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, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or Peabody's future financial performance. 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. 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" of Part II of this Quarterly Report on Form 10-Q, and Item 1A. "Risk Factors" and Item 3. "Legal Proceedings" of Part I of its Annual Report on Form 10-K for the year endedDecember 31, 2022 filed with theSEC onFebruary 24, 2023 . 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.
Non-GAAP Financial Measures
The following discussion of the Company's results of operations includes references to and analysis of Adjusted EBITDA and Total Reporting Segment Costs, which are financial measures not recognized in accordance 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 and allocate resources. Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments' operating performance. Also included in the following discussion of the Company's results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment. These metrics are used by management to measure each of its reporting segments' operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the "Reconciliation of Non-GAAP Financial Measures" section contained within this Item 2. The Company believes non-GAAP performance measures are used by investors to measure its operating performance. 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. 24
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Table of Contents Overview Peabody is a leading producer of metallurgical and thermal coal. In 2022, the Company produced and sold 122.9 million and 123.7 million tons of coal, respectively, from continuing operations. AtMarch 31, 2023 , 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; trades coal and freight-related contracts; and during 2022, partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in theU.S. , for utility-scale photovoltaic solar generation and battery storage. 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 13. "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. Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 index thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal andIllinois Basin 11,500 Btu/Lb coal during the three months endedMarch 31, 2023 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, 2023 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. The Company's typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. In 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, 2023 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. March 31, April 28, High Low Average 2023 2023 Premium HCC (1)$ 390.00 $ 294.50 $ 343.91 $ 301.00 $ 231.50 Premium PCI coal (1) 344.00 263.50 313.01 263.50 201.00 Newcastle index thermal coal (1) 397.30 170.80 242.37 178.53 186.31 API 5 index thermal coal (1) 135.29 117.72 125.12 120.68 116.66 PRB 8,800 Btu/Lb coal (2) 15.50 14.60 14.96 14.60 14.55Illinois Basin 11,500 Btu/Lb coal (2) 133.00 73.00 92.08 73.00 65.00 (1) Prices expressed per metric tonne. (2) Prices expressed per short ton. Within the global coal industry, supply and demand for its products and the supplies used for mining have been impacted by the ongoing Russian-Ukrainian conflict. Furthermore, inflationary pressures and supply chain constraints have contributed to rising costs and may continue to impact future periods. As future developments related to the Russian-Ukrainian conflict and rising inflation are unknown, the global coal industry data for the three months endedMarch 31, 2023 presented herein may not be indicative of their ultimate impacts. 25
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Within the seaborne metallurgical coal market, the three months endedMarch 31, 2023 were characterized by ongoing volatility as global macroeconomic turbulence counteracted improving demand and further weather-induced supply disruptions inAustralia . Several steelmakers announced blast furnace capacity restarts in the three months endedMarch 31, 2023 , as growth in forward orders drives improvements to steel prices and margins. This is supportive for seaborne metallurgical coal demand in the coming period. Furthermore,China has ended its unofficial ban of Australian coal imports providing increased market depth for Australian products, especially for Premium HCC. Russian coal remains banned in theEuropean Union ,Japan and elsewhere, disrupting natural trade flows and resulting in low priced Russian products being made available to countries, such asChina andIndia , which can continue procurement. The PCI market remained exceedingly tight during the three months endedMarch 31, 2023 , especially inEurope , whereRussia traditionally held dominant market share. The Company believes energy shortages and the global inflationary environment present a risk to industrial activity in some markets, but the underlying market fundamentals remain constructive with continuing themes of supply tightness, resilient demand and further economic stimulus inChina and elsewhere. Within the seaborne thermal coal market, global thermal coal prices stabilized in March and recently showed improvement amid supply distributions inColombia andAustralia and ongoing robust demand fromIndia andChina .China has ended its unofficial ban of Australian coal imports, providing additional demand for Australian thermal coal. InChina , domestic coal production and renewable generation have been strong to start the year, however, import demand has been higher year-over-year, as overall coal demand has been strong. InIndia , strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent as supply has been disrupted due to logistics and weather issues and lower global natural gas prices. Inthe United States , overall electricity demand decreased nearly 4% year-over-year, negatively impacted by weather. Through the three months endedMarch 31, 2023 , electricity generation from thermal coal has declined year-over-year due to low gas prices, and stronger gas and renewable generation despite lower overall electricity demand. Coal's share of electricity generation has declined to approximately 15% for the three months endedMarch 31, 2023 , while wind and solar's combined generation share has increased to 17% and the share of gas generation has increased to 39%. Coal inventories have increased during the three months endedMarch 31, 2023 , with an increase of approximately 25% or 22 million tons. During the three months endedMarch 31, 2023 , utility consumption of PRB coal declined approximately 25% compared to the prior year period. Surety Agreement Amendment OnApril 14, 2023 , the Company amended its existing agreement with the providers of its surety bond portfolio, datedNovember 6, 2020 . Under the agreement, the Company was required to post collateral on a periodic basis. Pursuant to the amendment, the Company and its surety bond providers agreed to (i) establish a combined maximum collateral cap, (ii) remove the restrictions on shareholder returns contained in the original agreement, subject to a minimum liquidity threshold, and (iii) extend the expiration date of the existing agreement fromDecember 31, 2025 toDecember 31, 2026 . Peabody also terminated the letter of credit facility which was previously used primarily for surety collateral, further reducing interest costs and increasing financial flexibility.
Refer to the "Liquidity and Capital Resources" section contained within this Item 2 for a further discussion of the surety agreement amendment.
Other
OnMarch 29, 2023 , theCompany's Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine. All mine personnel were safely evacuated from the mine. TheMine Safety and Health Administration (MSHA) has allowed mine rescue-equipped personnel into the mine at various times to assess the situation. OnApril 26, 2023 , MSHA approved a temporary sealing program which was completed onApril 28, 2023 , and the Company continues to monitor air quality in the affected underground area.
Results of Operations
Three Months Ended
Summary The increase in results from continuing operations, net of income taxes for the three months endedMarch 31, 2023 compared to the same period in the prior year ($403.9 million ), was primarily driven by higher revenue ($672.6 million ) due to higher realized prices and volumes. This favorable variance was partially offset by higher operating costs and expenses ($147.6 million ), which reflect increased sales price sensitive costs and inflationary pressures for commodities, materials, services, repairs and labor; and a higher income tax provision ($119.0 million ). 26
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Adjusted EBITDA for the three months ended
Tons Sold
The following table presents tons sold by operating segment:
(Decrease) Increase
Three Months Ended March 31, to Volumes
2023 2022 Tons %
(Tons in millions)
Seaborne Thermal Mining 3.6 3.8 (0.2) (5) %
Seaborne Metallurgical Mining 1.3 1.2 0.1 8 %
Powder River Basin Mining 22.0 20.6 1.4 7 %
Other U.S. Thermal Mining 4.5 4.2 0.3 7 %
Total tons sold from operating segments 31.4 29.8 1.6 5 %
Corporate and Other 0.1 0.1 - - %
Total tons sold 31.5 29.9 1.6 5 %
Supplemental Financial Data
The following table presents supplemental financial data by operating segment:
Increase
Three Months Ended March 31, (Decrease)
2023 2022 $ %
Revenue per Ton - Mining Operations (1)
Seaborne Thermal $ 96.82 $ 66.86 $ 29.96 45 %
Seaborne Metallurgical 220.60 258.43 (37.83) (15) %
Powder River Basin 13.89 12.18 1.71 14 %
Other U.S. Thermal 54.73 48.46 6.27 13 %
Costs per Ton - Mining Operations (1)(2)
Seaborne Thermal $ 51.01 $ 42.77 $ 8.24 19 %
Seaborne Metallurgical 151.13 112.87 38.26 34 %
Powder River Basin 12.26 11.81 0.45 4 %
Other U.S. Thermal 40.65 36.54 4.11 11 %
Adjusted EBITDA Margin per Ton - Mining Operations (1)(2)
Seaborne Thermal $ 45.81 $ 24.09 $ 21.72 90 %
Seaborne Metallurgical 69.47 145.56 (76.09) (52) %
Powder River Basin 1.63 0.37 1.26 341 %
Other U.S. Thermal 14.08 11.92 2.16 18 %
(1)This is an operating/statistical measure not recognized in accordance with
U.S. GAAP. Refer to the "Reconciliation of Non-GAAP Financial Measures" section
below for definitions and reconciliations to the most comparable measures under
U.S. GAAP.
(2)Includes revenue-based production taxes and royalties; excludes depreciation,
depletion and amortization; asset retirement obligation expenses; selling and
administrative expenses; restructuring charges; asset impairment; amortization
of take-or-pay contract-based intangibles; and certain other costs related to
post-mining activities.
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Table of Contents Revenue
The following table presents revenue by reporting segment:
Three Months Ended March 31, Increase (Decrease) to Revenue
2023 2022 $ %
(Dollars in millions)
Seaborne Thermal Mining $ 346.5 $ 251.2 $ 95.3 38 %
Seaborne Metallurgical Mining 288.4 321.3 (32.9) (10) %
Powder River Basin Mining 305.3 251.2 54.1 22 %
Other U.S. Thermal Mining 249.4 203.1 46.3 23 %
Corporate and Other 174.4 (335.4) 509.8 152 %
Revenue $ 1,364.0 $ 691.4 $ 672.6 97 %
Seaborne Thermal Mining. Segment revenue increased during the three months ended
March 31, 2023 compared to the same period in the prior year due to favorable
realized prices ($68.7 million ) and favorable mix variances ($26.6 million )
which offset unfavorable volumes.
Seaborne Metallurgical Mining. Segment revenue decreased during the three months
ended
PowderRiver Basin Mining . Segment revenue increased during the three months endedMarch 31, 2023 compared to the same period in the prior year due to favorable realized prices ($33.3 million ) and favorable volumes ($20.8 million ) resulting from improved rail performance.
Other
Corporate and Other. Segment revenue increased during the three months endedMarch 31, 2023 compared to the same period in the prior year due to net unrealized mark-to-market gains on derivative contracts related to forecasted coal sales in the current year compared to net unrealized mark-to-market losses in the prior year ($419.7 million ); higher results from trading activities ($72.7 million ) due to higher margins recognized on the physical sale of coal and lower net realized losses on derivative contracts related to forecasted coal sales; and revenue related to the Company's assignment of rights to its excess port and rail capacity ($19.2 million ) as discussed in Note 14. "Other Events" to the accompanying unaudited condensed consolidated financial statements.
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of the Company's reporting
segments:
Increase (Decrease) to Segment
Three Months Ended March 31, Adjusted EBITDA
2023 2022 $ %
(Dollars in millions)
Seaborne Thermal Mining $ 164.0 $ 90.5 $ 73.5 81 %
Seaborne Metallurgical Mining 90.8 181.0 (90.2) (50) %
Powder River Basin Mining 35.8 7.6 28.2 371 %
Other U.S. Thermal Mining 64.2 50.0 14.2 28 %
Corporate and Other 35.8 (1.6) 37.4 2,338 %
Adjusted EBITDA (1) $ 390.6 $ 327.5 $ 63.1 19 %
(1)This is a financial measure not recognized in accordance with
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Seaborne Thermal Mining. Segment Adjusted EBITDA increased during the three months endedMarch 31, 2023 compared to the same period in the prior year as a result of higher realized prices net of sales sensitive costs ($64.1 million ) and favorable mix variances ($26.6 million ), partially offset by higher commodity pricing ($8.9 million ) and higher port and demurrage costs ($7.1 million ). Seaborne Metallurgical Mining. Segment Adjusted EBITDA decreased during the three months endedMarch 31, 2023 compared to the same period in the prior year due to unfavorable operational costs ($50.4 million ) resulting from wet weather impacts at the Coppabella and Moorvale Mines and geological conditions at theShoal Creek Mine and lower realized prices net of sales sensitive costs ($43.8million ). PowderRiver Basin Mining . Segment Adjusted EBITDA increased during the three months endedMarch 31, 2023 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($22.1 million ); decreased overburden removal costs ($11.0 million ); and favorable volumes ($7.3 million ) resulting from improved rail performance. The increases were partially offset by higher costs for materials, services, repairs and labor ($9.7 million ) due in part to timing, increased repairs for an aging equipment fleet and inflationary pressures on materials and services. OtherU.S. Thermal Mining. Segment Adjusted EBITDA increased during the three months endedMarch 31, 2023 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($24.6 million ) and favorable volumes ($11.0 million ). These increases were offset by higher costs for materials, services, repairs and labor ($16.9 million ) due in part to increased equipment repairs and headcount resulting from increasing volume demands and inflationary pressures on materials and services.
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
Three Months Ended March (Decrease) Increase to Adjusted
31, EBITDA
2023 2022 $ %
(Dollars in millions)
Middlemount (1) $ 2.3 $ 45.1 $ (42.8) (95) %
Resource management activities (2) 2.3 3.5 (1.2) (34) %
Selling and administrative expenses (22.8) (23.1) 0.3 1 %
Other items, net (3) 54.0 (27.1) 81.1 299 %
Corporate and Other Adjusted EBITDA $ 35.8 $ (1.6) $ 37.4 2,338 %
(1)Middlemount's results are before the impact of related changes in
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 $2.6 million and $20.2 million during the three months ended
March 31, 2023 and 2022, respectively.
(2)Includes gains (losses) on certain surplus coal reserve, resource and surface land sales and property management costs and revenue.
(3)Includes trading and brokerage activities, costs associated with post-mining
activities, gains (losses) on certain asset disposals, minimum charges on
certain transportation-related contracts, costs associated with suspended
operations including the
Corporate and Other Adjusted EBITDA benefited during the three months endedMarch 31, 2023 compared to the same period in the prior year from favorable trading results ($69.7 million ) and revenue related to the Company's assignment of rights to its excess port and rail capacity ($19.2 million ) as discussed in Note 14. "Other Events" to the accompanying unaudited condensed consolidated financial statements. This benefit was offset by unfavorable variances in Middlemount's results due to lower sales pricing and sales volumes. 29
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Income (Loss) From Continuing Operations, Net of Income Taxes
The following table presents income (loss) from continuing operations, net of
income taxes:
Three Months Ended March 31, Increase (Decrease) to Income
2023 2022 $ %
(Dollars in millions)
Adjusted EBITDA (1) $ 390.6 $ 327.5 $ 63.1 19 %
Depreciation, depletion and amortization (76.3) (72.9) (3.4) (5) %
Asset retirement obligation expenses (15.4) (15.0) (0.4) (3) %
Restructuring charges (0.1) (1.6) 1.5 94 %
Asset impairment (2.0) - (2.0) n.m.
Changes in amortization of basis difference related to equity affiliates
0.3 0.6 (0.3) (50) %
Interest expense (18.4) (39.4) 21.0 53 %
Net loss on early debt extinguishment (6.8) (23.5) 16.7 71 %
Interest income 13.1 0.5 12.6 2,520 %
Unrealized gains (losses) on derivative contracts related to forecasted sales
118.7 (301.0) 419.7 139 %
Unrealized (losses) gains on foreign currency option contracts
(2.2) 3.3 (5.5) (167) %
Take-or-pay contract-based intangible recognition 0.6 0.7 (0.1) (14) %
Income tax (provision) benefit (118.0) 1.0 (119.0) (11,900) %
Income (loss) from continuing operations, net of income taxes
$ 284.1 $ (119.8) $ 403.9 337 %
(1)This is a financial measure not recognized in accordance with
Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment:
Three Months Ended March 31, Increase (Decrease) to Income
2023 2022 $ %
(Dollars in millions)
Seaborne Thermal Mining $ (23.8) $ (24.0) $ 0.2 1 %
Seaborne Metallurgical Mining (21.1) (19.9) (1.2) (6) %
Powder River Basin Mining (11.7) (10.5) (1.2) (11) %
Other U.S. Thermal Mining (17.7) (15.7) (2.0) (13) %
Corporate and Other (2.0) (2.8) 0.8 29 %
Total $ (76.3) $ (72.9) $ (3.4) (5) %
Additionally, the following table presents a summary of the Company's
weighted-average depletion rate per ton for active mines in each of its
operating segments:
Three Months Ended March 31,
2023 2022
Seaborne Thermal Mining $ 2.17
Seaborne Metallurgical Mining 2.16 2.12
Powder River Basin Mining 0.31 0.33
Other U.S. Thermal Mining 1.21 1.17
The decrease in the weighted-average depletion rate per ton for the Seaborne Thermal Mining segment during the three months endedMarch 31, 2023 compared to the same period in the prior year reflects the impact of volume and mix variances across the segment. 30
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Interest Expense. The decrease in interest expense during the three months endedMarch 31, 2023 primarily reflects the impacts of debt retirements completed by the Company during 2022 as further described in Note 8. "Long-term Debt" to the accompanying unaudited condensed consolidated financial statements and Note 10. "Long-term Debt" to the Annual Report on Form 10-K for the year endedDecember 31, 2022 . Net Loss on Early Debt Extinguishment. The losses recognized during the three months endedMarch 31, 2023 were primarily related to the amendment of the Company's now-terminated letter of credit facility as further discussed in Note 11. "Financial Instruments and Other Guarantees" to the accompanying unaudited condensed consolidated financial statements. The losses recognized during the prior year period were primarily related to the redemption of existing notes during the period as further described in Note 8. "Long-term Debt" to the accompanying unaudited condensed consolidated financial statements and Note 10. "Long-term Debt" to the Annual Report on Form 10-K for the year endedDecember 31, 2022 . Interest Income. The increase in interest income during the three months endedMarch 31, 2023 was primarily due to higher cash balances, including restricted cash balances on which the Company earns interest, and higher interest rates in the current year. Based upon projected cash balances and interest rates, the Company anticipates significantly higher interest income throughout 2023 as compared to the prior year. Unrealized Gains (Losses) on Derivative Contracts Related to Forecasted Sales. Unrealized gains (losses) primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales. For additional information, refer to Note 5. "Derivatives and Fair Value Measurements" to the accompanying unaudited condensed consolidated financial statements. Unrealized (Losses) Gains on Foreign Currency Option Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 5. "Derivatives and Fair Value Measurements" to the accompanying unaudited condensed consolidated financial statements. Income Tax (Provision) Benefit. The increase in the income tax provision during the three months endedMarch 31, 2023 compared to the same period in the prior year was primarily due to an increase in pretax income and the release of valuation allowance related to Australian net operating losses during the fourth quarter of 2022. Refer to Note 7. "Income Taxes" to the accompanying unaudited condensed consolidated financial statements for additional information.
Net Income (Loss) Attributable to Common Stockholders
The following table presents net income (loss) attributable to common
stockholders:
Increase (Decrease)
Three Months Ended March 31, to Income
2023 2022 $ %
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes $ 284.1 $ (119.8) $ 403.9 337 %
Loss from discontinued operations, net of income taxes (1.3) (0.8) (0.5) (63) %
Net income (loss) 282.8 (120.6) 403.4 334 %
Less: Net income (loss) attributable to noncontrolling interests
14.3 (1.1) 15.4 1,400 %
Net income (loss) attributable to common stockholders
$ (119.5) $ 388.0 325 % Net Income (Loss) Attributable to Noncontrolling Interests. The increase in the results attributable to noncontrolling interests during the three months endedMarch 31, 2023 compared to the same period in the prior year was primarily due to stronger financial results of Peabody's majority-owned Wambo operations in which there is an outside non-controlling interest. 31
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Diluted Earnings per Share (EPS)
The following table presents diluted EPS:
Increase
Three Months Ended March 31, to EPS
2023 2022 $ %
Diluted EPS attributable to common stockholders:
Income (loss) from continuing operations $ 1.69 $ (0.87) $ 2.56 294 %
Loss from discontinued operations (0.01) (0.01) - - %
Net income (loss) attributable to common stockholders
$ (0.88) $ 2.56 291 % 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 161.4 million and 136.2 million for the three months endedMarch 31, 2023 and 2022, respectively.
Reconciliation of Non-GAAP Financial Measures
Adjusted EBITDA is defined as income (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,
2023 2022
(Dollars in millions)
Income (loss) from continuing operations, net of income taxes $ 284.1 $ (119.8)
Depreciation, depletion and amortization 76.3 72.9
Asset retirement obligation expenses 15.4 15.0
Restructuring charges 0.1 1.6
Asset impairment 2.0 -
Changes in amortization of basis difference related to equity affiliates
(0.3) (0.6)
Interest expense 18.4 39.4
Net loss on early debt extinguishment 6.8 23.5
Interest income (13.1) (0.5)
Unrealized (gains) losses on derivative contracts related to forecasted sales (118.7)
301.0
Unrealized losses (gains) on foreign currency option contracts 2.2 (3.3)
Take-or-pay contract-based intangible recognition (0.6) (0.7)
Income tax provision (benefit) 118.0 (1.0)
Total Adjusted EBITDA $ 390.6 $ 327.5 Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its segments' operating performance, as displayed in the reconciliations below.
Three Months Ended March 31,
2023 2022
(Dollars in millions)
Operating costs and expenses $ 846.6 $ 699.0
Unrealized (losses) gains on foreign currency option contracts (2.2) 3.3
Take-or-pay contract-based intangible recognition 0.6 0.7
Net periodic benefit credit, excluding service cost (9.7) (12.2)
Total Reporting Segment Costs $ 835.3 $ 690.8
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The following table presents Total Reporting Segment Costs by reporting segment:
Three Months Ended March 31,
2023 2022
(Dollars in millions)
Seaborne Thermal Mining $ 182.5 $ 160.7
Seaborne Metallurgical Mining 197.6 140.3
Powder River Basin Mining 269.5 243.6
Other U.S. Thermal Mining 185.2 153.1
Corporate and Other 0.5 (6.9)
Total Reporting Segment Costs $ 835.3 $ 690.8
Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment, respectively, divided by segment tons sold. Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton.
The following tables present tons sold, revenue, Total Reporting Segment Costs and Adjusted EBITDA by operating 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 3.6 1.3 22.0 4.5
Revenue $ 346.5 $
288.4
182.5 197.6 269.5 185.2
Adjusted EBITDA $ 164.0 $ 90.8 $ 35.8 $ 64.2
Revenue per Ton $ 96.82 $ 220.60 $ 13.89 $ 54.73
Costs per Ton 51.01 151.13 12.26 40.65
Adjusted EBITDA Margin per Ton $ 45.81 $
69.47
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 3.8 1.2 20.6 4.2
Revenue $ 251.2 $
321.3
160.7 140.3 243.6 153.1
Adjusted EBITDA $ 90.5 $ 181.0 $ 7.6 $ 50.0
Revenue per Ton $ 66.86 $ 258.43 $ 12.18 $ 48.46
Costs per Ton 42.77 112.87 11.81 36.54
Adjusted EBITDA Margin per Ton $ 24.09 $ 145.56 $ 0.37 $ 11.92
Regulatory Update
Other than as described in the following section, there were no significant
changes to the Company's regulatory matters subsequent to December 31, 2022 .
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 ended
December 31, 2022 .
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Table of Contents Regulatory Matters -U.S. National Ambient Air Quality Standards (NAAQS). The Clean Air Act (CAA) requires theUnited States Environmental Protection Agency (EPA ) to review national ambient air quality standards 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 NAAQS promulgated in 2015, including both the primary (public health) and secondary (public welfare) standards. TheEPA subsequently promulgated final standards to this effect. In 2021, fifteen states and other petitioners filed a petition for review of the rule in theUnited States Court of Appeals for the D.C. Circuit (D.C. Circuit). The litigation is currently in abeyance following a motion filed by theEPA to allow for review of the standards. TheEPA also proposed in 2020 to retain the particulate matter (PM) NAAQS last revised 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. The case is currently in abeyance following a motion filed by theEPA to allow for review of the standards. OnJanuary 6, 2023 , theEPA proposed to lower the level of the annual PM2.5 NAAQS from 12.0 ug/m3 to within the range of 9.0 to 10.0 ug/m3. If enacted as proposed, this rule would require fossil fuel generating units to install additional nitrogen oxide (NOx) reducing technologies ultimately increasing the cost of fossil fuel generated energy or causing potential unit retirements. 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 additional reductions in NOx beginning in 2017 in 22 states subject to CSAPR. This rule was subsequently remanded back to theEPA .Wisconsin v.EPA , 938 F.3d 303. InApril 2021 , theEPA published a final rule in theFederal Register to address the D.C. Circuit remand. This rule imposed further reductions of NOx emissions in 12 states that were subject to the original 2016 rule, which was based on the 2008 ozone NAAQS. In the same rule, theEPA determined that 9 states did not significantly contribute to downwind nonattainment and/or maintenance issues and therefore did not require additional emission reductions. TheEPA subsequently issued Federal Implementation Plans to lower state ozone season NOx budgets in 2021 to 2024 in the affected states. A petition for review challenging the 2021 rule was filed in the D.C. Circuit. Briefing is completed and oral arguments were heldSeptember 28, 2022 , but this does not stay the effectiveness of the rule. OnMarch 15, 2023 , theEPA Administrator signed a final rule to address regional ozone transport for the 2015 ozone NAAQS by imposing new federal ozone season emission budgets for NOx in 23 states, includingCalifornia ,Nevada ,Oklahoma andTexas , as well as some areas in Indian country. The rule includes emission limits for NOx for fossil fuel-fired power plants and a "backstop daily emissions rate" for large coal-fired power plants if they exceed specified limits. The rule also sets first-time limits on certain industrial sources that will apply starting with the 2026 ozone season in 20 states. TheEPA estimates that annual compliance costs (for 2023 through 2042) will be$770 million to$910 million , depending on the discount rate applied. These emission limitations would apply in addition to requirements contained in State Implementation Plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations. When implemented, this rule could influence the closure of some coal generating units that haven't installed selective catalytic reduction technologies. Mercury and Air Toxic Standards (MATS). TheEPA published the final MATS rule in theFederal Register in 2012. The MATS rule revised the New Source Performance Standards for NOx, sulfur dioxide and PM for new and modified coal-fueled electricity generating plants, and imposed maximum achievable control technology (MACT) emission limits on hazardous air pollutants (HAPs) from new and existing coal-fueled and oil-fueled electric generating plants. MACT standards limit emissions of mercury, acid gas HAPs, non-mercury HAP metals and organic HAPs. 34
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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 electricity utility generating units source category. Both actions were challenged in the D.C. Circuit but this litigation was placed in abeyance. OnFebruary 9, 2022 theEPA proposed a rule to revoke the 2020 finding and to reaffirm the agency's 2016 finding that it remained "appropriate and necessary" to regulate HAP emissions from coal- and oil-fired power plants under Section 112 of the CAA. In the same proposal, theEPA solicited comments on the performance and cost of new or improved technologies to control HAPs from these power plants as part of the agency's review of related residual risk and technology review standards. TheEPA finalized the 2022 proposed rule onMarch 6, 2023 , revoking the 2020 finding and concluding that it is appropriate and necessary to regulate coal- and oil-fired electric steam generating units under CAA Section 112. If enacted, this rule could influence closure of additional coal generating units. Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. OnSeptember 30, 2015 , theEPA published a final rule setting new or additional requirements for various wastewater discharges from steam electric power plants. The rule set zero discharge requirements for some waste streams, as well as new, more stringent limits for arsenic, mercury, selenium and nitrogen applicable to certain other waste streams. OnOctober 13, 2020 , theEPA issued a final rule revising the technology-based effluent limitations guidelines and standards for the steam electric power generating point source category applicable to flue gas desulfurization wastewater and bottom ash transport water. However, onMarch 8, 2023 , theEPA released the pre-publication versions of two actions to further revise certain discharge limits applicable to steam electric power plants. The first action is a proposed rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate. If the proposed rule is finalized in substantially the same form, the revised effluent limitations guidelines would significantly increase costs for many coal-fired steam electric power plants. The second action is a direct final rule that extends the deadline for steam electric power plants to opt in to the 2028 early retirement provision that was part of the 2020 rule. The direct final rule could influence fuel switching or additional coal generating unit retirements by the end of 2028.
Regulatory Matters -
New South Wales Coal Directions. TheState of New South Wales (NSW) enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). OnDecember 22, 2022 , the State Premier declared a coal market price emergency on the basis that the declaration was necessary to reduce the risk that increases in coal prices could contribute to an increase in electricity prices. OnDecember 23, 2022 , directions were issued toPeabody Energy Australia Pty Ltd and a number of other coal producers with operations in NSW. Those directions were amended onJanuary 31, 2023 andFebruary 16, 2023 . The most recent directions requirePeabody Energy Australia Pty Ltd to reserve a portion of coal produced byWambo Coal Pty Ltd and byWilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price untilJune 30, 2024 and impose additional reporting obligations to demonstrate compliance with the directions. While these directions are currently not anticipated to significantly impact the Wambo Mines or theWilpinjong Mine , the nature and extent of those obligations and associated reporting requirements may continue to evolve if further directions are issued. National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system. The Clean Energy Regulator administers the NGER Act. The federalDepartment of Environment and Energy is responsible for NGER Act-related policy developments and review. OnJuly 1, 2016 , amendments to the NGER Act implemented the Emissions Reduction Fund Safeguard Mechanism. From that date, large designated facilities such as coal mines were issued with a baseline for their covered emissions and must take steps to keep their emissions at or below the baseline or face penalties. The National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 outlines key elements of a responsible emitter's duty to avoid an excess emissions situation and provides detail on how it can meet that requirement. The rule was amended between 2019 and 2021 to transition responsible emitters to new baseline setting arrangements. From the start of the 2020-21 compliance year, baselines must use prescribed production variables (an example being run of mine coal) and default emissions intensity values (being values set by the government to represent the industry average emissions intensity of production over five years) unless specific exemptions apply (such as a facility having site-specific values set). 35
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OnJanuary 10, 2023 , the Australian federal government released its Safeguard Mechanism Reforms Position Paper setting out the proposed changes to the emissions reduction regime. The reforms will commence onJuly 1, 2023 utilizing site specific baseline emissions as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of$75 Australian dollars per tonne of carbon dioxide (CO2) in 2023-24, increasing with the Consumer Price Index plus 2% each year. OnMarch 27, 2023 , the Australian Federal Government announced a number of additional measures in the Safeguard Mechanism (Crediting) Amendments Bill 2023 which was introduced and passed both Houses ofParliament onMarch 30, 2023 . The legislation introduces a cap on overall net emissions from facilities covered by the scheme through to 2030. The legislation also sets a cap of net zero tonnes CO2-e for any financial year beginning afterJune 30, 2049 . In addition, if the Minister for Environment and Water grants an approval under the Environment Protection and Biodiversity Conservation Act 1999 (Cth) (EPBC Act) to a new or expanded facility covered by the scheme, the Minister will be required to give an estimate of the facility's Scope 1 emissions to the Minister for Climate Change, the Climate Change Secretary and theClimate Change Authority for assessment against scheme targets. The legislation is now awaiting assent and is expected to commence onJuly 1, 2023 . The potential impact of these reforms to Peabody's Australian operations is under review.
Risks Related to Global Climate Change
Peabody recognizes that climate change is occurring and that human activity, including the use of fossil fuels, contributes to greenhouse gas (GHG) emissions. The Company's largest contribution to GHG emissions occurs indirectly, through the coal used by its customers in the generation of electricity and the production of steel (Scope 3). To a lesser extent, the Company directly and indirectly contributes to GHG emissions from various aspects of its mining operations, including from the use of electrical power and combustible fuels, as well as from the fugitive methane emissions associated with coal mines and stockpiles (Scopes 1 and 2). Peabody's board of directors and management believe that coal is essential to affordable, reliable energy and will continue to play a significant role in the global energy mix for the foreseeable future. Peabody views technology as vital to advancing global climate change solutions, and the Company supports advanced coal technologies to drive continuous improvement toward the ultimate goal of net-zero emissions from coal. The board of directors has ultimate oversight for climate-related risk and opportunity assessments, and has delegated certain aspects of these assessments to subject matter committees of the board. In addition, the board and its committees are provided regular updates on major risks and changes, including climate-related matters. The senior management team champions the strategic objectives set forth by the board of directors and Peabody's global workforce turns those objectives into meaningful actions. Management believes that the Company's external communications, including environmental regulatory filings and public notices,U.S. Securities and Exchange Commission filings, its annual Environmental, Social and Governance (ESG) Report, its website and various other stakeholder-focused publications provide a comprehensive picture of the Company's material risks and progress. All such communications are subject to oversight and review protocols established by Peabody's board of directors and executive leadership team. The Company faces risks from both the global transition to a net-zero emissions economy and the potential physical impacts of climate change. Such risks may involve financial, policy, legal, technological, reputational and other impacts as the Company meets various mitigation and adaptation requirements. 36
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The transition to a net-zero emissions economy is driven by many factors, including, but not limited to, legislative and regulatory rulemaking processes, campaigns undertaken by non-governmental organizations to minimize or eliminate the use of coal as a source of electricity generation, and the ESG-related policies of financial institutions and other private companies. The Company has experienced, or may in the future experience, negative effects on its results of operations due to the following specific risks as a result of such factors:
•Reduced utilization or closure of existing coal-fired electricity generating plants;
•Electricity generators switching from coal to alternative fuels, when feasible;
•Increased costs associated with regulatory compliance;
•Unfavorable impact of regulatory compliance on supply and demand fundamentals, such as limitations on financing or construction of new coal-fueled power stations;
•Uncertainty and inconsistency in rulemaking processes related to periodic governmental administrative and policy changes;
•Unfavorable costs of capital and access to financial markets and products due to the policies of financial institutions;
•Disruption to operations or markets due to anti-coal activism and litigation; and
•Reputational damage associated with involvement in GHG emissions.
With respect to the potential or actual physical impacts of climate change, the Company has identified the following specific risks:
•Disruption to water supplies vital to mining operations;
•Disruption to transportation and other supply chain activities;
•Damage to the Company's, customers' or suppliers' plant and equipment, or third-party infrastructure, resulting from weather events or changes in environmental trends and conditions; and
•Electrical grid failures and power outages.
While the Company faces numerous risks associated with the transition to a net-zero emissions economy and the physical impacts of climate change, certain opportunities may also emerge, such as:
•Heightened emphasis among multiple stakeholders to develop high-efficiency, low-emissions (HELE) technologies and carbon capture, use and storage (CCUS) technologies;
•Increased steel demand related to construction and other infrastructure projects related to climate change concerns; and
•The relative expense and reliability of renewable energy sources compared to coal may encourage support for balanced-source energy policies and regulations.
Global climate issues continue to attract public and scientific attention. Numerous reports, such as the Fourth and the Fifth Assessment Report of theIntergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to GHG emissions, including emissions of carbon dioxide from coal combustion by power plants. There have been significant developments in federal and state legislation and regulation and international accords regarding climate change. Such developments are described within Part I, Item 1. "Business" in the Company's Annual Report on Form 10-K for the year endedDecember 31, 2022 . 37
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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 Peabody of such future laws, regulations or other policies will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws, regulations or other policies, the time periods over which those laws, regulations or other policies would be phased in, the state of development and deployment of CCUS technologies as well as acceptance of CCUS technologies to meet regulations and the alternative uses for coal. Higher-efficiency coal-fired power plants may also be an option for meeting laws or regulations related to emissions from coal use. Several countries, including major coal users such asChina ,India andJapan , included using higher-efficiency coal-fueled power plants in their plans under the Paris Agreement. The Company believes HELE and CCUS technologies should be part of the solution to achieve substantial reductions in GHG emissions and should be broadly supported and encouraged, including through eligibility for public funding from national and international sources. In addition, CCUS merits targeted deployment incentives, like those provided to other low-emission sources of energy. From time to time, the Company's board of directors and management attempt to analyze the potential impact on the Company of as-yet-unadopted, potential laws, regulations and policies. Such analyses require significant assumptions as to the specific provisions of such potential laws, regulations and policies which sometimes show that if implemented in the manner assumed by the analyses, the potential laws, regulations and policies could result in material adverse impacts on the Company's operations, financial condition or cash flows. Such analyses cannot be relied upon to reasonably predict the quantitative impact that future laws, regulations or other policies may have on the Company's results of operations, financial condition or cash flows.
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, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company's primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, capital and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral and margining requirements, and selling and administrative expenses. The Company has also used cash for early debt retirements, dividends, and share repurchases. As described below, the Company recently amended its existing agreement with the providers of its surety bond portfolio, which included lifting the previous restrictions on capital returns to shareholders. In connection with the amendment, the Company announced a new shareholder return plan, as discussed in Part II, Item 2. "Unregistered Sales ofEquity Securities and Use of Proceeds." Any future determinations to return capital to stockholders, such as dividends or share repurchases will depend on a variety of factors, including 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.
Liquidity
As ofMarch 31, 2023 , the Company's cash balances totaled$892.2 million , including approximately$563.6 million held by Australian subsidiaries,$301.8 million held byU.S. subsidiaries, and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in theU.S. A significant majority of the cash held by the Company's 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 . From time to time, the Company may repatriate excess cash from its foreign subsidiaries to theU.S. During the three months endedMarch 31, 2023 , the Company repatriated approximately$100 million through intercompany dividends. If additional foreign-held cash is repatriated in the future, the Company does not expect restrictions or potential taxes will have a material effect to its near-term liquidity. 38
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The Company's available liquidity decreased from
December 31,
March 31, 2023 2022
(Dollars in millions)
Cash and cash equivalents $ 892.2 $ 1,307.3
Credit facility availability - 3.5
Accounts receivable securitization program availability 15.3 7.0
Total liquidity $ 907.5 $ 1,317.8 Surety Agreement Amendment and Collateral Requirements
InApril 2023 , the Company amended its existing agreement with the providers of its surety bond portfolio, datedNovember 6, 2020 . Under the agreement, the Company was required to post collateral on a periodic basis throughDecember 31, 2025 . Prior to theApril 2023 amendment, the Company had posted cumulative collateral of$557.8 million , primarily in the form of letters of credit. Under theApril 2023 amendment, the Company and surety providers agreed to a maximum aggregate collateral amount of$721.8 million based upon bonding levels at the effective date of the amendment. This maximum collateral amount represents a negotiated increase from the uncapped cumulative collateral amount prior to the amendment and may vary prospectively as future bonding levels increase or decrease. The amendment also removes restrictions on the payment of dividends and share repurchases, and extends the agreement throughDecember 31, 2026 . In order to maintain the new maximum collateral standstill, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter. The minimum liquidity test requires the Company to maintain liquidity at the greater of$400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers. The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months. For purposes of calculating the ratio, only 50% of the outstanding principal amount of the Company's 2028 Convertible Notes is deemed to be funded debt. The Company's ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test. Such compliance requirements will commence for the second quarter of 2023. The Company granted second liens on$200.0 million of mining equipment under the original agreement, which remain in force under theApril 2023 amendment. To fund the maximum collateral amount, the Company deposited$566.3 million into trust accounts for the benefit of certain surety providers onMarch 31, 2023 . The remainder was comprised of$140.5 million of existing cash-collateralized letters of credit and$15.0 million already held on behalf of a surety provider. The amendment became effective onApril 14, 2023 , when the Company terminated a credit agreement which, as amended, provided for$237.2 million of capacity for irrevocable standby letters of credit (LC Facility). The$223.8 million of letters of credit that were outstanding under the LC Facility atMarch 31, 2023 were subsequently cancelled and, in certain cases, replaced by cash-collateralized letters of credit or letters of credit issued under the Company's accounts receivable securitization program.
Collateralized Letter of Credit Agreement
InFebruary 2022 , the Company entered into an agreement which provides up to$250.0 million of capacity for irrevocable standby letters of credit, primarily to support reclamation bonding requirements. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to$5.0 million total excess collateralization.) Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum. The Company receives a variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date ofDecember 31, 2025 . AtMarch 31, 2023 , letters of credit of$245.3 million were outstanding under the agreement, which were collateralized by cash of approximately$250 million .
Margin Requirements
From time to time, the Company enters into hedging arrangements, including
economic hedging arrangements, to manage various risks, including coal price
volatility. Most hedging arrangements require the Company to post margin with
its clearing broker based on the value of the related instruments and other
credit factors. If the fair value of its exchange-cleared hedge portfolio moves
significantly, the Company could be required to post additional margin, which
could negatively impact its liquidity.
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At
AtMarch 31, 2023 andDecember 31, 2022 , the Company had margin posted of$59.8 million and$255.5 million , respectively, related to its coal derivative contracts. For additional information regarding the Company's coal derivative contracts, refer to Part I, Item 3. "Quantitative and Qualitative Disclosures About Market Risk" of this Quarterly Report.
Indebtedness
The Company's total indebtedness as of
Debt Instrument (defined below, as applicable) March 31, 2023 December 31, 2022
(Dollars in millions)
3.250% Convertible Senior Notes dueMarch 2028 (2028 Convertible Notes)$ 320.0 $ 320.0 Finance lease obligations 25.0 23.6 Less: Debt issuance costs (9.4) (9.8) 335.6 333.8 Less: Current portion of long-term debt 13.2 13.2 Long-term debt$ 322.4 $ 320.6 During 2022, the Company utilized various methods allowable or required under its then-existing debt agreements to retire all of its senior secured long-term debt, leaving only the 3.250% Convertible Senior Notes due 2028 (the 2028 Convertible Notes), which are further described below, and various finance lease obligations outstanding atDecember 31, 2022 . The Company's remaining indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect atMarch 31, 2023 , of approximately$12 million in 2023,$23 million in 2024,$16 million in 2025,$13 million in 2026,$12 million in 2027 and$322 million thereafter. Cash payments for interest related to the Company's indebtedness and financial assurance instruments amounted to$19.1 million and$37.2 million during the three months endedMarch 31, 2023 and 2022, respectively.
2028 Convertible Notes
On
The Company used the proceeds of the offering of the 2028 Convertible Notes and available cash to redeem$62.6 million of senior secured notes maturing in 2024 and$257.4 million of senior secured notes maturing in 2025, and to pay related premiums, fees and expenses relating to the offering and redemptions. The 2028 Convertible Notes will mature onMarch 1, 2028 , unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes will bear interest fromMarch 1, 2022 at a rate of 3.250% per year payable semi-annually in arrears onMarch 1 andSeptember 1 of each year, beginning onSeptember 1, 2022 . During the first quarter of 2023, the Company's reported common stock prices did not prompt the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes are not convertible at the option of the holders during the second quarter of 2023.
LC Facility
The now-terminated LC Facility had an original capacity of$324.0 million and was subsequently amended at various dates to reduce its capacity and effect certain other changes, including inFebruary 2023 to reduce capacity by$65.0 million , accelerate the expiration date toDecember 31, 2023 fromDecember 31, 2024 , and eliminate the prepayment premium due upon any reduction of commitments thereunder prior toJuly 29, 2023 . 40
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Accounts Receivable Securitization Program
As described in Note 11. "Financial Instruments and Other Guarantees" of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017. The securitization program was amended inFebruary 2023 to increase the available funding capacity from$175.0 million to$225.0 million and adjust the relevant interest rate for borrowings to a secured overnight financing rate (SOFR). Funding capacity is limited to the availability of eligible receivables and is accounted for as a secured borrowing. Funding capacity under the program may also be utilized for letters of credit in support of other obligations, which has been the Company's primary utilization. AtMarch 31, 2023 , the Company had no outstanding borrowings and$190.7 million of letters of credit outstanding under the program, which were primarily in support of portions of the Company's reclamation obligations. The Company was not required to post cash collateral under the securitization program atMarch 31, 2023 . ByApril 14, 2023 ,$101.3 million of letters of credit outstanding under the securitization program were cancelled in connection with the surety agreement amendment and related trust accounts described above. Covenant Compliance The Company was compliant with all relevant covenants under its debt and other finance agreements atMarch 31, 2023 . TheApril 2023 termination of the Company's credit agreement and related letter of credit facility eliminated the related compliance requirements as ofMarch 31, 2023 and prospectively.
Cash Flows
The following table summarizes the Company's cash flows for the three months
ended
Three Months Ended March 31,
2023 2022
(Dollars in millions)
Net cash provided by (used in) operating activities $ 386.3 $ (273.7)
Net cash (used in) provided by investing activities (58.5) 35.2
Net cash (used in) provided by financing activities (39.0) 132.2
Net change in cash, cash equivalents and restricted cash 288.8 (106.3)
Cash, cash equivalents and restricted cash at beginning of period
1,417.6 954.3
Cash, cash equivalents and restricted cash at end of period
Operating Activities. The increase in net cash provided by operating activities for the three months endedMarch 31, 2023 compared to the same period in the prior year was driven by lower cash utilization with respect to the margin requirements associated with derivative financial instruments ($547.4 million ) and the year-over-year increase in operating cash flow from Company's mining operations ($112.6 million ). Investing Activities. The increase in net cash used in investing activities for the three months endedMarch 31, 2023 compared to the same period in the prior year was driven by lower cash receipts from Middlemount ($47.2 million ), higher net contributions to joint ventures and related parties ($25.7 million ), and higher capital expenditures and the payment of capital accruals ($20.6 million ). Financing Activities. The decrease in net cash provided by financing activities for the three months endedMarch 31, 2023 compared to the same period in the prior year was driven by the cash proceeds from common stock and debt issuances in the prior year ($222.0 million and$545.0 million , respectively), partially offset by lower repayments of long-term debt ($597.2 million ) in the current year.
Off-Balance-Sheet Arrangements
In the normal course of business, the Company is a party to various guarantees
and financial instruments that carry off-balance-sheet risk and are not
reflected in the accompanying condensed consolidated balance sheets. Such
financial instruments provide support for the Company's reclamation bonding
requirements, lease obligations, insurance policies and various other
performance guarantees. The Company periodically evaluates the instruments for
on-balance-sheet treatment based on the amount of exposure under the instrument
and the likelihood of required performance. The Company does not expect any
material losses to result from these guarantees or off-balance-sheet instruments
in excess of liabilities provided for in the accompanying condensed consolidated
balance sheets.
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The following table summarizes the Company's financial instruments that carry
off-balance-sheet risk.
March 31, 2023 December 31, 2022
Reclamation Other Reclamation Other
Support Support (1) Total Support Support (1) Total
(Dollars in millions)Surety bonds$ 1,236.4 $ 152.1 $ 1,388.5 $ 1,250.1 $ 126.7 $ 1,376.8 Letters of credit (2) 22.4 67.0 89.4 437.8 131.8 569.6 1,258.8 219.1 1,477.9 1,687.9 258.5 1,946.4 Less: Letters of credit in support of surety bonds (3) (22.4) (5.4) (27.8) (431.7) (37.2) (468.9) Obligations supported, net$ 1,236.4 $ 213.7 $ 1,450.1 $ 1,256.2 $ 221.3 $ 1,477.5
(1) Instruments support obligations related to pension and health care plans, workers' compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities.
(2)March 31, 2023 balances exclude$223.8 million of letters of credit outstanding under the LC Facility and$101.3 million of letters of credit outstanding under the Company's accounts receivable securitization program that were cancelled byApril 14, 2023 . The collateral obligations related to such letters of credit were met by theMarch 31, 2023 funding of collateral trust accounts in connection with the surety agreement amendment described above. Amounts do not include cash collateralized letters of credit.
(3) Certain letters of credit serve as collateral for surety bonds at the request of surety bond providers.
AtMarch 31, 2023 , the Company had total asset retirement obligations of$752.5 million . 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. Not presented in the above table is approximately$936.7 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets atMarch 31, 2023 , as described in Note 11. "Financial Instruments and Other Guarantees" of the accompanying unaudited condensed consolidated financial statements. Such collateral is primarily in support of the financial instruments noted above, including in relation to the Company's surety bond portfolio, its collateralized letter of credit agreement, mandatory repurchases of credit facility capacity, and amounts held directly with beneficiaries which are not supported by surety bonds.
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, revenue 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. The Company's critical accounting policies and estimates are discussed 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, 2022 . The Company's critical accounting policies remain unchanged atMarch 31, 2023 , and there have been no material changes in the Company's critical accounting estimates.
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
Although there are new accounting pronouncements issued by the
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