PEABODY ENERGY CORPORATION As used in this report, the terms "Peabody" or "the Company" refer toPeabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to the Company's continuing operations. When used in this filing, the term "ton" refers to 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 Peabody's expectations, intentions, plans and beliefs that constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 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 Peabody's future financial performance, including, without limitation, the section captioned "Outlook" in this Item 2. 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 Peabody'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 Peabody 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 the Company's control. Factors that could affect its results or an investment in its securities include, but are not limited to: •the Company's profitability depends upon the prices it receives for its coal; •if a substantial number of the Company's long-term coal supply agreements, including those with its largest customers, terminate, or if the pricing, volumes or other elements of those agreements materially adjust, its revenues and operating profits could suffer if the Company is unable to find alternate buyers willing to purchase its coal on comparable terms to those in its contracts; •risks inherent to mining could increase the cost of operating the Company's business, and events and conditions that could occur during the course of its mining operations could have a material adverse impact on the Company; •the Company's take-or-pay arrangements could unfavorably affect its profitability; •the Company may not recover its investments in its mining, exploration and other assets, which may require the Company to recognize impairment charges related to those assets; •the Company could be negatively affected if it fails to maintain satisfactory labor relations; •the Company could be adversely affected if it fails to appropriately provide financial assurances for its obligations; •the Company's mining operations are extensively regulated, which imposes significant costs on it, and future regulations and developments could increase those costs or limit its ability to produce coal; •the Company's operations may impact the environment or cause exposure to hazardous substances, and its properties may have environmental contamination, which could result in material liabilities to the Company; •the Company may be unable to obtain, renew or maintain permits necessary for its operations, or the Company may be unable to obtain, renew or maintain such permits without conditions on the manner in which it runs its operations, which would reduce its production, cash flows and profitability; •concerns about the impacts of coal combustion on global climate are increasingly leading to consequences that have affected and could continue to affect demand for the Company's products or its securities and its ability to produce, including increased governmental regulation of coal combustion and unfavorable investment decisions by electricity generators; •numerous activist groups are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal, and potentially materially and adversely impacting the Company's future financial results, liquidity and growth prospects; •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 the Company's asset retirement obligations for reclamation and mine closures are materially inaccurate, its costs could be significantly greater than anticipated; 27 -------------------------------------------------------------------------------- •the Company's future success depends upon its ability to continue acquiring and developing coal reserves that are economically recoverable; •the Company faces numerous uncertainties in estimating its economically recoverable coal reserves and inaccuracies in its estimates could result in lower than expected revenues, higher than expected costs and decreased profitability; •joint ventures, partnerships or non-managed operations may not be successful and may not comply with the Company's operating standards; •the Company may undertake further repositioning plans that would require additional charges; •the Company's business, results of operations, financial condition and prospects could be materially and adversely affected by the coronavirus (COVID-19) pandemic and the related effects on public health; •the Company's expenditures for postretirement benefit obligations could be materially higher than it has predicted if its underlying assumptions prove to be incorrect; •the Company is subject to various general operating risks which may be fully or partially outside of its control; •the Company's financial performance could be adversely affected by its funded indebtedness (Indebtedness); •despite the Company's Indebtedness, it may still be able to incur more debt, which could further increase the risks associated with its Indebtedness; •the terms of the indentures governing the Company's senior secured notes and the agreements and instruments governing its other Indebtedness and surety bonding obligations impose restrictions that may limit its operating and financial flexibility; •the 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 byNew York Stock Exchange listing requirements; •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; •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 its deferred tax assets; •acquisitions and divestitures are a potentially important part of the Company's long-term strategy, subject to its investment criteria, and involve a number of risks, any of which could cause the Company not to realize the anticipated benefits; •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 may impact the Company's reported financial results; 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 the Company's otherSecurities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect its results contained in Item 1A. "Risk Factors" and Item 3. "Legal Proceedings" of its Annual Report on Form 10-K for the year endedDecember 31, 2020 filed with theSEC onFebruary 23, 2021 . These forward-looking statements speak only as of the date on which such statements were made, and the Company undertakes no obligation to update these statements except as required by federal securities laws. 28
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Overview
Peabody is a leading coal producer. In 2020, the Company produced and sold 128.8 million and 132.6 million tons of coal, respectively, from continuing operations. AtMarch 31, 2021 , the Company owned interests in 17 active coal mining operations located inthe United States (U.S. ) andAustralia . Included in that count is Peabody's 50% equity interest inMiddlemount Coal Pty Ltd. (Middlemount), which owns theMiddlemount Mine inQueensland, Australia . In addition to its mining operations, the Company markets and brokers coal from other coal producers, both as principal and agent, and trades coal and freight-related contracts. The Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal Mining, Seaborne Metallurgical Mining, PowderRiver Basin Mining , OtherU.S. Thermal Mining and Corporate and Other. Refer to Note 18. "Segment Information" to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of its Corporate and Other segment. 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$6.5 million during the three months endedMarch 31, 2021 and 2020, respectively, related to workforce reductions made across the organization through the use of 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 restart of mine production and coal shipments is contingent upon successful completion of these initiatives and stable customer demand. Included in the initiatives is a preparation plant upgrade project, which is anticipated to be commissioned by the middle of the third quarter of 2021. Additionally, theShoal Creek labor contract expired onApril 1, 2021 and negotiations with the workforce are ongoing. While discussions are ongoing with customers and workforce, theMetropolitan Mine full workforce returned to the mine in early May. Development work at the mine has been ongoing through the idle period and longwall production is anticipated to restart in the second quarter of 2021, with ramp up to full production in the third quarter of 2021. Results of Operations Non-GAAP Financial Measures The following discussion of the Company's results of operations includes references to and analysis of Adjusted EBITDA, which is a financial measure not recognized in accordance withU.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by management as the primary metric to measure each of its segments' operating performance. 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 its operating performance and lenders to measure its ability to incur and service debt. These measures are not intended to serve as alternatives toU.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the "Reconciliation of Non-GAAP Financial Measures" section contained within this Item 2 for definitions and reconciliations to the most comparable measures underU.S. GAAP. 29
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Three Months EndedMarch 31, 2021 Compared to the Three Months EndedMarch 31, 2020 Summary Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal andIllinois Basin 11,500 Btu/Lb coal during the three months endedMarch 31, 2021 is set forth in the table below. The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months endedMarch 31, 2021 due to quality differentials and the majority of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically. The Company's typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. In theU.S. , the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months endedMarch 31, 2021 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in theU.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company's realized pricing. High Low
Average
Premium HCC (1)$ 158.70 $ 99.50 $
127.57
Premium PCI coal (1) 110.50 91.50 103.22 110.50 Newcastle index thermal coal (1) 103.95 80.78 88.50 100.59 API 5 thermal coal (1) 59.32 50.75 54.65 56.00 PRB 8,800 Btu/Lb coal (2) 11.95 11.85 11.91 11.95
32.00
(1) Prices expressed per tonne.
(2) Prices expressed per ton.
Within the global coal industry, supply and demand disruptions have been
widespread as the COVID-19 pandemic has forced country-wide lockdowns and
regional restrictions. Future COVID-19-related developments are unknown,
including the duration, severity, scope and the necessary government actions to
limit the spread of COVID-19. The global coal industry data for the three months
ended March 31, 2021 presented herein may not be indicative of the ultimate
impacts of the COVID-19 pandemic given the various levels of response and
unknown duration, and the potential for continued weak demand for the Company's
products.
Within the seaborne metallurgical coal market, the imbalance between Australian
export and Chinese delivered prices remains wide, with the delivered price into
China trading at roughly double those seen free on board Australia as the
unofficial ban on Australian coals remains in place. In addition, increased
COVID-19 concerns in India are further weighing on Australian hard coking coal
pricing. These factors continue to pressure the seaborne metallurgical coal
market despite global steel production increasing 5% year-over-year.
In contrast, the spread between Australian hard coking coal pricing and low-vol
PCI has recently narrowed to near parity. Tight low-vol PCI supply, coupled with
China paying a premium for Russian coals, have contributed to rising low-vol PCI
prices.
Within the seaborne thermal coal market, tight supplies and low inventory levels
have kept Newcastle thermal coal pricing at improved levels year-to-date.
China's domestic thermal coal supply remains hampered by heightened safety
inspections. In addition, India's thermal coal stockpiles have been falling
gradually since mid-December as government-owned plants have reduced intake and
there has been a delay in typical restocking ahead of the monsoon season in
June. As of the end of March 2021 , India's plant inventory levels were estimated
at approximately 15 days burn versus 28 days a year ago.
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Inthe United States , overall electricity demand increased 2% year-over-year, positively impacted by cold weather during the three months endedMarch 31, 2021 . Electricity generation from thermal coal has increased by 37% year-over-year as a result of higher natural gas prices. This has positively impacted coal's share of electricity generation, with a rise to approximately 24% for the three months endedMarch 31, 2021 , while causing natural gas's share to decline to approximately 34%. Stronger coal use has contributed to decreasing coal stockpile levels. SinceDecember 2020 , coal inventories have fallen by approximately 20 million tons. Through the three months endedMarch 31, 2021 , utility consumption of PRB coal rose approximately 35% compared to the prior year period. The Company's revenues for the three months endedMarch 31, 2021 decreased compared to the same periods in 2020 ($194.9 million ) primarily due to lower sales volumes and lower realized prices. Results from continuing operations, net of income taxes for the three months endedMarch 31, 2021 increased compared to the same period in the prior year ($51.6 million ) as the result of lower operating costs and expenses due largely to the sales volume decline as well as production efficiencies and other cost improvements ($196.9 million ) and lower depreciation, depletion and amortization ($37.7 million ). These favorable variances were offset by the unfavorable revenue variance described above and increased interest expense ($19.3 million ) primarily resulting from fees related to new debt arrangements entered into during the three months endedMarch 31, 2021 . Adjusted EBITDA for the three months endedMarch 31, 2021 reflected a year-over-year increase of$24.3 million . As ofMarch 31, 2021 , the Company's available liquidity was approximately$604 million . Refer to the "Liquidity and Capital Resources" section contained within this Item 2 for a further discussion of factors affecting the Company's available liquidity. Tons Sold The following table presents tons sold by operating segment: Three Months Ended Decrease March 31, to Volumes 2021 2020 Tons % (Tons in millions) Seaborne Thermal Mining 4.1 4.6 (0.5) (11) % Seaborne Metallurgical Mining 1.0 2.0 (1.0) (50) % Powder River Basin Mining 20.7 23.5 (2.8) (12) % Other U.S. Thermal Mining 3.9 4.9 (1.0) (20) % Total tons sold from mining segments 29.7 35.0 (5.3) (15) % Corporate and Other 0.5 0.6 (0.1) (17) % Total tons sold 30.2 35.6 (5.4) (15) % 31
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Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Three Months Ended (Decrease)
March 31, Increase
2021 2020 $ %
Revenues per Ton - Mining Operations (1)
Seaborne Thermal $ 43.36 $ 44.10 $ (0.74) (2) %
Seaborne Metallurgical 87.47 95.65 (8.18) (9) %
Powder River Basin 11.01 11.36 (0.35) (3) %
Other U.S. Thermal 38.76 39.25 (0.49) (1) %
Costs per Ton - Mining Operations (1)(2)
Seaborne Thermal $ 36.36 $ 32.03 $ 4.33 14 %
Seaborne Metallurgical 109.89 111.82 (1.93) (2) %
Powder River Basin 9.56 10.28 (0.72) (7) %
Other U.S. Thermal 29.37 31.39 (2.02) (6) % Adjusted EBITDA Margin per Ton - Mining Operations (1)(2) Seaborne Thermal
$ 7.00 $ 12.07 $ (5.07) (42) % Seaborne Metallurgical (22.42) (16.17) (6.25) (39) % Powder River Basin 1.45 1.08 0.37 34 % Other U.S. Thermal 9.39 7.86 1.53 19 % (1)This is an operating/statistical measure not recognized in accordance withU.S. GAAP. Refer to the "Reconciliation of Non-GAAP Financial Measures" section below for definitions and reconciliations to the most comparable measures underU.S. GAAP. (2)Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. Revenues The following table presents revenues by reporting segment: Three Months Ended (Decrease) Increase March 31, to Revenues 2021 2020 $ % (Dollars in millions) Seaborne Thermal Mining$ 176.4 $ 201.1 $ (24.7) (12) % Seaborne Metallurgical Mining 87.5 193.2 (105.7) (55) % Powder River Basin Mining 228.4 266.6 (38.2) (14) % Other U.S. Thermal Mining 149.3 192.3 (43.0) (22) % Corporate and Other 9.7 (7.0) 16.7 239 % Revenues$ 651.3 $ 846.2 $ (194.9) (23) % Seaborne Thermal Mining. Segment revenues decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year due to unfavorable volume and mix variances ($18.6 million ) and unfavorable realized coal pricing ($6.1 million ). Seaborne Metallurgical Mining. Segment revenues decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year due to unfavorable volume and mix variances ($101.3 million ) and unfavorable realized coal pricing ($4.4 million ). The unfavorable volume variances resulted from the idling of theShoal Creek andMetropolitan Mines during the fourth quarter of 2020, lower demand and the closure of theMillennium Mine during the second quarter of 2020. 32
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PowderRiver Basin Mining . Segment revenues decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year primarily due to lower demand ($31.6 million ) and unfavorable realized coal pricing ($6.6 million ). OtherU.S. Thermal Mining. Segment revenues decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year primarily due to lower demand. Corporate and Other. Segment revenues increased during the three months endedMarch 31, 2021 compared to the same period in the prior year primarily due to higher results from trading activities. Adjusted EBITDA The following table presents Adjusted EBITDA for each of the Company's reporting segments: Three Months Ended (Decrease) Increase March 31, to Segment Adjusted EBITDA 2021 2020 $ % (Dollars in millions) Seaborne Thermal Mining$ 28.5 $ 55.1 $ (26.6) (48) % Seaborne Metallurgical Mining (22.4) (32.7) 10.3 31 % Powder River Basin Mining 30.1 25.4 4.7 19 % Other U.S. Thermal Mining 36.2 38.5 (2.3) (6) % Corporate and Other (11.3) (49.5) 38.2 77 % Adjusted EBITDA (1)$ 61.1 $ 36.8 $ 24.3 66 % (1)This is a financial measure not recognized in accordance withU.S. GAAP. Refer to the "Reconciliation of Non-GAAP Financial Measures" section below for definitions and reconciliations to the most comparable measures underU.S. GAAP. Seaborne Thermal Mining. Segment Adjusted EBITDA decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year as a result of unfavorable foreign currency impacts ($16.5 million ), unfavorable volume variances ($14.6 million ) and lower realized net coal pricing ($5.6 million ). The decrease was partially offset by various cost improvements ($7.5 million ). Seaborne Metallurgical Mining. Segment Adjusted EBITDA increased during the three months endedMarch 31, 2021 compared to the same period in the prior year due to cost improvements at certain mines ($18.6 million ) and lower costs for materials, services, repairs and labor ($21.2 million ) as a result of the idling of theMetropolitan Mine during the fourth quarter of 2020 and the closure of theMillennium Mine during the second quarter of 2020. The increase was offset by unfavorable foreign currency impacts ($28.2 million ). PowderRiver Basin Mining . Segment Adjusted EBITDA increased during the three months endedMarch 31, 2021 compared to the same period in the prior year due to lower costs for materials, services, repairs and labor ($7.4 million ) and favorable mine sequencing impacts ($3.8 million ). The increase was partially offset by the impact of lower volumes ($4.9 million ) and lower realized net coal pricing ($3.8 million ). OtherU.S. Thermal Mining. Segment Adjusted EBITDA decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year due to unfavorable volume and mix variances ($21.5 million ), offset by lower costs for materials, services, repairs and labor ($21.3 million ). 33
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Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
Three Months Ended Increase (Decrease)
March 31, to Adjusted EBITDA
2021 2020 $ %
(Dollars in millions)
Middlemount (1) $ (2.3) $ (9.7) $ 7.4 76 %
Resource management activities (2) 0.4 8.0 (7.6) (95) %
Selling and administrative expenses (21.7) (24.9) 3.2 13 %
Other items, net (3) 12.3 (22.9) 35.2 154 %
Corporate and Other Adjusted EBITDA $ (11.3) $ (49.5) $ 38.2 77 %
(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$11.7 million and$4.4 million during the three months endedMarch 31, 2021 and 2020, respectively. (2)Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. (3)Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including theNorth Goonyella Mine and expenses related to the Company's other commercial activities. The increase in Corporate and Other Adjusted EBITDA during the three months endedMarch 31, 2021 compared to the same period in the prior year was primarily driven by favorable trading results ($12.1 million ); lower postretirement healthcare costs ($11.3 million ) primarily due to changes made to one of the Company's postretirement health care benefit plans during the third quarter of 2020; a favorable variance in Middlemount's results due to the combined impact of improved production and cost improvements; lower containment and holding costs for theCompany's North Goonyella Mine ($6.1 million ); and favorable corporate hedging results ($5.7 million ). These favorable results were partially offset by resource management gains recorded in the prior year period ($7.5 million ). 34
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Loss From Continuing Operations, Net of Income Taxes
The following table presents loss from continuing operations, net of income
taxes:
Three Months Ended Increase (Decrease)
March 31, to Income
2021 2020 $ %
(Dollars in millions)
Adjusted EBITDA (1) $ 61.1 $ 36.8 $ 24.3 66 %
Depreciation, depletion and amortization (68.3) (106.0) 37.7 36 %
Asset retirement obligation expenses (15.9) (17.6) 1.7 10 %
Restructuring charges (2.1) (6.5) 4.4 68 %
Transaction costs related to joint ventures - (4.2) 4.2 100 %
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates 1.5 0.7 0.8 114 % Interest expense (52.4) (33.1) (19.3) (58) % Gain on early debt extinguishment 3.5 - 3.5 n.m. Interest income 1.5 3.1 (1.6) (52) % Unrealized losses on economic hedges (1.9) (2.2) 0.3 14 %
Unrealized (losses) gains on non-coal trading derivative contracts
(7.6) 0.1 (7.7) (7,700) %
Take-or-pay contract-based intangible recognition 1.1 2.6 (1.5) (58) %
Income tax benefit (provision) 1.8 (3.0) 4.8 160 %
Loss from continuing operations, net of income taxes $ (77.7) $ (129.3) $ 51.6 40 %
(1)This is a financial measure not recognized in accordance with U.S. GAAP.
Refer to the "Reconciliation of Non-GAAP Financial Measures" section below for
definitions and reconciliations to the most comparable measures under U.S. GAAP.
Depreciation, Depletion and Amortization. The following table presents a summary
of depreciation, depletion and amortization expense by segment:
Three Months Ended Increase (Decrease)
March 31, to Income
2021 2020 $ %
(Dollars in millions)
Seaborne Thermal Mining $ (21.1) $ (22.2) $ 1.1 5 %
Seaborne Metallurgical Mining (16.5) (24.8) 8.3 33 %
Powder River Basin Mining (9.6) (35.2) 25.6 73 %
Other U.S. Thermal Mining (17.2) (21.4) 4.2 20 %
Corporate and Other (3.9) (2.4) (1.5) (63) %
Total $ (68.3) $ (106.0) $ 37.7 36 %
Additionally, the following table presents a summary of the Company's
weighted-average depletion rate per ton for active mines in each of its mining
segments:
Three Months Ended
March 31,
2021 2020
Seaborne Thermal Mining $ 1.87 $ 1.90
Seaborne Metallurgical Mining 1.00 2.68
Powder River Basin Mining 0.23 0.79
Other U.S. Thermal Mining 1.12 1.06
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Depreciation, depletion and amortization expense decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year primarily due to the impact of the asset impairment recorded at theNorth Antelope Rochelle Mine during the second quarter of 2020 ($25.2 million ) and decreased depletion driven by lower sales volumes ($6.6 million ). The decrease in the weighted-average depletion rate per ton for the Seaborne Metallurgical Mining segment during the three months endedMarch 31, 2021 compared to the same period in the prior year reflects the volume and mix variances which impacted the Company's revenues as described above. The decrease in the weighted-average depletion rate per ton for the PowderRiver Basin Mining segment during the three months endedMarch 31, 2021 compared to the same period in the prior year reflects the asset impairment recorded during the second quarter of 2020. Restructuring Charges. Restructuring charges decreased during the three months endedMarch 31, 2021 compared to the same period in the prior year as the result of workforce reductions made across the organization during the prior year through the use of involuntary and voluntary reductions, as discussed in Note 14. "Other Events" to the accompanying unaudited condensed consolidated financial statements. 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. Interest Expense. Interest expense increased during the three months endedMarch 31, 2021 compared to the same period in the prior year as the result of a series of refinancing transactions completed by the Company during the first quarter of 2021, which included a senior notes exchange, a revolving credit facility exchange and various amendments to the Company's existing debt agreements as further discussed in Note 11. "Long-term Debt" to the accompanying unaudited condensed consolidated financial statements. Gain on Early Debt Extinguishment. The gain recognized during the three months endedMarch 31, 2021 related to the senior notes exchange completed during the first quarter of 2021 as further discussed in Note 11. "Long-term Debt" to the accompanying unaudited condensed consolidated financial statements. Unrealized (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. For additional information, refer to Note 7. "Derivatives and Fair Value Measurements" to the accompanying unaudited condensed consolidated financial statements. Income Tax Benefit (Provision). The decrease in the income tax provision for the three months endedMarch 31, 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 10. "Income Taxes" to the accompanying unaudited condensed consolidated financial statements for additional information. Net Loss Attributable to Common Stockholders The following table presents net loss attributable to common stockholders: Three Months Ended Increase March 31, to Income 2021 2020 $ % (Dollars in millions) Loss from continuing operations, net of income taxes$ (77.7) $ (129.3) $ 51.6 40 % Loss from discontinued operations, net of income taxes (2.0) (2.2) 0.2 9 % Net loss (79.7) (131.5) 51.8
39 % Less: Net income (loss) attributable to noncontrolling interests
0.4 (1.8) 2.2 122 %
Net loss attributable to common stockholders $ (80.1) $ (129.7) $ 49.6 38 %
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Diluted Earnings per Share (EPS)
The following table presents diluted EPS:
Three Months Ended Increase
March 31, to EPS
2021 2020 $ %
Diluted EPS attributable to common stockholders:
Loss from continuing operations $ (0.79) $ (1.31) $ 0.52 40 %
Loss from discontinued operations (0.02) (0.02) - - %
Net loss attributable to common stockholders $ (0.81) $ (1.33) $ 0.52 39 %
Diluted EPS is commensurate with the changes in results from continuing operations and discontinued operations during that period. Diluted EPS reflects weighted average diluted common shares outstanding of 98.4 million and 97.2 million for the three months endedMarch 31, 2021 and 2020, respectively. Reconciliation of Non-GAAP Financial Measures Adjusted 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 segment's operating performance, as displayed in the reconciliations below. Three Months Ended March 31, 2021 2020 (Dollars in millions) Loss from continuing operations, net of income taxes$ (77.7) $ (129.3) Depreciation, depletion and amortization 68.3 106.0 Asset retirement obligation expenses 15.9 17.6 Restructuring charges 2.1 6.5 Transaction costs related to joint ventures - 4.2
Changes in deferred tax asset valuation allowance and reserves and amortization of basis difference related to equity affiliates
(1.5) (0.7)
Interest expense 52.4 33.1
Gain on early debt extinguishment (3.5) -
Interest income (1.5) (3.1)
Unrealized losses on economic hedges 1.9 2.2
Unrealized losses (gains) on non-coal trading derivative contracts
7.6 (0.1)
Take-or-pay contract-based intangible recognition (1.1) (2.6)
Income tax (benefit) provision (1.8) 3.0
Total Adjusted EBITDA $ 61.1 $ 36.8
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Revenues per Ton and Adjusted EBITDA Margin per Ton are equal to revenues by
segment and Adjusted EBITDA by segment, respectively, divided by segment tons
sold. Costs per Ton is equal to Revenues per Ton less Adjusted EBITDA Margin per
Ton, and are reconciled to operating costs and expenses as follows:
Three Months Ended
March 31,
2021 2020
(Dollars in millions)
Operating costs and expenses $ 582.6 $ 779.5 Unrealized (losses) gains on non-coal trading derivative contracts
(7.6) 0.1
Take-or-pay contract-based intangible recognition 1.1 2.6
Net periodic benefit (credit) costs, excluding service cost (8.7) 2.8
Total Reporting Segment Costs $ 567.4 $ 785.0 The following table presents Reporting Segment Costs by reporting segment:
Three Months Ended
March 31,
2021 2020
(Dollars in millions)
Seaborne Thermal Mining $ 147.9 $ 146.0
Seaborne Metallurgical Mining 109.9 225.9
Powder River Basin Mining 198.3 241.2
Other U.S. Thermal Mining 113.1 153.8
Corporate and Other (1.8) 18.1
Total Reporting Segment Costs $ 567.4 $ 785.0 The following tables present tons sold, revenues, Reporting Segment Costs and Adjusted EBITDA by mining segment:
Three Months Ended
Seaborne
Seaborne Metallurgical Powder River Other U.S.
Thermal Mining Mining Basin Mining Thermal Mining
(Amounts in millions, except per ton data)
Tons sold 4.1 1.0 20.7 3.9
Revenues $ 176.4 $ 87.5 $ 228.4 $ 149.3
Reporting Segment Costs 147.9 109.9 198.3 113.1
Adjusted EBITDA $ 28.5 $ (22.4) $ 30.1 $ 36.2
Revenues per Ton $ 43.36 $ 87.47 $ 11.01 $ 38.76
Costs per Ton 36.36 109.89 9.56 29.37
Adjusted EBITDA Margin per Ton $ 7.00 $ (22.42) $ 1.45 $ 9.39
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Three Months Ended
Seaborne
Seaborne Metallurgical Powder River Other U.S.
Thermal Mining Mining Basin Mining Thermal Mining
(Amounts in millions, except per ton data)
Tons sold 4.6 2.0 23.5 4.9
Revenues $ 201.1 $ 193.2 $ 266.6 $ 192.3
Reporting Segment Costs 146.0 225.9 241.2 153.8
Adjusted EBITDA $ 55.1 $ (32.7) $ 25.4 $ 38.5
Revenues per Ton $ 44.10 $ 95.65 $ 11.36 $ 39.25
Costs per Ton 32.03 111.82 10.28 31.39
Adjusted EBITDA Margin per Ton $ 12.07 $
(16.17)
Free Cash Flow is defined as net cash provided by (used in) operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. See the table below for a reconciliation of Free Cash Flow to its most comparable measure underU.S. GAAP. Three Months EndedMarch 31, 2021 2020 (Dollars in millions)
Net cash provided by (used in) operating activities $ 71.0 $ (4.7)
Net cash used in investing activities (93.2) (37.1)
Free Cash Flow $ (22.2) $ (41.8) Outlook
As part of its normal planning and forecasting process, Peabody utilizes a broad approach to develop macroeconomic assumptions for key variables, including country-level gross domestic product, industrial production, fixed asset investment and third-party inputs, driving detailed supply and demand projections for key demand centers for coal, electricity generation and steel. Specific to theU.S. , the Company evaluates individual plant needs, including expected retirements, on a plant by plant basis in developing its demand models. Supply models and cost curves concentrate on major supply regions/countries that impact the regions in which the Company operates. The Company's estimates involve risks and uncertainties and are subject to change based on various factors as summarized in the "Cautionary Notice Regarding Forward-Looking Statements" section contained within this Item 2. The Company's near-term outlook is intended to coincide with the next 12 to 24 months, with subsequent periods addressed in its long-term outlook. Peabody is continuing to monitor the rapidly evolving COVID-19 pandemic and any impacts related to both its near-term and long-term outlook. Near-Term Outlook Within the global coal industry, supply and demand disruptions have been widespread as the COVID-19 pandemic has forced country-wide lockdowns and regional restrictions. Future COVID-19-related developments are unknown, including the duration, severity, scope and the necessary government actions to limit the spread of COVID-19. Within the seaborne metallurgical coal market, the imbalance between Australian export and Chinese delivered prices remains wide, with the delivered price intoChina trading at roughly double those seen free on boardAustralia as the unofficial ban on Australian coals remains in place. In addition, increased COVID-19 concerns inIndia are further weighing on Australian hard coking coal pricing. These factors continue to pressure the seaborne metallurgical coal market despite global steel production increasing 5% year-over-year. In contrast, the spread between Australian hard coking coal pricing and low-vol PCI has recently narrowed to near parity. Tight low-vol PCI supply, coupled withChina paying a premium for Russian coals, have contributed to rising low-vol PCI prices. 39
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Within the seaborne thermal coal market, tight supplies and low inventory levels have kept Newcastle thermal coal pricing at improved levels year-to-date.China's domestic thermal coal supply remains hampered by heightened safety inspections. In addition,India's thermal coal stockpiles have been falling gradually since mid-December as government-owned plants have reduced intake and there has been a delay in typical restocking ahead of the monsoon season in June. As of the end ofMarch 2021 ,India's plant inventory levels were estimated at approximately 15 days burn versus 28 days a year ago. Inthe United States , overall electricity demand increased 2% year-over-year, positively impacted by cold weather during the three months endedMarch 31, 2021 . Electricity generation from thermal coal has increased by 37% year-over-year as a result of higher natural gas prices. This has positively impacted coal's share of electricity generation, with a rise to approximately 24% for the three months endedMarch 31, 2021 , while causing natural gas's share to decline to approximately 34%. Stronger coal use has contributed to decreasing coal stockpile levels. SinceDecember 2020 , coal inventories have fallen by approximately 20 million tons. Through the three months endedMarch 31, 2021 , utility consumption of PRB coal rose approximately 35% compared to the prior year period. Ultimately,U.S. thermal coal demand will be dependent on general economic conditions, weather, natural gas prices, utility inventory levels and other factors. Long-Term Outlook There were no significant changes to the Company's Long-Term Outlook subsequent toDecember 31, 2020 . Information regarding the Company's Long-Term Outlook is outlined in Part II. Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" in its Annual Report on Form 10-K for the year endedDecember 31, 2020 . Regulatory Update Other than as described in the following section, there were no significant changes to the Company's regulatory matters subsequent toDecember 31, 2020 . Information regarding the Company's regulatory matters is outlined in Part I, Item 1. "Business" in its Annual Report on Form 10-K for the year endedDecember 31, 2020 . Regulatory Matters -U.S. Clean Air Act (CAA). The CAA, enacted in 1970, and comparable state and tribal laws that regulate air emissions affect the Company'sU.S. coal mining operations both directly and indirectly. The Clean Air Act requires theEPA 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, theEPA in 2020 proposed to retain the ozone standards promulgated in 2015, including current secondary standards, and subsequently promulgated final standards to this effect. Fifteen states and other petitioners have filed a petition for review of the rule in the D.C. Circuit,State of New York v.EPA , No. 21-1028. TheEPA also proposed to retain the particulate matter (PM) standards promulgated in 2012. OnDecember 18, 2020 , theEPA issued a final rule to retain both the primary annual and 24-hour PM standards for fine particulate matter (PM2.5) and the primary 24-hour standard for coarse particulate matter (PM10) and secondary PM10 standards. This rule has also been challenged in the D.C. Circuit by several states and environmental organizations,State of California v.EPA , No. 21-2014. More stringent PM or ozone standards would require new state implementation plans to be developed and filed with theEPA and may trigger additional control technology for mining equipment or result in additional challenges to permitting and expansion efforts. This could also be the case with respect to the implementation for other NAAQS for nitrogen oxide and SO2 although theEPA promulgated a final rule onMarch 18, 2019 that retains, without revision, the existing NAAQS for SO2 of 75 ppb averaged over an hour.EPA Regulation of Greenhouse Gas Emissions from Existing Fossil Fuel-Fired EGUs. OnOctober 23, 2015 , theEPA published a final rule in theFederal Register regulating greenhouse gas emissions from existing fossil fuel-fired EGUs under Section 111(d) of the CAA (80 Fed. Reg. 64,662 (Oct. 23, 2015 )). The rule (known as the Clean Power Plan or CPP) established emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired EGUs. The CPP required that the states individually or collectively create systems that would reduce carbon emissions from any EGU located within their borders by 28% in 2025 and 32% in 2030 (compared with a 2005 baseline). 40
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TheEPA has since proposed to repeal the CPP and inAugust 2018 issued a proposed rule to replace the CPP, with the Affordable Clean Energy (ACE) Rule. InJune 2019 , theEPA 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). TheEPA 's final rule also revises certain regulations to give the states greater flexibility on the content and timing of their state plans. Based on theEPA 's final rules repealing and replacing the CPP, petitioners in the D.C. Circuit matter seeking review of CPP, including the Company, filed a motion to dismiss, which the court granted inSeptember 2019 . Numerous petitions for review challenging the ACE Rule were filed in the D.C. Circuit and subsequently consolidated. InJanuary 2021 , a 3-judge panel of the D.C. Circuit vacated and remanded the ACE Rule to theEPA , including its repeal of the CPP and amendments to the implementing regulations that extended the compliance timeline. Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule. In 2011, theEPA finalized the CSAPR, which requires theDistrict of Columbia and 27 states fromTexas eastward (not including theNew England states orDelaware ) to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine particle pollution in other states. In 2016, theEPA published the final CSAPR Update Rule which imposed reductions in nitrogen oxides emissions beginning in 2017 in 22 states subject to CSAPR. InOctober 2020 , theEPA proposed a rule to address a previousD.C. Circuit remand as well as NOx emissions in 21 states targeted by the CSAPR Update Rule. OnMarch 15, 2021 , theEPA signed a final rule which determined that 9 states do not significantly contribute to downwind nonattainment and/or maintenance issues and therefore do not need additional emission reductions. For 12 other states, however,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). TheEPA published the final MATS rule in theFederal Register in 2012. The MATS rule revised the NSPS for nitrogen oxides, SO2 and PM for new and modified coal-fueled electricity generating plants, and imposed MACT emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. In 2020, theEPA issued a final rule reversing a prior finding and determined that it is not "appropriate and necessary" under the CAA to regulate HAP emissions from coal- and oil-fired power plants. This rule also finalized residual risk and technology review standards for the coal- and oil-fired EGU source category. Both actions have been challenged in the D.C. Circuit and placed in abeyance. CWA Definition of "Waters ofthe United States ". InJanuary 2020 theEPA and the Corps finalized the Navigable Waters Protection Rule to revise the definition of "Waters ofthe United States " and thereby establish the scope of federal regulatory authority under the CWA. A federal district judge inColorado preliminarily enjoined the Navigable Waters Protection Rule in theState of Colorado onJune 19, 2020 , but the new rule took effect in all other states onJune 22, 2020 .The U.S. Court of Appeals for the Tenth Circuit reversed the preliminary injunction inColorado onMarch 2, 2021 , so the Navigable Waters Protection Rule is in effect nationwide. Litigation over the 2020 Navigable Waters Protection Rule remains pending in several federal district courts. Regulatory Matters -Australia The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines) and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed. 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 mines from 12,500ppm to 5,000ppm. Currently there is a separate TWA for CO2 in coal mines however SWA proposes to remove this to align with a general industry standard. If implemented, the change has the potential to affect underground mines operating in CO2 rich coal seams, including the primary coal seam of theCompany's Metropolitan Mine . Importantly, a minimum three-year transition period applies for any change to standards. 41
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Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021. OnFebruary 25, 2021 the Commonwealth Government introduced the Environment Protection and Biodiversity Conservation Amendment (Standards and Assurance) Bill 2021 intoParliament , which proposes amendments to the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) following the release of the Final Report of the Independent Review of the Act undertaken by ProfessorGraeme Samuel (the Samuel Review) that made 38 recommendations for short and long-term reforms, and ultimately calls for a complete overhaul of the existing legislative framework by 2022, to be undertaken in several tranches, with a strong focus on the setting of National Environmental Standards, assurance and compliance, data availability and management, and indigenous engagement. The bill responds to some of the recommendations for immediate reform made in the Samuel Review, and seeks to: establish a framework for the making, varying, revoking and application of National Environmental Standards; apply the National Environmental Standards to bilateral agreements with States and Territories; and establish an Environment Assurance Commissioner to monitor and audit bilateral agreements and other processes under the EPBC Act. Native Title and Cultural Heritage. OnFebruary 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 vRegistrar 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 theNational 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 theU.S. ,Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date, no such legislation has been signed into law. While it is possible that theU.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of newU.S. federal legislation, theEPA has taken steps to regulate greenhouse gas emissions pursuant to the CAA. In response to theU.S. Supreme Court ruling inMassachusetts v.EPA ,549 U.S. 497 (2007) theEPA commenced several rulemaking projects as described under "Regulatory Matters -U.S. " In particular, in 2015, theEPA announced final rules (known as the CPP) for regulating carbon dioxide emissions from existing and new fossil fuel-fired EGUs. Twenty-seven states and governmental entities, as well as utilities, industry groups, trade associations, coal companies (including Peabody), and other entities, challenged the CPP in federal court. Implementation of the CPP was stayed by theU.S. Supreme Court pending resolution of its legal challenges. InOctober 2017 , theEPA proposed to change its legal interpretation of section 111(d) of the CAA, the authority that the agency relied on for the original CPP. TheEPA relied on the proposed reinterpretation untilAugust 2018 , when it proposed the Affordable Clean Energy Rule (the ACE Rule) to replace the CPP with a system where states would develop emissions reduction plans using BSER measures (essentially efficiency heat rate improvements), and theEPA would approve the state plans if they useEPA -approved candidate technologies. TheEPA thereafter repealed the CPP and promulgated the final ACE Rule onJuly 8, 2019 . OnJanuary 19, 2021 , theD.C. Circuit Court of Appeals vacated and remanded the ACE Rule, including the repeal of the CPP and amendments to implementing regulations that extended compliance timelines. Several changes in the NSR program 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 and herein. 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. 42
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At the same time, a number of states in theU.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 andVermont ) 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 andWisconsin ) 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 andWashington ) 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, inNovember 2011 , the WCI announced that six states had withdrawn from the WCI, leavingCalifornia and four Canadian provinces as the remaining members. Of those five jurisdictions, onlyCalifornia andQuebec 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 newNorth 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. Several otherU.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 theDepartment of Energy's Voluntary Reporting of Greenhouse Gases Program until its suspension inMay 2011 , andPeabody regularly discloses in its annual Environmental, Social and Governance Report the quantity of emissions per ton of coal produced by the Company in theU.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 inDecember 1997 by the signatories to the 1992United Nations Framework Convention on Climate Change (UNFCCC), established a binding set of greenhouse gas emission targets for developed nations. TheU.S. signed the Kyoto Protocol but it has never been ratified by theU.S. Senate .Australia ratified the Kyoto Protocol inDecember 2007 and became a full member inMarch 2008 . There were discussions to develop a treaty to replace theKyoto Protocol after the expiration of its commitment period in 2012, including at the UNFCCC conferences inCancun (2010),Durban (2011),Doha (2012) andParis (2015). At theDurban 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 theDoha meeting, an amendment to the Kyoto Protocol was adopted, which included new commitments for certain parties in a second commitment period, from 2013 to 2020. InDecember 2012 ,Australia signed on to the second commitment period. During the UNFCCC conference inParis, 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 onNovember 4, 2016 after ratification and execution by more than 55 countries, includingAustralia , that account for at least 55% of global greenhouse gas emissions. InJanuary 2021 , theU.S. reentered the Paris Agreement by accepting the agreement and all of its articles and clauses, after having announced its withdrawal from the agreement inNovember 2019 . InApril 2021 , theU.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, theU.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. 43
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InOctober 2017 , the Australian Federal Government released a plan aimed at delivering an affordable and reliable energy system that meetsAustralia'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 inSeptember 2018 . Following the outcome of the federal election inMay 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 downAustralia'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 meetingAustralia's Paris Agreement targets but that the focus of energy policy will be on driving down electricity prices. The enactment of future laws or the passage of regulations regarding emissions from the use of coal by theU.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 asChina ,India andJapan , included using higher-efficiency coal-fueled power plants in their plans under theParis 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 thatPeabody 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 The Company's primary source of cash is proceeds from the sale of its coal production to customers. The Company has also generated cash from the sale of non-strategic assets, including coal reserves and surface lands, borrowings under its credit facilities and, from time to time, the issuance of securities. The Company's primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, and selling and administrative expenses. The Company has also used cash for dividends, share repurchases and early debt retirements. Any future determinations to return capital to stockholders, such as dividends or share repurchases will depend on a variety of factors, including the restrictions set forth under the Company's debt and surety agreements, its net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. The Company's ability to early retire debt, declare dividends or repurchase shares in the future will depend on its future financial performance, which in turn depends on the successful implementation of its strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to its industry, many of which are beyond the Company's control. The Company has presently suspended the payment of dividends and share repurchases, as discussed in Part II, Item 2. "Unregistered Sales ofEquity Securities and Use of Proceeds." Liquidity As ofMarch 31, 2021 , the Company's cash balances totaled$580.2 million , including approximately$396 million held byU.S. subsidiaries and$157 million held by Australian subsidiaries, approximately$104 million of which was held by the subsidiaries that conduct the operations of itsWilpinjong Mine . The Company's remaining balance was held by other foreign subsidiaries in accounts predominantly domiciled in theU.S. A significant majority of the cash held by its foreign subsidiaries is denominated inU.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures inAustralia . 44
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The Company's available liquidity declined from
March 31, 2021 December 31, 2020
(Dollars in millions)
Cash and cash equivalents $ 580.2 $ 709.2
Revolving credit facility availability 22.8 0.2
Accounts receivable securitization program availability 0.8 19.3
Total liquidity $ 603.8 $ 728.7
Refinancing and Related Transactions
During the fourth quarter of 2020 and the first quarter of 2021, the Company
entered into a series of interrelated agreements with its surety bond providers,
the revolving lenders under its credit agreement and certain holders of its
senior secured notes to extend a significant portion of its near-term debt
maturities to December 2024 and to stabilize collateral requirements for its
existing surety bond portfolio. Such agreements and related activities are
described below.
Organizational Realignment
In July and August 2020 , the Company effected certain changes to its corporate
structure in contemplation of a debt-for-debt exchange, which included, among
other steps, the formation of certain wholly-owned subsidiaries (the
Co-Issuers). In connection with the change in structure, the Company's
subsidiary which owns and operates its Wilpinjong Mine in Australia became a
subsidiary of the Co-Issuers. The Co-Issuers and the Wilpinjong subsidiary were
designated as unrestricted subsidiaries under the Company's Credit Agreement 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 capital needs over the
next twelve months.
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 2021 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 have asset sales in excess of $10.0 million . Further, the Participating
Sureties have agreed to a standstill through December 31, 2024 , 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 near-term operating liquidity and financial flexibility. The
Refinancing Transactions included a senior notes exchange and related consent
solicitation, a revolving credit facility exchange, and various amendments to
its existing debt agreements, as summarized below.
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Exchange Offer OnJanuary 29, 2021 , the Company settled an exchange offer (Exchange Offer) pursuant to which$398.7 million aggregate principal amount of its 6.000% Senior Secured Notes dueMarch 2022 (2022 Notes) were validly tendered, accepted by the Company and exchanged for aggregate consideration consisting of (a)$193.9 million aggregate principal amount of new 10.000% Senior Secured Notes due 2024 issued by the Co-Issuers (Co-Issuer Notes), (b)$195.1 million aggregate principal amount of new 8.500% Senior Secured Notes due 2024 issued byPeabody (Peabody Notes), and (c) a cash payment of approximately$9.4 million . In connection with the settlement of the Exchange Offer, the Company also paid early tender premiums totaling$4.0 million in cash. Refer to Note 11. "Long-term Debt" for additional information associated with the Co-Issuer Notes and the Peabody Notes. Following the settlement of the Exchange Offer, approximately$60.3 million aggregate principal amount of the 2022 Notes remain outstanding and are governed by the Existing Indenture, as amended by the supplemental indenture described below. As required under the Exchange Offer, the Company purchased$22.4 million 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 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 Existing Indenture and (ii) release the collateral securing the 2022 Notes and eliminate certain other related 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 onJanuary 29, 2021 . Revolver Transactions In connection with the Refinancing Transactions, the Company restructured the revolving loans under the Credit Agreement by (i) making a pay down of revolving loans thereunder in the aggregate amount of$10.0 million , (ii) the Co-Issuers incurring$206.0 million of term loans under a credit agreement, dated as of the Settlement Date (Co-Issuer Term Loans, Co-Issuer Term Loan Agreement), (iii)Peabody entering into a letter of credit facility (the Company LC Agreement), and (iv) amending the Credit Agreement (collectively, the Revolver Transactions). The Co-Issuer Term Loans mature onDecember 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 the Credit Agreement, pursuant to which the Company obtained a$324.0 million letter of credit facility under which its existing letters of credit under the Credit Agreement were deemed to be issued. The commitments under the Company LC Agreement mature onDecember 31, 2024 . Undrawn letters of credit under the Company LC Agreement bear interest at 6.00% per annum and unused commitments are subject to a 0.50% per annum commitment fee. In connection with the Revolver Transactions, the Company amended the Credit Agreement to make certain changes in consideration of the Company LC Agreement. After giving effect to the Revolver Transactions, there remain no revolving commitments or revolving loans under the Credit Agreement and the first lien net leverage ratio covenant was eliminated, effectively negating the compliance requirement atDecember 31, 2020 and prospectively. 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 throughDecember 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$475.3 million atMarch 31, 2021 . Other Debt Financing The Refinancing Transactions did not significantly impact the Company's existing senior secured term loan under the Credit Facility, or its$500.0 million of 6.375% senior secured notes dueMarch 2025 . The senior secured term loan had a balance of$387.3 million atMarch 31, 2021 . The term loan requires quarterly principal payments of$1.0 million and periodic interest payments, currently at LIBOR plus 2.75%, throughDecember 2024 with the remaining balance due inMarch 2025 . The senior secured notes require semi-annual interest payments eachMarch 31 andSeptember 30 until maturity. 46
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The Company's debt agreements impose various restrictions and limits on certain categories of payments that the Company may make, such as those for dividends, investments, and stock repurchases. The Company is also subject to customary affirmative and negative covenants. The Company was compliant with all covenants under its debt agreements atMarch 31, 2021 . Considering the Refinancing Transactions, the Company expects to incur approximately$200 million of interest expense, including approximately$50 million of non-cash interest expense, during the year endedDecember 31, 2021 . Accounts Receivable Securitization Program As described in Note 16. "Financial Instruments and Other Guarantees" of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017 which currently expires in 2022. The program provides for up to$250.0 million in funding, limited to the availability of eligible receivables, accounted for as a secured borrowing. Funding capacity under the program may also be utilized for letters of credit in support of other obligations. AtMarch 31, 2021 , the Company had no outstanding borrowings and$120.8 million of letters of credit issued under the program, which were primarily in support of portions of the Company's obligations for property and casualty insurance. The Company had$43.5 million of cash collateral posted under the Securitization Program atMarch 31, 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$225 million , which includes approximately$135 million for ongoing extension projects primarily related to its Seaborne Thermal Mining segment. The Company has no substantial future payment requirements underU.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 endedDecember 31, 2020 . Cash Flows and Free Cash Flow The following table summarizes the Company's cash flows for the three months endedMarch 31, 2021 and 2020, as reported in the accompanying unaudited condensed consolidated financial statements. Free Cash Flow is a financial measure not recognized in accordance withU.S. GAAP. Refer to the "Reconciliation of Non-GAAP Financial Measures" section above for definitions and reconciliations to the most comparable measures underU.S. GAAP. Three Months Ended March 31, 2021 2020 (Dollars in millions) Net cash provided by (used in) operating activities $ 71.0$ (4.7) Net cash used in investing activities (93.2) (37.1) Net cash used in financing activities (63.3) (7.9) Net change in cash, cash equivalents and restricted cash (85.5) (49.7)
Cash, cash equivalents and restricted cash at beginning of period
709.2 732.2
Cash, cash equivalents and restricted cash at end of period
Net cash provided by (used in) operating activities $ 71.0$ (4.7) Net cash used in investing activities (93.2) (37.1) Free Cash Flow$ (22.2) $ (41.8) 47
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Operating Activities. The net increase in net cash (used in) provided by operating activities for the three months endedMarch 31, 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 and a favorable change in net cash flows associated with its working capital ($59.0 million ). Investing Activities. The increase in net cash used in investing activities for the three months endedMarch 31, 2021 compared to the same period in the prior year was driven by higher capital expenditures ($19.0 million ) and higher net contributions to joint ventures ($35.8 million ). Financing Activities. The increase in net cash used in financing activities for the three months endedMarch 31, 2021 compared to the same period in the prior year was driven by comparatively higher long-term debt repayments ($33.0 million ), including$37.3 million associated with the Refinancing Transactions, and the payment of deferred financing costs associated with the Refinancing Transactions ($22.5 million ). 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. AtMarch 31, 2021 , such instruments included$1,570.8 million of surety bonds and$423.4 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 ofMarch 31, 2021 , the Company was party to financial instruments with off-balance-sheet risk in support of the following obligations: Health and Contract Leased property Reclamation welfare (1) performance (2) and equipment Other (3) Total (Dollars in millions)
Surety bonds and bank guarantees
$ 87.6$ 30.9 $ 15.7 $ 1,570.8 Letters of credit outstanding under letter of credit facility 198.3 90.4 7.5 5.0 -
301.2
Letters of credit outstanding under
accounts receivable securitization
program 99.4 17.0 4.4 - - 120.8
Other letters of credit - 1.4 - - - 1.4
1,692.2 150.9 99.5 35.9 15.7 1,994.2
Less: Letters of credit in support of
surety bonds (4) (297.7) (29.5) - (1.2) - (328.4)
Less: Cash collateral in support of surety bonds (4) (15.0) - - - - (15.0) Obligations supported, net$ 1,379.5 $ 121.4 $ 99.5$ 34.7 $ 15.7 $ 1,650.8 (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$5.3 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. 48
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As described in Note 16. "Financial Instruments and Other Guarantees" in the accompanying unaudited condensed consolidated financial statements, the Company is required to provide various forms of financial assurance in support of its mining reclamation obligations in the jurisdictions in which it operates. Such requirements are typically established by statute or under mining permits. Historically, such assurances have taken the form of third-party instruments such as surety bonds, bank guarantees and letters of credit, as well as self-bonding arrangements in theU.S. Self-bonding in theU.S. has become increasingly restricted in recent years, leading to the Company's increased usage of surety bonds and similar third-party instruments. This change in practice has had an unfavorable impact on its liquidity due to increased collateral requirements and surety and related fees. AtMarch 31, 2021 , the Company had total asset retirement obligations of$735.9 million which were backed by a combination of surety bonds, bank guarantees and letters of credit. Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company's accounting liabilities are discounted from the end of a mine's economic life (when final reclamation work would begin) to the balance sheet date. Guarantees and Other Financial Instruments with Off-Balance-Sheet Risk. See Note 16. "Financial Instruments and Other Guarantees" in the Company's unaudited condensed consolidated financial statements for a discussion of its accounts receivable securitization program and guarantees and other financial instruments with off-balance-sheet risk. Critical Accounting Policies and Estimates The Company's discussion and analysis of its financial condition, results of operations, liquidity and capital resources is based upon its financial statements, which have been prepared in accordance withU.S. GAAP. The Company is also required underU.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, the Company evaluates its estimates. The Company bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. AtMarch 31, 2021 , the Company identified certain assets with an aggregate carrying value of approximately$1.2 billion in its Seaborne Metallurgical Mining, PowderRiver Basin Mining , OtherU.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 ofMarch 31, 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 its Annual Report on Form 10-K for the year endedDecember 31, 2020 . The Company's critical accounting policies remain unchanged atMarch 31, 2021 . Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented See Note 2. "Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented" to the Company's unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented. 49
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