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 the Company’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 the Company’s future financial performance. The Company uses words such as “anticipate,” “believe,” “expect,” “intend,” “may,” “forecast,” “project,” “should,” “estimate,” “goal,” “plan,” “outlook,” “target,” “likely,” “could,” “will,” “would,” “to be” or other similar words to identify forward-looking statements. Without limiting the foregoing, all statements relating to the Company’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 and expectations that the Company believes in good faith to be 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, 2025 filed with the SEC on February 19, 2026. 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 Peabody’s results of operations includes references to and analysis of Adjusted EBITDA and Total Segment Costs, which are financial measures not recognized in accordance with United States generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by the chief operating decision maker, defined as Peabody’s President and Chief Executive Officer, as the primary financial metric to measure each segment’s operating performance against expected results and to allocate resources, including capital investment in mining operations and potential expansions. Total Segment Costs is also used by management as a component of a metric to measure each segment’s operating performance. Also included in the following discussion of Peabody’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reportable segment. These metrics are used by management to measure each reportable segment’s operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reportable 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 Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2. Peabody believes non-GAAP 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. 22 Table of Contents Overview Peabody is a leading producer of metallurgical and thermal coal. In 2025, Peabody sold 122.0 million tons of coal. February 2026 marked the start-up of the Centurion Mine in the Seaborne Metallurgical segment. As a result, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia at March 31, 2026. Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia. The Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin and Other U.S. Thermal. Refer to Note 14. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of the Company’s Corporate and Other category. Pricing during the three months ended March 31, 2026 is set forth in the table below. High Low Average March 31, 2026 May 1, 2026 Premium low-vol hard coking coal (Premium HCC) (1) $ 252.50 $ 218.00 $ 234.67 $ 236.80 $ 230.80 Premium low-vol pulverized coal injection (Premium PCI) coal (1) 174.40 146.50 161.15 158.50 154.90 Newcastle index thermal coal (1) 143.71 107.05 118.75 143.71 131.67 API 5 index thermal coal (1) 88.00 70.88 80.84 88.00 96.79 PRB 8,800 Btu/Lb coal (2) 15.15 15.00 15.12 15.15 15.40 Illinois Basin 11,500 Btu/Lb coal (2) 55.75 51.25 53.46 55.75 55.50 (1) Spot pricing expressed per metric tonne. (2) Prompt month pricing expressed per short ton. The seaborne pricing included in the table above is not necessarily indicative of the pricing the Company realized during the three months ended March 31, 2026 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 above is also not necessarily indicative of the pricing the Company realized during the three months ended March 31, 2026 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. Within the global coal industry, supply and demand for its products and the supplies used for mining are being impacted by recent geopolitical events and changes to trade policy, including tariffs and customs regulations. As future developments related to geopolitical events and trade policy, including additional or retaliatory tariffs, delays in implementing previously announced changes or ongoing negotiations between countries, are unknown, the global coal industry data for the three months ended March 31, 2026 presented herein may not be indicative of their ultimate impacts. 23 Table of Contents The seaborne metallurgical coal market experienced weather-related disruptions in Australia and supply tightness in key product segments. This, combined with steady import demand from key metallurgical coal import markets, contributed to the increases in average quarterly pricing for premium coking coal (17%) and PCI (15%) during the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. In China, the continued implementation of anti-involution policies, mandated steel production limits and the introduction of steel export quotas have the potential to lead to decreased Chinese steel exports, while increasing steel-trade protectionism is supportive of steel production and seaborne metallurgical coal demand in markets outside of China. The biggest steel growth market, India, continued to see an increase in crude steel output in the quarter. Recent geopolitical events have increased the cost of seaborne energy, which has the potential to significantly impact the global ferrous complex, by placing upward pressure on raw material costs and downward pressure on steel product pricing through weakened downstream demand. Looking forward, the seaborne metallurgical coal price may remain volatile based on mining rates in Australia, geopolitical events, Chinese supply reforms and the pace of growth of the Indian steel industry. Within the seaborne thermal coal market, global thermal coal prices started the year stable but increased during the three months ended March 31, 2026, due to the closure of the Strait of Hormuz and the conflict in the Middle East. The conflict has elevated global liquefied natural gas (LNG) prices and created volatility in global thermal energy markets. In China, power generation increased year-over-year through March 31, 2026, which has resulted in stronger thermal generation year-over-year. However, both domestic coal production and coal imports have remained flat year-over-year through the three months ended March 31, 2026. In India, stronger domestic coal production, lower import demand and slightly lower coal generation led to stable coal stockpiles. Looking forward, seaborne thermal coal prices may remain volatile based on accessibility to shipping in the Strait of Hormuz and the duration of the ongoing conflict in the Middle East. Approximately 20% of global LNG exports flow through the Strait of Hormuz, which has created volatility in the global LNG market, a main competitor of global coal generation. In addition, summer re-stocking activity in the Northern Hemisphere may impact global thermal coal markets in the coming months. In the U.S., overall electricity demand increased just under 1% year-over-year through the three months ended March 31, 2026. Through the first three months of 2026, electricity generation from thermal coal decreased year-over-year, driven by lower natural gas prices, stronger renewable generation and milder winter weather in coal-heavy markets in the U.S. Coal’s share of electricity generation decreased to approximately 16% for the three months ended March 31, 2026, while wind and solar’s combined generation share was at 20% and the share of natural gas generation remained stable at approximately 37%. U.S. coal inventories have increased slightly compared to the end of 2025 through March 31, 2026. Arbitration Relating to Terminated Anglo American Acquisition On November 25, 2024, Peabody entered into definitive agreements (the Purchase Agreements) with Anglo American plc (Anglo), to acquire a portion of the assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia, including Anglo’s interests in the Moranbah North and Grosvenor mines, the Moranbah South development project, the Capcoal complex, the Roper Creek mine and the Dawson complex (comprising the Dawson Main/Central operating mine, the Dawson South operating mine, the Dawson South Exploration project and the Theodore South exploration project, collectively, the Dawson Assets). The Company agreed to, following the prospective closing of the Anglo acquisition, sell the Dawson Assets to Pt Bukit Makmur Mandiri Utama or one of its subsidiaries (BUMA). On August 19, 2025, Peabody terminated the Purchase Agreements. The termination of the Purchase Agreements followed Peabody’s prior delivery of a notice of a Material Adverse Change (MAC) as a result of an ignition event at the Moranbah North mine on March 31, 2025, which had led to the closure of the mine. See Note 13. “Commitments and Contingencies” to the accompanying unaudited condensed consolidated financial statements for further information. On September 23, 2025, various subsidiaries of Anglo initiated International Chamber of Commerce arbitration proceedings in London, United Kingdom, against Peabody and certain of its affiliates. Anglo’s complaint alleges, among other things, that Peabody wrongfully terminated the Purchase Agreements and seeks, among other things, declarations that the ignition event at the Moranbah North mine did not constitute a MAC, as well as damages for losses in an unspecified amount, plus costs and interest. Peabody remains confident that a MAC occurred, and that it was entitled to terminate the Purchase Agreements. Potential Recovery of Rare Earth Elements (REEs) Peabody is advancing its evaluation of the potential recovery of REEs and critical minerals through ongoing testing to evaluate mineral types and concentrations at certain of its operations. The Company has continued to progress technical and economic studies, advance commercial partnerships and pursue multiple federal and state funding pathways to support domestic supply chain development. 24 Table of Contents Centurion Update During the initial longwall commissioning, mechanical and electrical issues were encountered at the Centurion Mine. The issues were resolved, but the disruptions constrained cutting speeds which contributed to temporary challenges to roof conditions. The Company implemented a comprehensive response plan focused on proactive strata management, targeted equipment optimization and deployment of additional technical and operational resources. The Company anticipates completing commissioning and production ramp-up in the second quarter of 2026 and running at full longwall production rates during the second half of 2026. Results of Operations Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025 Summary The decrease in results from continuing operations, net of income taxes for the three months ended March 31, 2026 compared to the same period in the prior year ($63.7 million) was driven by higher operating costs and expenses ($94.5 million) and depreciation, depletion and amortization ($17.4 million). This unfavorable variance was partially offset by higher revenue ($36.3 million) driven by favorable volume and mix variances and lower year-over-year income taxes ($20.9 million). Adjusted EBITDA for the three months ended March 31, 2026 reflected a year-over-year decrease of $61.5 million. Tons Sold The following table presents tons sold: Three Months Ended March 31, (Decrease) Increase to Volumes 2026 2025 Tons % (Tons in millions) Seaborne Thermal 3.0 4.4 (1.4) (32) % Seaborne Metallurgical 2.0 1.8 0.2 11 % Powder River Basin 21.2 19.6 1.6 8 % Other U.S. Thermal 3.3 3.1 0.2 6 % Total tons sold from reportable segments 29.5 28.9 0.6 2 % Corporate and Other 0.1 — 0.1 n.m. Total tons sold 29.6 28.9 0.7 2 % 25 Table of Contents Supplemental Financial Data The following table presents supplemental financial data by reportable segment: Three Months Ended March 31, Increase (Decrease) 2026 2025 $ % Revenue per Ton (1) Seaborne Thermal $ 66.61 $ 60.64 $ 5.97 10 % Seaborne Metallurgical 138.28 125.15 13.13 10 % Powder River Basin 13.65 14.02 (0.37) (3) % Other U.S. Thermal 55.79 54.32 1.47 3 % Costs per Ton (1)(2) Seaborne Thermal $ 50.26 $ 41.37 $ 8.89 21 % Seaborne Metallurgical 141.72 117.66 24.06 20 % Powder River Basin 12.53 12.18 0.35 3 % Other U.S. Thermal 44.37 43.71 0.66 2 % Adjusted EBITDA Margin per Ton (1)(2) Seaborne Thermal $ 16.35 $ 19.27 $ (2.92) (15) % Seaborne Metallurgical (3.44) 7.49 (10.93) (146) % Powder River Basin 1.12 1.84 (0.72) (39) % Other U.S. Thermal 11.42 10.61 0.81 8 % (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. Revenue The following table presents revenue by segment: Three Months Ended March 31, (Decrease) Increase to Revenue 2026 2025 $ % (Dollars in millions) Seaborne Thermal $ 197.5 $ 265.1 $ (67.6) (25) % Seaborne Metallurgical 283.0 220.1 62.9 29 % Powder River Basin 289.5 275.6 13.9 5 % Other U.S. Thermal 184.5 168.7 15.8 9 % Corporate and Other 18.8 7.5 11.3 151 % Revenue $ 973.3 $ 937.0 $ 36.3 4 % Seaborne Thermal. Segment revenue decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to unfavorable volume ($91.8 million) driven by reductions at the Wilpinjong Mine due to mine sequencing and the closure of the Wambo Underground Mine in September 2025, partially offset by favorable realized prices ($24.2 million). Seaborne Metallurgical. Segment revenue increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable volume ($39.8 million) primarily from the Shoal Creek and Centurion Mines and favorable realized prices ($23.1 million). 26 Table of Contents Powder River Basin. Segment revenue increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable volume ($22.6 million) driven by increased demand. The increase was offset by unfavorable realized prices ($8.7 million) which were driven by the impact of adjustments to cost pass-through contracts with certain customers resulting from the federal royalty rate reduction included in the One Big Beautiful Bill Act of 2025 (OBBBA). Other U.S. Thermal. Segment revenue increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable volume ($10.3 million) driven by increased demand and favorable realized prices ($5.5 million). Corporate and Other. The increase in revenue during the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by higher results from trading activities. Segment Costs The following table presents costs by segment: Three Months Ended March 31, (Decrease) Increase to Total Segment Costs 2026 2025 $ % (Dollars in millions) Seaborne Thermal $ 149.0 $ 180.9 $ (31.9) (18) % Seaborne Metallurgical 290.0 206.9 83.1 40 % Powder River Basin 265.8 239.3 26.5 11 % Other U.S. Thermal 146.7 135.8 10.9 8 % Corporate and Other 13.1 4.4 8.7 198 % Total Segment Costs (1) $ 864.6 $ 767.3 $ 97.3 13 % (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 Costs decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to lower variable operational costs ($17.1 million) and lower sales related costs ($15.1 million), which were both driven by decreased volume (1.4 million tons). Seaborne Metallurgical. Segment Costs increased during the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services ($63.2 million) driven by challenging longwall commissioning conditions at the Centurion Mine and higher sales related costs ($15.0 million) resulting from increased volume (0.2 million tons) and higher realized pricing. Powder River Basin. Segment Costs increased during the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services ($22.6 million) as the result of higher volume (1.6 million tons) and planned equipment outages and higher costs for commodities ($12.2 million). These increases were offset by lower sales related costs ($11.5 million) which were largely driven by the federal royalty rate reduction on coal production included in the OBBBA. Other U.S. Thermal. Segment Costs increased during the three months ended March 31, 2026 compared to the same period in the prior year primarily due to higher variable operational costs ($9.9 million) driven by increased volume (0.2 million tons). Corporate and Other. The increase to Segment Costs during the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by lower net periodic benefit credit, excluding service cost due to the final amortization in the prior year of a previously established prior service credit ($7.0 million). 27 Table of Contents Adjusted EBITDA The following table presents Adjusted EBITDA for each of the Company’s segments: Three Months Ended March 31, (Decrease) Increase to Segment Adjusted EBITDA 2026 2025 $ % (Dollars in millions) Seaborne Thermal $ 48.5 $ 84.2 $ (35.7) (42) % Seaborne Metallurgical (7.0) 13.2 (20.2) (153) % Powder River Basin 23.7 36.3 (12.6) (35) % Other U.S. Thermal 37.8 32.9 4.9 15 % Corporate and Other (20.5) (22.6) 2.1 9 % Adjusted EBITDA (1) $ 82.5 $ 144.0 $ (61.5) (43) % (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, 2026 compared to the same period in the prior year due to unfavorable volume ($30.8 million), unfavorable operational costs at the Wilpinjong Mine ($22.8 million) driven by mine sequencing and the unfavorable impact of higher foreign exchange rates on expenses ($10.2 million). These decreases were offset by higher realized prices net of sales sensitive costs ($31.5 million). Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services, as described above, offset by higher realized prices net of sales sensitive costs ($27.4 million) and favorable volume ($12.0 million). Powder River Basin. Segment Adjusted EBITDA decreased for the three months ended March 31, 2026 compared to the same period in the prior year due to higher costs for labor, repairs and outside services and commodities as described above, offset by favorable volume ($12.5 million) and lower sales related costs as described above. Other U.S. Thermal. Segment Adjusted EBITDA increased during the three months ended March 31, 2026 compared to the same period in the prior year primarily due to higher realized prices net of sales sensitive costs ($4.1 million) and favorable volume ($2.4 million), offset by increased commodity pricing and usage ($3.4 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, Increase (Decrease) to Adjusted EBITDA 2026 2025 $ % (Dollars in millions) Middlemount (1) $ (5.0) $ (6.9) $ 1.9 28 % Resource management activities (2) 14.0 5.5 8.5 155 % Selling and administrative expenses (31.6) (23.6) (8.0) (34) % Other items, net (3) 2.1 2.4 (0.3) (13) % Corporate and Other Adjusted EBITDA $ (20.5) $ (22.6) $ 2.1 9 % (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, results from the Company’s other equity method investments, costs associated with suspended operations, holding costs associated with the Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities. 28 Table of Contents Corporate and Other Adjusted EBITDA increased during the three months ended March 31, 2026 compared to the same period in the prior year due to favorable variances in Middlemount’s results driven by higher sales pricing and higher gains on equipment and land sales ($6.5 million). These increases were offset by higher selling and administrative expenses. The decrease in other items was driven by lower net periodic benefit credit, excluding service cost, as described above ($7.0 million), offset by the favorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($6.5 million). (Loss) Income From Continuing Operations, Net of Income Taxes The following table presents (loss) income from continuing operations, net of income taxes: Three Months Ended March 31, (Decrease) Increase to Income 2026 2025 $ % (Dollars in millions) Adjusted EBITDA (1) $ 82.5 $ 144.0 $ (61.5) (43) % Depreciation, depletion and amortization (109.5) (92.1) (17.4) (19) % Asset retirement obligation expenses (13.6) (13.6) — — % Restructuring charges (1.1) (1.7) 0.6 35 % Costs related to terminated acquisition (3.0) (2.4) (0.6) (25) % Changes in amortization of basis difference related to equity affiliates 0.6 0.6 — — % Interest expense, net of capitalized interest (10.7) (11.5) 0.8 7 % Interest income 13.1 15.4 (2.3) (15) % Unrealized gains on foreign currency option contracts 0.3 4.3 (4.0) (93) % Take-or-pay contract-based intangible recognition — 0.2 (0.2) (100) % Income tax benefit (provision) 16.0 (4.9) 20.9 427 % (Loss) income from continuing operations, net of income taxes $ (25.4) $ 38.3 $ (63.7) (166) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by segment: Three Months Ended March 31, Increase (Decrease) to Income 2026 2025 $ % (Dollars in millions) Seaborne Thermal $ (21.8) $ (33.4) $ 11.6 35 % Seaborne Metallurgical (55.2) (28.8) (26.4) (92) % Powder River Basin (15.4) (12.8) (2.6) (20) % Other U.S. Thermal (16.0) (15.7) (0.3) (2) % Corporate and Other (1.1) (1.4) 0.3 21 % Total depreciation, depletion and amortization $ (109.5) $ (92.1) $ (17.4) (19) % Additionally, the following table presents a summary of the Company’s weighted-average depletion rate per ton for active mines in each of its reportable segments: Three Months Ended March 31, 2026 2025 Seaborne Thermal $ 1.04 $ 2.00 Seaborne Metallurgical 5.42 2.72 Powder River Basin 0.30 0.31 Other U.S. Thermal 1.76 1.82 29 Table of Contents Depreciation, depletion and amortization expense increased during the three months ended March 31, 2026 compared to the same period in the prior year primarily due to increased depreciation and amortization resulting from shortened mine lives. The decrease in the weighted-average depletion rate per ton for the Seaborne Thermal segment during the three months ended March 31, 2026 compared to the same period in the prior year reflects the increased quantity of proven and probable coal reserves resulting from the conversion of coal resources to proven and probable reserves. The increase in the weighted-average depletion rate per ton for the Seaborne Metallurgical segment during the three months ended March 31, 2026 compared to the same period in the prior year reflects the impact of volume and mix variances across the segment. Interest Income. The decrease in income during the three months ended March 31, 2026 compared to the same period in the prior year was driven by lower average cash balances during the current period. Unrealized Gains on Foreign Currency Option Contracts. Unrealized gains primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements. Income Tax Benefit (Provision). The decrease in the income tax benefit (provision) during the three months ended March 31, 2026 compared to the same period in the prior year was primarily due to lower expected pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information. Net (Loss) Income Attributable to Common Stockholders The following table presents net (loss) income attributable to common stockholders: Three Months Ended March 31, (Decrease) Increase to Income 2026 2025 $ % (Dollars in millions) (Loss) income from continuing operations, net of income taxes $ (25.4) $ 38.3 $ (63.7) (166) % Loss from discontinued operations, net of income taxes (0.2) (0.3) 0.1 33 % Net (loss) income (25.6) 38.0 (63.6) (167) % Less: Net income attributable to noncontrolling interests 6.8 3.6 3.2 89 % Net (loss) income attributable to common stockholders $ (32.4) $ 34.4 $ (66.8) (194) % Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests during the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by income associated with 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 2026 2025 $ % Diluted EPS attributable to common stockholders: (Loss) income from continuing operations $ (0.26) $ 0.27 $ (0.53) (196) % Loss from discontinued operations (0.01) — (0.01) n.m. Net (loss) income attributable to common stockholders $ (0.27) $ 0.27 $ (0.54) (200) % 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 122.0 million and 138.7 million for the three months ended March 31, 2026 and 2025, respectively. 30 Table of Contents Reconciliation of Non-GAAP Financial Measures Adjusted EBITDA is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the reportable segments’ operating performance, as displayed in the reconciliations below. Three Months Ended March 31, 2026 2025 (Dollars in millions) (Loss) income from continuing operations, net of income taxes $ (25.4) $ 38.3 Depreciation, depletion and amortization 109.5 92.1 Asset retirement obligation expenses 13.6 13.6 Restructuring charges 1.1 1.7 Costs related to terminated acquisition 3.0 2.4 Changes in amortization of basis difference related to equity affiliates (0.6) (0.6) Interest expense, net of capitalized interest 10.7 11.5 Interest income (13.1) (15.4) Unrealized gains on foreign currency option contracts (0.3) (4.3) Take-or-pay contract-based intangible recognition — (0.2) Income tax (benefit) provision (16.0) 4.9 Total Adjusted EBITDA $ 82.5 $ 144.0 Total Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its reportable segments’ operating performance, as displayed in the reconciliations below. Three Months Ended March 31, 2026 2025 (Dollars in millions) Operating costs and expenses $ 864.7 $ 770.2 Unrealized gains on foreign currency option contracts 0.3 4.3 Take-or-pay contract-based intangible recognition — 0.2 Net periodic benefit credit, excluding service cost (0.4) (7.4) Total Segment Costs $ 864.6 $ 767.3 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. 31 Table of Contents The following tables present tons sold, revenue, Total Segment Costs and Adjusted EBITDA by reportable segment: Three Months Ended March 31, 2026 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 3.0 2.0 21.2 3.3 Revenue $ 197.5 $ 283.0 $ 289.5 $ 184.5 Total Segment Costs 149.0 290.0 265.8 146.7 Adjusted EBITDA $ 48.5 $ (7.0) $ 23.7 $ 37.8 Revenue per Ton $ 66.61 $ 138.28 $ 13.65 $ 55.79 Costs per Ton 50.26 141.72 12.53 44.37 Adjusted EBITDA Margin per Ton $ 16.35 $ (3.44) $ 1.12 $ 11.42 Three Months Ended March 31, 2025 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 4.4 1.8 19.6 3.1 Revenue $ 265.1 $ 220.1 $ 275.6 $ 168.7 Total Segment Costs 180.9 206.9 239.3 135.8 Adjusted EBITDA $ 84.2 $ 13.2 $ 36.3 $ 32.9 Revenue per Ton $ 60.64 $ 125.15 $ 14.02 $ 54.32 Costs per Ton 41.37 117.66 12.18 43.71 Adjusted EBITDA Margin per Ton $ 19.27 $ 7.49 $ 1.84 $ 10.61 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, 2025. 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, 2025. Regulatory Matters - U.S. Mercury and Air Toxic Standards (MATS) . In 2012, the U.S. Environmental Protection Agency (EPA) published the final MATS rule, which revised the New Source Performance Standards for nitrogen oxide, sulfur dioxide and fine particulate matter (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. On March 6, 2023, the EPA issued a final rule which reaffirmed its determination to regulate coal- and oil-fired electric generating units (EGUs) under Clean Air Act section 112, including the regulation of HAPs from EGUs after considering cost. On April 24, 2023, the EPA proposed to amend the 2012 MATS rule and require an additional two-thirds reduction in the filterable PM emission of non-mercury HAP metals from existing coal-fired power plants and to reduce the mercury standard for lignite plants by 70%. On May 7, 2024, the EPA finalized a MATS rule which significantly tightened the filterable PM emissions limit for existing coal-fired EGU’s, lowering the standard from 0.030 lb/MMBtu to 0.010 lb/MMBtu for all coal-fired power plants. This rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in North Dakota v. EPA (D.C. Cir., No. 24-1119). The EPA proposed on June 17, 2025 to repeal parts of the final 2024 MATS rule regarding filterable PM standards and revise the mercury standard for existing lignite-fired EGUs. This rule was finalized on February 24, 2026 (91 Fed. Reg. 9088) and became effective on April 27, 2026. 32 Table of Contents Clean Water Act (CWA) Water Quality Certification Rule . The EPA issued a final rule in 2020 that would have limited state and tribal regulators’ certification authority under CWA Section 401 by allowing the EPA to certify projects over state or tribal regulator objections in some circumstances. On September 27, 2023, the EPA finalized a superseding rule that would expand state and tribal regulators’ authority to review activities that require federal permits or licenses and to impose conditions they believe are necessary to ensure compliance with water quality requirements. That rule took effect on November 27, 2023. Challenges to the 2023 rule remain pending in the U.S. District Court for the Western District of Louisiana. On January 15, 2026, the EPA published proposed revisions to the 2023 rule in the Federal Register , and the EPA announced that it planned to propose and finalize changes later in 2026. 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 May 9, 2024, the EPA published a final rule that would have established 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 have significantly increased costs for many coal-fueled steam electric power plants. In addition, the finalized final rule allowed 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 remains subject to numerous legal challenges that have been consolidated in the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). If the Eighth Circuit affirms the final rule, it could influence fuel switching or additional coal generating unit retirements by the end of 2034. On December 31, 2025, the EPA published a final Deadline Extensions Rule that extends seven compliance deadlines in the 2024 rule. The EPA is allowing EGUs six additional years (until December 31, 2031) to determine whether to submit a notice of planned participation for the permanent cessation of coal combustion. The EPA further extended the deadlines by five years (to December 31, 2034) for direct discharging EGUs to comply with zero-discharge limitations for flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate. Finally, the EPA is allowing EGUs that discharge to wastewater treatment plants an additional year-and-a-half to seven-and-a-half years to comply with zero-discharge limitations for those same wastestreams. The EPA also issued a No Action Assurance memorandum announcing it will not pursue enforcement actions for certain permit violations by EGUs not yet in compliance with permit requirements related to the 2020 and 2024 rules, if those EGUs satisfy certain conditions. In parallel, the EPA announced that it plans to propose a Reconsideration Rule in 2026 to revise some of the limitations and standards in the 2024 rule. 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. The EPA has not yet issued a final rule, but it has indicated that it plans to reopen the comment period for that proposal in a future action. 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 November 28, 2025, the EPA proposed to extend, by three years, the compliance deadline in the 2020 amendments for owners and operators to complete closure of unlined impoundments larger than 40 acres. On May 8, 2024, the EPA published a final rule containing additional amendments to the 2015 CCR rule that further address aspects of the D.C. Circuit’s 2018 decision. On February 10, 2026, the EPA published a final rule that provides additional time to meet certain requirements in the May 2024 Rule. Finally, on April 9, 2026, the EPA published a proposed rule to amend several provisions governing the disposal of CCR in landfills and surface impoundments and the benefit use for CCR. Regulatory Matters - Australia New South Wales (NSW) Strategic Statement on Coal Exploration and Mining. The NSW Government released a new NSW Coal Industry 2026-50 policy (the Policy) in March 2026 (replacing the Strategic Statement on Coal Exploration and Mining) that provided a high level framework for the government's policy approach to the future of the coal sector. The Policy’s key features include: no new standalone greenfield coal mines; no further government investment in coal exploration, although exploration will continue to be permitted near existing mine sites; extensions to existing operations will continue to be considered; and strengthened emissions regulation requirements for coal mine emissions. Risks and Regulations Related to Global Climate Change There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2025. Refer to Part I, Item 1. “Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 for information regarding the Company’s global climate matters. 33 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, early debt retirements, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral requirements, dividends, share repurchases and selling and administrative expenses. 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, 2026, the Company’s cash and cash equivalents balances totaled $492.5 million, including approximately $353 million held by U.S. subsidiaries, approximately $129 million held by Australian 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 and payment of the foreign subsidiaries’ share of certain U.S. corporate expenditures. From time to time, the Company may repatriate profits from its foreign subsidiaries to the U.S. in the form of intercompany dividends. During the three months ended March 31, 2026, no profits from foreign subsidiaries were repatriated. 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 decreased from $942.1 million as of December 31, 2025 to $868.2 million as of March 31, 2026. Available liquidity was comprised of the following: March 31, 2026 December 31, 2025 (Dollars in millions) Cash and cash equivalents $ 492.5 $ 575.3 Revolving credit facility availability 270.8 270.8 Accounts receivable securitization program availability 104.9 96.0 Total liquidity $ 868.2 $ 942.1 Capital Returns to Shareholders The Company paid dividends of $9.2 million during the three months ended March 31, 2026. 34 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 based upon bonding levels which will vary prospectively as bonding levels increase or decrease. The amendment also 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 included within the surety bond portfolio and the amount of collateral posted in favor of surety providers, which was $479.0 million at March 31, 2026. 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, 2026. At March 31, 2026, the Company’s maximum aggregate collateral amount was $504.1 million, which was comprised of $377.7 million in trust accounts and letters of credit of $126.4 million held for the benefit of certain surety providers. 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. 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 was amended on November 3, 2025, to (i) extend the expiration date to December 31, 2030 and (ii) reduce the required minimum cash collateral amount to 102% of the aggregate amount of letters of credit outstanding under the agreement, provided that in the event the Company’s credit rating falls below certain thresholds, the minimum collateral amount shall increase to 103%. At March 31, 2026, letters of credit of $78.1 million were outstanding under the agreement. In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements. At March 31, 2026, guarantees of $218.5 million were issued for which the Company receives a variable deposit rate on the amount of cash collateral posted in support of the facilities, which mature at various dates between 2026 and 2030. Revolving Credit Facility The Company established a 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 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, 2026, the 2024 Credit Agreement had only been utilized for letters of credit, including $49.2 million outstanding as of March 31, 2026. 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 $270.8 million at March 31, 2026. 35 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, 2026 and December 31, 2025 is presented in the table below. Debt Instrument (defined below, as applicable) March 31, 2026 December 31, 2025 (Dollars in millions) 3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) $ 320.0 $ 320.0 Finance lease obligations 19.1 20.8 Less: Debt issuance costs (3.9) (4.4) 335.2 336.4 Less: Current portion of long-term debt 14.3 15.2 Long-term debt $ 320.9 $ 321.2 The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at March 31, 2026, of approximately $18 million in 2026, $16 million in 2027, $327 million in 2028, and less than $1 million in 2029 and thereafter. The Company paid cash of $9.9 million during both the three months ended March 31, 2026 and 2025, for interest, net of capitalized interest, related to the Company’s indebtedness and financial assurance instruments. 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 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 both the fourth quarter of 2025 and the first quarter of 2026, the Company’s reported common stock prices prompted the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes were convertible at the option of the holders during the first quarter of 2026, for which no conversion requests were received, and remain convertible during the second quarter of 2026. It is the Company’s current intent to settle any conversions of the 2028 Convertible Notes through shares of its common stock. As such, the 2028 Convertible Notes are not classified as a current obligation in the accompanying condensed consolidated balance sheets. Through May 4, 2026, the Company has not received any conversion requests and does not anticipate receiving any conversion requests in the near term as the market value of the 2028 Convertible Notes exceeds their conversion value. 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 provides up to $225.0 million of funding capacity which is accounted for as a secured borrowing, limited to the availability of eligible receivables, and may be secured by a combination of collateral and the trade receivables underlying the program. 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, 2026, the Company had no outstanding borrowings and $66.0 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, 2026. The accounts receivable securitization program was amended in January 2025 to extend its maturity to January 2028. 36 Table of Contents Covenant Compliance The Company was compliant with all relevant covenants under its debt and other finance agreements at March 31, 2026. Cash Flows The following table summarizes the Company’s cash flows for the three months ended March 31, 2026 and 2025, as reported in the accompanying unaudited condensed consolidated financial statements. Three Months Ended March 31, 2026 2025 (Dollars in millions) Net cash provided by operating activities $ 30.0 $ 119.9 Net cash used in investing activities (123.5) (89.6) Net cash used in financing activities (22.6) (29.1) Net change in cash, cash equivalents and restricted cash (116.1) 1.2 Cash, cash equivalents and restricted cash at beginning of period 1,284.5 1,382.6 Cash, cash equivalents and restricted cash at end of period $ 1,168.4 $ 1,383.8 Operating Activities. The decrease in net cash provided by operating activities for the three months ended March 31, 2026 compared to the prior year was driven by lower cash generated from mining operations and a year-over-year decrease in operating cash flow from working capital ($33.8 million). Investing Activities. The increase in net cash used in investing activities for the three months ended March 31, 2026 compared to the prior year was driven by higher net contributions to joint ventures ($17.9 million) and higher capital expenditures ($15.0 million). Financing Activities. The decrease in net cash used in financing activities for the three months ended March 31, 2026 compared to the same period in the prior year was primarily driven by decreases in distributions to noncontrolling interests ($7.0 million). Off-Balance-Sheet Arrangements In the normal course of business, the Company is a party to various guarantees and financial instruments that carry off-balance-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. The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk. March 31, 2026 Reclamation Support Other Support (1) Total (Dollars in millions) Surety bonds $ 937.5 $ 82.1 $ 1,019.6 Letters of credit (2) 53.5 61.7 115.2 991.0 143.8 1,134.8 Less: Letters of credit in support of surety bonds (3) (53.5) (1.7) (55.2) Obligations supported, net $ 937.5 $ 142.1 $ 1,079.6 (1) Instruments support obligations related to leases, 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. 37 Table of Contents Not presented in the above table is $811.3 million of restricted cash and collateral which are included in the accompanying condensed consolidated balance sheets at March 31, 2026, 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 decreased $32.8 million during the three months ended March 31, 2026 due to a change in the mix of financial instruments used to support the Company’s obligations, partially offset by the impact of foreign currency rate changes. At March 31, 2026, the Company had total asset retirement obligations of $756.3 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. At March 31, 2026, the Company’s reclamation bonding requirements were supported by approximately $705 million of restricted cash and other balances serving as collateral. 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 unaudited condensed consolidated 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, 2026, the Company identified certain assets with an aggregate carrying value of approximately $60 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, 2025. The Company’s critical accounting policies remain unchanged at March 31, 2026, and there have been no material changes in the Company’s critical accounting estimates. 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.