 | ) | | (2 | )% |
Western U.S. | 38.54 |
| | | 44.68 |
| | 40.47 |
| | 38.72 |
| | 1.75 |
| | 5 | % |
Australian Metallurgical | 128.89 |
| | | 150.22 |
| | 135.03 |
| | 67.39 |
| | 67.64 |
| | 100 | % |
Australian Thermal | 51.65 |
| | | 48.65 |
| | 50.69 |
| | 35.60 |
| | 15.09 |
| | 42 | ��% |
Operating Costs per Ton - Mining Operations (1) | | | | | | | | | | | | |
Powder River Basin | $ | 9.47 |
| | | $ | 9.75 |
| | $ | 9.57 |
| | $ | 9.80 |
| | $ | (0.23 | ) | | (2 | )% |
Midwestern U.S. | 32.42 |
| | | 31.84 |
| | 32.23 |
| | 30.96 |
| | 1.27 |
| | 4 | % |
Western U.S. | 27.65 |
| | | 29.76 |
| | 28.31 |
| | 30.39 |
| | (2.08 | ) | | (7 | )% |
Australian Metallurgical | 89.53 |
| | | 100.16 |
| | 92.57 |
| | 79.34 |
| | 13.23 |
| | 17 | % |
Australian Thermal | 30.79 |
| | | 32.27 |
| | 31.29 |
| | 26.90 |
| | 4.39 |
| | 16 | % |
Gross Margin per Ton - Mining Operations (1) | | | | | | | | | | | | |
Powder River Basin | $ | 3.18 |
| | | $ | 2.95 |
| | $ | 3.10 |
| | $ | 3.48 |
| | $ | (0.38 | ) | | (11 | )% |
Midwestern U.S. | 10.15 |
| | | 11.12 |
| | 10.46 |
| | 12.49 |
| | (2.03 | ) | | (16 | )% |
Western U.S. | 10.89 |
| | | 14.92 |
| | 12.16 |
| | 8.33 |
| | 3.83 |
| | 46 | % |
Australian Metallurgical | 39.36 |
| | | 50.06 |
| | 42.46 |
| | (11.95 | ) | | 54.41 |
| | 455 | % |
Australian Thermal | 20.86 |
| | | 16.38 |
| | 19.40 |
| | 8.70 |
| | 10.70 |
| | 123 | % |
| |
(1) | Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; coal inventory revaluation; take-or-pay contract-based intangible recognition; and certain other costs related to post-mining activities. |
Revenues
The following tables presenttable presents revenues by reporting segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Increase (Decrease) to Revenues | | Six Months Ended June 30, | | Increase (Decrease) to Revenues |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 194.1 | | | $ | 162.0 | | | $ | 32.1 | | | 20 | % | | $ | 370.5 | | | $ | 363.1 | | | $ | 7.4 | | | 2 | % |
Seaborne Metallurgical Mining | 121.0 | | | 91.6 | | | 29.4 | | | 32 | % | | 208.5 | | | 284.8 | | | (76.3) | | | (27) | % |
Powder River Basin Mining | 248.6 | | | 205.8 | | | 42.8 | | | 21 | % | | 477.0 | | | 472.4 | | | 4.6 | | | 1 | % |
Other U.S. Thermal Mining | 162.1 | | | 152.0 | | | 10.1 | | | 7 | % | | 311.4 | | | 344.3 | | | (32.9) | | | (10) | % |
Corporate and Other | (2.4) | | | 15.3 | | | (17.7) | | | (116) | % | | 7.3 | | | 8.3 | | | (1.0) | | | (12) | % |
Revenues | $ | 723.4 | | | $ | 626.7 | | | $ | 96.7 | | | 15 | % | | $ | 1,374.7 | | | $ | 1,472.9 | | | $ | (98.2) | | | (7) | % |
|
| | | | | | | | | | | | | | | |
Three Month Comparison | 2017 | | | 2016 | | | | |
| Successor | | | Predecessor | | Increase (Decrease) |
| Three Months Ended | | to Revenues |
| September 30 | | $ | | % |
| (Dollars in millions) | | |
Powder River Basin Mining | $ | 420.9 |
| | | $ | 419.6 |
| | $ | 1.3 |
| | — | % |
Midwestern U.S. Mining | 207.7 |
| | | 211.0 |
| | (3.3 | ) | | (2 | )% |
Western U.S. Mining | 155.7 |
| | | 162.4 |
| | (6.7 | ) | | (4 | )% |
Australian Metallurgical Mining | 415.9 |
| | | 232.5 |
| | 183.4 |
| | 79 | % |
Australian Thermal Mining | 265.8 |
| | | 197.9 |
| | 67.9 |
| | 34 | % |
Trading and Brokerage | 19.4 |
| | | 2.7 |
| | 16.7 |
| | 619 | % |
Corporate and Other | (8.2 | ) | | | (19.0 | ) | | 10.8 |
| | 57 | % |
Total revenues | $ | 1,477.2 |
| | | $ | 1,207.1 |
| | $ | 270.1 |
| | 22 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Month Comparison | 2017 | | 2016 | | | | |
| Successor | | | Predecessor | | Combined | | Predecessor | | Increase (Decrease) |
| April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended | | to Revenues |
| | | | September 30 | | $ | | % |
| (Dollars in millions) | | |
Powder River Basin Mining | $ | 786.3 |
| | | $ | 394.3 |
| | $ | 1,180.6 |
| | $ | 1,062.2 |
| | $ | 118.4 |
| | 11 | % |
Midwestern U.S. Mining | 402.6 |
| | | 193.2 |
| | 595.8 |
| | 599.6 |
| | (3.8 | ) | | (1 | )% |
Western U.S. Mining | 281.1 |
| | | 149.7 |
| | 430.8 |
| | 387.0 |
| | 43.8 |
| | 11 | % |
Australian Metallurgical Mining | 703.7 |
| | | 328.9 |
| | 1,032.6 |
| | 682.8 |
| | 349.8 |
| | 51 | % |
Australian Thermal Mining | 505.0 |
| | | 224.8 |
| | 729.8 |
| | 561.4 |
| | 168.4 |
| | 30 | % |
Trading and Brokerage | 24.6 |
| | | 15.0 |
| | 39.6 |
| | 16.5 |
| | 23.1 |
| | 140 | % |
Corporate and Other | 32.2 |
| | | 20.3 |
| | 52.5 |
| | (35.0 | ) | | 87.5 |
| | 250 | % |
Total revenues | $ | 2,735.5 |
| | | $ | 1,326.2 |
| | $ | 4,061.7 |
| | $ | 3,274.5 |
| | $ | 787.2 |
| | 24 | % |
Powder River BasinSeaborne Thermal Mining. Segment revenues increased during the three and ninesix months ended SeptemberJune 30, 20172021 compared to the same periods in the prior year due to demand-based volume increases across the entire region as the result of increased natural gas pricing (three months, 0.7 million tons, $13.4 million; nine months, 13.2 million tons, $176.7 million) which drove a switch from natural gas to coal by customers, partially offset by lowerfavorable realized coal pricing (three months, $12.1$46.6 million; ninesix months, $58.3$40.9 million), offset by unfavorable volume and mix variances (three months, $14.5 million; six months, $33.5 million).
Midwestern U.S.Seaborne Metallurgical Mining.Segment revenues increased during the three months ended June 30, 2021 compared to the same period in the prior year due to favorable volume and mix variances ($33.2 million), partially offset by unfavorable realized coal pricing ($3.8 million). Segment revenues decreased during the threesix months ended SeptemberJune 30, 20172021 compared to the same period in the prior year due to unfavorable volume and mix variances ($2.066.7 million) and lowerunfavorable realized coal pricing ($1.39.6 million). The unfavorable volume variances resulted from the Shoal Creek Mine being idled through the first half of 2021, the Metropolitan Mine being idled through the first quarter of 2021 and the closure of the Millennium Mine during the second quarter of 2020. These unfavorable volume variances were partially offset by improved demand at the Coppabella and Moorvale Mines.
Powder River Basin Mining. Segment revenues increased during the three and six months ended June 30, 2021 compared to the same periods in the prior year primarily due to increased demand (three months, $47.3 million; six months, $15.8 million), partially offset by unfavorable realized coal pricing (three months, $4.5 million; six months, $11.2 million).
Other U.S. Thermal Mining. Segment revenues increased during the three months ended June 30, 2021 compared to the same period in the prior year due to favorable realized pricing ($5.9 million) and higher demand ($4.2 million). Segment revenues decreased during the ninesix months ended SeptemberJune 30, 20172021 compared to the same period in the prior year due to primarily due to lower demand ($38.0 million), partially offset by favorable realized pricing ($5.1 million).
Corporate and Other. Segment revenues decreased during the three months ended June 30, 2021 compared to the same period in the prior year primarily due to lower realized coal pricing ($5.0 million) which was slightly offset by favorable volume and mix variances ($1.2 million).results from trading activities.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of the Company’s reporting segments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Increase to Segment Adjusted EBITDA | | Six Months Ended June 30, | | Increase to Segment Adjusted EBITDA |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Seaborne Thermal Mining | $ | 71.4 | | | $ | 27.7 | | | $ | 43.7 | | | 158 | % | | $ | 99.9 | | | $ | 82.8 | | | $ | 17.1 | | | 21 | % |
Seaborne Metallurgical Mining | (26.4) | | | (36.1) | | | 9.7 | | | 27 | % | | (48.8) | | | (68.8) | | | 20.0 | | | 29 | % |
Powder River Basin Mining | 45.5 | | | 39.3 | | | 6.2 | | | 16 | % | | 75.6 | | | 64.7 | | | 10.9 | | | 17 | % |
Other U.S. Thermal Mining | 44.3 | | | 32.9 | | | 11.4 | | | 35 | % | | 80.5 | | | 71.4 | | | 9.1 | | | 13 | % |
Corporate and Other | (12.7) | | | (40.4) | | | 27.7 | | | 69 | % | | (24.0) | | | (89.9) | | | 65.9 | | | 73 | % |
Adjusted EBITDA (1) | $ | 122.1 | | | $ | 23.4 | | | $ | 98.7 | | | 422 | % | | $ | 183.2 | | | $ | 60.2 | | | $ | 123.0 | | | 204 | % |
(1)This is a financial measure not recognized in accordance with U.S. Mining. Segment revenues decreased during the three months ended September 30, 2017 comparedGAAP. Refer to the same period in the prior year due to lower realized coal pricing ($3.4 million)“Reconciliation of Non-GAAP Financial Measures” section below for definitions and unfavorable volume and mix variances ($3.3 million). Segment revenues increased during the nine months ended September 30, 2017 comparedreconciliations to the same period in the prior year predominately due to favorable volume and mix variances from higher margin operations ($35.0 million) and the liquidated damages settlement collected from Arizona Public Service Company and PacifiCorp ($13.0 million).most comparable measures under U.S. GAAP.
Australian Metallurgical Mining. Segment revenues increased during the three months ended September 30, 2017 compared to the same period in the prior year primarily as the result of significantly improved realized coal pricing ($166.4 million) and a favorable volume and mix variance ($17.0 million) driven by improved production at our North Goonyella Mine due to a longwall move in the prior year period. Segment revenues increased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to significantly improved realized coal pricing ($513.3 million) which was partially offset by an unfavorable volume and mix variance ($163.5 million). The volume decrease reflected lower sales volumes due to the cessation of mining activities at our Burton Mine during the fourth quarter of 2016, the impact of Cyclone Debbie and an extended longwall move at the Metropolitan Mine during the first half of 2017.
AustralianSeaborne Thermal Mining.Segment revenuesAdjusted EBITDA increased during the three and ninesix months ended SeptemberJune 30, 20172021 compared to the same periods in the prior year primarily due to significantly improvedas a result of higher realized net coal pricing (three months, $75.8$42.9 million; ninesix months, $214.2$37.6 million), and cost improvements across the operations and product mix (three months, $27.2 million; six months, $33.6 million). The increases were partially offset by anunfavorable foreign currency impacts (three months, $9.7 million; six months, $26.7 million) and unfavorable volume and mix variancevariances (three months, $7.9$9.7 million; ninesix months, $45.8$23.4 million) which was attributable to lower sales volumes from our Wambo Mine as the result of temporary geological issues associated with a longwall move..
Trading and Brokerage. Seaborne Metallurgical Mining. Segment revenuesAdjusted EBITDA increased during the three and ninesix months ended SeptemberJune 30, 20172021 compared to the same periods in the prior year due to deliveries hedged in 2016.favorable volume variances (three months, $18.0 million; six months, $13.4 million) and cost improvements at certain mines (three months, $12.0 million; six months, $42.0 million), offset by unfavorable foreign currency impacts (three months, $15.0 million; six months, $40.3 million).
Corporate and Other. Powder River Basin Mining.Segment revenuesAdjusted EBITDA increased during the three and ninesix months ended SeptemberJune 30, 20172021 compared to the same periods in the prior year due to improved results on economic hedgesfavorable mine sequencing impacts (three months, $11.1$21.8 million; ninesix months, $64.3$27.5 million) and favorable volume variances (three months, $9.9 million). The increases were offset by higher costs for materials, services, repairs and labor (three months, $12.5 million; six months, $5.9 million) and the receiptunfavorable impacts of break fees (ninehigher commodity pricing (three months, $28.0$10.3 million; six months, $10.2 million) related to terminated asset sales which are further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements..
Income (Loss) From Continuing Operations Before Income Taxes
The following table presents income (loss) from continuing operations before income taxes:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | | 2016 | | 2017 | | 2016 |
| Successor | | | Predecessor | | Successor | | | Predecessor | | Combined | | Predecessor |
| Three Months Ended | | April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended |
| September 30 | | | | | September 30 |
| (Dollars in millions) |
Income (loss) from continuing operations before income taxes | $ | 149.6 |
| | | $ | (108.5 | ) | | $ | 255.7 |
| | | $ | (459.3 | ) | | $ | (203.6 | ) | | $ | (596.8 | ) |
Depreciation, depletion and amortization | (194.5 | ) | | | (117.8 | ) | | (342.8 | ) | | | (119.9 | ) | | (462.7 | ) | | (345.5 | ) |
Asset retirement obligation expenses | (11.3 | ) | | | (12.7 | ) | | (22.3 | ) | | | (14.6 | ) | | (36.9 | ) | | (37.3 | ) |
Selling and administrative expenses related to debt restructuring | — |
| | | — |
| | — |
| | | — |
| | — |
| | (21.5 | ) |
Asset impairment | — |
| | | — |
| | — |
| | | (30.5 | ) | | (30.5 | ) | | (17.2 | ) |
Change in deferred tax asset valuation allowance related to equity affiliates | 3.4 |
| | | 0.6 |
| | 7.7 |
| | | 5.2 |
| | 12.9 |
| | 0.6 |
|
Interest expense | (42.4 | ) | | | (58.5 | ) | | (83.8 | ) | | | (32.9 | ) | | (116.7 | ) | | (243.7 | ) |
Loss on early debt extinguishment | (12.9 | ) | | | — |
| | (12.9 | ) | | | — |
| | (12.9 | ) | | — |
|
Interest income | 2.0 |
| | | 1.3 |
| | 3.5 |
| | | 2.7 |
| | 6.2 |
| | 4.0 |
|
Break fees related to terminated asset sales | — |
| | | — |
| | 28.0 |
| | | — |
| | 28.0 |
| | — |
|
Unrealized (losses) gains on non-coal trading derivative contracts | (1.7 | ) | | | — |
| | 1.5 |
| | | — |
| | 1.5 |
| | — |
|
Unrealized (losses) gains on economic hedges | (10.8 | ) | | | (21.9 | ) | | (1.4 | ) | | | 16.6 |
| | 15.2 |
| | (49.1 | ) |
Coal inventory revaluation | — |
| | | — |
| | (67.3 | ) | | | — |
| | (67.3 | ) | | — |
|
Take-or-pay contract-based intangible recognition | 6.5 |
| | | — |
| | 16.4 |
| | | — |
| | 16.4 |
| | — |
|
Reorganization items, net | — |
| | | (29.7 | ) | | — |
| | | (627.2 | ) | | (627.2 | ) | | (125.1 | ) |
Adjusted EBITDA | $ | 411.3 |
| | | $ | 130.2 |
| | $ | 729.1 |
| | | $ | 341.3 |
| | $ | 1,070.4 |
| | $ | 238.0 |
|
Results from continuing operations before income taxes for the Successor three months ended September 30, 2017 resulted in Adjusted EBITDA of $411.3 million which was partially offset by depreciation, depletion and amortization, interest expense. and loss on early debt extinguishment. Results from continuing operations before income taxes for the Successor period April 2 through September 30, 2017 included Adjusted EBITDA of $729.1 million and break fees related to terminated asset sales, which were partially decreased by depreciation, depletion and amortization, fresh start reporting fair value adjustments, interest expense and loss on early debt extinguishment.
Results from continuing operations before income taxes for the Predecessor period January 1 through April 1, 2017 were impacted by reorganization items, net, depreciation, depletion and amortization and interest expense. These results were partially offset by Adjusted EBITDA of $341.3 million.
During the three and nine months ended September 30, 2016, the Predecessor Company’s results from continuing operations before income taxes included Adjusted EBITDA of $130.2 million and $238.0 million, respectively. These results were offset by depreciation, depletion and amortization, interest expense and reorganization items, net.
Adjusted EBITDA
The following tables present Adjusted EBITDA for each of our reporting segments:
|
| | | | | | | | | | | | | | | |
Three Month Comparison | 2017 | | | 2016 | | (Decrease) Increase |
| Successor | | | Predecessor | | to Segment Adjusted |
| Three Months Ended | | EBITDA |
| September 30 | | $ | | % |
| (Dollars in millions) | | |
Powder River Basin Mining | $ | 112.7 |
| | | $ | 123.9 |
| | $ | (11.2 | ) | | (9 | )% |
Midwestern U.S. Mining | 49.5 |
| | | 59.1 |
| | (9.6 | ) | | (16 | )% |
Western U.S. Mining | 34.5 |
| | | 34.3 |
| | 0.2 |
| | 1 | % |
Australian Metallurgical Mining | 143.1 |
| | | (34.5 | ) | | 177.6 |
| | 515 | % |
Australian Thermal Mining | 97.8 |
| | | 48.9 |
| | 48.9 |
| | 100 | % |
Trading and Brokerage | 2.7 |
| | | (9.4 | ) | | 12.1 |
| | 129 | % |
Corporate and Other | (29.0 | ) | | | (92.1 | ) | | 63.1 |
| | 69 | % |
Adjusted EBITDA | $ | 411.3 |
| | | $ | 130.2 |
| | $ | 281.1 |
| | 216 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Month Comparison | 2017 | | 2016 | | Increase (Decrease) |
| Successor | | | Predecessor | | Combined | | Predecessor | | to Segment Adjusted |
| April 2 through September 30 |
|
| January 1 through April 1 | | Nine Months Ended | | EBITDA |
|
|
| | September 30 | | $ | | % |
| (Dollars in millions) | | |
Powder River Basin Mining | $ | 197.5 |
| | | $ | 91.7 |
| | $ | 289.2 |
| | $ | 278.3 |
| | $ | 10.9 |
| | 4 | % |
Midwestern U.S. Mining | 96.0 |
| | | 50.0 |
| | 146.0 |
| | 172.4 |
| | (26.4 | ) | | (15 | )% |
Western U.S. Mining | 79.4 |
| | | 50.0 |
| | 129.4 |
| | 83.2 |
| | 46.2 |
| | 56 | % |
Australian Metallurgical Mining | 215.0 |
| | | 109.6 |
| | 324.6 |
| | (121.0 | ) | | 445.6 |
| | 368 | % |
Australian Thermal Mining | 203.7 |
| | | 75.6 |
| | 279.3 |
| | 137.2 |
| | 142.1 |
| | 104 | % |
Trading and Brokerage | (2.4 | ) | | | 8.8 |
| | 6.4 |
| | (41.3 | ) | | 47.7 |
| | 115 | % |
Corporate and Other | (60.1 | ) | | | (44.4 | ) | | (104.5 | ) | | (270.8 | ) | | 166.3 |
| | 61 | % |
Adjusted EBITDA | $ | 729.1 |
| | | $ | 341.3 |
| | $ | 1,070.4 |
| | $ | 238.0 |
| | $ | 832.4 |
| | 350 | % |
Powder River BasinOther U.S. Thermal Mining. Segment Adjusted EBITDA decreased during the three months ended September 30, 2017 compared to the same period in the prior year due to lower realized coal pricing, net of sales-related costs ($9.7 million), higher materials, services and repairs costs ($3.7 million) and increased pricing for fuel and explosives ($2.9 million), partially offset by reduced lease expenses resulting from early lease buyouts ($6.0 million). Segment Adjusted EBITDA increased during the ninethree and six months ended SeptemberJune 30, 2017 compared to the same period in the prior year due to higher volume driven by increased natural gas pricing ($50.6 million) and reduced expenses for leases ($16.5 million) and labor ($12.3 million), partially offset by lower realized coal pricing, net of sales-related costs ($59.0 million) and increased pricing for fuel and explosives ($11.4 million).
Midwestern U.S. Mining. Segment Adjusted EBITDA decreased during the three and nine months ended September 30, 20172021 compared to the same periods in the prior year primarily due to higher materials, services and repairs costsfavorable volume variances (three months, $4.4$15.0 million; ninesix months, $13.3$16.9 million), increased pricing for fuel and explosivesfavorable mine sequencing impacts (three months, $1.5$10.0 million; ninesix months, $8.2$9.9 million), offset by the unfavorable impacts of higher commodity pricing (three months, $7.9 million; six months, $9.5 million) and lower realized coal pricing, net of sales-relatedhigher costs (three months, $2.7 million; nine months, $7.4 million).
Western U.S. Mining. Segment Adjusted EBITDA increased during the nine months ended September 30, 2017 compared to the same period in the prior year primarily due to improved sales volumes from higher margin operations ($27.3 million), the liquidated damages settlement collected from Arizona Public Service Company and PacifiCorp ($13.0 million) and decreased spending for materials, services, repairs and repairs costs ($12.7labor (three months, $7.3 million; six months, $4.9 million), partially offset by lower realized coal pricing, net of sales-related costs ($5.5 million).
Australian Metallurgical Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily driven by improved realized coal pricing, net of sales-related costs (three months, $155.2 million; nine months, $478.2 million), improved volumes at our North Goonyella Mine (three months, $23.5 million; nine months, $14.9 million) resulting from longwall moves in the prior year, improved production volumes at our Coppabella Mine (three months, $14.8 million; nine months, $19.2 million) and lower contractor and rail costs due to the cessation of mining activities at our Burton Mine during the fourth quarter of 2016 (nine months, $14.8 million). The increases were offset by the impact of Cyclone Debbie, unfavorable foreign exchange rate movements (three months, $9.4 million; nine months, $16.1 million) and cost escalations (three months, $6.0 million; nine months, $17.5 million).
Australian Thermal Mining. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to improved realized coal pricing, net of sales-related costs (three months, $69.9 million; nine months, $197.5 million) and improved production and leasing costs at our Wilpinjong Mine (three months, $6.8 million), offset by lower sales volume caused by geological issues at our Wambo Mine (three months, $26.8 million; nine months, $28.2 million) and higher fuel pricing and other cost escalations (three months, $3.5 million; nine months, $13.3 million).
Trading and Brokerage. Segment Adjusted EBITDA increased during the three and nine months ended September 30, 2017 compared to the same periods in the prior year primarily due to market and business opportunities recognized.
Corporate and Other Adjusted EBITDA. The following tables presenttable presents a summary of the components of Corporate and Other Adjusted EBITDA:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Increase to Adjusted EBITDA | | Six Months Ended June 30, | | Increase (Decrease) to Adjusted EBITDA |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Middlemount (1) | $ | (4.1) | | | $ | (6.4) | | | $ | 2.3 | | | 36 | % | | $ | (6.4) | | | $ | (16.1) | | | $ | 9.7 | | | 60 | % |
Resource management activities (2) | 3.9 | | | 0.8 | | | 3.1 | | | 388 | % | | 4.3 | | | 8.8 | | | (4.5) | | | (51) | % |
Selling and administrative expenses | (21.4) | | | (25.2) | | | 3.8 | | | 15 | % | | (43.1) | | | (50.1) | | | 7.0 | | | 14 | % |
Other items, net (3) | 8.9 | | | (9.6) | | | 18.5 | | | 193 | % | | 21.2 | | | (32.5) | | | 53.7 | | | 165 | % |
Corporate and Other Adjusted EBITDA | $ | (12.7) | | | $ | (40.4) | | | $ | 27.7 | | | 69 | % | | $ | (24.0) | | | $ | (89.9) | | | $ | 65.9 | | | 73 | % |
|
| | | | | | | | | | | | | | | |
Three Month Comparison | 2017 | | | 2016 | | | | |
| Successor | | | Predecessor | | (Decrease) Increase |
| Three Months Ended | | to Income |
| September 30 | | Tons | | $ |
| (Dollars in millions) | | |
Resource management activities (1) | $ | 0.4 |
| | | $ | 1.3 |
| | $ | (0.9 | ) | | (69 | )% |
Selling and administrative expenses (excluding debt restructuring) | (33.4 | ) | | | (32.1 | ) | | (1.3 | ) | | (4 | )% |
Restructuring charges | (1.1 | ) | | | (0.3 | ) | | (0.8 | ) | | (267 | )% |
Corporate hedging | 7.3 |
| | | (47.4 | ) | | 54.7 |
| | 115 | % |
Other items, net (2) | (2.2 | ) | | | (13.6 | ) | | 11.4 |
| | 84 | % |
Corporate and Other Adjusted EBITDA | $ | (29.0 | ) | | | $ | (92.1 | ) | | $ | 63.1 |
| | 69 | % |
| |
(1)
| Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. |
| |
(2)
| Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), 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. |
(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 $11.1 million and $8.8 million during the three months ended June 30, 2021 and 2020, respectively, and $22.8 million and $13.2 million during the six months ended June 30, 2021 and 2020, respectively.
(2)Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues.
62
|
| | | | | | | | | | | | | | | | | | | | | | | |
Nine Month Comparison | 2017 | | 2016 | | | | |
| Successor | | | Predecessor | | Combined | | Predecessor | | (Decrease) Increase |
| April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended | | to Income |
| | | | September 30 | | $ | | % |
| (Dollars in millions) | | |
Resource management activities (1) | $ | 1.6 |
| | | $ | 2.9 |
| | $ | 4.5 |
| | $ | 11.3 |
| | $ | (6.8 | ) | | (60 | )% |
Selling and administrative expenses (excluding debt restructuring) | (67.8 | ) | | | (37.2 | ) | | (105.0 | ) | | (93.1 | ) | | (11.9 | ) | | (13 | )% |
Restructuring charges | (1.1 | ) | | | — |
| | (1.1 | ) | | (15.5 | ) | | 14.4 |
| | 93 | % |
Corporate hedging | 6.9 |
| | | (27.6 | ) | | (20.7 | ) | | (197.8 | ) | | 177.1 |
| | 90 | % |
UMWA voluntary employee beneficiary association settlement | — |
| | | — |
| | — |
| | 68.1 |
| | (68.1 | ) | | (100 | )% |
Gain on sale of interest in Dominion Terminal Associates | — |
| | | 19.7 |
| | 19.7 |
| | — |
| | 19.7 |
| | n.m. |
|
Other items, net (2) | 0.3 |
| | | (2.2 | ) | | (1.9 | ) | | (43.8 | ) | | 41.9 |
| | 96 | % |
Corporate and Other Adjusted EBITDA | $ | (60.1 | ) | | | $ | (44.4 | ) | | $ | (104.5 | ) | | $ | (270.8 | ) | | $ | 166.3 |
| | 61 | % |
| |
(1)
| Includes gains (losses) on certain surplus coal reserve and surface land sales and property management(3)Includes trading and brokerage activities, costs and revenues. |
| |
(2)
| Includes results from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and amortization of basis difference), costs associated with past 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 increases associated with corporate hedging results, which includes foreign currencypost-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 commodity hedging, were dueexpenses related to a decreasethe Company’s other commercial activities.
The increase in realized losses asCorporate and Other Adjusted EBITDA during the three and six months ended June 30, 2021 compared to the same periodperiods in the prior year. The increases associated with “Other items, net” wereyear was driven by lower postretirement healthcare costs (three months, $11.2 million; six months, $22.4 million) primarily attributabledue to improved Middlemountchanges made to one of the Company’s postretirement health care benefit plans announced in 2020; lower containment and holding costs for the Company’s North Goonyella Mine (three months, $8.2 million; six months, $14.4 million); favorable trading results as compared(six months, $11.8 million); a favorable variance in Middlemount’s results due to the prior year driven by higher pricing. Duringcombined impact of improved production and cost improvements; and favorable corporate hedging results (six months, $6.2 million).
Loss From Continuing Operations, Net of Income Taxes
The following table presents loss from continuing operations, net of income taxes:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Increase (Decrease) to Income | | Six Months Ended June 30, | | Increase (Decrease) to Income |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Adjusted EBITDA (1) | $ | 122.1 | | | $ | 23.4 | | | $ | 98.7 | | | 422 | % | | $ | 183.2 | | | $ | 60.2 | | | $ | 123.0 | | | 204 | % |
Depreciation, depletion and amortization | (77.1) | | | (88.3) | | | 11.2 | | | 13 | % | | (145.4) | | | (194.3) | | | 48.9 | | | 25 | % |
Asset retirement obligation expenses | (15.1) | | | (14.1) | | | (1.0) | | | (7) | % | | (31.0) | | | (31.7) | | | 0.7 | | | 2 | % |
Restructuring charges | (2.1) | | | (16.5) | | | 14.4 | | | 87 | % | | (4.2) | | | (23.0) | | | 18.8 | | | 82 | % |
Transaction costs related to joint ventures | — | | | (12.9) | | | 12.9 | | | 100 | % | | — | | | (17.1) | | | 17.1 | | | 100 | % |
Asset impairment | — | | | (1,418.1) | | | 1,418.1 | | | 100 | % | | — | | | (1,418.1) | | | 1,418.1 | | | 100 | % |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | 0.5 | | | 0.4 | | | 0.1 | | | 25 | % | | 2.0 | | | 1.1 | | | 0.9 | | | 82 | % |
Interest expense | (45.4) | | | (34.3) | | | (11.1) | | | (32) | % | | (97.8) | | | (67.4) | | | (30.4) | | | (45) | % |
Net gain on early debt extinguishment | 11.8 | | | — | | | 11.8 | | | n.m. | | 15.3 | | | — | | | 15.3 | | | n.m. |
Interest income | 1.3 | | | 2.4 | | | (1.1) | | | (46) | % | | 2.8 | | | 5.5 | | | (2.7) | | | (49) | % |
| | | | | | | | | | | | | | | |
Unrealized (losses) gains on economic hedges | (23.7) | | | 7.0 | | | (30.7) | | | (439) | % | | (25.6) | | | 4.8 | | | (30.4) | | | (633) | % |
Unrealized (losses) gains on non-coal trading derivative contracts | (1.2) | | | 2.8 | | | (4.0) | | | (143) | % | | (8.8) | | | 2.9 | | | (11.7) | | | (403) | % |
Take-or-pay contract-based intangible recognition | 1.1 | | | 2.7 | | | (1.6) | | | (59) | % | | 2.2 | | | 5.3 | | | (3.1) | | | (58) | % |
Income tax benefit (provision) | 4.8 | | | 0.2 | | | 4.6 | | | 2,300 | % | | 6.6 | | | (2.8) | | | 9.4 | | | 336 | % |
Loss from continuing operations, net of income taxes | $ | (23.0) | | | $ | (1,545.3) | | | $ | 1,522.3 | | | 99 | % | | $ | (100.7) | | | $ | (1,674.6) | | | $ | 1,573.9 | | | 94 | % |
(1)This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the first quarter“Reconciliation of 2017, a $19.7 million gain was recorded in connection withNon-GAAP Financial Measures” section below for definitions and reconciliations to the sale of our interest in Dominion Terminal Associates. Restructuring charges for the nine months ended September 30, 2017 decreased as workforce reductions were made during 2016 at multiple mines in our Power River Basin Mining and Midwesternmost comparable measures under U.S. Mining segments. During 2016, a gain of $68.1 million was recognized for the voluntary employee beneficiary association (VEBA) settlement with the United Mine Workers of America (UMWA) as further described in Note 5. “Discontinued Operations” of the accompanying unaudited condensed consolidated financial statements. The increases in selling and administrative expenses were driven by charges for shared-based compensation expense.GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | (Decrease) Increase to Income | | Six Months Ended June 30, | | (Decrease) Increase to Income |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Seaborne Thermal Mining | $ | (26.9) | | | $ | (20.5) | | | $ | (6.4) | | | (31) | % | | $ | (48.0) | | | $ | (42.7) | | | $ | (5.3) | | | (12) | % |
Seaborne Metallurgical Mining | (17.4) | | | (20.5) | | | 3.1 | | | 15 | % | | (33.9) | | | (45.3) | | | 11.4 | | | 25 | % |
Powder River Basin Mining | (10.3) | | | (28.3) | | | 18.0 | | | 64 | % | | (19.9) | | | (63.5) | | | 43.6 | | | 69 | % |
Other U.S. Thermal Mining | (16.0) | | | (15.6) | | | (0.4) | | | (3) | % | | (33.2) | | | (37.0) | | | 3.8 | | | 10 | % |
Corporate and Other | (6.5) | | | (3.4) | | | (3.1) | | | (91) | % | | (10.4) | | | (5.8) | | | (4.6) | | | (79) | % |
Total | $ | (77.1) | | | $ | (88.3) | | | $ | 11.2 | | | 13 | % | | $ | (145.4) | | | $ | (194.3) | | | $ | 48.9 | | | 25 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| 2017 | | | 2016 | | 2017 | | 2016 |
| Successor | | | Predecessor | | Successor | | | Predecessor | | Predecessor |
| Three Months Ended September 30 | | April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended September 30 |
| (Dollars in millions) |
Powder River Basin Mining | $ | (57.4 | ) | | | $ | (33.5 | ) | | $ | (95.6 | ) | | | $ | (32.0 | ) | | $ | (90.2 | ) |
Midwestern U.S. Mining | (38.1 | ) | | | (12.9 | ) | | (73.4 | ) | | | (13.3 | ) | | (40.1 | ) |
Western U.S. Mining | (32.9 | ) | | | (11.2 | ) | | (57.7 | ) | | | (23.6 | ) | | (34.3 | ) |
Australian Metallurgical Mining | (37.1 | ) | | | (30.9 | ) | | (64.3 | ) | | | (20.6 | ) | | (90.3 | ) |
Australian Thermal Mining | (25.7 | ) | | | (26.2 | ) | | (45.5 | ) | | | (24.0 | ) | | (77.2 | ) |
Trading and Brokerage | (0.1 | ) | | | — |
| | (0.1 | ) | | | — |
| | (0.1 | ) |
Corporate and Other | (3.2 | ) | | | (3.1 | ) | | (6.2 | ) | | | (6.4 | ) | | (13.3 | ) |
Total | $ | (194.5 | ) | | | $ | (117.8 | ) | | $ | (342.8 | ) | | | $ | (119.9 | ) | | $ | (345.5 | ) |
39
Additionally, the following table presents a summary of ourthe Company’s weighted-average depletion rate per ton for active mines in each of ourits mining segments:
|
| | | | | | | | | | | | | | | | | | | | | |
| 2017 | | | 2016 | | 2017 | | 2016 |
| Successor | | | Predecessor | | Successor | | | Predecessor | | Predecessor |
| Three Months Ended September 30 | | April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended September 30 |
Powder River Basin Mining | $ | 0.84 |
| | | $ | 0.69 |
| | $ | 0.83 |
| | | $ | 0.69 |
| | $ | 0.73 |
|
Midwestern U.S. Mining | 0.83 |
| | | 0.54 |
| | 0.78 |
| | | 0.61 |
| | 0.52 |
|
Western U.S. Mining | 1.06 |
| | | 0.91 |
| | 1.06 |
| | | 4.30 |
| | 0.91 |
|
Australian Metallurgical Mining | 0.66 |
| | | 4.29 |
| | 0.68 |
| | | 4.72 |
| | 4.24 |
|
Australian Thermal Mining | 1.73 |
| | | 2.59 |
| | 1.72 |
| | | 2.62 |
| | 2.61 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Seaborne Thermal Mining | $ | 2.47 | | | $ | 2.08 | | | $ | 2.17 | | | $ | 1.99 | |
Seaborne Metallurgical Mining | 1.03 | | | 1.81 | | | 1.02 | | | 2.38 | |
Powder River Basin Mining | 0.24 | | | 0.80 | | | 0.24 | | | 0.79 | |
Other U.S. Thermal Mining | 1.17 | | | 0.96 | | | 1.15 | | | 1.02 | |
Depreciation, depletion and amortization expense decreased during the three and six months ended June 30, 2021 compared to the same periods in the prior year primarily due to the impact of the asset impairment recorded at the North Antelope Rochelle Mine during the second quarter of 2020 (three months, $18.8 million; six months, $44.0 million). The decrease in the weighted-average depletion rate per ton for the SuccessorSeaborne Metallurgical Mining segment during the three and six months ended SeptemberJune 30, 2017 includes2021 compared to the same periods in the prior year reflects the volume and mix variances which impacted the Company’s revenues as described above. The decrease in the weighted-average depletion expense ($50.3 million), amortizationrate per ton for the Powder River Basin Mining segment during the three and six months ended June 30, 2021 compared to the same periods in the prior year reflects the asset impairment recorded during the second quarter of 2020.
Restructuring Charges. Restructuring charges decreased during the three and six months ended June 30, 2021 compared to the same periods in the prior year as the result of workforce reductions made across the organization during the prior year.
Transaction Costs Related to Joint Ventures. The charges recorded during the prior year period related to the proposed PRB Colorado joint venture with Arch Resources, Inc. which was terminated during the third quarter of 2020.
Asset Impairment. During the three and six months ended June 30, 2020, the Company recognized $1,418.1 million in aggregate asset impairment charges related to the fair value of certain U.S. coal supply agreements ($41.5 million), amortization associated with our asset retirement obligation assets ($14.8 million) and depreciation expense ($87.9 million). Depreciation, depletion and amortization expense was higher for the Successor three months ended September 30, 2017 as compared to the Successor period April 2 through June 30, 2017 as the result of volume increasesits North Antelope Rochelle Mine in the period which impacted the portion of our depreciation, depletion and amortization expense that is recorded on a units-of-production method.
Depreciation, depletion and amortization expense for the Predecessor period January 1 through April 1, 2017 reflected additional expense at some of our mines due to changes in the estimated life of mine and at Corporate and Other for leasehold improvements that were vacated in 2017. The additional expense was offset by a decrease at our Metropolitan Mine as the assets were classified as held for sale during the period and depreciation, depletion and amortization was therefore not recorded. The share sale and purchase agreement related to our Metropolitan Mine was terminated in April 2017,its Powder River Basin Mining segment as discussed in Note. 16. “Other Events”Note 8. “Property, Plant, Equipment and Mine Development” to the accompanying unaudited condensed consolidated financial statements. Depreciation, depletion and amortization
Interest Expense. Interest expense forincreased during the three and ninesix months ended SeptemberJune 30, 2016 was impacted by a reduction2021 compared to the same periods in the asset bases at severalprior year as the result of our mines due to impairment charges that had been recognized during 2015.
Selling and Administrative Expenses Related to Debt Restructuring. The general and administrative expenses related to debt restructuring recorded during 2016 related to legal and other expenditures made in connection with debt restructuring initiatives prior toa series of refinancing transactions completed by the Debtors’ filing of the Bankruptcy Petitions.
Asset Impairment. Refer to Note 4. “Asset Impairment” in the accompanying unaudited condensed consolidated financial statements for information surrounding the impairment charges recordedCompany during the Predecessor period January 1 through April 1, 2017 and the nine months ended September 30, 2016.
Interest Expense. Interest expense for the Successor Company primarily related to the 6.000% Senior Secured Notes due March 2022, the 6.375% Senior Secured Notes due March 2025 and the Senior Secured Term Loan due 2022. For additional details on debt, refer tofirst quarter of 2021 as described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” and Note. 13.11. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.
Interest expense for the Predecessor period January 1 through April 1, 2017 andNet Gain on Early Debt Extinguishment. The gain recognized during the three and ninesix months ended SeptemberJune 30, 2016,2021 was impacted by our filing of the Bankruptcy Petitions, which resulted in only accruing adequate protection payments subsequent to the Petition Date to certain secured lenders and other parties in accordance with Section 502(b)(2) of the Bankruptcy Code.
Loss on Early Debt Extinguishment. The loss on early debt extinguishment recorded on the Successor Company,primarily related to debt retirements made through various open market purchases during the amendmentsecond quarter of 2021 and the Senior Secured Term Loan due 2022senior notes exchange completed during the first quarter of 2021 as describedfurther discussed in Note 13.11. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements.
Break Fees Related to Terminated Asset Sales. The Successor Company received break fees of $28.0 million during the period April 2 through September 30, 2017 related to terminated asset sales which are further described in Note 16. “Other Events” of the accompanying unaudited condensed consolidated financial statements.
Unrealized (Losses) Gains on Economic Hedges.Unrealized (losses) gains primarily relate to mark-to-market activity from financial contract trading activities.
Coal Inventory Revaluation. As a part of the fresh start reporting adjustments, the book value ofeconomic hedge activities intended to hedge future coal inventories was increased to reflect the estimated fair value, less costs to sell the inventories. During the Successor period April 2 through September 30, 2017, this adjustment was fully amortized as the inventory was sold.sales. For additional details,information, refer to Note 3. “Emergence from the Chapter 11 Cases7. “Derivatives and Fresh Start Reporting”Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.
Take-or-Pay Contract-Based Intangible Recognition. Included in the fresh start reporting adjustments were contract-based intangible liabilities for port and rail take-or-payUnrealized (Losses) Gains on Non-Coal Trading Derivative Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity from economic hedge activities intended to hedge foreign currency option contracts. During the Successor three months ended September 30, 2017 and the period April 2 through September 30, 2017, the Company has ratably recognized these contract-based intangible liabilities. For additional details,information, refer to Note 3. “Emergence from the Chapter 11 Cases7. “Derivatives and Fresh Start Reporting”Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.
Reorganization Items, Net.Income Tax Benefit (Provision). The reorganization items recorded duringincrease in the Predecessor period January 1 through April 1, 2017 reflected the impact of the Plan provisions and the application of fresh start reporting. Expense recorded duringincome tax benefit for the three and nine months ended SeptemberJune 30, 20162021 compared to the same period in the prior year was primarily due to differences in forecasted taxable income and a decrease in the provision related to expenses recordedthe remeasurement of foreign income tax accounts. The increase in connection with our Chapter 11 Cases.the income tax benefit for the six months ended June 30, 2021 compared to the same period in the prior year was primarily due to differences in forecasted taxable income, partially offset by an increase in the provision related to the remeasurement of foreign income tax accounts. Refer to Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” to the accompanying unaudited condensed consolidated financial statements for further information regarding our reorganization items.
Income (Loss) from Continuing Operations, Net of Income Taxes
The following tables present income (loss) from continuing operations, net of income taxes:
|
| | | | | | | | | | | | | | | | | | | | | |
| 2017 | | | 2016 | | 2017 | | 2016 |
| Successor | | | Predecessor | | Successor | | | Predecessor | | Predecessor |
| Three Months Ended September 30 | | April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended September 30 |
| | | | |
| (Dollars in millions) |
Income (loss) from continuing operations before income taxes | $ | 149.6 |
| | | $ | (108.5 | ) | | $ | 255.7 |
| | | $ | (459.3 | ) | | $ | (596.8 | ) |
Income tax benefit | (84.1 | ) | | | (10.8 | ) | | (79.4 | ) | | | (263.8 | ) | | (108.2 | ) |
Income (loss) from continuing operations, net of income taxes | $ | 233.7 |
| | | $ | (97.7 | ) | | $ | 335.1 |
| | | $ | (195.5 | ) | | $ | (488.6 | ) |
Income Tax Benefit. The income tax benefit recorded for the Successor periods presented primarily related to expected refunds for U.S. net operating loss carrybacks.
The income tax benefit recorded for the Predecessor period January 1 through April 1, 2017, was primarily comprised of benefits related to Predecessor deferred tax liabilities ($177.8 million), accumulated other comprehensive income ($81.5 million) and unrecognized tax benefits ($6.7 million). Refer to Note 12.10. “Income Taxes” into the accompanying unaudited condensed consolidated financial statements for additional information.
Net Income (Loss)Loss Attributable to Common Stockholders
The following tables presenttable presents net loss attributable to common stockholders:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Increase to Income | | Six Months Ended June 30, | | Increase to Income |
| 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
| (Dollars in millions) | | | | (Dollars in millions) | | |
Loss from continuing operations, net of income taxes | $ | (23.0) | | | $ | (1,545.3) | | | $ | 1,522.3 | | | 99 | % | | $ | (100.7) | | | $ | (1,674.6) | | | $ | 1,573.9 | | | 94 | % |
Loss from discontinued operations, net of income taxes | (2.3) | | | (2.3) | | | — | | | — | % | | (4.3) | | | (4.5) | | | 0.2 | | | 4 | % |
Net loss | (25.3) | | | (1,547.6) | | | 1,522.3 | | | 98 | % | | (105.0) | | | (1,679.1) | | | 1,574.1 | | | 94 | % |
Less: Net income (loss) attributable to noncontrolling interests | 3.3 | | | (3.4) | | | 6.7 | | | 197 | % | | 3.7 | | | (5.2) | | | 8.9 | | | 171 | % |
Net loss attributable to common stockholders | $ | (28.6) | | | $ | (1,544.2) | | | $ | 1,515.6 | | | 98 | % | | $ | (108.7) | | | $ | (1,673.9) | | | $ | 1,565.2 | | | 94 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| 2017 | | | 2016 | | 2017 | | 2016 |
| Successor | | | Predecessor | | Successor | | | Predecessor | | Predecessor |
| Three Months Ended September 30 | | April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended September 30 |
| | | | |
| (Dollars in millions) |
Income (loss) from continuing operations, net of income taxes | $ | 233.7 |
| | | $ | (97.7 | ) | | $ | 335.1 |
| | | $ | (195.5 | ) | | $ | (488.6 | ) |
Loss from discontinued operations, net of income taxes | (3.7 | ) | | | (38.1 | ) | | (6.4 | ) | | | (16.2 | ) | | (44.5 | ) |
Net income (loss) | 230.0 |
| | | (135.8 | ) | | 328.7 |
| | | (211.7 | ) | | (533.1 | ) |
Less: Series A Convertible Preferred Stock dividends | 23.5 |
| | | — |
| | 138.6 |
| | | — |
| | — |
|
Less: Net income attributable to noncontrolling interests | 5.1 |
| | | 1.8 |
| | 8.9 |
| | | 4.8 |
| | 3.5 |
|
Net income (loss) attributable to common stockholders | $ | 201.4 |
| | | $ | (137.6 | ) | | $ | 181.2 |
| | | $ | (216.5 | ) | | $ | (536.6 | ) |
Loss from Discontinued Operations, Net of Income Taxes. The loss from discontinued operations for the Predecessor three and nine months ended September 30, 2016 was primarily comprised of a charge of $35.0 million for the UMWA 1974 Pension Plan. For additional details, refer to Note 5. “Discontinued Operations” to the accompanying unaudited condensed consolidated financial statements.
Series A Convertible Preferred Stock Dividends. The Series A Convertible Preferred Stock dividends for the Successor three months ended September 30, 2017 and the period April 2 through September 30, 2017 were comprised of the deemed dividends (three months, $23.5 million; nine months, $135.5 million) granted for the Preferred Stock shares that were converted during the respective periods and the first semi-annual payment of preferred dividends (nine months, $3.1 million) which was pro-rated for the period of April 3 through April 30, 2017.
Diluted EPSEarnings per Share (EPS)
The following table presents diluted EPS:
| | | 2017 | | | 2016 | | 2017 | | 2016 | |
| Successor | | | Predecessor | | Successor | | | Predecessor | | Predecessor | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30 | | April 2 through September 30 | | | January 1 through April 1 | | Nine Months Ended September 30 | | Three Months Ended June 30, | | Increase to EPS | | Six Months Ended June 30, | | Increase to EPS |
| | | | | | 2021 | | 2020 | | $ | | % | | 2021 | | 2020 | | $ | | % |
Diluted EPS attributable to common stockholders: | | | | | | | | | | | | Diluted EPS attributable to common stockholders: | | | | | | | | | | | | | | | |
Income (loss) from continuing operations | $ | 1.49 |
| | | $ | (5.44 | ) | | $ | 1.37 |
| | | $ | (10.93 | ) | | $ | (26.91 | ) | |
Loss from continuing operations | | Loss from continuing operations | $ | (0.26) | | | $ | (15.76) | | | $ | 15.50 | | | 98 | % | | $ | (1.05) | | | $ | (17.12) | | | $ | 16.07 | | | 94 | % |
Loss from discontinued operations | (0.02 | ) | | | (2.09 | ) | | (0.05 | ) | | | (0.88 | ) | | (2.43 | ) | Loss from discontinued operations | (0.02) | | | (0.02) | | | — | | | — | % | | (0.04) | | | (0.04) | | | — | | | — | % |
Net income (loss) | $ | 1.47 |
| | | $ | (7.53 | ) | | $ | 1.32 |
| | | $ | (11.81 | ) | | $ | (29.34 | ) | |
Net loss attributable to common stockholders | | Net loss attributable to common stockholders | $ | (0.28) | | | $ | (15.78) | | | $ | 15.50 | | | 98 | % | | $ | (1.09) | | | $ | (17.16) | | | $ | 16.07 | | | 94 | % |
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS for the Successor Company reflects weighted average diluted common shares outstanding of 103.1101.2 million and 97.9 million for the three months ended SeptemberJune 30, 20172021 and 100.22020, respectively, and 99.8 million and 97.5 million for the period April 2 through September 30, 2017. Diluted EPS for the Predecessor periods January 1 through April 1, 2017 and the three and ninesix months ended SeptemberJune 30, 2016 reflect weighted average diluted common shares outstanding of 18.3 million,2021 and 2020, respectively.
Reconciliation of Non-GAAP Financial Measures
Outlook
As partAdjusted EBITDA is defined as loss from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its normal planningsegment’s operating performance, as displayed in the reconciliations below.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (Dollars in millions) |
Loss from continuing operations, net of income taxes | $ | (23.0) | | | $ | (1,545.3) | | | $ | (100.7) | | | $ | (1,674.6) | |
Depreciation, depletion and amortization | 77.1 | | | 88.3 | | | 145.4 | | | 194.3 | |
Asset retirement obligation expenses | 15.1 | | | 14.1 | | | 31.0 | | | 31.7 | |
Restructuring charges | 2.1 | | | 16.5 | | | 4.2 | | | 23.0 | |
Transaction costs related to joint ventures | — | | | 12.9 | | | — | | | 17.1 | |
Asset impairment | — | | | 1,418.1 | | | — | | | 1,418.1 | |
| | | | | | | |
| | | | | | | |
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates | (0.5) | | | (0.4) | | | (2.0) | | | (1.1) | |
Interest expense | 45.4 | | | 34.3 | | | 97.8 | | | 67.4 | |
Net gain on early debt extinguishment | (11.8) | | | — | | | (15.3) | | | — | |
Interest income | (1.3) | | | (2.4) | | | (2.8) | | | (5.5) | |
| | | | | | | |
Unrealized losses (gains) on economic hedges | 23.7 | | | (7.0) | | | 25.6 | | | (4.8) | |
Unrealized losses (gains) on non-coal trading derivative contracts | 1.2 | | | (2.8) | | | 8.8 | | | (2.9) | |
Take-or-pay contract-based intangible recognition | (1.1) | | | (2.7) | | | (2.2) | | | (5.3) | |
Income tax (benefit) provision | (4.8) | | | (0.2) | | | (6.6) | | | 2.8 | |
Total Adjusted EBITDA | $ | 122.1 | | | $ | 23.4 | | | $ | 183.2 | | | $ | 60.2 | |
Revenues per Ton and forecasting process, Peabody utilizes a bottom-up approachAdjusted EBITDA Margin per Ton are equal to develop macroeconomic assumptions for key variables, including country level gross domestic product, industrial production, fixed asset investmentrevenues by segment and third-party inputs, driving detailed supply and demand projections. This includes demand for coal, electricity generation and steel, while cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates. Our estimates involve risks and uncertaintiesAdjusted 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 subjectreconciled to change based on various factorsoperating costs and expenses as described more fullyfollows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (Dollars in millions) |
Operating costs and expenses | $ | 611.4 | | | $ | 556.3 | | | $ | 1,194.0 | | | $ | 1,335.8 | |
Unrealized (losses) gains on non-coal trading derivative contracts | (1.2) | | | 2.8 | | | (8.8) | | | 2.9 | |
Take-or-pay contract-based intangible recognition | 1.1 | | | 2.7 | | | 2.2 | | | 5.3 | |
| | | | | | | |
Net periodic benefit (credit) costs, excluding service cost | (8.7) | | | 2.7 | | | (17.4) | | | 5.5 | |
Total Reporting Segment Costs | $ | 602.6 | | | $ | 564.5 | | | $ | 1,170.0 | | | $ | 1,349.5 | |
The following table presents Reporting Segment Costs by reporting segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (Dollars in millions) |
Seaborne Thermal Mining | $ | 122.7 | | | $ | 134.3 | | | $ | 270.6 | | | $ | 280.3 | |
Seaborne Metallurgical Mining | 147.4 | | | 127.7 | | | 257.3 | | | 353.6 | |
Powder River Basin Mining | 203.1 | | | 166.5 | | | 401.4 | | | 407.7 | |
Other U.S. Thermal Mining | 117.8 | | | 119.1 | | | 230.9 | | | 272.9 | |
Corporate and Other | 11.6 | | | 16.9 | | | 9.8 | | | 35.0 | |
Total Reporting Segment Costs | $ | 602.6 | | | $ | 564.5 | | | $ | 1,170.0 | | | $ | 1,349.5 | |
The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2021 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Other U.S. Thermal Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 4.1 | | | 1.4 | | | 22.5 | | | 3.9 | |
| | | | | | | |
Revenues | $ | 194.1 | | | $ | 121.0 | | | $ | 248.6 | | | $ | 162.1 | |
Reporting Segment Costs | 122.7 | | | 147.4 | | | 203.1 | | | 117.8 | |
Adjusted EBITDA | $ | 71.4 | | | $ | (26.4) | | | $ | 45.5 | | | $ | 44.3 | |
| | | | | | | |
Revenues per Ton | $ | 46.92 | | | $ | 85.48 | | | $ | 11.06 | | | $ | 40.70 | |
Costs per Ton | 29.61 | | | 104.24 | | | 9.04 | | | 29.57 | |
Adjusted EBITDA Margin per Ton | $ | 17.31 | | | $ | (18.76) | | | $ | 2.02 | | | $ | 11.13 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2020 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Other U.S. Thermal Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 4.6 | | | 1.1 | | | 17.9 | | | 3.8 | |
| | | | | | | |
Revenues | $ | 162.0 | | | $ | 91.6 | | | $ | 205.8 | | | $ | 152.0 | |
Reporting Segment Costs | 134.3 | | | 127.7 | | | 166.5 | | | 119.1 | |
Adjusted EBITDA | $ | 27.7 | | | $ | (36.1) | | | $ | 39.3 | | | $ | 32.9 | |
| | | | | | | |
Revenues per Ton | $ | 35.10 | | | $ | 86.80 | | | $ | 11.45 | | | $ | 39.81 | |
Costs per Ton | 29.19 | | | 120.72 | | | 9.26 | | | 31.22 | |
Adjusted EBITDA Margin per Ton | $ | 5.91 | | | $ | (33.92) | | | $ | 2.19 | | | $ | 8.59 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2021 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Other U.S. Thermal Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 8.2 | | | 2.4 | | | 43.2 | | | 7.8 | |
| | | | | | | |
Revenues | $ | 370.5 | | | $ | 208.5 | | | $ | 477.0 | | | $ | 311.4 | |
Reporting Segment Costs | 270.6 | | | 257.3 | | | 401.4 | | | 230.9 | |
Adjusted EBITDA | $ | 99.9 | | | $ | (48.8) | | | $ | 75.6 | | | $ | 80.5 | |
| | | | | | | |
Revenues per Ton | $ | 45.15 | | | $ | 86.31 | | | $ | 11.04 | | | $ | 39.75 | |
Costs per Ton | 32.97 | | | 106.51 | | | 9.29 | | | 29.47 | |
Adjusted EBITDA Margin per Ton | $ | 12.18 | | | $ | (20.20) | | | $ | 1.75 | | | $ | 10.28 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2020 |
| Seaborne Thermal Mining | | Seaborne Metallurgical Mining | | Powder River Basin Mining | | Other U.S. Thermal Mining |
| (Amounts in millions, except per ton data) |
Tons sold | 9.2 | | | 3.1 | | | 41.4 | | | 8.7 | |
| | | | | | | |
Revenues | $ | 363.1 | | | $ | 284.8 | | | $ | 472.4 | | | $ | 344.3 | |
Reporting Segment Costs | 280.3 | | | 353.6 | | | 407.7 | | | 272.9 | |
Adjusted EBITDA | $ | 82.8 | | | $ | (68.8) | | | $ | 64.7 | | | $ | 71.4 | |
| | | | | | | |
Revenues per Ton | $ | 39.58 | | | $ | 92.61 | | | $ | 11.40 | | | $ | 39.49 | |
Costs per Ton | 30.56 | | | 115.00 | | | 9.84 | | | 31.31 | |
Adjusted EBITDA Margin per Ton | $ | 9.02 | | | $ | (22.39) | | | $ | 1.56 | | | $ | 8.18 | |
Free Cash Flow is defined as net cash used in operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the “Cautionary Notice Regarding Forward-Looking Statements” section contained within this Item 2.table below for a reconciliation of Free Cash Flow to its most comparable measure under U.S. GAAP.
Our near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in our long-term outlook. | | | | | | | | | | | |
| Six Months Ended June 30, |
| 2021 | | 2020 |
| (Dollars in millions) |
Net cash used in operating activities | $ | (22.8) | | | $ | (53.1) | |
Net cash used in investing activities | (82.6) | | | (115.6) | |
| | | |
Free Cash Flow | $ | (105.4) | | | $ | (168.7) | |
Near-Term Outlook
U.S. Thermal Coal. U.S. domestic electricity generation decreased 2% in the nine months ended September 30, 2017 compared to the prior year as a result of mild weather. Even as overall electricity demand weakened year-over-year through September, utility consumption of Powder River Basin coal rose approximately 8% with natural gas consumption decreasing 12% compared to the prior year period (on 30% higher average natural gas prices year-over-year through September).
Cooling degree days in June, July and August 2017 were down approximately 16% from the prior year in coal-heavy regions. As a result, Peabody now expects U.S. coal consumption from electricity generation to be largely flat for full-year 2017 compared to 2016 levels.
Seaborne Thermal Coal. Seaborne thermal coal demand and pricing continue to be supported by robust Asian demand primarily in China and South Korea. Chinese thermal coal imports are up approximately 15 million tonnes year-to-date through September compared to the prior year period on strong electricity generation that exceeded domestic production growth. In addition, South Korean imports have strengthened approximately 15 million tonnes through September, a 23% increase year-over-year, as nuclear generation has been curtailed. While import demand from India has been sluggish on increased domestic coal usage, stockpiles are currently at multi-year lows, which is supportive of additional imports in the fourth quarter. For full-year 2017, Peabody now projects seaborne thermal coal demand to increase approximately 10 to 15 million tonnes from 2016 levels.
Seaborne Metallurgical Coal. With respect to seaborne metallurgical coal, global steel production has risen approximately 5% during the nine months ended September 30, 2017 as compared to the prior year period, led by record Chinese steel production. In addition, Chinese steel exports are down 30% year-to-date through September. Through the nine months ended September 30, 2017 metallurgical coal imports in China rose 9 million tonnes as compared to the prior year period on strong demand and curtailed domestic production on geologic issues. For full-year 2017, Peabody now expects global seaborne metallurgical coal demand to increase approximately 10 million tonnes from 2016 levels.
Seaborne metallurgical coal prompt prices averaged $189 per tonne in the third quarter of 2017, up over $50 per tonne from the prior year, with the index-based settlement price for hard coking coal set at approximately $170 per tonne. In addition, Peabody set third quarter low-vol PCI pricing at $115 per tonne with an additional settlement later in the quarter of $127.50 per tonne. The Company also negotiated a fourth quarter low-vol PCI settlement of $127.50 per tonne.
Long-Term Outlook
There were no significant changes to our Long-term Outlook subsequent to December 31, 2016. Information regarding our Long-term Outlook is outlined in Part II. Item 7. “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, 2016, as amended on July 10, 2017 and August 14, 2017.
Regulatory Update
Other than as described in the following section, there were no significant changes to ourthe Company’s regulatory matters subsequent to December 31, 2016.2020. Information regarding ourthe Company’s regulatory matters is outlined in Part I, Item 1. “Business” in ourits Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
2020.
Regulatory Matters - U.S.
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.
Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect ourthe Company’s U.S. coal mining operations both directly and indirectly and may result in additional capital and operating costs.indirectly.
Direct impacts on coal mining and processing operations may occur through the
The CAA permitting requirements and/or emission control requirements relating to national ambient air quality standards (NAAQS) for particulate matter (PM), sulfur dioxide and ozone. It is possible that modifications to current NAAQS could impact our mining operations in a manner that includes, but is not limited to, designating new nonattainment areas or expanding existing nonattainment areas, requiring changes in vehicle/engine emission standards for vehicles/equipment utilized in our operations, or through the adoption of additional local control measures that could be required pursuant to state implementation plans required to address revised NAAQS.
In recent yearsrequires the United States Environmental Protection Agency (EPA) has adopted more stringent NAAQS for PM, nitrogen oxide and sulfur dioxide. In 2015,to review national ambient air quality standards (NAAQS) every five years to determine whether revision to current standards are appropriate. As part of this recurring review process, the EPA in 2020 proposed to retain the ozone standards promulgated in 2015, including current secondary standards, and subsequently promulgated final standards to this effect. Fifteen states and other petitioners have filed a more stringent NAAQSpetition for ozone (80 Fed. Reg. 65,292, (Oct. 25, 2015)review of the rule in the D.C. Circuit. The litigation is currently in abeyance following a motion filed by the EPA to allow for review of the standards.
The EPA also proposed in 2020 to retain the particulate matter (PM) standards last revised in 2012. On December 18, 2020, the EPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5). and the primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. This NAAQS for ozone rule washas also been challenged in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit). Althoughby several states and environmental organizations. The case is currently in abeyance following a motion filed by the rule is not stayed during litigation, on April 7, 2017, the Department of Justice, on behalfEPA to allow for review of the EPA, filed a motion asking that the case be removed from the argument calendar so that the EPA can consider whether it “should reconsider the rule or some part of it.” On April 14, 2017, the D.C. Circuit granted the EPA’s motion and stayed the litigation indefinitely with regular 90 day status reports due to the court. standards.
More stringent PM or ozone standards would require that states develop and submit new state implementation plans to be developed and filed with the EPA. Depending on the need for further emission reductions necessary to meet the standard, such plans could includeEPA and may trigger additional control technology requirements for mining equipment or result in additional challenges to permitting requirements affecting operations and expansion efforts.
In 2009, This could also be the EPA also adopted revised rulescase with respect to add more stringent PM emissions limitsother NAAQS for coal preparationnitrogen dioxide (NO2) and processing plants constructed or modified after April 28, 2008. The PM NAAQS was thereafter revised and made more stringent (78 Fed. Reg. 3,085 (Jan. 15, 2013). The D.C. Circuit subsequently upheld the revised PM NAAQS (National Association of Manufacturers v. EPA, Nos. 13-1069, 13-1071 (May 9, 2014)). 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.
The CAA also indirectly, but significantly affects the U.S. coal industry by extensively regulating the air emissions of sulfur dioxide nitrogen oxides, mercury and other substances emitted by coal-fueled electricity generating plants. Other CAA programs may require further emission reductions and may affect our operations, directly or indirectly. These include, but are not limited(SO2), although there is no significant pending EPA rulemaking with respect to the Acid Rain Program, interstate transport rules such as the Cross-State Air Pollution 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.those pollutants.
NSPS forEPA Regulation of Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electricity Utility Generating Units (EGUs).EGUs. On April 13, 2012, pursuant to section 111(b) of the CAA,October 23, 2015, the EPA published for commenta final rule in the Federal Register a proposed NSPS for emissions of carbon dioxide for new, modified and reconstructed fossil fuel-fired EGUs (proposed NSPS). On January 8, 2014, however, the EPA withdrew the proposed NSPS and issued a new proposed NSPS for the same sources. The EPA then issued a Notice of Data Availability (NODA) and technical support document in support of the proposed NSPS on February 26, 2014. After extensions, the public comment period for the re-proposed NSPS and the NODA closed on May 9, 2014. The EPA released the final rule on August 3, 2015, and the rule was published in the Federal Register on October 23, 2015 (80 Fed. Reg. 64,510).
The final NSPS 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 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).
Sixteen separate petitions for review of the NSPS were filed in the D.C. Circuit, and the challengers included 25 states, utilities, mining companies (including Peabody Energy), labor unions, trade organizations and other groups. The cases were consolidated under a petition filed by North Dakota. States and other organizations intervened in the litigation on behalf of the Respondent EPA.
Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions that were submitted to the EPA regarding the final rule. This denial was published as a final action in the May 6, 2016 Federal Register (81 Fed. Reg. 27,442). States and other organizations also intervened on behalf of the EPA. Upon petitioners’ request, the D.C. Circuit suspended the briefing schedule in this case and consolidated the challenges to the EPA’s denial of petitions for reconsideration with the previously filed North Dakota case. On August 30, 2016, the Court entered a briefing schedule under which final briefs were due February 6, 2017. Oral arguments were scheduled for April 17, 2017.
On March 28, 2017, however, the EPA moved to hold the case in abeyance pending its reconsideration of the NSPS pursuant to the terms of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth (EI Order), which was signed the same day. On April 28, 2017, the court granted the motion to hold the case in abeyance for 60 days and required the EPA to file regular status reports. The court also ordered that parties file supplemental briefs on whether the cases should be remanded to the EPA, rather than held in abeyance. The EPA filed a supplemental brief on May 15, 2017 and, at the present time, the case remains in abeyance and the NSPS remains in effect.
Rules for Regulating Carbon Dioxide Emissions From Existing Fossil Fuel-Fired EGUs. On June 2, 2014, the EPA issued and later formally published for comment proposed rules for regulating carbon dioxidegreenhouse gas emissions from existing fossil fuel-fired EGUs under sectionSection 111(d) of the CAA. On August 3, 2015,CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015)). The rule (known as the EPA announced the final rule, and published the rule in the Federal Register on October 23, 2015. In the final rule, the EPAClean 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. These guidelines requireThe CPP required that the states individually or collectively create systems that would reduce carbon emissions from steam electric and natural gas-fired power plantsany EGU located within their borders. Individual states were required to submit their proposed implementation plans to the EPA by September 6, 2016, unless an extension was approved, in which case the states would have until September 6, 2018 to submit those plans. The rule also set emission performance rates for affected sources to be phased in over the period from 2022 through 2030. State plans were required to impose these rates on existing plants or implement other measures (such as emission caps, increased use of renewable energy or energy efficiency measures) that would yield the same result. Overall, the rule was intended to reduce carbon dioxide emissions from steam electric and natural gas-fired power plantsborders by 28% in 2025 and 32% in 2030 compared(compared with a 2005 baseline emission rates. baseline).
Legal challengesThe EPA subsequently proposed to repeal the CPP and in August 2018 issued a proposed rule began when it was still being proposed. One action by an industry petitioner, joined by intervenors, including us, and another by a coalition of states led by West Virginia, asserted thatto replace the EPA does not haveCPP, with the authority to issue the regulations of existing power plants under section 111(d) of the CAA. The D.C. Circuit heard oral arguments on the challenges in April 2015. The petitions to enjoin the proposed rulemaking were denied as premature inAffordable Clean Energy (ACE) Rule. In June 2015. However, the D.C. Circuit acknowledged that a legal challenge could be filed after2019, the EPA issued a combined package that finalized the CPP repeal rule as well as the replacement rule, ACE. The ACE rule sets emissions guidelines for greenhouse gas emissions from existing EGUs based on a determination that efficiency heat rate improvements constitute the Best System of Emission Reduction (BSER). The EPA’s final rule. In September 2015rule also revises certain regulations to give the states greater flexibility on the content and timing of their state plans.
Based on the EPA’s final rules repealing and replacing the CPP, petitioners in the D.C. Circuit refusedmatter seeking review of CPP, including the Company, filed a motion to staydismiss, which the rule, holding that it could not review the rule until it was publishedcourt granted in the Federal Register which occurred on October 23, 2015. September 2019.
Following Federal Register publication of the rule on October 23, 2015, 39 separateNumerous petitions for review by approximately 157 entitieschallenging the ACE Rule were filed in the D.C. Circuit challenging the final rule. The petitions reflected challenges by 27 states and governmental entities, as well as challenges by utilities, industry groups, trade associations, coal companies, and other entities. The lawsuits were consolidated with the case filed by West Virginia and Texas (which other States joined). On October 29, 2015, we filedsubsequently consolidated. In January 2021, a motion to intervene in the case filed by West Virginia and Texas, in support3-judge panel of the petitioning States. The motion was granted on January 11, 2016. Numerous states and cities were also allowed to intervene in support of the EPA.
On January 21, 2016, the D.C. Circuit deniedvacated and remanded the state and industry petitioners’ motionsACE Rule to stay the implementationEPA, including its repeal of the rule but provided for an expedited schedule for review ofCPP and amendments to the rule, with oral arguments beginning on June 2, 2016. The stateimplementing regulations that extended the compliance timeline.
Cross State Air Pollution Rule (CSAPR) and industry petitioners appealed and filed application for stay with the United States Supreme Court on January 27, 2016. On February 9, 2016, the Supreme Court overruled the lower court and granted the motion to stay implementation of the rule until its legal challenges are resolved. The stay provides that, if a writ of certiorari is sought and the Supreme Court denies the petition, the stay will terminate automatically. The stay also provides that, if the Supreme Court grants the petition for a writ of certiorari, the stay will terminate when the Supreme Court enters its judgment. Briefing on the merits of the petitions for review in the D.C. Circuit has concluded. Oral arguments in the case were heard en banc by ten active D.C. Circuit judges on September 27, 2016 but, to date, the D.C. Court has not yet issued an opinion.
On March 28, 2017,CSAPR Update Rule. In 2011, the EPA movedfinalized the CSAPR, which requires the District of Columbia and 27 states from Texas eastward (not including the New England states or Delaware) to hold the casereduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in abeyance pending its reconsideration of the final rule pursuant to the EI Order. On April 4, 2017other states. In 2016, the EPA published a Federal Register notice announcing that the Agency would review the rule and that it may actfinal CSAPR Update Rule which imposed additional reductions in nitrogen oxide emissions beginning in 2017 in 22 states subject to suspend, revise or rescind the rule (82 Fed. Reg. 16,329).CSAPR.
The EI Order included a directive to reexamine the CAA 111(d) rule and, if appropriate, suspend, revise or rescind the rule. On April 28, 2017, the court granted the motion to hold the case in abeyance for 60 days and requiredIn October 2020, the EPA proposed a rule to file regular status reports;address a previous D.C. Circuit remand of the court also ordered that parties file supplemental briefs on whether the cases should be remanded toCSAPR Update Rule. On March 15, 2021, the EPA rather than held in abeyance. The EPA filed a supplemental brief on May 15, 2017 and, at the present time, the case remains in abeyance. On October 10, 2017, the EPA reported to the D.C. Circuit Court of Appeals that it signed a Federal Register notice proposing to repeal the Clean Power Plan. The EPA further reported that it is considering the scope of any potential replacement rule.
Federal Coal Leasing Moratorium. The EI Order also 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.
Stream Protection Rule. On December 20, 2016, the Office of Surface Mining Reclamation and Enforcement (OSM) issued its final Stream Protection Rule (SPR). The final rule would have impacted both surface and underground mining operations and would have increased testing and monitoring requirements related to the quality or quantity of surface water and groundwater or the biological condition of streams. The SPR would have also required the collection of increased pre-mining data about the site of the proposed mining operation and adjacent areas to establish a baseline for evaluation of the impacts of mining and the effectiveness of reclamation associated with returning streams to pre-mining conditions. Both chambers of Congress passed legislation to repeal and invalidate the rulemaking, pursuant to the Congressional Review Act. The House passed H.J. Res. 38 on February 1, 2017 and the Senate passed the bill the next day. On February 16, 2017, President Trump signed H.J. Res. 38, resulting in the repeal of the SPR and preventing the OSM from promulgating any substantially similar rule. As a result of this repeal, longstanding regulations implementing requirements under the Surface Mining Control and Reclamation Act will continue to govern operations.
Clean Water Act (CWA). The CWA of 1972 directly impacts U.S. coal mining operations by requiring effluent limitations and treatment standards for wastewater discharge from mines through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting and performance standards are requirements of NPDES permits that govern the discharge of water from mine-related point sources into receiving waters.
The U.S. Army Corps of Engineers (Corps) regulates certain activities affecting navigable waters and waters of the U.S., including wetlands. Section 404 of the CWA requires mining companies to obtain Corps permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
States are empowered to develop and apply “in stream” 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. “In stream” standards vary from state to state. Additionally, through the CWA section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with their water quality standards and other applicable requirements in deciding whether or not to certify the activity.
A final rule defining the scope of waters protected under the Clean Water Act (commonly called the Waters of the United States (WOTUS Rule), was published by the EPA and the Corps in June 2015. Numerous lawsuits were filed in district courts and courts of appeals nationwide, and all courts of appeals challenges were consolidated in the U.S. Court of Appeals for the Sixth Circuit. District courts in Oklahoma and Georgia dismissed challenges for lack of jurisdiction, but a preliminary injunction was issued by the U.S. District Court in North Dakota in August 2015. On October 9, 2015, the Sixth Circuit stayed the WOTUS Rule nationwide pending further action of the court. On February 22, 2016, a three member panel of the Sixth Circuit held that the Sixth Circuit has exclusive jurisdiction to review challenges to the rule. A request for an en banc hearing was denied. The Tenth and Eleventh Circuits, which are presiding over appeals of the dismissals from Oklahoma and Georgia (respectively), have since stayed proceedings in those appeals. On October 7, 2016, several industry trade organizations and associations filed a petition requesting that the U.S. Supreme Court review the decision of the Sixth Circuit to exercise exclusive jurisdiction over challenges to the rule. The petition was granted on January 13, 2017. On February 28, 2017 the Trump Administration released an executive order directing the EPA and the Corps to consider rescinding or revising the WOTUS Rule, and the EPA and the Corps issued a similar notice that same day. The Department of Justice has notified the courts of this development and has requested that both the Supreme Court and the Sixth Circuit stay all litigation proceedings. The Supreme Court denied that stay request and merits briefing is complete, and oral arguments were held on October 11, 2017. The Sixth Circuit, however, granted the stay request and litigation in that Court is being held in abeyance pending the Supreme Court’s decision. Importantly, the Sixth Circuit’s order holding the case in abeyance did not lift the current nationwide stay against implementation of the WOTUS Rule, and therefore the stay will remain effective during the Supreme Court’s review, which is expected to take until late 2017 or early 2018. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements. On July 27, 2017, the EPA and the Corps published their proposed rule to rescind the 2015 WOTUS Rule and re-codify the prior definition of “waters of the U.S.” The agencies took public comment on that proposal through September 27, 2017 and could issue a final rule which imposed further reductions of NOx emmissions in late 2017 12 states while determining that 9 states did not significantly contribute to downwind nonattainment and/or early 2018.maintenance issues and therefore did not require additional emission reductions. In order to implement reductions in the 12 identified states, the EPA issued Federal Implementation Plans to lower state ozone season NOx budgets in 2021 to 2024, although limited emission trading can be used for compliance.
Mercury and Air Toxic Standards (MATS). The EPA published the final MATS rule in the Federal Register on February 16,in 2012. The MATS rule revised the NSPS for nitrogen oxides, sulfur dioxidesSO2 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
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 in the Federal Register a proposed supplemental finding that consideration of costs does not alter the EPA’s previous determination regarding the control of HAPs in the MATS rule. On December 15, 2015, the D.C. Circuit issued an order providing that the rule will remain in effect while the EPA responds to the U.S. Supreme Court decision.
On April 14, 2016,In 2020, the EPA issued a final supplementalrule reversing a prior finding and determined that largely tracked its proposed finding. Several states, companiesit is not “appropriate and industry groupsnecessary” under the CAA to regulate HAP emissions from coal- and oil-fired power plants. This rule also finalized residual risk and technology review standards for the coal- and oil-fired EGU source category. Both actions have been challenged that supplemental finding in the D.C. Circuit in separate petitions for review, which were subsequently consolidated. Several states and environmental groups also filed as intervenors for the respondent EPA. Briefing commenced in December 2016 and has now concluded. On April 27, 2017, the D.C. Circuit issued an order which removed the previously scheduled oral argument from the court’s calendar and held the consolidated cases challenging the supplemental findingplaced in abeyance. The order further directed
CWA Definition of “Waters of the United States”. In January 2020 the EPA and the Army Corps of Engineers (Corps) finalized the Navigable Waters Protection Rule to file status reports onrevise the agency’s reviewdefinition of “Waters of the supplemental finding every 90 days.United States” and thereby establish the scope of federal regulatory authority under the CWA. The EPA’s most recent status report indicates thatNavigable Waters Protection Rule is currently in effect in all fifty states, but on June 9, 2021, the EPA is continuingand the Corps announced their intent to review the Supplemental Finding “to determine whetherinitiate a new rulemaking proceeding to replace the rule should be maintained, modified or otherwise reconsidered” (D.C. Cir. No. 16-1127; July 26, 2017).with a new definition of “Waters of the United States.” Litigation over the 2020 Navigable Waters Protection Rule remains pending in several federal district courts.
Regulatory Matters - Australia
Occupational HealthThe Australian mining industry is regulated by Australian federal, state and Safety. State legislation requires uslocal governments with respect to provideenvironmental 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 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 mandatedissues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state legislation specificlaws. 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.
Safe Work Australia (SWA). As part of a broader review of workplace exposure standards, SWA is currently considering a proposal to reduce the time weighted average (TWA) Workplace Exposure Standard (WES) for carbon dioxide (CO2) in Australian coal mining industry. There are some differencesmines from 12,500 ppm to 5,000 ppm. Currently there is a separate TWA for CO2 in coal mines however SWA proposes to remove this to align with a general industry standard. If implemented, the application and detailchange has the potential to affect underground mines operating in CO2 rich coal seams, including the primary coal seam of the laws,Company’s Metropolitan Mine. Importantly, a minimum three-year transition period applies for any change to standards.
Environment Protection and mining operators, directors, officersBiodiversity Conservation Amendment (Standards and certain other employees are all subject toAssurance) Bill 2021. On February 25, 2021 the obligations under this legislation.
A small number of coal mine workers in QueenslandCommonwealth Government introduced the Environment Protection and New South Wales have been diagnosed with coal workers’ pneumoconiosis (CWP, also known as black lung) following decades of assumed eradication of the disease. This has led the Queensland government to sponsor a review of the system for screening coal mine workers for the disease with a view to improving early detection. The Queensland government has instituted increased reporting requirements for dust monitoring results, broader coal mine worker health assessment requirementsBiodiversity Conservation Amendment (Standards and voluntary retirement examinations for coal mine workers to be arranged by the relevant employer and further reform may follow. Peabody has undertaken a review of its practices and offered its Queensland workers the opportunity for additional CWP screening.
The Queensland government held a Parliamentary inquiryAssurance) Bill 2021 into the re-emergence of CWP in the State which included public hearings with appearances by representatives of the coal mining industry, including Peabody, coal mine workers, the Department of Natural Resources and others. The Queensland Parliamentary Committee conducting the inquiry issued an interim report on March 22, 2017 and its final report on May 29, 2017. In finding that it is highly unlikely CWP was ever eradicated in Queensland, the Committee has made 68 recommendations to ensure the safety and health of 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 0.05mg/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.
On August 23, 2017, the Queensland Parliament, passed the Workers' Compensation and Rehabilitation (Coal Workers' Pneumoconiosis) and Other Legislation Amendment Act 2017, which amends the Workers' Compensation and Rehabilitation Act 2003 by:
•establishing a medical examination process for retired or former coal workers with suspected CWP;
•introducing an additional lump sum compensation for workers with CWP; and
clarifying that a worker with CWP can access further workers’ compensation entitlements if they experience disease progression.
On August 24, 2017, the Queensland Parliamentary Committee released a report containing a draft of the Mine Safety and Health Authority Bill 2017, which proposes to establish the Mine Safety Authority foreshadowed in the Committee’s recommendations released in May 2017. The draft bill has been referred to the relevant Parliamentary Portfolio Committee for review.
On September 7, 2017, the Queensland Parliament introduced proposed amendments to legislation which, if passed, will increase civil penalties for mining companies breaching their obligations under the Coal Mining Safety and Health Act 1999. The proposed amendments would also give the Chief Executive of the Department of Natural Resources and Mining new powers to suspend or cancel an individual’s statutory certificate of competency and issue site senior executives (SSEs) notices if they fail to meet their safety and health obligations. Higher levels of competency for the statutory position of ventilation officer at underground mines will also be required if the legislation is passed.
Queensland Reclamation. The Environmental Protection Act 1994 (EP Act) is administered by the Department of Environment and Heritage Protection, 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, including the requirement for the submission of a Plan of Operations (PO) prior to the commencement of operations. All mining operations must be carried out in accordance with the PO which describes site activities and the progress toward environmental and rehabilitation outcomes, and which are updated on a regular basis or if mine plans change. The mines submit an annual return reporting on their EA compliance, including reclamation performance.
As a condition of the EA, bonding requirements are calculated to determine the amount of bonding required to cover the cost of reclamation based on the extent of disturbance during the PO period.
In May 2017, the Queensland government announced broad policy reform proposals in relation to financial assurance (FA) and rehabilitation for the mining and petroleum sector. The proposed regime represents a new approach to managing Queensland’s existing rehabilitation risk management.
On October 25, 2017, the Queensland Parliament introduced the Mineral and Energy Resources (Financial Provisioning) Bill 2017 (MERFP Bill), which contained proposed legislation to give effect to some of the policy reforms, including:
a remodeled FA framework that takes into account the financial strength of the EA holder and the risk level of the mine;
•a state-wide pooled FA fund covering most mines and most of the total industry liability;
•discontinuation of prior discounting of FA requirements;
other options for providing FA for those mines that are not part of the pooled FA fund (for example, allowing insurance bonds or cash);
•updated rehabilitation calculations; and
•regular monitoring and reporting measures for progressive mine rehabilitation.
However, the MERFP Bill lapsed on October 29, 2017 when a Queensland state election was called. The nature of the FA and rehabilitation policy reforms, and the timing for the reintroduction into Parliament of the MERFP Bill or other proposed legislation for implementing those reforms, is dependent on the outcome of the election.
Federal Reclamation. In February 2017, the Australian Senate established a Committee of Inquiry into the rehabilitation of mining and resources projects as it relates to Commonwealth responsibilities, for example, under the Environment Protection and Biodiversity Conservation Act 1999.1999 (EPBC Act) following the release of the Final Report of the Independent Review of the Act undertaken by Professor Graeme Samuel (the Samuel Review) that made 38 recommendations for short and long-term reforms, and ultimately calls for a complete overhaul of the existing legislative framework by 2022, to be undertaken in several tranches, with a strong focus on the setting of National Environmental Standards, assurance and compliance, data availability and management, and indigenous engagement. The Committee is holding public hearingsbill responds to some of the recommendations for immediate reform made in the Samuel Review, and is currently dueseeks to: establish a framework for the making, varying, revoking and application of National Environmental Standards; apply the National Environmental Standards to reportbilateral agreements with States and Territories; and establish an Environment Assurance Commissioner to monitor and audit bilateral agreements and other processes under the EPBC Act. The bill passed the Australian Parliament’s House of Representatives in June 2021 and will now be considered by the Australian Senate during its August sittings.
Native Title and Cultural Heritage. On February 3, 2021 the Native Title Act 1993 was amended largely directed at improving the efficiency of the native title system for all parties. The amendments confirm the validity of most section 31 right to negotiate agreements which might be invalid because of non-execution by any of the persons comprising the registered native title claimant following the Full Federal Court's decision in McGlade v Registrar National Native Title Tribunal. Other significant amendments include that: during the right to negotiate process the parties to section 31 agreements are now required to notify the National Native Title Tribunal of the existence of any ancillary agreements; new section 47C allows historical extinguishment to be disregarded on park areas including extinguishment by public works; and new section 24MD(6B)(f) creates a new 8 month objection period for the creation of a right to mine for the purpose of an infrastructure facility associated with mining and to some compulsory acquisitions of native title.
Global Climate
In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no legislation directly affecting fossil fuel-fired powerplants has been signed into law. Congress did include climate legislation, the American Innovation and Manufacturing Act of 2020, within a large appropriations bill for the 2021 fiscal year. This legislation was enacted in December, 2020, and will require phasedown of the production and use of hydrofluorocarbons (HFCs) in the United States. While it is possible that the U.S. will adopt broader legislation in the future, the timing and specific requirements of any such legislation are uncertain.
In the absence of new U.S. federal legislation, the EPA has taken steps to regulate greenhouse gas emissions pursuant to the CAA. In response to the U.S. Supreme Court ruling in Massachusetts v. EPA, 549 U.S. 497 (2007) the EPA commenced several rulemaking projects as described under “Regulatory Matters - U.S.” As described above, however, the EPA’s rules affecting existing fossil-fuel fired power plants (i.e. the ACE Rule and the EPA’s repeal of the CPP) were vacated and remanded back to the EPA by the D.C. Circuit Court of Appeals. Greenhouse gas requirements for new, reconstructed and modified fossil fuel fired power plants remain in effect.
Several changes in the New Source Review (NSR) program, a permitting plan under the CAA for new source construction and major modifications, have also been issued through guidance and rulemaking as described under “Regulatory Matters – U.S.” in the Company’s Annual Report on Form 10-K. The NSR program provides for the pre-construction review of new, reconstructed and modified stationary sources and results in determinations concerning the emission control technology that must be installed and operated at a source. Clean Air Act standards, known as new source performance standards, generally serve as a “floor” level of control for sources subject to NSR review; the final level of control is determined through the permitting process. In certain cases, performance standards or controls regarding greenhouse gas emissions may be required through the NSR process.
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. 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. Separately, California has committed through Executive Order B-55-18 and SB 100 to 100 percent “clean energy” by 2045 and the state of Washington has passed legislation to commit to carbon neutrality by 2050.
Several other U.S. states have enacted legislation establishing greenhouse gas emissions reduction goals or requirements. In addition, several states have enacted legislation or have in effect regulations requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources. Some states have initiated public utility proceedings that may establish values for carbon emissions.
Increasingly, both foreign and domestic banks, insurance companies and large investors are curtailing or ending their financial relationships with fossil fuel-related companies. This has had adverse impacts on the liquidity and operations of coal producers.
Peabody participated in the Department of Energy’s Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and Peabody regularly discloses in its annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by the Company in the U.S. The vast majority of the Company’s emissions are generated by the operation of heavy machinery to extract and transport material at its mines and fugitive emissions from the extraction of coal.
The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gas emission targets for developed nations. The U.S. signed the Kyoto Protocol but it has never been ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There were discussions to develop a treaty to replace the Kyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences in Cancun (2010), Durban (2011), Doha (2012) and Paris (2015). At the Durban conference, an ad hoc working group was established to develop a protocol, another legal instrument or an agreed outcome with legal force under the UNFCCC, applicable to all parties. At the Doha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second quartercommitment 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 2018.global greenhouse gas emissions.
In January 2021, the U.S. reentered the Paris Agreement by accepting the agreement and all of its articles and clauses, after having announced its withdrawal from the agreement in November 2019. In April 2021, the U.S. announced its own Nationally Determined Contribution (NDC) with respect to the Paris Agreement. The NDC is voluntary and would aim to cut carbon dioxide output by 50% to 52% compared with 2005 levels by 2030. Recently, the U.S. has announced the goal of a completely emissions-free power grid by 2035, but has not provided specificity for a regulatory framework to achieve that goal. The Company anticipates a series of executive actions and/or orders from the current presidential administration aimed at curbing emission levels as well as associated rulemaking using the CAA and potentially other statutory authorities.
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 has not formally committed to net zero emissions by 2050 with the focus of energy policy on the use of technology to accelerate the development and commercialization of low and zero emissions technologies and 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 the Company 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, Peabody attempts to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require that Peabody 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 its operations, financial condition or cash flow. The Company does not believe that such analyses reasonably predict the quantitative impact that future laws, regulations or other policies may have on its results of operations, financial condition or cash flows.
Liquidity and Capital Resources
Overview
OurThe Company’s primary sourcessource of cash areis proceeds from the sale of ourits coal production to customers. We haveThe Company has also generated cash from the sale of non-strategic assets, including coal reserves and surface lands. Ourlands, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining retirementreclamation obligations, and selling and administrative expenses. Historically, we haveThe Company has also generatedused cash from borrowings under our credit facilitiesfor dividends, share repurchases and from time to time, the issuance of securities. We believe that our reorganized capital structure subsequent to the Effective Date will allow us to satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations and cash on hand.early debt retirements.
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 Successor Notesthe Company’s debt and Successor Credit Agreement, oursurety agreements, its net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. OurThe Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on ourits future financial performance, which in turn depends on the successful implementation of ourits strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to ourits industry, many of which are beyond ourthe Company’s control. See also, Debt ReductionThe Company has presently suspended the payment of dividends and Shareholder Return Initiatives, below.
Total Indebtedness. Our total indebtedness asEquity Securities and Use of September 30, 2017 and December 31, 2016 consisted of the following:
|
| | | | | | |
| Successor | Predecessor |
| September 30, 2017 | December 31, 2016 |
| (Dollars in millions) |
6.00% Senior Secured Notes due March 2022 | $ | 500.0 |
| $ | — |
|
6.375% Senior Secured Notes due March 2025 | 500.0 |
| — |
|
Senior Secured Term Loan due 2022 | 645.0 |
| — |
|
2013 Revolver | — |
| 1,558.1 |
|
2013 Term Loan Facility due September 2020 | — |
| 1,162.3 |
|
6.00% Senior Notes due November 2018 | — |
| 1,518.8 |
|
6.50% Senior Notes due September 2020 | — |
| 650.0 |
|
6.25% Senior Notes due November 2021 | — |
| 1,339.6 |
|
10.00% Senior Secured Second Lien Notes due March 2022 | — |
| 979.4 |
|
7.875% Senior Notes due November 2026 | — |
| 247.8 |
|
Convertible Junior Subordinated Debentures due December 2066 | — |
| 386.1 |
|
Capital lease and other obligations | 84.0 |
| 20.1 |
|
Less: Debt issuance costs | (69.9 | ) | (70.8 | ) |
| 1,659.1 |
| 7,791.4 |
|
Less: Current portion of long-term debt | 47.1 |
| 20.2 |
|
Less: Liabilities subject to compromise | — |
| 7,771.2 |
|
Long-term debt | $ | 1,612.0 |
| $ | — |
|
Refer to Note 1. “Basis of Presentation” and Note 13. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements for further information regarding our indebtedness, including our capital structure subsequent to the Effective Date.Proceeds.”
Liquidity
As of SeptemberJune 30, 2017, our available liquidity was $942.7 million which was comprised of cash and cash equivalents and availability under our receivables securitization program described below. As of September 30, 2017, our2021, the Company’s cash balances totaled $925.0$548.3 million, including approximately $708.0$366 million held by U.S. entities, withsubsidiaries and $153 million held by Australian subsidiaries, approximately $102 million of which was held by the subsidiaries that conduct the operations of its Wilpinjong Mine. The remaining cash balance was held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by ourthe Company’s foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in AustraliaAustralia.
The Company’s available liquidity declined from $728.7 million as of December 31, 2020 to $564.1 million as of June 30, 2021. Available liquidity, which excluded $13.6 million of restricted cash as of June 30, 2021, was comprised of the following:
| | | | | | | | | | | | | |
| | | June 30, 2021 | | December 31, 2020 |
| | | (Dollars in millions) |
Cash and cash equivalents | | | $ | 548.3 | | | $ | 709.2 | |
Credit facility availability | | | 15.5 | | | 0.2 | |
Accounts receivable securitization program availability | | | 0.3 | | | 19.3 | |
Total liquidity | | | $ | 564.1 | | | $ | 728.7 | |
Indebtedness
The Company’s total funded indebtedness (Indebtedness) as of June 30, 2021 and December 31, 2020 is presented in the table below.
| | | | | | | | | | | |
Debt Instrument (defined below, as applicable) | June 30, 2021 | | December 31, 2020 |
| (Dollars in millions) |
6.000% Senior Secured Notes due March 2022 (2022 Notes) | $ | 29.5 | | | $ | 459.0 | |
8.500% Senior Secured Notes due December 2024 (Peabody Notes) | 156.3 | | | — | |
10.000% Senior Secured Notes due December 2024 (Co-Issuer Notes) | 193.9 | | | — | |
6.375% Senior Secured Notes due March 2025 (2025 Notes) | 482.6 | | | 500.0 | |
Senior Secured Term Loan due 2024 (Co-Issuer Term Loans) | 206.0 | | | — | |
Senior Secured Term Loan due 2025, net of original issue discount (Senior Secured Term Loan) | 368.6 | | | 388.2 | |
Revolving credit facility | — | | | 216.0 | |
| | | |
Finance lease obligations | 32.3 | | | 27.3 | |
Less: Debt issuance costs | (51.1) | | | (42.7) | |
| 1,418.1 | | | 1,547.8 | |
Less: Current portion of long-term debt | 94.0 | | | 44.9 | |
Long-term debt | $ | 1,324.1 | | | $ | 1,502.9 | |
The Company’s Indebtedness was significantly impacted subsequent to December 31, 2020 as a result of various agreements and transactions described below.
Refinancing and Related Transactions
During the fourth quarter of 2020 and the foreign operationsfirst quarter of our Trading2021, the Company entered into a series of interrelated agreements with its surety bond providers, the revolving lenders under its credit agreement and Brokerage segment. We do not expect restrictions or potential taxes oncertain holders of its senior secured notes to extend a significant portion of its near-term debt maturities to December 2024 and to stabilize collateral requirements for its existing surety bond portfolio. Such agreements and related activities are described below.
Organizational Realignment
In July and August 2020, the repatriationCompany effected certain changes to its corporate structure in contemplation of amounts held by our foreigna debt-for-debt exchange, which included, among other steps, the formation of certain wholly-owned subsidiaries to have(the Co-Issuers). In connection with the change in structure, the Company’s subsidiary which owns and operates its Wilpinjong Mine in Australia became a material effect on our overall liquidity, financial condition or resultssubsidiary of operations.
Subsequent to our emergence from the Chapter 11 Cases our liquidity primarily consists of cash and cash equivalentsCo-Issuers. The Co-Issuers and the available balancesWilpinjong subsidiary were designated as unrestricted subsidiaries under the Company’s credit agreement (Credit Agreement) and its senior notes’ indenture (the Existing Indenture). In connection with these actions, the Company contributed $100.0 million to the Co-Issuers to provide the Wilpinjong Mine with operating liquidity and address its near-term capital needs.
Surety Agreement
In November 2020, the Company entered into a surety transaction support agreement (Surety Agreement) with the providers of 99% of its surety bond portfolio (Participating Sureties) to resolve previous collateral demands made by the Participating Sureties. In accordance with the Surety Agreement, the Company initially provided $75.0 million of collateral, in the form of letters of credit.
Upon completion of the Refinancing Transactions, as defined below, other provisions of the Surety Agreement became effective. In particular, the Company granted second liens on $200.0 million of certain mining equipment and will post an additional $25.0 million of collateral per year from our accounts receivable securitization program. Our ability2021 through 2024 for the benefit of the Participating Sureties. The collateral postings may also further increase to the extent the Company generates more than $100.0 million of free cash flow (as defined in the Surety Agreement) in any twelve-month period or has cumulative asset sales in excess of $10.0 million, as of the last quarter end during the term of the agreement. Further, the Participating Sureties have agreed to a standstill through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025), during which time, the Participating Sureties will not demand any additional collateral, draw on letters of credit posted for the benefit of themselves or cancel any existing surety bond. The Company will not pay dividends or make share repurchases during the standstill period, unless otherwise agreed between parties.
Refinancing Transactions
On January 29, 2021 (the Settlement Date), the Company completed a series of transactions (collectively, the Refinancing Transactions) to, among other things, provide it with maturity extensions and covenant relief, while allowing it to maintain adequatenear-term operating liquidity depends onand financial flexibility. The Refinancing Transactions included a senior notes exchange and related consent solicitation, a revolving credit facility exchange and various amendments to its existing debt agreements, as summarized below.
Exchange Offer
On the successful operation of our business and appropriate management of operating expenses and capital spending. Our anticipated liquidity needs are highly sensitive to changes in each of these and other factors.
The Successor Notes and Successor Credit Agreement
As described in Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting” and Note 13. “Long-term Debt” of the accompanying unaudited condensed consolidated financial statements, on the EffectiveSettlement Date, the proceeds from the 6.00%Company settled an exchange offer (Exchange Offer) pursuant to which $398.7 million aggregate principal amount of its 6.000% Senior Secured Notes due March 2022 (2022 Notes) were validly tendered, accepted by the Company and the 6.375%exchanged for aggregate consideration consisting of (a) $193.9 million aggregate principal amount of new 10.000% Senior Secured Notes due March 2025 (collectively,2024 issued by the SuccessorCo-Issuers (Co-Issuer Notes) and the Senior Secured Term Loan under the Successor Credit Agreement were used to repay the predecessor first lien obligations. The proceeds from the Successor Notes and the Senior Secured Term Loan, net of debt issuance costs and an original issue discount, as applicable, were $950.5, (b) $195.1 million and $912.7 million, respectively.
We voluntarily prepaid $300.0 million of the original $950.0 million loan principal on the Senior Secured Term Loan in $150.0 million installments on July 31, 2017 and September 11, 2017. On September 18, 2017, we entered into an amendment to the Successor Credit Agreement which lowered the interest rate from LIBOR plus 4.50% per annum with a 1.00% LIBOR floor to LIBOR plus 3.50% per annum with a 1.00% LIBOR floor. The amendment permits us to add an incremental revolving credit facility in addition to our ability to add one or more incremental term loan facilities under the Successor Credit Agreement. The incremental revolving credit facility and/or incremental term loan facilities, which remain unutilized, can be in an aggregate principal amount of up to $300.0 million plus additional amounts so long asnew 8.500% Senior Secured Notes due 2024 issued by Peabody (Peabody Notes), and (c) a cash payment of approximately $9.4 million. In connection with the settlement of the Exchange Offer, the Company maintains compliancealso paid early tender premiums totaling $4.0 million in cash. Refer to Note 11. “Long-term Debt” for additional information associated with the Total Leverage Ratio, as definedCo-Issuer Notes and the Peabody Notes.
As required under the Exchange Offer, the Company purchased $22.4 million of the Peabody Notes at 80% of their accreted value, plus accrued and unpaid interest, during the first quarter of 2021 and recognized a related net gain on extinguishment of $3.5 million.
Consent Solicitation
Concurrently with the Exchange Offer, the Company solicited consents from holders of the 2022 Notes to certain proposed amendments to the Existing Indenture to (i) eliminate substantially all of the restrictive covenants, certain events of default applicable to the 2022 Notes and certain other provisions contained in the agreement.The amendment also made available an additional restricted payment basket that permits additional repurchases, dividends orExisting Indenture and (ii) release the collateral securing the 2022 Notes and eliminate certain other distributionsrelated provisions contained in the Existing Indenture. The Company received the requisite consents from holders of the 2022 Notes and entered into a supplemental indenture to the Existing Indenture, which became operative on January 29, 2021.
Revolver Transactions
In connection with respect to our Common and Preferred Stockthe Refinancing Transactions, the Company restructured the revolving loans under the Credit Agreement by (i) making a pay down of revolving loans thereunder in anthe aggregate amount upof $10.0 million, (ii) the Co-Issuers incurring $206.0 million of term loans under a credit agreement, dated as of the Settlement Date (Co-Issuer Term Loans, Co-Issuer Term Loan Agreement), (iii) Peabody entering into a letter of credit facility (the Company LC Agreement), and (iv) amending the Credit Agreement (collectively, the Revolver Transactions).
The Co-Issuer Term Loans mature on December 31, 2024 and bear interest at a rate of 10.00% per annum.
On the Settlement Date, the Company entered into the Company LC Agreement with the revolving lenders party to $450.0the Credit Agreement, pursuant to which the Company obtained a $324.0 million so long as our Fixed Charge Coverage Ratio, as definedletter of credit facility under which its existing letters of credit under the Credit Agreement were deemed to be issued. The commitments under the Company LC Agreement mature on December 31, 2024. Undrawn letters of credit under the Company LC Agreement bear interest at 6.00% per annum and unused commitments are subject to a 0.50% per annum commitment fee.
In connection with the Revolver Transactions, the Company amended the Credit Agreement to make certain changes in consideration of the agreement, wouldCompany LC Agreement. After giving effect to the Revolver Transactions, there remain no revolving commitments or revolving loans under the Credit Agreement and the first lien net leverage ratio covenant was eliminated. The Company LC Agreement requires that the Company’s restricted subsidiaries maintain minimum aggregate liquidity of $125.0 million at the end of each quarter through December 31, 2024. As such, liquidity attributable to the Co-Issuers, its subsidiaries and other unrestricted subsidiaries is excluded from the calculation. Liquidity calculated in this manner amounted to $444.9 million at June 30, 2021.
The indenture which governs the Peabody Notes and the Company LC Agreement allow the Company to make open market debt repurchases, subject to certain limitations, including, but not exceed 2.00:1.00limited to: (i) the Company’s unrestricted subsidiaries’ liquidity must be greater than or equal to $200.0 million after giving effect to such repurchases and (ii) for every $4 of principal repurchased in any fiscal quarter, the Company must make an offer on a pro forma basis.
Interest payments onrata basis to purchase $1 of principal amount of debt from holders of the SuccessorPeabody Notes are scheduled to occur each year on March 31 and September 30 until maturity. We may redeem the 6.00% Senior Secured Notes beginning in 2019 and the 6.375% Senior Secured Notes beginning in 2020, in whole or in part, and subjectpriority lien obligations under the Company LC Agreement within 30 days of the end of such fiscal quarter at a price equal to periodically decreasing redemption premiums, through maturity.the weighted average repurchase price paid over that quarter (Mandatory Repurchase Offer).
Other Debt Financing
The SeniorRefinancing Transactions did not significantly impact the Company’s existing senior secured term loan under the Credit Facility (Senior Secured Term LoanLoan), or its $500.0 million of 6.375% senior secured notes due March 2025 (2025 Notes), but these debt instruments were impacted by subsequent financing transactions described below. The term loan requires quarterly principal is payable in quarterly installmentspayments of $1.0 million and periodic interest payments, currently at LIBOR plus accrued interest2.75%, through December 20212024 with the remaining balance due in March 2022.2025. The loan principalsenior secured notes require semi-annual interest payments each March 31 and September 30 until maturity.
The Company’s debt agreements impose various restrictions and limits on certain categories of payments that the Company may make, such as those for dividends, investments, and stock repurchases. The Company is voluntarily prepayablealso subject to customary affirmative and negative covenants. The Company was compliant with all covenants under its debt agreements including the minimum liquidity covenant under the Company LC Agreement at 101%June 30, 2021.
Subsequent Financing Transactions
Subsequent to the Refinancing Transactions, the Company completed a series of financing transactions intended to improve its capital structure.
In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its common stock. Such sales are allowed using methods permissible under Rule 415 of the principal amount repaid if voluntarily prepaid priorSecurities Act. The shares are offered and sold pursuant to March 18, 2018 (subjectthe Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as supplemented by a prospectus supplement dated June 4, 2021, relating to certain exceptions, including prepayments made with internally generated cash)the offer and is voluntarily prepayable at any time thereafter without premium or penalty. Thesale of the shares. During the three months ended June 30, 2021, the Company sold approximately 8.1 million shares for net cash proceeds of $65.1 million. Subsequent to June 30, 2021, the Company settled sales of an additional 2.7 million shares for net proceeds of $21.5 million.
During the three months ended June 30, 2021, the Company retired $18.0 million of Peabody Notes, $17.4 million of 2025 Notes and $17.8 million of its Senior Secured Term Loan may require mandatoryprimarily through various open market purchases at an aggregate cost of $39.2 million. The Company recorded a gain on early debt extinguishment of $11.9 million, net of debt issuance costs and original issue discount related to the retired debt of $2.1 million.
Also during the three months ended June 30, 2021, the Company completed multiple bilateral transactions with holders of the 2022 Notes in which the Company issued an aggregate 4.5 million shares of its common stock in exchange for $30.9 million aggregate principal prepaymentsamount of 75%the 2022 Notes. Based upon the fair value of Excess Cash Flow (as definedthe Company’s common stock at the respective settlement dates, the Company recorded a net loss on early debt extinguishment of $0.1 million in the Successor Credit Agreement) for any fiscal year (commencingconnection with the fiscal year ending December 31, 2018).transactions. The mandatoryissuance of shares of common stock in exchange for the 2022 Notes was exempt from registration under the Securities Act, on the basis that the exchange was completed with existing holders of the Company’s securities, and no commission or other remuneration was paid or given for soliciting the exchange.
The Company also reached agreements to retire an additional $49.5 million of aggregate principal, prepayment requirement changeswhich will settle subsequent to (i) 50%June 30, 2021. This included $44.0 million of Excess Cash Flow if our Total Leverage Ratio (as defined in the Successor Credit Agreement and calculated as of December 31) is less than or equal to 2.00:1.00 and greater than 1.50:1.00, (ii) 25% of Excess Cash Flow if our Total Leverage Ratio is less than or equal to 1.50:1.00 and greater than 1.00:1.00, or (iii) zero if the our Total Leverage Ratio is less than or equal to 1.00:1.00. If required, mandatory prepayments resulting from Excess Cash Flows are payable within 100 days after the end of each fiscal year. In certain circumstances, theits Senior Secured Term Loan also requires that Excess Proceeds (as defineddue 2025 and $1.5 million of 2025 Notes through similar open market purchases for an aggregate cost of $30.2 million, and by issuing an aggregate 0.5 million shares of its common stock in exchange for $4.0 million aggregate principal amount of the 2022 Notes in a similar manner noted above. Such amounts are reflected within the current portion of long-term debt in the Successor Credit Agreement)accompanying condensed consolidated balance sheets at June 30, 2021.
As a result of $10the Company’s open market purchases of its debt during the three months ended June 30, 2021, on July 7, 2021, the Company announced a Mandatory Repurchase Offer of up to $13.3 million or greater from sales of our assets be applied against the loan principal, unless such proceeds are reinvested within one year.
Under the Successor Credit Agreement, our annual capital expenditures are limited to $220.0 million, $220.0 million, $250.0 million, $250.0 million,its 2024 Peabody Notes, at 73.840% of their aggregate accreted value, plus accrued and $300.0 million from 2017 through 2021, respectively, subject to certain adjustments.
In addition to the $450.0 million restricted payment basket provided forunpaid interest, and a concurrent repurchase offer of priority lien obligations under the amendment,Company LC Agreement. The offers expire on August 6, 2021, unless extended by the Successor Credit AgreementCompany.
Considering the Refinancing Transactions and Successor Notes allow for $50the subsequent financing transactions described above, the Company expects to incur approximately $190 million of otherwise restricted payments. Additive to this general limit are certain “builder basket” provisions that may increaseinterest expense, including approximately $40 million of non-cash interest expense, during the amount of allowable restricted payments, as calculated periodically based upon our operating performance. Beginning on January 1, 2018, the payment of dividends and purchases of our own common stock are permitted under additional provisions of the Successor Notes and the Successor Credit Agreement in an aggregate amount in any calendar year not to exceed $25 million, so long as our Total Leverage Ratio would not exceed 1.25:1.00 on a pro forma basis.ended December 31, 2021.
Accounts Receivable Securitization Program
As described in Note 18.16. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, on the Effective Date, weCompany entered into an amended Receivables Purchase Agreement to extend the receivables securitization facility previously in place and expand that facility to include certain receivables from the Company’s Australian operations. The term of the receivablesaccounts receivable securitization program (Securitization Program) ends on April 3, 2020, subjectduring 2017 which currently matures in 2022. The Company intends to certain liquidity requirements and other customary events of default set forth inrenew the Receivables Purchase Agreement.facility prior to maturity. The Securitization Programprogram provides for up to $250$250.0 million in funding, accounted for as a secured borrowing, limited to the availability of eligible receivables, and may beaccounted for as a secured by a combination of cash collateral and the trade receivables underlying the program, from time to time.borrowing. Funding capacity under the Securitization Programprogram may also be drawn uponutilized for letters of credit in support of other obligations. OnAt June 30, 2017, we entered into an amendment to2021, the Securitization Program to include the receivables of additional Australian operations and reduce the associated fees payable.
At September 30, 2017, we hadCompany had no outstanding borrowings and $179.5$125.5 million of letters of credit drawnissued under the Securitization Program. The letters of creditprogram, which were primarily in support of portions of our obligations forthe Company’s reclamation workers’ compensation and postretirement benefits. There was noobligations. The Company had $13.6 million of cash collateral requirementposted under the Securitization Program at SeptemberJune 30, 2017.2021 due to outstanding letters of credit temporarily exceeding the balance of eligible receivables at quarter-end.
Capital Requirements
For 2021, the Company is targeting capital expenditures of approximately $200 million, which includes approximately $100 million for ongoing extension projects primarily related to its Seaborne Thermal Mining segment. The Company has no substantial future payment requirements under U.S. federal coal reserve leases.
Contractual Obligations
There were no material changes to the Company’s contractual obligations from the information previously provided in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.
Cash Flows and Free Cash Flow
The following table summarizes the Company’s cash flows for the six months ended June 30, 2021 and 2020, as reported in the accompanying unaudited condensed consolidated financial statements. Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP.
| | | | | | | | | | | |
| Six Months Ended June 30, |
| 2021 | | 2020 |
| (Dollars in millions) |
Net cash used in operating activities | $ | (22.8) | | | $ | (53.1) | |
Net cash used in investing activities | (82.6) | | | (115.6) | |
Net cash (used in) provided by financing activities | (41.9) | | | 285.0 | |
Net change in cash, cash equivalents and restricted cash | (147.3) | | | 116.3 | |
Cash, cash equivalents and restricted cash at beginning of period | 709.2 | | | 732.2 | |
Cash, cash equivalents and restricted cash at end of period | $ | 561.9 | | | $ | 848.5 | |
| | | |
Net cash used in operating activities | $ | (22.8) | | | $ | (53.1) | |
Net cash used in investing activities | (82.6) | | | (115.6) | |
| | | |
Free Cash Flow | $ | (105.4) | | | $ | (168.7) | |
Operating Activities. The decrease in net cash used in operating activities for the six months ended June 30, 2021 compared to the same period in the prior year was driven by a year-over-year increase in cash generated by Company’s mining operations, partially offset by an unfavorable change in net cash flows associated with its working capital ($67.2 million).
Reclamation BondingInvesting Activities. The decrease in net cash used in investing activities for the six months ended June 30, 2021 compared to the same period in the prior year was driven by lower advances to related parties and joint ventures, on a net basis ($34.8 million).
Financing Activities. The decrease in net cash provided by financing activities for the six months ended June 30, 2021 compared to the same period in the prior year was driven by $300.0 million of revolving loan borrowings in the prior year, higher repayments of debt principal ($73.2 million) and payments for deferred financing costs ($22.5 million) in the current year, partially offset by $65.1 million proceeds from the issuance of common stock in the current year.
Off-Balance-Sheet Arrangements
In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. At June 30, 2021, such instruments included $1,555.0 million of surety bonds and $435.4 million of letters of credit. Such financial instruments provide support for its reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in its condensed consolidated balance sheets.
As of June 30, 2021, the Company was party to financial instruments with off-balance-sheet risk in support of the following obligations:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Reclamation | | Health and welfare (1) | | Contract performance (2) | | Leased property and equipment | | Other (3) | | Total |
| (Dollars in millions) |
Surety bonds and bank guarantees | $ | 1,379.0 | | | $ | 42.1 | | | $ | 87.3 | | | $ | 30.9 | | | $ | 15.7 | | | $ | 1,555.0 | |
Letters of credit outstanding under letter of credit facility | 206.0 | | | 90.4 | | | 7.1 | | | 5.0 | | | — | | | 308.5 | |
Letters of credit outstanding under accounts receivable securitization program | 104.5 | | | 16.6 | | | 4.4 | | | — | | | — | | | 125.5 | |
Other letters of credit | — | | | 1.4 | | | — | | | — | | | — | | | 1.4 | |
| 1,689.5 | | | 150.5 | | | 98.8 | | | 35.9 | | | 15.7 | | | 1,990.4 | |
Less: Letters of credit in support of surety bonds (4) | (303.8) | | | (29.7) | | | — | | | (1.2) | | | — | | | (334.7) | |
Less: Cash collateral in support of surety bonds (4) | (15.0) | | | — | | | — | | | — | | | — | | | (15.0) | |
Obligations supported, net | $ | 1,370.7 | | | $ | 120.8 | | | $ | 98.8 | | | $ | 34.7 | | | $ | 15.7 | | | $ | 1,640.7 | |
(1) Obligations include pension and healthcare plans, workers’ compensation, and property and casualty insurance
(2) Obligations pertain to customer and vendor contracts
(3) Obligations primarily pertain to the disturbance or alteration of public roadways in connection with the Company’s mining activities that is subject to future restoration
(4) Serve as collateral for certain surety bonds at the request of surety bond providers. The Company has also posted $5.2 million in incremental collateral directly with the beneficiary that is not supported by a surety bond.
Financial assurances associated with new reclamation bonding requirements, surety bonds or other obligations may require additional collateral in the form of cash or letters of credit causing a decline in the Company’s liquidity.
As described in Note 18.16. “Financial Instruments and Other Guarantees” ofin the accompanying unaudited condensed consolidated financial statements, we arethe Company is required to provide various forms of financial assurance in support of ourits mining reclamation obligations in the jurisdictions in which we operate.it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in the U.S. In connection with our emergence from the Chapter 11 Cases, we shifted away from extensive self-bondingSelf-bonding in the U.S. has become increasingly restricted in favor ofrecent years, leading to the Company’s increased usage of surety bonds and similar third-party instruments, but have retained the ability to utilize self-bonding in the future, dependent upon state-by-state approval and internal cost-benefit considerations.instruments. This divergencechange in practice mayhas had an unfavorable impact ouron its liquidity in the future due to increased cash collateral requirements and surety and related fees.
At SeptemberJune 30, 2017, we2021, the Company had total asset retirement obligations of $636.0$741.8 million which were backed by a combination of surety bonds, bank guarantees and letters of credit and restricted cash collateral. Cash collateral balances related to reclamation and other obligations are maintained on our balance sheets within “Investments and other assets,” but are excluded from our available liquidity. Such cash collateral amounted to $530.3 million at September 30, 2017, of which $160.1 million was held in the U.S. and $370.2 million in Australia.credit.
Bonding requirement amounts may differ significantly from the relatedrelated asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas ourthe Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.
Capital Requirements
There were no material changes to our capital requirements from the information provided in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017.
Contractual Obligations
The consummation of the Plan and related reorganization activities resulted in significant changes to our future contractual obligations with respect to our long-term debt and capital and operating lease obligations which were disclosed in Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017. Our future contractual obligations with respect to our long-term debt have further changed as a result of the principal repayments on our Senior Secured Term Loan and the amendment to our Successor Credit Facility as more fully described in Note 13. “Long-term Debt” to the accompanying unaudited financial statements. Our resulting future long-term debt obligations for periods subsequent to September 30, 2017 are set forth in the table below. The related interest on long-term obligations was calculated using rates in effect at September 30, 2017 for the remaining contractual term of the outstanding borrowings. There were no other material changes to our contractual obligations from the information previously provided in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017, and Item 2 of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Payments Due By Period |
| Total | | Three Months Ending December 31, 2017 | | 2018-2019 | | 2020-2021 | | 2022-2023 | | Subsequent to 2023 |
| (Dollars in millions) |
Long-term debt obligations (principal and interest) | $ | 2,176.4 |
| | $ | 25.1 |
| | $ | 204.5 |
| | $ | 208.3 |
| | $ | 1,198.7 |
| | $ | 539.8 |
|
Debt Reduction and Shareholder Return Initiatives
In the second quarter of 2017, we outlined our debt reduction and shareholder return initiatives. The details of these initiatives are as follows:
Liquidity Targets. Peabody is targeting liquidity of approximately $800 million. This target takes into account variability of pricing and cash flows and the ability to sustain cyclical downdrafts.
Debt Targets. Peabody is targeting gross debt of $1.2 billion to $1.4 billion over time to enhance the sustainability of its capital structure across all cycles. Peabody is targeting $500 million of debt reduction by December 2018 and made $300 million in voluntary payments of its term loan under the Successor Credit Agreement during the three months ended September 30, 2017.
Return of Capital to Shareholders. Peabody’s board of directors authorized a $500 million share repurchase program. Repurchases may be made from time to time at our discretion. The specific timing, price and size of purchases will depend on the share price, general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time. No expiration date has been set for the repurchase program, and the program may be suspended or discontinued at any time. During the three months ended September 30, 2017, we repurchased approximately 1.5 million shares of our Common Stock for $40.0 million in connection with an underwritten secondary offering and made additional open-market purchases of approximately 1.0 million shares of our Common Stock for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, we have purchased an additional 1.3 million shares of our Common Stock for $37.7 million. The purchases were made in compliance with our debt provisions that limit our ability to repurchase shares following the Plan Effective Date.
Dividends. Peabody’s board of directors will regularly evaluate a sustainable dividend program, targeting commencement in the first quarter of 2018. The timing and amount of dividends under such a program will depend on general market and economic conditions and other considerations, including compliance with various debt agreements as they may be amended from time to time.
Historical Cash Flows
The following table summarizes our cash flows for the period April 2 through September 30, 2017, January 1 through April 1, 2017, and the three and nine months ended September 30, 2016, as reported in the accompanying unaudited condensed consolidated financial statements:
|
| | | | | | | | | | |
| Successor | Predecessor |
| April 2 through September 30, 2017 | January 1 through April 1, 2017 | | Nine Months Ended September 30, 2016 |
| |
| (Dollars in millions) |
Net cash provided by (used in) operating activities | 330.3 |
| 214.0 |
| | (276.8 | ) |
Net cash (used in) provided by investing activities | (34.9 | ) | 15.1 |
| | (199.7 | ) |
Net cash (used in) provided by financing activities | (424.1 | ) | (47.7 | ) | | 1,383.0 |
|
Net change in cash and cash equivalents | (128.7 | ) | 181.4 |
| | 906.5 |
|
Cash and cash equivalents at beginning of period | 1,053.7 |
| 872.3 |
| | 261.3 |
|
Cash and cash equivalents at end of period | $ | 925.0 |
| $ | 1,053.7 |
| | $ | 1,167.8 |
|
Cash Flow - Successor
Cash provided by operating activities in the Successor period April 2, 2017 through September 30, 2017 resulted from improved supply and demand conditions leading to increased cash from our mining operations. In addition, $99.4 million of restricted cash collateral became unrestricted. These factors were partially offset by the greater use of working capital related to coal stockpile increases and the payment of claims and professional fees related to the Chapter 11 Cases.
Cash used in investing activities in the Successor period April 2, 2017 through September 30, 2017 resulted from additions to property, plant, equipment and mine development, which was partially offset by repayments of loans from related parties.
Cash used in financing activities in the Successor period April 2, 2017 through September 30, 2017 resulted primarily from $300.0 million of repayments on the Senior Secured Term Loan and $69.2 million of repurchases of Common Stock in accordance with our debt reduction and shareholder return initiatives.
Cash Flow - Predecessor
Cash provided by operating activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from year-over-year increase in cash from our operations from improved supply and demand conditions.
Cash used in operating activities during the nine months ended September 30, 2016 resulted from unfavorable supply and demand conditions leading to decreased cash from our mining operations, greater use of working capital, and cash restrictions brought about by increased collateral demands on various obligations.
Cash provided by investing activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from repayments of loans from related parties and proceeds from disposals of assets driven by the sale of Dominion Terminal Associates, which was offset by payments for additions to property, plant and equipment.
Cash used in investing activities during the nine months ended September 30, 2016 resulted primarily from federal coal lease and other capital expenditures of approximately $305 million, partially offset by proceeds from the disposal of our 5.06% participation interest in the Prairie State Energy Campus, as well as our disposal of interests in undeveloped metallurgical reserve tenements in Queensland’s Bowen Basin, which included the Olive Downs South, Olive Downs South Extended and Willunga tenements.
Cash used in financing activities in the Predecessor period January 1, 2017 through April 1, 2017 resulted from payments of Predecessor deferred financing costs associated with the new Successor debt entered into upon our emergence from the Chapter 11 Cases.
Cash provided by financing activities during the nine months ended September 30, 2016 resulted from proceeds from long-term debt, primarily due to the proceeds received from our Predecessor interim financing facility during the second quarter of 2016 and the net draws on our 2013 Predecessor Revolver during the first quarter of 2016.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to guarantees and financial instruments with off-balance-sheet risk, most of which are not reflected in the accompanying unaudited condensed consolidated balance sheets. We could experience a decline in our liquidity as financial assurances associated with reclamation bonding requirements, bank guarantees, surety bonds or other obligations are required to be collateralized by cash or letters of credit.
Guarantees and Other Financial Instruments with Off-Balance SheetOff-Balance-Sheet Risk. See Note 18.16. “Financial Instruments and Other Guarantees” to ourin the Company’s unaudited condensed consolidated financial statements for a discussion of ourits accounts receivable securitization program and guarantees and other financial instruments with off-balance sheetoff-balance-sheet risk.
Critical Accounting Policies and Estimates
OurThe Company’s discussion and analysis of ourits financial condition, results of operations, liquidity and capital resources is based upon ourits financial statements, which have been prepared in accordance with U.S. GAAP. We areThe Company is also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate ourthe Company evaluates its estimates. We base ourThe Company bases its estimates on historical experience and on various other assumptions that we believeit believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
OurAt June 30, 2021, the Company identified certain assets with an aggregate carrying value of approximately $1.2 billion in its Seaborne Metallurgical Mining, Powder River Basin Mining, Other U.S. Thermal Mining and Corporate and Other segments whose recoverability is most sensitive to coal pricing, cost pressures, customer demand, customer concentration risk and future economic viability. The Company conducted a review of those assets for recoverability as of June 30, 2021 and determined that no impairment charges were necessary as of that date.
The Company’s critical accounting policies are discussed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in ourits Annual Report on Form 10-K for the year ended December 31, 2016, as amended on July 10, 2017 and August 14, 2017. Our2020. The Company’s critical accounting policies remain unchanged at SeptemberJune 30, 2017, with the exception of the accounting policy elections described in the following paragraph that we made in connection with fresh start reporting. These elections impact the Successor period presented in the accompanying condensed consolidated financial statements and will impact prospective periods.2021.
We will classify the amortization associated with our asset retirement obligation assets within “Depreciation, depletion and amortization” in our consolidated statements of operations, rather than within “Asset retirement obligation expenses”, as in Predecessor periods. With respect to our accrued postretirement benefit and pension obligations, we will prospectively record amounts attributable to prior service cost and actuarial valuation changes, as applicable, currently in earnings rather than recording such amounts within accumulated other comprehensive income and amortizing to expense over applicable time periods.
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to ourthe Company’s unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Foreign Currency Risk
We haveThe Company has historically utilized currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 7. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Subsequent toAs of June 30, 2021, the Effective Date, we entered into a series of currency options and, as of September 30, 2017,Company had currency options outstanding with an aggregate notional amount of approximately $450 million and $675$580.0 million Australian dollars to hedge currency risk associated with anticipated Australian dollar expenditures duringover the remainder of 2017 andnine-month period ending March 31, 2022. Assuming the first half of 2018, respectively. Assuming weCompany had no foreign currency hedging instruments in place, ourits exposure in operating costs and expenses due to a $0.05$0.10 change in the Australian dollar/U.S. dollar exchange rate is approximately $95 to $105$130 million for the next twelve months. Taking into considerationBased upon the Australian dollar/U.S. dollar exchange rate at June 30, 2021, the currency option contracts put into place subsequent tooutstanding at that date would limit the Effective Date, ourCompany’s net exposure to a $0.10 unfavorable change in the exchange rate changesto approximately $104 million for the next twelve months is approximately $70 to $80 million.months.
Other Non-Coal Trading Activities — Diesel Fuel Price Risk
Diesel Fuel and Explosives Hedges. We have historically Previously, the Company managed price risk of the diesel fuel and explosives used in ourits mining activities through the use of cost pass-through contracts and from time to time, derivatives, primarily swaps.As of SeptemberJune 30, 2017, we no longer2021, the Company did not have any diesel fuel derivative instruments in place. The Company also manages the price risk of diesel fuel through the use of cost pass-through contacts with certain customers.
We expectThe Company expects to consume 12575 to 13585 million gallons of diesel fuel during the next twelve months. A $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease ourits annual diesel fuel costs by approximately $31$20 million based on ourits expected usage.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of ourThe Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) ofare designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the Securities Exchange Act of 1934, as amended) as of September 30, 2017. Based upon that evaluation, oursecurities laws to be disclosed is accumulated and communicated to senior management, including its principal executive and financial officers, on a timely basis. The Company’s Chief Executive Officer and Chief Financial Officer have concluded that ourevaluated its disclosure controls and procedures were not effective(as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of SeptemberJune 30, 2017 because of the material weaknesses in our internal control over financial reporting described below.
All systems of internal control, no matter how well designed, have inherent limitations. Therefore, even those systems deemed to be effective can provide only reasonable assurance with respect to financial statement preparation2021, and presentation. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim consolidated financial statements will not be prevented or detected on a timely basis.
Evaluation of the Internal Control over Financial Reporting
Management determined that the internal control around the reconciliation of tax basis balance sheets to deferred tax balances was not designed effectively and did not operate at a sufficient level of precision to prevent or detect a material misstatement on a timely basis. Specifically, an immaterial misstatement related to deferred tax liabilities of a single taxpayer outside of the consolidated Australian tax paying group was identified, which resulted in the understatement of the income tax valuation allowance required to reduce the carrying value of its deferred tax assets. The Company has subsequently revised its financial statements and related disclosures to correct these errors.
This control deficiency created a reasonable possibility that a material misstatement to the annual consolidated financial statements would not be prevented or detected on a timely basis. Accordingly, management concluded that this control deficiency represents a material weakness.
Management’s Plans for Remediation
Management has been engaged and will continue to advance remedial activities to address the material weakness described above. We believe the risk of a material weakness in subsequent periods will be mitigated by the implementation of an improved general ledger structure and a comprehensive analysis of all deferred tax positions. Additionally we have revised and enhanced the design of existingsuch controls and procedures were effective to properly apply accounting principles in this area, which includes strengthening our income tax controls with improved documentation standards, training and technical oversight.
The material weakness will not be considered fully remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. We expectprovide reasonable assurance that the remediation of this material weakness will be completed prior to the end of fiscal year 2017.
Changes in Internal Control Over Financial Reporting
Other than as discussed above,desired control objectives were achieved. Additionally, there have been no changes into the Company’s internal control over financial reporting during the three months ended September 30, 2017most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, ourits internal control over financial reporting.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
We areThe Company is subject to various legal and regulatory proceedings. For a description of ourits significant legal proceedings refer to Note 1. “Basis of Presentation,” Note 3. “Emergence from the Chapter 11 Cases and Fresh Start Reporting,” Note 5.4. “Discontinued Operations,”Operations” and Note 19.17. “Commitments and Contingencies” to the unaudited condensed consolidated financial statements included in Part I, Item 1. “Financial Statements” of this Quarterly Report, which information is incorporated by reference herein.
Item 1A. Risk Factors.
InThe Company operates in a rapidly changing environment that involves a number of risks. For information regarding factors that could affect the third quarterCompany's results of 2017, there were no significant changes to ouroperations, financial condition and liquidity, see the risk factors from those disclosed in Part I, Item 1A. “Risk Factors” in ourits Annual Report on Form 10-K for the year ended December 31, 20162020 filed with the SEC on March 22, 2017, in Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on April 11, 2017 and in our Annual Report on Form 10-K/A (Amendment No. 1) for the year ended December 31, 2016 filed with the SEC on July 10, 2017. The Risk Factors described in such Forms 8-K and 10-K/A restate certain Risk Factors included in our Annual Report on Form 10-K and are incorporated by reference herein.February 23, 2021. In addition to the other information set forth in this Quarterly Report, including the information presented in Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” you should carefully consider thosethe risk factors disclosed in the aforementioned filings,filing, which could materially affect the Company’s results of operations, financial condition and liquidity.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Dividends
The Company suspended dividends in 2020. As more fully described within “Liquidity and Capital Resources” of Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” during the fourth quarter of 2020, the Company entered into transaction support agreements with its surety bond providers which prohibit the payment of dividends through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in its credit facility and in the indentures governing its senior secured notes also limit the Company’s ability to pay cash dividends.
Share Repurchase ProgramsProgram
On August 1, 2017, wethe Company announced that ourits Board of Directors authorized a share repurchase program to allow repurchases of up to $500 million of the then outstanding shares of ourits common stock and/or preferred stock (Repurchase Program). RepurchasesOn April 25, 2018, the Company announced that the Board authorized the expansion of the Repurchase Program to $1.0 billion. On October 30, 2018, the Company announced that the Board authorized an additional expansion of the Repurchase Program to $1.5 billion. The Repurchase Program does not have an expiration date and may be made from timediscontinued at any time. Through June 30, 2021, the Company has repurchased 41.5 million shares of its common stock for $1,340.3 million, which included commissions paid of $0.8 million, leaving $160.5 million available for share repurchase under the Repurchase Program.
The Company suspended share repurchases in 2019, and similar to timethe payment of dividends as described above, the same agreements with its surety bond providers prohibit share repurchases through the earlier of December 31, 2025, or the maturity of the Credit Agreement (currently March 31, 2025) unless otherwise agreed to by the parties to the agreements. Additionally, restrictive covenants in its credit facility and in the indentures governing its senior secured notes also limit the Company’s ability to repurchase shares. Prior to the suspension, repurchases were made at the Company’s discretion. The specific timing, price and size of purchases will depend ondepended 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.
Issuances of Equity Securities
In June 2021, the Company announced an at-the-market equity offering program pursuant to which the Company could offer and sell up to 12.5 million shares of its common stock. Such sales are allowed using methods permissible under Rule 415 of the Securities Act. The shares are offered and sold pursuant to the Company’s Registration Statement on Form S-3, which was declared effective by the Securities and Exchange Commission on April 23, 2021, as they may be amended from timesupplemented by a prospectus supplement dated June 4, 2021, relating to time. The Repurchase Program does not have an expiration datethe offer and may be discontinued at any time.sale of the shares. During the three months ended SeptemberJune 30, 2017, we repurchased2021, the Company sold approximately 1.58.1 million shares for net cash proceeds of $65.1 million. Subsequent to June 30, 2021, the Company settled sales of an additional 2.7 million shares for net proceeds of $21.5 million.
Also during the three months ended June 30, 2021, the Company completed multiple bilateral transactions with holders of the 2022 Notes in which the Company issued an aggregate 4.5 million shares of our Common Stockits common stock in exchange for $40.0$30.9 million aggregate principal amount of the 2022 Notes. The issuance of shares of common stock in connectionexchange for the 2022 Notes was exempt from registration under the Securities Act, on the basis that the exchange was completed with existing holders of the Company’s securities, and no commission or other remuneration was paid or given for soliciting the exchange. Subsequent to June 30, 2021, the Company issued an underwritten secondary offering and made additional open-market purchases of approximately 1.0aggregate 0.5 million shares of our Common Stockits common stock in exchange for $29.2 million. Subsequent to September 30, 2017 and through October 30, 2017, we have purchased an additional 1.3$4.0 million sharesaggregate principal amount of our Common Stock for $37.7 million. The purchases were madethe 2022 Notes in compliance with our debt provisions that limit our ability to repurchase shares following the Plan Effective Date. See “Risk Factors — The potential 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” in Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on April 11, 2017.
similar manner as noted above.
Share Relinquishments
WeThe Company routinely allowallows employees to relinquish common stock to pay estimated taxes upon the vesting of equity awardsrestricted stock units and upon the issuancepayout of performance units that are settled in common stock related to ourunder its equity incentive plans. The value of common stock tendered by employees is determined based on the closing price of ourthe Company’s common stock on the dates of the respective relinquishments.
Purchases of Equity Securities
The following table summarizes all share purchases for the three months ended SeptemberJune 30, 2017:2021:
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Period | | Total Number of Shares Purchased (1) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Program | | Maximum Dollar Value that May Yet Be Used to Repurchase Shares Under the Publicly Announced Program (In millions) |
April 1 through April 30, 2021 | | 2,649 | | | $ | 3.01 | | | — | | | $ | 160.5 | |
May 1 through May 31, 2021 | | 295 | | | 6.63 | | | — | | | 160.5 | |
June 1 through June 30, 2021 | | 96,549 | | | 7.41 | | | — | | | 160.5 | |
Total | | 99,493 | | | 7.29 | | | — | | | |
(1)Includes shares withheld to cover the withholding taxes upon the vesting of equity awards, which are not part of the Repurchase Program.
Item 4. Mine Safety Disclosures.
Item 6. Exhibits.
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.