Exhibit 99.1
 | ||||||||
Media Release | ||||||||
PEABODY REPORTS EARNINGS FOR QUARTER ENDED SEPTEMBER 30, 2020
ST. LOUIS, Nov. 9, 2020 – Peabody (NYSE: BTU) today announced its third quarter 2020 operating results, including revenues of $671.0 million; loss from continuing operations, net of income taxes of
$64.8 million; net loss attributable to common stockholders of $67.2 million; diluted loss per share from continuing operations of $0.66; and Adjusted EBITDA1 of $95.4 million.
“Peabody drove strong cost performance within our thermal segments during the third quarter, including record-low PRB costs per ton,” said President and Chief Executive Officer Glenn Kellow. “We have had a number of achievements across the portfolio and look to further build upon our progress as we tackle structural improvements within the seaborne met segment. In addition to our ongoing portfolio enhancements, we have been working to achieve specific financing objectives. While we have made progress, there is still more to do. Together, these actions are intended to provide a solid base to strengthen our financial and operating performance.”
Third Quarter 2020 Results
Third quarter revenues declined 39 percent from the prior year to $671.0 million due to lower volumes, mix changes and weaker seaborne pricing. U.S. thermal revenues declined $215.4 million, including $82.6 million from Kayenta’s closure in the third quarter of 2019.
Operating costs and expenses also fell by 39 percent, reflecting the benefit of cost saving initiatives taken to date, as well as lower volumes. These initiatives included further headcount reductions, which resulted in a restructuring charge of $8.1 million in the third quarter.
The company also modified its approach to its non-represented retiree medical coverage to better align with evolving business conditions and industry benchmarks. Given this change, the company’s postretirement benefit obligation was adjusted to fair value, utilizing lower discount rates, which resulted in a $13.0 million loss in the quarter and a $174.5 million reduction in the liability.
Peabody ended the third quarter with $814.6 million of cash and cash equivalents and $860.1 million of available liquidity.
Segment Performance
During the quarter, the seaborne thermal segment shipped 4.6 million tons, with 2.7 million tons exported at an average realized price of $45.86 per short ton. The remaining 1.9 million tons were sold under a long-term domestic contract.
1 Adjusted EBITDA is a non-GAAP financial measure. Revenues per ton, costs per ton, Adjusted EBITDA margin per ton and percent are non-GAAP operating/statistical measures. Adjusted EBITDA margin is equal to segment Adjusted EBITDA divided by segment revenues. Please refer to the tables and related notes in this press release for a reconciliation and definition of non-GAAP financial measures. | ||
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Seaborne thermal segment costs per ton of $27.59 improved 22 percent compared to the prior year due to strong cost performance from the Wambo surface mine and Wilpinjong. Lower ratio and improved geology contributed to significantly lower year-over-year costs at the surface operations.
In the quarter, the seaborne met segment shipped 1.1 million tons at an average realized price of $71.88 per short ton. Compared to the prior year, third quarter 2020 realized pricing was impacted by lower pricing and a higher mix of PCI sales.
Seaborne met costs per ton, excluding prior year North Goonyella equipment and development costs, improved 15 percent from the prior year to $96.87. Lower costs per ton were driven by ongoing actions to improve the cost structure at Metropolitan, Coppabella and Moorvale. Year-to-date 2020 met costs per ton included an approximately $5 per ton impact related to an adjustment to record certain mines’ inventory at net realizable value.
Peabody’s U.S. thermal mines delivered strong cost performance driven by optimizing the company’s maintenance program through use of condition-based monitoring. These benefits largely offset the impacts of lower demand.
Third quarter PRB Adjusted EBITDA of $78.3 million increased $7.6 million from the prior year on record low PRB costs per ton of $7.93, despite a 22 percent decline in shipments. Third quarter PRB costs benefited from lower maintenance spending, and fuel and sales related costs associated with reduced volumes, including a one-time benefit of $0.35 per ton.
The other U.S. thermal segment earned $51.6 million of Adjusted EBITDA in the quarter on continued strong cost performance. Costs per ton declined 22 percent from the prior year to $26.52 due to reduced maintenance spending, favorable mix impacts, and lower personnel costs, among other items.
Financing Update
As part of the company’s comprehensive process to explore financing alternatives, the company engaged with its surety bond providers to reach a mutual agreement to support Peabody’s continued reclamation efforts. In early November, Peabody reached a standstill agreement with its surety bond providers for the company’s $1.6 billion surety program to resolve approximately $800 million of collateral requests made in the third quarter and limit future collateral requirements.
“We are grateful for the tremendous collaboration with our surety providers to reach a first-of-its-kind solution that offers a greater line of sight into Peabody’s future collateral requirements,” said Executive Vice President and Chief Financial Officer Mark Spurbeck. “The agreement lays the foundation for stability and provides the necessary support for our longstanding commitment to reclamation. We are now focused on continuing to work with our 2022 noteholders and revolving credit lenders to effectuate a holistic transaction that provides for maturity extensions and covenant relief, while maintaining sufficient operating liquidity and financial flexibility.”
Providers of 99 percent of the company’s surety bond portfolio have agreed to the following terms and conditions:
•Under the terms of the transaction support agreement, Peabody will post $75 million of collateral and provide second liens on $200 million of certain mining equipment for the benefit of the surety providers.
•In addition, Peabody will post an additional $25 million of collateral per year through 2025 for the benefit of the surety providers. The collateral postings will also further increase to the extent the company generates more than $100 million of free cash flow (as defined in the transaction support agreement) in any twelve-month period or has asset sales in excess of $10 million.
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•Surety providers have agreed to a standstill through the earlier of December 2025 or the maturity date of the company’s credit agreement (as amended or refinanced). During which time, surety bond providers agree not to demand any additional collateral; draw on letters of credit posted for the benefit of themselves; or cancel, or attempt to cancel, any existing surety bond.
Based on the company’s current outlook, it is probable that Peabody’s fourth quarter 2020 results will not be sufficient to meet the minimum required net leverage ratio as defined under the revolving credit agreement. Peabody has been engaged in discussions with its revolving credit lenders and an ad hoc group of 2022 noteholders. While no agreement has been reached with these parties to date, Peabody expects to continue to have discussions with all or certain of these constituencies in the future. The surety standstill outlined above is contingent upon the company ultimately completing a deal with its revolving credit lenders and 2022 noteholders by Dec. 31, 2020, which can be extended at the company’s discretion to Jan. 29, 2021 for purposes of increasing participation.
The additional collateral demands and probable financial covenant noncompliance under the revolving credit facility, requires that the company’s debt be reported as current on its balance sheet as of Sept. 30, 2020. Upon completion of a comprehensive resolution with its revolving credit lenders and 2022 noteholders, Peabody would expect its debt to be classified as current or non-current based upon the timing of its stated maturity.
Operational/Portfolio Update
The company has benefited from a comprehensive improvement program with board oversight across operational and functional aspects of the business, and continues to drive structural changes throughout the organization.
Actions recently taken include:
•Further scaled back production and the workforce at Wambo Underground, including temporarily suspending production for 59 days during the third quarter in response to challenging demand conditions. The mine is focused on enhancing its competitive position to enable continued mining in the current district post-2021.
•Temporarily idled Shoal Creek in early October to reset the cost structure of the mine. Costs per ton in 2020 have been elevated due to a combination of weak demand, lower productivity rates, and poor geological conditions in the final H-panel. Production is expected to be suspended for the next several months. Idle costs are anticipated to average approximately $4 million per month.
•Idling an excavator fleet at Moorvale in November in light of elevated inventory levels and weak pricing.
Other initiatives, including the following, are also underway across the portfolio:
•Resetting Metropolitan’s cost structure by improving development rates and scaling the mine to reduce longwall output in periods of weak market conditions. In addition, the mine is in discussions with its customers and workforce to reach agreements that best serve the needs of all stakeholders and enable the mine to continue to operate during challenging market conditions.
•Middlemount is beginning to see the benefits of a recent change in management earlier this year, along with recognizing cost improvement initiatives. Fourth quarter Middlemount volumes are fully committed amid improving customer demand.
•Sharing of production at the United Wambo joint venture is anticipated to begin later this year. While production will be lower in the near term, Peabody will benefit from lower strip ratios and access to otherwise stratified reserves, enabling continued production of a high-quality seaborne thermal product.
•The North Goonyella commercial process and review of strategic alternatives is ongoing.
•In the U.S., Peabody intends to continue to adjust to changing demand profiles and enhance its competitiveness against natural gas and subsidized renewables following the termination of its PRB/Colorado joint venture agreement with Arch. In September, the court issued its decision to support the FTC’s efforts to block the transaction.
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Market Update
The global economy is showing a marked improvement in industrial production, even as the timing of a recovery varies across countries and sectors. Seaborne coal pricing remains muted and below pre-pandemic levels and rising COVID-19 cases worldwide continue to pose a threat to commodity pricing.
Steel industry fundamentals are improving in most regions relative to COVID-driven lows earlier in the year, although seaborne met coal demand has yet to recover to pre-pandemic levels. While China is leading the steel production recovery, met coal imports have been muted given unofficial import controls. In addition, year to date through September, India’s met imports fell 8 million tonnes compared to the prior year. Looking ahead, Peabody projects global seaborne met coal demand to show consistent, albeit modest, growth over the next several years. During this time, India is expected to account for the vast majority of overall demand growth amid significant steel capacity additions and lack of domestic reserves. ASEAN countries are also projected to be a notable contributor to growth as demand in Japan and Korea remains largely stable. Australia is projected to continue to account for more than 50 percent of seaborne supply.
Within seaborne thermal, weak demand continues to pressure prices. India imports have declined 24 million tonnes due to inventory overhangs and higher domestic production, while China imports are down 9 million tonnes year to date through September. ASEAN countries are the only major importing regions showing sizable year-over-year growth, with imports up 9 million tonnes year to date through September. Longer term, coal is expected to maintain a leading position in the electricity generation mix. In absolute terms, coal is expected to grow while its share of overall generation is expected to decline. ASEAN countries and India are expected to be drivers for seaborne coal demand growth due to increased electrification and economic gains. This growth is anticipated to more than offset sharp declines in global coal use from developed economies, including the U.S. and Western Europe. From a supply-side perspective, year-to-date thermal exports for every major exporting country are down relative to the prior year. Indonesia leads the decline with thermal exports down 34 million tonnes, followed by Colombia and the United States. In fact, Colombia exports marked an all-time low in September.
In the U.S., the impacts of COVID-19 have accelerated a multi-year decline in coal demand. Year-to-date through September, coal generation is down 24 percent and represents 19 percent of the overall generation mix. While still at elevated levels, strong summer draws have lowered U.S. utility coal inventories to just under 130 million tons, or approximately 56 days based on maximum usage. Current natural gas forwards are above $3.00 for the remainder of the year and into 2021.
Outlook
Based on current estimates, fourth quarter seaborne volumes are expected to improve modestly, while U.S. thermal volumes are expected to decline slightly compared to the third quarter. Seaborne met costs are anticipated to rise primarily due to a planned longwall move at Metropolitan and changes in product mix, while seaborne thermal costs are expected to be largely in line with the third quarter. Current fourth quarter 2020 priced and committed sales are as follows:
•23 million tons of PRB sales at an average realized price of $11.28 per ton
•5 million tons of other U.S. thermal sales at an average realized price of $36 per ton
•2 million tons of seaborne thermal export sales at an average realized price of $47 per short ton
•0.7 million tons of seaborne met sales at an average realized price of $88 per short ton
In addition, 2020 full year capital expenditures and SG&A have been reduced to approximately $185 million and $105 million, respectively.
Current 2021 market expectations reflect improvement in seaborne coal demand as economies continue to recover from COVID-19. In addition, modestly higher forward natural gas prices are expected to offset the impact of additional retirements within the U.S. thermal market. Other factors that will determine Peabody’s 2021 sales volume include the anticipated resumption of production at Shoal Creek in early 2021 as well as lower production due to the United Wambo joint venture transition.
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Today’s earnings call is scheduled for 10 a.m. CT and can be accessed via the company’s website at PeabodyEnergy.com.
Peabody (NYSE: BTU) is a leading coal producer, serving customers in more than 25 countries on six continents. We provide essential products to fuel baseload electricity for emerging and developed countries and create the steel needed to build foundational infrastructure. Our commitment to sustainability underpins our activities today and helps to shape our strategy for the future. For further information, visit PeabodyEnergy.com.
Contact:
Julie Gates
314.342.4336
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| Condensed Consolidated Statements of Operations (Unaudited) | | |||||||||||||||||||||||||
| For the Quarters and Nine Months Ended Sept. 30, 2020 and 2019 | ||||||||||||||||||||||||||
| (In Millions, Except Per Share Data) | ||||||||||||||||||||||||||
| Quarter Ended | Nine Months Ended | |||||||||||||||||||||||||
| Sept. | Sept. | Sept. | Sept. | |||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
Tons Sold | 34.7 | 44.8 | 98.6 | 124.7 | ||||||||||||||||||||||
Revenues | $ | 671.0 | $ | 1,106.4 | $ | 2,143.9 | $ | 3,506.0 | ||||||||||||||||||
Operating Costs and Expenses (1) | 550.9 | 905.5 | 1,886.7 | 2,711.5 | ||||||||||||||||||||||
Depreciation, Depletion and Amortization | 72.2 | 141.5 | 266.5 | 479.4 | ||||||||||||||||||||||
Asset Retirement Obligation Expenses | 14.3 | 15.5 | 46.0 | 44.6 | ||||||||||||||||||||||
Selling and Administrative Expenses | 27.2 | 32.2 | 77.3 | 107.8 | ||||||||||||||||||||||
Restructuring Charges | 8.1 | 0.7 | 31.1 | 1.3 | ||||||||||||||||||||||
Transaction Costs Related to Joint Ventures | 6.0 | 8.2 | 23.1 | 9.8 | ||||||||||||||||||||||
Other Operating Loss (Income): | ||||||||||||||||||||||||||
| Net Gain on Disposals | (2.5) | (1.1) | (10.4) | (2.8) | ||||||||||||||||||||||
Asset Impairment | — | 20.0 | 1,418.1 | 20.0 | ||||||||||||||||||||||
Provision for North Goonyella Equipment Loss | — | — | — | 24.7 | ||||||||||||||||||||||
North Goonyella Insurance Recovery | — | — | — | (125.0) | ||||||||||||||||||||||
| Loss from Equity Affiliates | 10.6 | 20.7 | 25.7 | 7.5 | ||||||||||||||||||||||
| Operating (Loss) Profit | (15.8) | (36.8) | (1,620.2) | 227.2 | ||||||||||||||||||||||
Interest Expense | 34.9 | 35.4 | 102.3 | 107.2 | ||||||||||||||||||||||
Interest Income | (1.6) | (7.0) | (7.1) | (22.5) | ||||||||||||||||||||||
Net Periodic Benefit Costs, Excluding Service Cost | 2.8 | 4.9 | 8.3 | 14.6 | ||||||||||||||||||||||
Net Mark-to-Market Adjustment on Actuarially Determined Liabilities | 13.0 | — | 13.0 | — | ||||||||||||||||||||||
| (Loss) Income from Continuing Operations Before Income Taxes | (64.9) | (70.1) | (1,736.7) | 127.9 | ||||||||||||||||||||||
| Income Tax (Benefit) Provision | (0.1) | 4.2 | 2.7 | 26.0 | ||||||||||||||||||||||
| (Loss) Income from Continuing Operations, Net of Income Taxes | (64.8) | (74.3) | (1,739.4) | 101.9 | ||||||||||||||||||||||
| Loss from Discontinued Operations, Net of Income Taxes | (2.3) | (3.8) | (6.8) | (10.6) | ||||||||||||||||||||||
| Net (Loss) Income | (67.1) | (78.1) | (1,746.2) | 91.3 | ||||||||||||||||||||||
| Less: Net Income (Loss) Attributable to Noncontrolling Interests | 0.1 | 4.7 | (5.1) | 12.8 | ||||||||||||||||||||||
| Net (Loss) Income Attributable to Common Stockholders | $ | (67.2) | $ | (82.8) | $ | (1,741.1) | $ | 78.5 | ||||||||||||||||||
Adjusted EBITDA (2) | $ | 95.4 | $ | 159.2 | $ | 155.6 | $ | 643.3 | ||||||||||||||||||
Diluted EPS - (Loss) Income from Continuing Operations (3)(4) | $ | (0.66) | $ | (0.77) | $ | (17.76) | $ | 0.83 | ||||||||||||||||||
Diluted EPS - Net (Loss) Income Attributable to Common Stockholders (3) | $ | (0.69) | $ | (0.81) | $ | (17.83) | $ | 0.73 | ||||||||||||||||||
| (1) | Excludes items shown separately. | |||||||||||||||||||||||||
| (2) | Adjusted EBITDA is a non-GAAP financial measure. Refer to the “Reconciliation of Non-GAAP Financial Measures” section in this document for definitions and reconciliations to the most comparable measures under U.S. GAAP. | |||||||||||||||||||||||||
| (3) | During the quarters ended September 30, 2020 and 2019, weighted average diluted shares outstanding were 97.9 million and 102.2 million, respectively. During the nine months ended September 30, 2020 and 2019, weighted average diluted shares outstanding were 97.6 million and 107.4 million, respectively. | |||||||||||||||||||||||||
| (4) | Reflects (loss) income from continuing operations, net of income taxes less net income (loss) attributable to noncontrolling interests. | |||||||||||||||||||||||||
| This information is intended to be reviewed in conjunction with the company's filings with the SEC. | ||||||||||||||||||||||||||
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| Supplemental Financial Data (Unaudited) | | |||||||||||||||||||||||||
| For the Quarters and Nine Months Ended Sept. 30, 2020 and 2019 | ||||||||||||||||||||||||||
| Quarter Ended | Nine Months Ended | |||||||||||||||||||||||||
| Sept. | Sept. | Sept. | Sept. | |||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| Tons Sold (In Millions) | ||||||||||||||||||||||||||
| Seaborne Thermal Mining Operations | 4.6 | 4.9 | 13.8 | 14.1 | ||||||||||||||||||||||
| Seaborne Metallurgical Mining Operations | 1.1 | 1.8 | 4.2 | 6.2 | ||||||||||||||||||||||
| Powder River Basin Mining Operations | 23.6 | 30.2 | 65.0 | 80.5 | ||||||||||||||||||||||
Other U.S. Thermal Mining Operations (1) | 4.8 | 7.2 | 13.5 | 22.3 | ||||||||||||||||||||||
| Total U.S. Thermal Mining Operations | 28.4 | 37.4 | 78.5 | 102.8 | ||||||||||||||||||||||
| Corporate and Other | 0.6 | 0.7 | 2.1 | 1.6 | ||||||||||||||||||||||
| Total | 34.7 | 44.8 | 98.6 | 124.7 | ||||||||||||||||||||||
| Revenue Summary (In Millions) | ||||||||||||||||||||||||||
| Seaborne Thermal Mining Operations | $ | 163.0 | $ | 249.5 | $ | 526.1 | $ | 720.7 | ||||||||||||||||||
| Seaborne Metallurgical Mining Operations | 78.8 | 216.3 | 363.6 | 831.7 | ||||||||||||||||||||||
| Powder River Basin Mining Operations | 264.8 | 333.6 | 737.2 | 903.5 | ||||||||||||||||||||||
Other U.S. Thermal Mining Operations (1) | 179.8 | 326.4 | 524.1 | 970.8 | ||||||||||||||||||||||
| Total U.S. Thermal Mining Operations | 444.6 | 660.0 | 1,261.3 | 1,874.3 | ||||||||||||||||||||||
| Corporate and Other | (15.4) | (19.4) | (7.1) | 79.3 | ||||||||||||||||||||||
| Total | $ | 671.0 | $ | 1,106.4 | $ | 2,143.9 | $ | 3,506.0 | ||||||||||||||||||
Total Reporting Segment Costs Summary (In Millions) (2) | ||||||||||||||||||||||||||
| Seaborne Thermal Mining Operations | $ | 127.7 | $ | 172.7 | $ | 408.0 | $ | 474.8 | ||||||||||||||||||
| Seaborne Metallurgical Mining Operations | 106.1 | 232.5 | 459.7 | 704.7 | ||||||||||||||||||||||
North Goonyella Equipment & Development Costs (3) | — | 29.3 | — | 60.7 | ||||||||||||||||||||||
| Seaborne Metallurgical Mining Operations, Excluding North Goonyella Equipment & Development Costs | 106.1 | 203.2 | 459.7 | 644.0 | ||||||||||||||||||||||
| Powder River Basin Mining Operations | 186.5 | 262.9 | 594.2 | 756.2 | ||||||||||||||||||||||
Other U.S. Thermal Mining Operations (1) | 128.2 | 244.1 | 401.1 | 729.5 | ||||||||||||||||||||||
| Total U.S. Thermal Mining Operations | 314.7 | 507.0 | 995.3 | 1,485.7 | ||||||||||||||||||||||
| Corporate and Other | 7.4 | 1.2 | 42.4 | 41.1 | ||||||||||||||||||||||
| Total | $ | 555.9 | $ | 913.4 | $ | 1,905.4 | $ | 2,706.3 | ||||||||||||||||||
| Other Supplemental Financial Data (In Millions) | ||||||||||||||||||||||||||
| Adjusted EBITDA - Seaborne Thermal Mining Operations | $ | 35.3 | $ | 76.8 | $ | 118.1 | $ | 245.9 | ||||||||||||||||||
| Adjusted EBITDA - Seaborne Metallurgical Mining Operations | (27.3) | (16.2) | (96.1) | 127.0 | ||||||||||||||||||||||
North Goonyella Equipment & Development Costs (3) | — | 29.3 | — | 60.7 | ||||||||||||||||||||||
| Adjusted EBITDA - Seaborne Metallurgical Mining Operations, Excluding North Goonyella Equipment & Development Costs | (27.3) | 13.1 | (96.1) | 187.7 | ||||||||||||||||||||||
| Adjusted EBITDA - Powder River Basin Mining Operations | 78.3 | 70.7 | 143.0 | 147.3 | ||||||||||||||||||||||
Adjusted EBITDA - Other U.S. Thermal Mining Operations (1) | 51.6 | 82.3 | 123.0 | 241.3 | ||||||||||||||||||||||
| Adjusted EBITDA - Total U.S. Thermal Mining Operations | 129.9 | 153.0 | 266.0 | 388.6 | ||||||||||||||||||||||
Middlemount (4) | (11.1) | (18.8) | (27.2) | (4.9) | ||||||||||||||||||||||
Resource Management Results (5) | 1.0 | 2.3 | 9.8 | 6.0 | ||||||||||||||||||||||
| Selling and Administrative Expenses | (27.2) | (32.2) | (77.3) | (107.8) | ||||||||||||||||||||||
Other Operating Costs, Net (6) | (5.2) | (5.7) | (37.7) | (11.5) | ||||||||||||||||||||||
Adjusted EBITDA (2) | $ | 95.4 | $ | 159.2 | $ | 155.6 | $ | 643.3 | ||||||||||||||||||
Note: See footnote explanations on following page | ||||||||||||||||||||||||||
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| Supplemental Financial Data (Unaudited) | | |||||||||||||||||||||||||
| For the Quarters and Nine Months Ended Sept. 30, 2020 and 2019 | ||||||||||||||||||||||||||
| Quarter Ended | Nine Months Ended | |||||||||||||||||||||||||
| Sept. | Sept. | Sept. | Sept. | |||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
Revenues per Ton - Mining Operations (7) | ||||||||||||||||||||||||||
| Seaborne Thermal | $ | 35.28 | $ | 51.06 | $ | 38.14 | $ | 51.14 | ||||||||||||||||||
| Seaborne Metallurgical | 71.88 | 120.94 | 87.16 | 134.80 | ||||||||||||||||||||||
| Powder River Basin | 11.26 | 11.02 | 11.35 | 11.22 | ||||||||||||||||||||||
Other U.S. Thermal (1) | 37.20 | 45.45 | 38.67 | 43.52 | ||||||||||||||||||||||
| Total U.S. Thermal | 15.68 | 17.62 | 16.07 | 18.22 | ||||||||||||||||||||||
Costs per Ton - Mining Operations (7)(8) | ||||||||||||||||||||||||||
| Seaborne Thermal | $ | 27.59 | $ | 35.33 | $ | 29.58 | $ | 33.69 | ||||||||||||||||||
| Seaborne Metallurgical | 96.87 | 130.01 | 110.20 | 114.22 | ||||||||||||||||||||||
North Goonyella Equipment & Development Costs (3) | — | 16.38 | — | 9.84 | ||||||||||||||||||||||
| Seaborne Metallurgical, Excluding North Goonyella Equipment & Development Costs | 96.87 | 113.63 | 110.20 | 104.38 | ||||||||||||||||||||||
| Powder River Basin | 7.93 | 8.69 | 9.15 | 9.39 | ||||||||||||||||||||||
Other U.S. Thermal (1) | 26.52 | 34.00 | 29.60 | 32.70 | ||||||||||||||||||||||
| Total U.S. Thermal | 11.10 | 13.54 | 12.68 | 14.44 | ||||||||||||||||||||||
Adjusted EBITDA Margin per Ton - Mining Operations (7)(8) | ||||||||||||||||||||||||||
| Seaborne Thermal | $ | 7.69 | $ | 15.73 | $ | 8.56 | $ | 17.45 | ||||||||||||||||||
| Seaborne Metallurgical | (24.99) | (9.07) | (23.04) | 20.58 | ||||||||||||||||||||||
North Goonyella Equipment & Development Costs (3) | — | 16.38 | — | 9.84 | ||||||||||||||||||||||
| Seaborne Metallurgical, Excluding North Goonyella Equipment & Development Costs | (24.99) | 7.31 | (23.04) | 30.42 | ||||||||||||||||||||||
| Powder River Basin | 3.33 | 2.33 | 2.20 | 1.83 | ||||||||||||||||||||||
Other U.S. Thermal (1) | 10.68 | 11.45 | 9.07 | 10.82 | ||||||||||||||||||||||
| Total U.S. Thermal | 4.58 | 4.08 | 3.39 | 3.78 | ||||||||||||||||||||||
| (1) | Beginning Q1 2020, we have combined the Midwestern U.S. Mining segment with the Western U.S. Mining segment to reflect the manner in which our chief operating decision maker now views our businesses for purposes of reviewing performance, allocating resources and assessing future prospects and strategic execution. All periods presented have been recast for comparability. | |||||||||||||||||||||||||
| (2) | Total Reporting Segment Costs and Adjusted EBITDA are non-GAAP financial measures. Refer to the “Reconciliation of Non-GAAP Financial Measures” section in this document for definitions and reconciliations to the most comparable measures under U.S. GAAP. | |||||||||||||||||||||||||
| (3) | Costs incurred from January 1, 2020 forward are included within Other Operating Costs, Net. Costs incurred prior to January 1, 2020 remain within the Seaborne Metallurgical segment. | |||||||||||||||||||||||||
| (4) | We account for our 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine, under the equity method. Middlemount's standalone results exclude the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference recorded by the company in applying the equity method. Middlemount's standalone results include (on a 50% attributable basis): | |||||||||||||||||||||||||
| Quarter Ended | Nine Months Ended | |||||||||||||||||||||||||
| Sept. | Sept. | Sept. | Sept. | |||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| (In Millions) | ||||||||||||||||||||||||||
| Tons sold | 0.4 | 0.2 | 1.2 | 1.2 | ||||||||||||||||||||||
Depreciation, depletion and amortization and asset retirement obligation expenses | $ | 9.2 | $ | 8.2 | $ | 23.5 | $ | 15.3 | ||||||||||||||||||
| Net interest expense | 4.1 | 2.4 | 10.0 | 6.4 | ||||||||||||||||||||||
| Income tax benefit | (4.7) | (7.5) | (11.7) | (1.6) | ||||||||||||||||||||||
| (5) | Includes gains (losses) on certain surplus coal reserve and surface land sales and property management costs and revenues. | |||||||||||||||||||||||||
| (6) | Includes trading and brokerage activities, costs associated with post-mining activities, minimum charges on certain transportation-related contracts and costs associated with suspended operations including the North Goonyella Mine. | |||||||||||||||||||||||||
| (7) | Revenues per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton are metrics used by management to measure each of our mining segment’s operating performance. 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. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the mining segment level. We consider all measures reported on a per ton basis to be operating/statistical measures; however, we include reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section in this document. | |||||||||||||||||||||||||
| (8) | Includes revenue-based production taxes and royalties; excludes depreciation, depletion and amortization; asset retirement obligation expenses; selling and administrative expenses; restructuring charges; asset impairment; provision for North Goonyella equipment loss and related insurance recovery; amortization of take-or-pay contract-based intangibles; and certain other costs related to post-mining activities. | |||||||||||||||||||||||||
| This information is intended to be reviewed in conjunction with the company's filings with the SEC. | ||||||||||||||||||||||||||
8
| Condensed Consolidated Balance Sheets | | |||||||||||||
| As of Sept. 30, 2020 and Dec. 31, 2019 | ||||||||||||||
| (Dollars In Millions) | ||||||||||||||
| (Unaudited) | ||||||||||||||
| Sept. 30, 2020 | Dec. 31, 2019 | |||||||||||||
Cash and Cash Equivalents | $ | 814.6 | $ | 732.2 | ||||||||||
Accounts Receivable, Net | 192.9 | 329.5 | ||||||||||||
Inventories | 319.7 | 331.5 | ||||||||||||
Other Current Assets | 209.2 | 220.7 | ||||||||||||
Total Current Assets | 1,536.4 | 1,613.9 | ||||||||||||
Property, Plant, Equipment and Mine Development, Net | 3,152.3 | 4,679.1 | ||||||||||||
Operating Lease Right-of-Use Assets | 44.9 | 82.4 | ||||||||||||
Investments and Other Assets | 122.4 | 139.1 | ||||||||||||
Deferred Income Taxes | 4.9 | 28.3 | ||||||||||||
Total Assets | $ | 4,860.9 | $ | 6,542.8 | ||||||||||
Current Portion of Long-Term Debt | $ | 1,600.1 | $ | 18.3 | ||||||||||
Accounts Payable and Accrued Expenses | 774.3 | 957.0 | ||||||||||||
Total Current Liabilities | 2,374.4 | 975.3 | ||||||||||||
Long-Term Debt, Less Current Portion | — | 1,292.5 | ||||||||||||
Deferred Income Taxes | 28.9 | 28.8 | ||||||||||||
Asset Retirement Obligations | 671.2 | 654.1 | ||||||||||||
Accrued Postretirement Benefit Costs | 419.6 | 593.4 | ||||||||||||
Operating Lease Liabilities, Less Current Portion | 7.1 | 52.8 | ||||||||||||
Other Noncurrent Liabilities | 258.9 | 273.4 | ||||||||||||
Total Liabilities | 3,760.1 | 3,870.3 | ||||||||||||
Common Stock | 1.4 | 1.4 | ||||||||||||
Additional Paid-in Capital | 3,361.0 | 3,351.1 | ||||||||||||
Treasury Stock | (1,368.9) | (1,367.3) | ||||||||||||
(Accumulated Deficit) Retained Earnings | (1,144.1) | 597.0 | ||||||||||||
Accumulated Other Comprehensive Income | 201.3 | 31.6 | ||||||||||||
Peabody Energy Corporation Stockholders' Equity | 1,050.7 | 2,613.8 | ||||||||||||
Noncontrolling Interests | 50.1 | 58.7 | ||||||||||||
Total Stockholders' Equity | 1,100.8 | 2,672.5 | ||||||||||||
Total Liabilities and Stockholders' Equity | $ | 4,860.9 | $ | 6,542.8 | ||||||||||
| This information is intended to be reviewed in conjunction with the company's filings with the SEC. | ||||||||||||||
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| Condensed Consolidated Statements of Cash Flows (Unaudited) | | ||||||||||||||||||||||
| For the Quarters and Nine Months Ended Sept. 30, 2020 and 2019 | |||||||||||||||||||||||
| (Dollars In Millions) | |||||||||||||||||||||||
| Quarter Ended | Nine Months Ended | ||||||||||||||||||||||
| Sept. | Sept. | Sept. | Sept. | ||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
Cash Flows From Operating Activities | |||||||||||||||||||||||
| Net Cash Provided By (Used In) Continuing Operations | $ | 23.0 | $ | 179.2 | $ | (9.7) | $ | 577.8 | |||||||||||||||
Net Cash Used in Discontinued Operations | (2.0) | (3.6) | (22.4) | (25.2) | |||||||||||||||||||
| Net Cash Provided By (Used In) Operating Activities | 21.0 | 175.6 | (32.1) | 552.6 | |||||||||||||||||||
Cash Flows From Investing Activities | |||||||||||||||||||||||
Additions to Property, Plant, Equipment and Mine Development | (46.1) | (86.0) | (131.9) | (182.8) | |||||||||||||||||||
Changes in Accrued Expenses Related to Capital Expenditures | (0.6) | (5.8) | (14.9) | (5.6) | |||||||||||||||||||
Insurance Proceeds Attributable to North Goonyella Equipment Losses | — | — | — | 23.2 | |||||||||||||||||||
Proceeds from Disposal of Assets, Net of Receivables | 3.4 | 11.8 | 15.4 | 27.6 | |||||||||||||||||||
Amount Attributable to Acquisition of Shoal Creek Mine | — | — | — | (2.4) | |||||||||||||||||||
Contributions to Joint Ventures | (83.2) | (106.8) | (275.2) | (326.4) | |||||||||||||||||||
Distributions from Joint Ventures | 82.8 | 111.2 | 271.0 | 316.7 | |||||||||||||||||||
Advances to Related Parties | — | (8.0) | (23.1) | (12.5) | |||||||||||||||||||
| Cash Receipts from Middlemount Coal Pty Ltd | — | — | — | 14.7 | |||||||||||||||||||
Other, Net | (0.1) | — | (0.7) | (0.1) | |||||||||||||||||||
Net Cash Used In Investing Activities | (43.8) | (83.6) | (159.4) | (147.6) | |||||||||||||||||||
Cash Flows From Financing Activities | |||||||||||||||||||||||
| Proceeds from Long-Term Debt | 60.0 | — | 360.0 | — | |||||||||||||||||||
Repayments of Long-Term Debt | (71.1) | (6.4) | (81.0) | (23.9) | |||||||||||||||||||
Payment of Debt Issuance and Other Deferred Financing Costs | — | (5.6) | — | (6.4) | |||||||||||||||||||
Common Stock Repurchases | — | (144.2) | — | (300.2) | |||||||||||||||||||
Repurchase of Employee Common Stock Relinquished for Tax Withholding | — | — | (1.6) | (12.3) | |||||||||||||||||||
Dividends Paid | — | (14.6) | — | (243.9) | |||||||||||||||||||
Distributions to Noncontrolling Interests | — | (9.0) | (3.5) | (23.4) | |||||||||||||||||||
Other, Net | — | 0.1 | — | 0.1 | |||||||||||||||||||
| Net Cash (Used In) Provided By Financing Activities | (11.1) | (179.7) | 273.9 | (610.0) | |||||||||||||||||||
Net Change in Cash, Cash Equivalents and Restricted Cash | (33.9) | (87.7) | 82.4 | (205.0) | |||||||||||||||||||
Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 848.5 | 900.1 | 732.2 | 1,017.4 | |||||||||||||||||||
Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 814.6 | $ | 812.4 | $ | 814.6 | $ | 812.4 | |||||||||||||||
| This information is intended to be reviewed in conjunction with the company's filings with the SEC. | |||||||||||||||||||||||
10
| Reconciliation of Non-GAAP Financial Measures (Unaudited) | | |||||||||||||||||||||||||
| For the Quarters and Nine Months Ended Sept. 30, 2020 and 2019 | ||||||||||||||||||||||||||
| (Dollars In Millions) | ||||||||||||||||||||||||||
Note: Management believes that non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. | ||||||||||||||||||||||||||
| Quarter Ended | Nine Months Ended | |||||||||||||||||||||||||
| Sept. | Sept. | Sept. | Sept. | |||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| (Loss) Income from Continuing Operations, Net of Income Taxes | $ | (64.8) | $ | (74.3) | $ | (1,739.4) | $ | 101.9 | ||||||||||||||||||
Depreciation, Depletion and Amortization | 72.2 | 141.5 | 266.5 | 479.4 | ||||||||||||||||||||||
Asset Retirement Obligation Expenses | 14.3 | 15.5 | 46.0 | 44.6 | ||||||||||||||||||||||
Restructuring Charges | 8.1 | 0.7 | 31.1 | 1.3 | ||||||||||||||||||||||
Transaction Costs Related to Joint Ventures | 6.0 | 8.2 | 23.1 | 9.8 | ||||||||||||||||||||||
Asset Impairment | — | 20.0 | 1,418.1 | 20.0 | ||||||||||||||||||||||
Provision for North Goonyella Equipment Loss | — | — | — | 24.7 | ||||||||||||||||||||||
North Goonyella Insurance Recovery - Equipment (1) | — | — | — | (91.1) | ||||||||||||||||||||||
Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates | (0.5) | — | (1.6) | 0.3 | ||||||||||||||||||||||
Interest Expense | 34.9 | 35.4 | 102.3 | 107.2 | ||||||||||||||||||||||
Interest Income | (1.6) | (7.0) | (7.1) | (22.5) | ||||||||||||||||||||||
| Net Mark-to-Market Adjustment on Actuarially Determined Liabilities | 13.0 | — | 13.0 | — | ||||||||||||||||||||||
| Unrealized Losses (Gains) on Economic Hedges | 16.1 | 18.0 | 11.3 | (44.2) | ||||||||||||||||||||||
| Unrealized Gains on Non-Coal Trading Derivative Contracts | (0.7) | (0.3) | (3.6) | (0.2) | ||||||||||||||||||||||
Take-or-Pay Contract-Based Intangible Recognition | (1.5) | (2.7) | (6.8) | (13.9) | ||||||||||||||||||||||
Income Tax (Benefit) Provision | (0.1) | 4.2 | 2.7 | 26.0 | ||||||||||||||||||||||
Adjusted EBITDA (2) | $ | 95.4 | $ | 159.2 | $ | 155.6 | $ | 643.3 | ||||||||||||||||||
Operating Costs and Expenses | $ | 550.9 | $ | 905.5 | $ | 1,886.7 | $ | 2,711.5 | ||||||||||||||||||
| Unrealized Gains on Non-Coal Trading Derivative Contracts | 0.7 | 0.3 | 3.6 | 0.2 | ||||||||||||||||||||||
Take-or-Pay Contract-Based Intangible Recognition | 1.5 | 2.7 | 6.8 | 13.9 | ||||||||||||||||||||||
North Goonyella Insurance Recovery - Cost Recovery and Business Interruption (1) | — | — | — | (33.9) | ||||||||||||||||||||||
Net Periodic Benefit Costs, Excluding Service Cost | 2.8 | 4.9 | 8.3 | 14.6 | ||||||||||||||||||||||
Total Reporting Segment Costs (3) | $ | 555.9 | $ | 913.4 | $ | 1,905.4 | $ | 2,706.3 | ||||||||||||||||||
| Net Cash Provided By (Used In) Operating Activities | $ | 21.0 | $ | 175.6 | $ | (32.1) | $ | 552.6 | ||||||||||||||||||
Net Cash Used In Investing Activities | (43.8) | (83.6) | (159.4) | (147.6) | ||||||||||||||||||||||
Add Back: Amount Attributable to Acquisition of Shoal Creek Mine | — | — | — | 2.4 | ||||||||||||||||||||||
Free Cash Flow (4) | $ | (22.8) | $ | 92.0 | $ | (191.5) | $ | 407.4 | ||||||||||||||||||
| (1) | We recorded a $125.0 million insurance recovery during the nine months ended September 30, 2019 related to losses incurred at our North Goonyella Mine. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the nine months ended September 30, 2019 and the year ended December 31, 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the nine months ended September 30, 2019. | |||||||||||||||||||||||||
| (2) | Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. 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 above. Adjusted EBITDA is used by management as the primary metric to measure each of our segment's operating performance. We have retrospectively modified our calculation of Adjusted EBITDA to exclude restructuring charges and transaction costs related to joint ventures as management does not view these items as part of our normal operations. | |||||||||||||||||||||||||
| (3) | Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of our segment's operating performance as displayed in the reconciliation above. Total Reporting Segment Costs is used by management as a metric to measure each of our segment's operating performance. We have retrospectively modified our calculation of Total Reporting Segment Costs to exclude restructuring charges as management does not view this item as part of our normal operations. | |||||||||||||||||||||||||
| (4) | 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. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations. | |||||||||||||||||||||||||
| This information is intended to be reviewed in conjunction with the company's filings with the SEC. | ||||||||||||||||||||||||||
11
| Reconciliation of Non-GAAP Financial Measures (Unaudited) | | |||||||||||||
| As of Sept. 30, 2020 and Dec. 31, 2019 | ||||||||||||||
| (Dollars In Millions) | ||||||||||||||
Note: Management believes that non-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. | ||||||||||||||
| (Unaudited) | ||||||||||||||
| Sept. 30, 2020 | Dec. 31, 2019 | |||||||||||||
Current Portion of Long-Term Debt | $ | 1,600.1 | $ | 18.3 | ||||||||||
Long-Term Debt, Less Current Portion | — | 1,292.5 | ||||||||||||
Less: Cash and Cash Equivalents | (814.6) | (732.2) | ||||||||||||
Net Debt (1) | $ | 785.5 | $ | 578.6 | ||||||||||
| (1) | Net Debt is defined as current portion of long-term debt plus long-term debt, less current portion less cash and cash equivalents. Net Debt is reviewed by management as an indicator of our overall financial flexibility, capital structure and leverage. | |||||||||||||
| This information is intended to be reviewed in conjunction with the company's filings with the SEC. | ||||||||||||||
12
Forward-Looking Statements
This press release contains forward-looking statements within the meaning of the securities laws. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. They often include words or variation of words such as "expects," "anticipates," "intends," "plans," "believes," "seeks," "estimates," "projects," "forecasts," "targets," "would," "will," "should," "goal," "could" or "may" or other similar expressions. Forward-looking statements provide management's current expectations or predictions of future conditions, events or results. All statements that address operating performance, events, or developments that Peabody expects will occur in the future are forward-looking statements. They may include estimates of sales targets, cost savings, capital expenditures, other expense items, actions relating to strategic initiatives, demand for the company’s products, liquidity, capital structure, market share, industry volume, other financial items, descriptions of management’s plans or objectives for future operations and descriptions of assumptions underlying any of the above. All forward-looking statements speak only as of the date they are made and reflect Peabody’s good faith beliefs, assumptions and expectations, but they are not guarantees of future performance or events. Furthermore, Peabody disclaims any obligation to publicly update or revise any forward-looking statement, except as required by law. By their nature, forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Factors that might cause such differences include, but are not limited to, a variety of economic, competitive and regulatory factors, many of which are beyond Peabody’s control, including the ongoing impact of the COVID-19 pandemic and factors that are described in Peabody’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019, and other factors that Peabody may describe from time to time in other filings with the SEC. You may get such filings for free at Peabody’s website at www.peabodyenergy.com. You should understand that it is not possible to predict or identify all such factors and, consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.
13