PEABODY ENERGY CORP 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. As used in this report, the terms “Peabody” or “the Company” refer to Peabody 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 other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect 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 ended December 31, 2023 filed with the SEC on February 23, 2024. 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 with U.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. In its discussion of liquidity and capital resources, the Company includes references to Available Free Cash Flow (AFCF) which is also a non-GAAP financial measure. AFCF is used by management as a measure of its ability to generate excess cash flow from its business operations. The Company believes non-GAAP performance measures are used by investors to measure its operating performance. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP. 24 Table of Contents Overview Peabody is a leading producer of metallurgical and thermal coal. In 2023, the Company produced and sold 126.7 million and 126.2 million tons of coal, respectively, from continuing operations. At March 31, 2024, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia. Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to its mining operations, the Company markets and brokers coal from other coal producers; trades coal and freight-related contracts; and since 2022, is partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.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, Seaborne Metallurgical, Powder River Basin, Other U.S. Thermal and Corporate and Other. Refer to Note 14. “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 and Illinois Basin 11,500 Btu/Lb coal during the three months ended March 31, 2024 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 ended March 31, 2024 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 the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended March 31, 2024 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company’s realized pricing. High Low Average March 31, 2024 May 3, 2024 Premium HCC (1) $ 338.10 $ 244.50 $ 308.38 $ 244.50 $ 238.00 Premium PCI coal (1) 176.00 148.00 164.77 148.00 156.00 Newcastle index thermal coal (1) 135.69 116.08 126.03 127.77 145.74 API 5 index thermal coal (1) 96.66 87.37 93.34 87.37 89.13 PRB 8,800 Btu/Lb coal (2) 13.85 13.40 13.58 13.40 13.40 Illinois Basin 11,500 Btu/Lb coal (2) 43.50 41.00 41.93 41.00 41.50 (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 continue to be impacted by the ongoing Russian-Ukrainian conflict. As future developments related to the Russian-Ukrainian conflict and geopolitical instability in key energy producing regions are unknown, the global coal industry data for the three months ended March 31, 2024 presented herein may not be indicative of their ultimate impacts. 25 Table of Contents Within the seaborne metallurgical coal market, coking coal prices retreated from a high base during the three months ended March 31, 2024. Outside of India and China, metallurgical coal demand was hampered by thin steel margins. In India robust economic output supported steel making profitability; while in China steel demand was mixed but generally weaker, pressured by real estate sector performance, and domestic metallurgical coal prices declined in response. Meanwhile, Australian high-quality coking coal showed signs of supply improvement after a period of extended production disruptions and relatively high segment prices. This incremental volume of high-quality coking coal was reportedly placed in the seaborne market at progressively lower prices during the three months ended March 31, 2024. In other metallurgical coal market segments, such as pulverized coal injection, prices also retreated during the period however not to the extent of high-quality coking coal given reduced steel making productivity targets under thin margin conditions had already been priced into these segments. In the coming period, improving steel margins, economic stimulus measures and seasonal restocking patterns may lend support to metallurgical coal market pricing. Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of recovery of exports from Australia and economic performance in China, India and elsewhere. Within the seaborne thermal coal market, global thermal coal prices were rangebound during the three months ended March 31, 2024, finding support in Asian markets due to potential supply disruptions following new Russian sanctions. In China, overall total generation demand has been elevated while domestic coal production has declined, which has driven stronger coal import demand year-over-year through the three months ended March 31, 2024. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent amid ample supply and seasonal demand requirements in the Northern Hemisphere, as well as volatile global natural gas markets. In the U.S., overall electricity demand increased approximately 4% year-over-year. Through the three months ended March 31, 2024, electricity generation from thermal coal has declined year-over-year due to low natural gas prices and stronger renewable generation, despite higher overall electricity demand. Coal’s share of electricity generation has declined to approximately 15% for the three months ended March 31, 2024, while wind and solar’s combined generation share is at 17% and the share of natural gas generation has increased to 41%. While U.S. coal inventories declined in January, these levels have reversed and increased through March 31, 2024, resulting in stockpiles slightly above levels seen at the end of 2023. During the three months ended March 31, 2024, utility consumption of PRB coal increased approximately 6% compared to the prior year period. Other The Company entered into a definitive agreement dated October 26, 2023, to acquire the southern part of the Wards Well tenements (Wards Well area) which are adjacent to the Company’s Centurion Mine in Queensland, Australia. The acquisition was completed on April 16, 2024 for cash consideration of approximately $134 million and a contingent royalty of up to $200 million. The royalty will only be payable once the Company has recovered its investment and development costs of the Wards Well area and if the average sales price achieved exceeds certain thresholds. No royalty is payable if the Company does not commence mining in the Wards Well area. Results of Operations Three Months Ended March 31, 2024 Compared to the Three Months Ended March 31, 2023 Summary The decrease in income from continuing operations, net of income taxes for the three months ended March 31, 2024 compared to the same period in the prior year ($238.4 million) was driven by lower revenue ($380.4 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S. thermal segments. This unfavorable variance was partially offset by a lower tax provision ($97.9 million) and operating costs and expenses ($32.4 million). Adjusted EBITDA for the three months ended March 31, 2024 reflected a year-over-year decrease of $230.1 million. 26 Table of Contents Tons Sold The following table presents tons sold by operating segment: Three Months Ended March 31, Increase (Decrease) to Volumes 2024 2023 Tons % (Tons in millions) Seaborne Thermal 4.0 3.6 0.4 11 % Seaborne Metallurgical 1.4 1.3 0.1 8 % Powder River Basin 18.7 22.0 (3.3) (15) % Other U.S. Thermal 3.2 4.5 (1.3) (29) % Total tons sold from operating segments 27.3 31.4 (4.1) (13) % Corporate and Other 0.1 0.1 — — % Total tons sold 27.4 31.5 (4.1) (13) % Supplemental Financial Data The following table presents supplemental financial data by operating segment: Three Months Ended March 31, (Decrease) Increase 2024 2023 $ % Revenue per Ton (1) Seaborne Thermal $ 71.24 $ 96.82 $ (25.58) (26) % Seaborne Metallurgical 172.60 220.60 (48.00) (22) % Powder River Basin 13.62 13.89 (0.27) (2) % Other U.S. Thermal 59.75 54.73 5.02 9 % Costs per Ton (1)(2) Seaborne Thermal $ 47.71 $ 51.01 $ (3.30) (6) % Seaborne Metallurgical 138.83 151.13 (12.30) (8) % Powder River Basin 12.74 12.26 0.48 4 % Other U.S. Thermal 45.25 40.65 4.60 11 % Adjusted EBITDA Margin per Ton (1)(2) Seaborne Thermal $ 23.53 $ 45.81 $ (22.28) (49) % Seaborne Metallurgical 33.77 69.47 (35.70) (51) % Powder River Basin 0.88 1.63 (0.75) (46) % Other U.S. Thermal 14.50 14.08 0.42 3 % (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. 27 Table of Contents Revenue The following table presents revenue by reporting segment: Three Months Ended March 31, Decrease to Revenue 2024 2023 $ % (Dollars in millions) Seaborne Thermal $ 283.9 $ 346.5 $ (62.6) (18) % Seaborne Metallurgical 247.0 288.4 (41.4) (14) % Powder River Basin 254.1 305.3 (51.2) (17) % Other U.S. Thermal 191.6 249.4 (57.8) (23) % Corporate and Other 7.0 174.4 (167.4) (96) % Revenue $ 983.6 $ 1,364.0 $ (380.4) (28) % Seaborne Thermal. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable realized prices ($94.9 million), partially offset by favorable export volumes ($32.3 million). Seaborne Metallurgical. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable realized prices ($89.9 million), offset by favorable volumes ($48.5 million) driven by increased production at the Shoal Creek Mine. Powder River Basin. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year primarily due to unfavorable volumes ($48.0 million) resulting from decreased demand driven by low natural gas pricing and mild weather. Other U.S. Thermal. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($67.2 million) resulting from decreased demand driven by low natural gas pricing and mild weather, partially offset by increased sales contract cancellation settlements ($12.4 million). Corporate and Other. Segment revenue decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($118.7 million) as all derivative contracts settled in 2023; lower results from trading activities ($31.8 million); and prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “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: Three Months Ended March 31, Decrease to Segment Adjusted EBITDA 2024 2023 $ % (Dollars in millions) Seaborne Thermal $ 93.8 $ 164.0 $ (70.2) (43) % Seaborne Metallurgical 48.3 90.8 (42.5) (47) % Powder River Basin 16.4 35.8 (19.4) (54) % Other U.S. Thermal 46.5 64.2 (17.7) (28) % Corporate and Other (44.5) 35.8 (80.3) (224) % Adjusted EBITDA (1) $ 160.5 $ 390.6 $ (230.1) (59) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Seaborne Thermal. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year as a result of lower realized prices net of sales price sensitive costs ($89.8 million), partially offset by favorable volume and mix variances ($21.1 million). 28 Table of Contents Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($71.0 million) and unfavorable volumes ($22.0 million) and operational costs ($15.4 million) at the Australian operations primarily resulting from a longwall move at the Metropolitan Mine in the first quarter of 2024. These decreases were offset by favorable volumes from the Shoal Creek Mine ($52.4 million) despite the outage at the Demopolis Lock in the first quarter of 2024. Powder River Basin. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($24.1 million) and elevated overburden removal costs ($10.5 million), offset by lower costs for materials, services, repairs and labor ($11.0 million) and favorable commodity pricing ($6.9 million). Other U.S. Thermal. Segment Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable volumes ($39.5 million), offset by increased sales contract cancellation settlements ($12.4 million) and lower costs for materials, services, repairs and labor ($8.2 million). Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA: Three Months Ended March 31, (Decrease) Increase to Adjusted EBITDA 2024 2023 $ % (Dollars in millions) Middlemount (1) $ (0.8) $ 2.3 $ (3.1) (135) % Resource management activities (2) 4.4 2.3 2.1 91 % Selling and administrative expenses (22.0) (22.8) 0.8 4 % Other items, net (3) (26.1) 54.0 (80.1) (148) % Corporate and Other Adjusted EBITDA $ (44.5) $ 35.8 $ (80.3) (224) % (1) Middlemount’s results are before the impact of related changes in amortization of basis difference. (2) Includes gains (losses) on certain surplus coal reserve, coal 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 Centurion Mine and expenses related to the Company’s other commercial activities. Corporate and Other Adjusted EBITDA decreased during the three months ended March 31, 2024 compared to the same period in the prior year due to unfavorable trading results ($40.2 million); prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; and the unfavorable net impact of foreign currency rate changes ($15.0 million). 29 Table of Contents Income From Continuing Operations, Net of Income Taxes The following table presents income from continuing operations, net of income taxes: Three Months Ended March 31, (Decrease) Increase to Income 2024 2023 $ % (Dollars in millions) Adjusted EBITDA (1) $ 160.5 $ 390.6 $ (230.1) (59) % Depreciation, depletion and amortization (79.8) (76.3) (3.5) (5) % Asset retirement obligation expenses (12.9) (15.4) 2.5 16 % Restructuring charges (0.1) (0.1) — — % Asset impairment — (2.0) 2.0 100 % Provision for NARM loss (1.8) — (1.8) n.m. Changes in amortization of basis difference related to equity affiliates 0.4 0.3 0.1 33 % Interest expense (14.7) (18.4) 3.7 20 % Net loss on early debt extinguishment — (6.8) 6.8 100 % Interest income 19.2 13.1 6.1 47 % Unrealized gains on derivative contracts related to forecasted sales — 118.7 (118.7) (100) % Unrealized losses on foreign currency option contracts (5.7) (2.2) (3.5) (159) % Take-or-pay contract-based intangible recognition 0.7 0.6 0.1 17 % Income tax provision (20.1) (118.0) 97.9 83 % Income from continuing operations, net of income taxes $ 45.7 $ 284.1 $ (238.4) (84) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment: Three Months Ended March 31, (Decrease) Increase to Income 2024 2023 $ % (Dollars in millions) Seaborne Thermal $ (27.6) $ (23.8) $ (3.8) (16) % Seaborne Metallurgical (21.8) (21.1) (0.7) (3) % Powder River Basin (12.5) (11.7) (0.8) (7) % Other U.S. Thermal (14.0) (17.7) 3.7 21 % Corporate and Other (3.9) (2.0) (1.9) (95) % Total $ (79.8) $ (76.3) $ (3.5) (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, 2024 2023 Seaborne Thermal $ 2.10 $ 2.17 Seaborne Metallurgical 2.78 2.16 Powder River Basin 0.38 0.31 Other U.S. Thermal 1.55 1.21 The increases in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S. Thermal segments during the three months ended March 31, 2024 compared to the same period in the prior year reflect the impact of volume and mix variances across the segments. 30 Table of Contents Net Loss on Early Debt Extinguishment. The loss recognized during the prior year was primarily related to the Company’s terminated letter of credit facility as further discussed in Note 12. “Financial Instruments and Other Guarantees” to the accompanying unaudited condensed consolidated financial statements. Interest Income. The increase in interest income during the three months ended March 31, 2024 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. Unrealized Gains on Derivative Contracts Related to Forecasted Sales. The prior year unrealized gains primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales. As further described in Note 6. "Derivatives and Fair Value Measurements" to the Annual Report on Form 10-K for the year ended December 31, 2023, all derivative contracts related to forecasted coal sales settled in 2023. Income Tax Provision. The decrease in the income tax provision during the three months ended March 31, 2024 compared to the same period in the prior year was primarily due to lower pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information. Net Income Attributable to Common Stockholders The following table presents net income attributable to common stockholders: Three Months Ended March 31, (Decrease) Increase to Income 2024 2023 $ % (Dollars in millions) Income from continuing operations, net of income taxes $ 45.7 $ 284.1 $ (238.4) (84) % Loss from discontinued operations, net of income taxes (0.7) (1.3) 0.6 46 % Net income 45.0 282.8 (237.8) (84) % Less: Net income attributable to noncontrolling interests 5.4 14.3 (8.9) (62) % Net income attributable to common stockholders $ 39.6 $ 268.5 $ (228.9) (85) % Net Income Attributable to Noncontrolling Interests. The decrease in the results attributable to noncontrolling interests during the three months ended March 31, 2024 compared to the same period in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest. Diluted Earnings per Share (EPS) The following table presents diluted EPS: Three Months Ended March 31, Decrease to EPS 2024 2023 $ % Diluted EPS attributable to common stockholders: Income from continuing operations $ 0.30 $ 1.69 $ (1.39) (82) % Loss from discontinued operations (0.01) (0.01) — — % Net income attributable to common stockholders $ 0.29 $ 1.68 $ (1.39) (83) % 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 144.9 million and 161.4 million for the three months ended March 31, 2024 and 2023, respectively. 31 Table of Contents Reconciliation of Non-GAAP Financial Measures Adjusted EBITDA is defined as 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 its segment’s operating performance, as displayed in the reconciliations below. Three Months Ended March 31, 2024 2023 (Dollars in millions) Income from continuing operations, net of income taxes $ 45.7 $ 284.1 Depreciation, depletion and amortization 79.8 76.3 Asset retirement obligation expenses 12.9 15.4 Restructuring charges 0.1 0.1 Asset impairment — 2.0 Provision for NARM loss 1.8 — Changes in amortization of basis difference related to equity affiliates (0.4) (0.3) Interest expense 14.7 18.4 Net loss on early debt extinguishment — 6.8 Interest income (19.2) (13.1) Unrealized gains on derivative contracts related to forecasted sales — (118.7) Unrealized losses on foreign currency option contracts 5.7 2.2 Take-or-pay contract-based intangible recognition (0.7) (0.6) Income tax provision 20.1 118.0 Total Adjusted EBITDA $ 160.5 $ 390.6 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, 2024 2023 (Dollars in millions) Operating costs and expenses $ 814.2 $ 846.6 Unrealized losses on foreign currency option contracts (5.7) (2.2) Take-or-pay contract-based intangible recognition 0.7 0.6 Net periodic benefit credit, excluding service cost (10.1) (9.7) Total Reporting Segment Costs $ 799.1 $ 835.3 The following table presents Total Reporting Segment Costs by reporting segment: Three Months Ended March 31, 2024 2023 (Dollars in millions) Seaborne Thermal $ 190.1 $ 182.5 Seaborne Metallurgical 198.7 197.6 Powder River Basin 237.7 269.5 Other U.S. Thermal 145.1 185.2 Corporate and Other 27.5 0.5 Total Reporting Segment Costs $ 799.1 $ 835.3 32 Table of Contents 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 March 31, 2024 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 4.0 1.4 18.7 3.2 Revenue $ 283.9 $ 247.0 $ 254.1 $ 191.6 Total Reporting Segment Costs 190.1 198.7 237.7 145.1 Adjusted EBITDA $ 93.8 $ 48.3 $ 16.4 $ 46.5 Revenue per Ton $ 71.24 $ 172.60 $ 13.62 $ 59.75 Costs per Ton 47.71 138.83 12.74 45.25 Adjusted EBITDA Margin per Ton $ 23.53 $ 33.77 $ 0.88 $ 14.50 Three Months Ended March 31, 2023 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 3.6 1.3 22.0 4.5 Revenue $ 346.5 $ 288.4 $ 305.3 $ 249.4 Total Reporting Segment Costs 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 $ 1.63 $ 14.08 Available Free Cash Flow is defined as operating cash flow minus investing cash flow and distributions to noncontrolling interests; plus/minus changes to restricted cash and collateral and other anticipated expenditures. See the table below for a reconciliation of Available Free Cash Flow to its most comparable measure under U.S. GAAP. Three Months Ended March 31, 2024 (Dollars in millions) Net cash provided by operating activities $ 119.0 - Net cash used in investing activities (75.2) - Distributions to noncontrolling interests (18.5) +/- Changes to restricted cash and collateral (29.7) - Anticipated expenditures or other requirements — Available Free Cash Flow $ (4.4) Regulatory Update Other than as described in the following section, there were no significant changes to the Company’s regulatory or global climate matters subsequent to December 31, 2023. This section should be considered in connection with the Company’s regulatory and global climate matters as outlined in Part I, Item 1. “Business” in its Annual Report on Form 10-K for the year ended December 31, 2023. 33 Table of Contents Regulatory Matters - U.S. National Ambient Air Quality Standards (NAAQS) . The Clean Air Act (CAA) requires the U.S. Environmental Protection Agency (EPA) to review national ambient air quality standards every five years to determine whether revisions to current standards are appropriate. On March 6, 2024, the EPA revised the level of the primary standard for fine particulate matter (PM 2.5), lowering the annual standard from 12.0 ug /m 3 to 9.0 ug /m 3 . States are now required to take several actions to implement the standards which could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies or operate in a different manner. Such actions could potentially increase the cost of utilizing fossil fuels for electric generation and industrial uses. The EPA is also in the process of reviewing the current ozone NAAQS. The level of the ozone NAAQS can also affect requirements to install new or improved emission control technologies at fossil fuel-fired EGUs and non-EGU industrial sources. Final New Source Performance Standards (NSPS) for Fossil Fuel-Fired EGUs . The EPA promulgated a final rule to limit carbon dioxide (CO 2 ) from new, modified and reconstructed fossil fuel-fired EGUs under Section 111(b) of the CAA on August 3, 2015, and published it in the Federal Register on October 23, 2015. The rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for CO 2 (known as the Best System of Emission Reduction (BSER)) which is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed EGUs must implement the most efficient generating technology based on the size of the unit. Numerous legal challenges to the final rule were filed in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports. On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology. On May 23, 2023, however, the EPA published a notice of proposed rulemaking addressing NSPS from new, modified and reconstructed fossil-fuel steam EGUs. In contrast to the 2018 proposed rule, the 2023 proposed rule did not propose to amend the 2015 NSPS for coal-fired EGUs. Status reports filed with the D.C. Circuit in North Dakota v. EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule and the 2023 proposed rule. As indicated in the following section, the EPA signed a final rule based on the 2023 proposed rule on April 24, 2024. This final rule did not amend the 2015 NSPS for coal-fired EGUs, but indicated that the EPA will continue to consider whether or not to make revisions to that rule in the future. EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs . On April 24, 2024, the EPA signed a pre-publication version of final rules for new, modified and reconstructed fossil fuel-fired EGUs. This rule package consists of four elements: (1) revised NSPS for controlling CO 2 emissions from new and reconstructed stationary combustion turbines; (2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification; (3) emission guidelines for existing fossil fuel-fired steam EGUs; and (4) repeal of the Affordable Clean Energy rule promulgated in 2019. 34 Table of Contents With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions. Pursuant to the final rules, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO 2 emission rate based on CCS with 90% capture by January 1, 2032. Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO 2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030. (This translates into a 16% reduction in CO 2 emissions determined from a unit-specific baseline). Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements. All requirements related to existing affected units in the final rules – whether fired by coal, oil or natural gas – will be imposed through state plans that are permitted to take into account the remaining useful life of a generating unit when determining appropriate controls. Under the final rules, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations. States are also permitted to impose more stringent standards. In addition, the final rules include several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order maintain adequate electric generation resources and grid reliability. Finally, as part of the final rules, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO 2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU. In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032. Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015. The final rules, as implemented by the EPA and states, could have substantial impacts on the use of coal, oil and natural gas for the generation of electricity. The Company is evaluating the impacts the final rules will have on its results of operations, cash flows and financial condition. Effluent Limitations Guidelines for the Steam Electric Power Generating Industry. In 2015, the EPA published a final rule setting requirements for wastewater discharge from EGUs. In 2020, the EPA finalized revisions to certain requirements in the 2015 rule. On April 24, 2024, the EPA signed a pre-publication version of a final rule that would establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments. The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants. In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim. The final rule could influence fuel switching or additional coal generating unit retirements by the end of 2034. Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around March 2026. Separately, on August 28, 2020 and November 12, 2020, the EPA finalized two sets of amendments to its 2015 CCR rule to partially address the D.C. Circuit’s 2018 decision holding that certain provisions of that rule were not sufficiently protective. On April 24, 2024, the EPA signed a pre-publication version of additional amendments to the 2015 CCR rule that further address aspects of the D.C. Circuit’s 2018 decision. Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units. Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule . The CSAPR and related updates require numerous U.S. states and the District of Columbia to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine PM pollution in other states. 35 Table of Contents On March 15, 2023, the EPA issued a final rule to address regional ozone transport by imposing new federal ozone season emission budgets for nitrogen oxide (NO x ) in 23 states, including California, Nevada, Oklahoma and Texas, as well as some Indian reservations. The rule includes state emission budgets for NO x affecting 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. The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million. 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 have not installed selective catalytic reduction technologies. Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S. Courts of Appeal, resulting in different court opinions and in requirements being implemented in some states, but stayed in others. On December 20, 2023, the U.S. Supreme Court issued an order for oral argument regarding applications for an emergency stay of the rule. The U.S. Supreme Court held oral argument on February 21, 2024. Regional Haze. The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from man-made air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal. States are required to revise plans every 10 years. On March 29, 2024, the EPA published a proposed consent decree under which deadlines would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026). Federal Coal Leasing Moratorium . The Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium. Environmental groups took the issue to court (District of Montana) and in April 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review. On May 22, 2020, the court held that the Department of the Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations. Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI. On August 12, 2022, the court invalidated the Environmental Assessment and FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis. On appeal, the U.S. Court of Appeals for the Ninth Circuit reversed the district court on February 21, 2024, explaining that the lawsuit was mooted by the Department of Interior’s April 2021 order revoking Order 3349. The Ninth Circuit directed the district court to dismiss the case as moot. Endangered Species Act (ESA) . The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans. During the Trump Administration, the Departments of the Interior and Commerce finalized five rules aiming to streamline and update the ESA. But in June 2021, the agencies announced their plan to revise, rescind or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives. The agencies issued proposed rules on June 22, 2023, and they issued pre-publication versions of three final revised rules on March 27, 2024. SEC Climate-Related Disclosures . On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition; certain greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider; and certain climate-related financial metrics to be included in a company’s audited financial statements. The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC voluntarily stayed implementation of the final rules. The Company is assessing the potential impact of the final rules. 36 Table of Contents Regulatory Matters - Australia New South Wales Environmental . In New South Wales (NSW), laws and regulations related to mining include, but are not limited to, the Mining Act 1992, Work Health and Safety (Mines) Act 2013, Coal Mine Subsidence Compensation Act 2017, Environmental Planning and Assessment Act 1979 (EPA Act), Environmental Planning and Assessment Regulations 2000, Protection of the Environment Operations Act 1997, Contaminated Land Management Act 1997, Explosives Act 2003, Water Management Act 2000, Water Act 1912, Radiation Control Act 1990, Biodiversity Conservation Act 2016 (BC Act), Heritage Act 1977, Aboriginal Land Rights Act 1983, Crown Land Management Act 2016, Dangerous Goods (Road and Rail Transport) Act 2008, Fisheries Management Act 1994, Forestry Act 2012, Native Title (New South Wales) Act 1994, Biosecurity Act 2015, Roads Act 1993 and National Parks & Wildlife Act 1974. Under the NSW EPA Act, environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve. On April 3, 2024, the Environment Protection Legislation Amendment (Stronger Regulation and Penalties) Bill 2024 was assented to by the Parliament of New South Wales. The bill increases the NSW Environment Protection Agency’s (NSW EPA) powers across a range of environmental legislation including increasing the NSW EPA’s maximum penalties for serious environmental offenses; increasing the NSW EPA’s on-the-spot maximum fines; providing the NSW EPA the power to issue what will be known as ‘Preliminary Investigation Notices’ which permit the NSW EPA to force a person to help the NSW EPA compile a criminal case against the person or against another person; extending the monetary benefits order so that it can apply to any ‘related entity’ as defined in the Corporations Act 2001; providing the NSW EPA the power to issue what will be known as ‘Recall Notices’ which order responsible entities to recall contaminated substances suspected of causing harm to the community and environment; and providing the NSW EPA the power to issue what will be known as ‘name and shame’ public warnings to call out poor and repeat environmental performers for the protection of communities. The reform also creates a new power in Australia for the NSW Land and Environment Court that empowers the court to ban offenders, upon the NSW EPA’s application, with a poor compliance history from seeking and obtaining environmental protection licenses. On August 25, 2017, the BC Act commenced in New South Wales and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied. The New South Wales government is currently considering fifty-eight recommendations of a 2023 independent review of the BC Act. Any changes to the BC Act have the potential to affect approval processes for future NSW mining projects. Risks Related to Global Climate Change There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2023. Refer to Part I, Item 1. “Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 for information regarding the Company’s global climate matters. 37 Table of Contents 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, coal resources 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, finance and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral and margining requirements, dividends, share repurchases and selling and administrative expenses. The Company has also used cash for early debt retirements. Any future determinations to return capital to stockholders, such as dividends or share repurchases, will depend on a variety of factors, including the Company’s 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 of March 31, 2024, the Company’s cash and cash equivalents balances totaled $855.7 million, including approximately $473 million held by Australian subsidiaries, approximately $366 million held by U.S. subsidiaries and the remainder held by other foreign subsidiaries in accounts predominantly domiciled in the U.S. A significant majority of the cash held by the Company’s foreign subsidiaries is denominated in U.S. dollars. This cash is generally used to support non-U.S. liquidity needs, including capital and operating expenditures in Australia. From time to time, the Company may repatriate excess cash from its foreign subsidiaries to the U.S. During the three months ended March 31, 2024, the Company did not repatriate any excess cash. If 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. The Company’s available liquidity increased to $1,157.4 million as of March 31, 2024 from $1,059.7 million as of December 31, 2023. Available liquidity was comprised of the following: March 31, 2024 December 31, 2023 (Dollars in millions) Cash and cash equivalents $ 855.7 $ 969.3 Revolving credit facility availability 221.0 — Accounts receivable securitization program availability 80.7 90.4 Total liquidity $ 1,157.4 $ 1,059.7 Capital Returns to Shareholders The Company repurchased approximately 3.2 million shares of its common stock for $80.5 million, including commission fees, and paid dividends of $9.7 million during the three months ended March 31, 2024. 38 Table of Contents Surety Agreement Amendment and Collateral Requirements In April 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020. Under the April 2023 amendment, the Company and its 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 will vary prospectively as bonding levels increase or decrease. The amendment extended the agreement through December 31, 2026. In order to maintain the maximum collateral agreement, 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, which was $521.8 million at March 31, 2024. 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 3.250% Convertible Senior Notes due March 2028 (the 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. The Company is in compliance with such requirements at March 31, 2024. To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 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 on April 14, 2023, when the Company terminated a then-existing credit agreement. Credit Support Facilities In February 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 of December 31, 2025. At March 31, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 million. In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements. The Company receives a variable deposit rate on the amount of cash collateral posted in support of the bank guarantee facilities, which mature at various dates between 2026 and 2029. At March 31, 2024, the bank guarantee facilities were backed by cash of $177.0 million. Revolving Credit Facility The Company established a new revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto. The revolving commitments and any related loans, if applicable (any such loans, the Revolving Loans), established by the 2024 Credit Agreement terminate or mature, as applicable, on January 18, 2028, subject to certain conditions relating to the Company’s outstanding 2028 Convertible Notes. The Revolving Loans bear interest at a secured overnight financing rate (SOFR) plus an applicable margin ranging from 3.50% to 4.25%, depending on the Company’s total net leverage ratio (as defined under the 2024 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option. Letters of credit issued under the 2024 Credit Agreement incur a combined fee equal to an applicable margin ranging from 3.50% to 4.25% plus a fronting fee equal to 0.125% per annum. Unused capacity under the 2024 Credit Agreement bears a commitment fee of 0.50% per annum. As of March 31, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $99.0 million outstanding as of March 31, 2024. These letters of credit support the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees as further described in Note 12. “Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $221.0 million at March 31, 2024. 39 Table of Contents The 2024 Credit Agreement contains customary covenants that, among other things and subject to certain exceptions (including compliance with financial ratios), may limit the Company and its subsidiaries’ ability to incur additional indebtedness, make certain restricted payments or investments, sell or otherwise dispose of assets, enter into transactions with affiliates, create or incur liens, and merge, consolidate or sell all or substantially all of their assets. The 2024 Credit Agreement is secured by substantially all assets of the Company and its U.S. subsidiaries, as well as a pledge of two Australian subsidiaries. Indebtedness The Company’s total indebtedness as of March 31, 2024 and December 31, 2023 is presented in the table below. Debt Instrument (defined below, as applicable) March 31, 2024 December 31, 2023 (Dollars in millions) 3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) $ 320.0 $ 320.0 Finance lease obligations 25.3 22.3 Less: Debt issuance costs (7.6) (8.1) 337.7 334.2 Less: Current portion of long-term debt 14.4 13.5 Long-term debt $ 323.3 $ 320.7 The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at March 31, 2024, of approximately $19 million in 2024, $18 million in 2025, $16 million in 2026, $12 million in 2027 and $325 million in 2028. Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $11.5 million and $19.1 million during the three months ended March 31, 2024 and 2023, respectively. 2028 Convertible Notes On March 1, 2022, through a private offering, the Company issued the 2028 Convertible Notes in the aggregate principal amount of $320.0 million. The 2028 Convertible Notes are senior unsecured obligations of the Company and are governed under an indenture. The Company used the proceeds of the offering of the 2028 Convertible Notes and available cash to redeem its then-existing senior secured notes, and to pay related premiums, fees and expenses relating to the offering and redemptions. The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes bear interest at a rate of 3.250% per year payable semi-annually in arrears on March 1 and September 1 of each year. During the first quarter of 2024, 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 will not be convertible at the option of the holders during the second quarter of 2024. Accounts Receivable Securitization Program As described in Note 12. “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 in February 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 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. At March 31, 2024, the Company had no outstanding borrowings and $53.1 million of letters of credit outstanding under the program. The Company was not required to post cash collateral under the securitization program at March 31, 2024. Covenant Compliance The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2024. 40 Table of Contents Cash Flows The following table summarizes the Company’s cash flows for the three months ended March 31, 2024 and 2023, as reported in the accompanying unaudited condensed consolidated financial statements. Available Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP. Three Months Ended March 31, 2024 2023 (Dollars in millions) Net cash provided by operating activities $ 119.0 $ 386.3 Net cash used in investing activities (75.2) (58.5) Net cash used in financing activities (127.7) (39.0) Net change in cash, cash equivalents and restricted cash (83.9) 288.8 Cash, cash equivalents and restricted cash at beginning of period 1,650.2 1,417.6 Cash, cash equivalents and restricted cash at end of period $ 1,566.3 $ 1,706.4 Available Free Cash Flow $ (4.4) Operating Activities. The decrease in net cash provided by operating activities for the three months ended March 31, 2024 compared to the same period in the prior year was driven by a year-over-year decrease in operating cash flow from working capital ($201.0 million); the prior year receipt of cash related to variation margin requirements associated with derivative financial instruments ($149.2 million); and lower cash generated from mining operations, partially offset by a decrease in cash used for collateral requirements ($197.2 million). Investing Activities. The increase in net cash used in investing activities for the three months ended March 31, 2024 compared to the same period in the prior year was driven by higher capital expenditures and payments of capital accruals ($10.9 million) and higher net contributions to joint ventures ($5.4 million). Financing Activities. The increase in net cash used by financing activities for the three months ended March 31, 2024 compared to the same period in the prior year was primarily driven by common stock repurchases and dividends paid in the current year ($83.1 million and $9.7 million, respectively). 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-she et 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. 41 Table of Contents The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk. March 31, 2024 Reclamation Support Other Support (1) Total (Dollars in millions) Surety bonds $ 962.1 $ 108.2 $ 1,070.3 Letters of credit (2) 53.6 98.5 152.1 1,015.7 206.7 1,222.4 Less: Letters of credit in support of surety bonds (3) (53.6) (14.4) (68.0) Obligations supported, net $ 962.1 $ 192.3 $ 1,154.4 (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) 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. Not presented in the above table is $836.0 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at March 31, 2024, as described in Note 12. “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, its bank guarantee facilities and amounts held directly with beneficiaries which are not supported by surety bonds. The restricted cash and collateral balance at March 31, 2024 decreased from $957.6 million at December 31, 2023 due to collateral releases related to reductions in reclamation bonding requirements, replacement of cash-collateralized letters of credit with letters of credit under the new revolving credit facility and the unfavorable impact of foreign currency rate changes. At March 31, 2024, the Company had total asset retirement obligations of $703.2 million. Bonding requirement amounts may differ significantly from the re lated 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. As noted above, the Company’s reclamation bonding requirements decreased during the three months ended March 31, 2024 primarily due to an approximate $85 million reduction in U.S. reclamation bonding requirements. The Company had an additional reduction in U.S. reclamation bonding requirements of approximately $20 million during April 2024. At March 31, 2024, the Company’s reclamation bonding requirements were supported by approximately $730 million of restricted cash and other balances serving as collateral, which exceeds the financial liability for final mine reclamation as calculated in accordance with U.S. GAAP. 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 with U.S. GAAP. The Company is also required under U.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. At March 31, 2024, the Company identified certain assets with an aggregate carrying value of approximately $219 million in its Other U.S. Thermal segment whose recoverability is most sensitive to customer concentration risk. 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 ended December 31, 2023. The Company’s critical accounting policies remain unchanged at March 31, 2024, and there have been no material changes in the Company’s critical accounting estimates. 42 Table of Contents Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to the Company’s unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.