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.
28
Table of Contents
Overview
Peabody is a leading producer of metallurgical and thermal coal. In 2025, Peabody sold 122.0 million tons of coal. The Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia at June 30, 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 June 30, 2026 is set forth in the table below.
High Low Average June 30, 2026 August 3, 2026
Premium low-vol hard coking coal (Premium HCC) (1) $ 245.00 $ 230.80 $ 238.27 $ 243.50 $ 214.00
Premium low-vol pulverized coal injection (Premium PCI) coal (1) 173.50 154.90 161.49 168.10 158.00
Newcastle index thermal coal (1) 152.75 125.26 135.86 128.06 131.25
API 5 index thermal coal (1) 104.52 87.24 96.51 96.00 94.50
PRB 8,800 Btu/Lb coal (2) 15.75 14.55 15.02 14.55 14.50
Illinois Basin 11,500 Btu/Lb coal (2) 55.75 54.75 55.14 54.75 54.50
(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 June 30, 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 June 30, 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 six months ended June 30, 2026 presented herein may not be indicative of their ultimate impacts.
29
Table of Contents
During the six months ended June 30, 2026, regional divergence in supply and demand fundamentals in the seaborne metallurgical coal market contributed to a 29% increase in the Premium HCC price and a 17% rise in the Premium PCI price. Weather-related interruptions and operational challenges in Australia periodically constrained export availability and provided support to Premium HCC and Premium PCI prices. Seaborne supply remained responsive to periods of price strength, with producer output recovering following disruption events. Robust blast furnace output in China and domestic coal supply constraints following a major mine accident in Shanxi Province which triggered widespread safety inspections and production suspensions, contributed to tighter domestic coking coal availability and increased Chinese imports of seaborne coal. While India remains the largest growth market for steel production, monsoon-related disruptions and softer steel margins contributed to a moderation in metallurgical coal import demand during the period. Continued geopolitical tensions, constrained availability of premium metallurgical coal products and disruptions to global trade routes contributed to ongoing volatility across energy, freight and raw material markets during the first half of 2026. Despite these headwinds, underlying steel production and industrial activity in key consuming markets continues to provide support for seaborne metallurgical coal demand.
During the six months ended June 30, 2026, the seaborne thermal coal market remained supported by national government energy security policies. Elevated liquefied natural gas (LNG) prices and continued volatility across global energy markets encouraged utilities in several importing regions to consider greater coal utilization, particularly in import-dependent regions, such as Asia and Europe. Chinese power demand remained resilient, supported by rising industrial activity and seasonal requirements, while domestic coal production growth moderated import demand. In India, high levels of domestic coal output continued to limit seaborne imports, as record high electricity consumption provided underlying support for domestic production. Thermal coal prices are expected to remain sensitive to geopolitical developments affecting energy trade flows, developments in LNG markets, Indonesia’s coal policy reforms, Asian inventory levels and global weather patterns influencing power demand trends. Demand for energy from thermal coal remains an important component of the global power generation mix through the remainder of 2026 as governments and utilities continue to prioritize reliable and affordable energy supply.
In the U.S., overall electricity demand increased just under 1% year-over-year through the six months ended June 30, 2026. Through the first six months of 2026, electricity generation from thermal coal decreased year-over-year, driven by lower natural gas prices, stronger renewable generation and milder spring temperatures in coal-heavy markets in the U.S. Coal’s share of electricity generation decreased to approximately 14% for the six months ended June 30, 2026, while wind and solar’s combined generation share increased to 22% and the share of natural gas generation remained stable at approximately 37%. U.S. coal inventories have increased almost 10 million tons compared to the end of 2025 through June 30, 2026.
Financing and Liquidity Transactions
During the second quarter of 2026, Peabody completed multiple financing transactions. The Company issued $250.0 million of new convertible senior unsecured notes and used the proceeds of the offering and available cash to purchase a capped call with a cap price of $50.61 per share and to repurchase $241.2 million of the existing convertible senior unsecured notes for cash consideration of $386.8 million. These transactions lowered the Company’s borrowing rates, extended debt maturities to 2031 and reduced potential common share dilution from the convertible notes by approximately 6.2 million shares to approximately 10.7 million potential shares. From an economic perspective, the $145.6 million premium paid above par value to repurchase the existing convertible senior notes was equivalent to repurchasing approximately 5.0 million shares at a weighted average price of $28.92 per share. The Company also entered into standard agreements with surety providers in the U.S. and Australia during the quarter, which reduced total reclamation collateral requirements and released formerly restricted cash and cash collateral. And finally, the Company amended its existing revolving credit facility to increase funding capacity, lower interest rates and extend the maturity date.
Refer to the “Liquidity and Capital Resources” section contained within this Item 2 for a further discussion of these financing and liquidity transactions.
Arbitration Relating to Terminated Anglo American plc (Anglo) Acquisition
On November 25, 2024, Peabody entered into definitive agreements (the Purchase Agreements) to acquire from Anglo certain assets and businesses associated with Anglo’s metallurgical coal portfolio in Australia (collectively, the Assets), 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.
30
Table of Contents
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. Following Peabody’s termination of the Purchase Agreements, Anglo returned $29.0 million of the $75.0 million deposit previously paid by Peabody, and Peabody has demanded the outstanding $46.0 million of the deposit also be returned. 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. At that time, Anglo’s complaint alleged, among other things, that Peabody wrongfully terminated the Purchase Agreements and sought, 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. On June 5, 2026, Anglo filed its Statement of Claim, in which it purported to quantify, for the first time in the arbitration proceedings, the damages that it is demanding at approximately $755.0 million. This amount primarily consists of $628.4 million in claimed losses, representing what Anglo contends is the difference in value of the Assets between November 25, 2024 and August 19, 2025, with the remainder consisting of Anglo’s claimed additional costs and interest on such claimed losses and costs.
Peabody disputes Anglo’s allegations in the arbitration proceedings and submits it properly terminated the Purchase Agreements. With respect to Anglo’s calculation of its supposed damages, Peabody believes it is fundamentally flawed for several reasons, including because Anglo’s calculation assumes that the substantial portion of any loss in value is not attributable to the MAC and specifically the ignition event at Moranbah North. In this regard, Peabody remains confident that a MAC occurred, and that it was entitled to terminate the Purchase Agreements. However, while Peabody strongly disagrees with Anglo’s claim that the ignition event at the Moranbah North mine did not constitute a MAC, it is reasonably possible that the Company may incur a loss in connection with Anglo’s claim. That said, given Peabody’s strong view that it was entitled to terminate the Purchase Agreements, as well as the fundamental disagreement over the basis for Anglo’s calculation of its alleged damages, Peabody is unable to provide a reasonable estimate of any possible loss or range of loss relating to this matter. In addition, Peabody expects to receive the remaining $46.0 million purchase deposit under the termination provisions of the Purchase Agreements.
A final hearing in the arbitration proceedings is scheduled for September 2027.
Potential Recovery of Rare Earth Elements (REE)
In early July 2026, it was announced that Peabody had been awarded a grant from the U.S. Department of Energy to advance REE and critical minerals (CM) development opportunities in the Powder River Basin. Combined with the Wyoming Energy Authority grant awarded in February 2026, the Company continues to advance its evaluation of the potential recovery of REE and CM and other REE/CM opportunities.
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 operating team has implemented effective processes to address face conditions while maintaining production momentum and is working through the remaining roof control issues. With operational constraints significantly reduced, Peabody's focus is on achieving targeted production rates.
Results of Operations
Three and Six Months Ended June 30, 2026 Compared to the Three and Six Months Ended June 30, 2025
Summary
The decrease in results from continuing operations, net of income taxes for the three and six months ended June 30, 2026 compared to the same periods in the prior year ($60.3 million and $124.0 million, respectively) was driven by higher operating costs and expenses ($164.5 million and $259.0 million, respectively), induced conversion expense recognized in the current year ($17.2 million, three and six months), higher depreciation, depletion and amortization ($14.1 million and $31.5 million, respectively), reduced net gains on disposals ($10.4 million and $3.9 million, respectively), increased losses from equity affiliates ($9.0 million and $8.0 million, respectively) and lower net periodic benefit credits ($7.1 million and $14.1 million, respectively). The unfavorable variances were partially offset by higher revenue ($113.1 million and $149.4 million, respectively) primarily driven by favorable pricing, increased tax benefits ($34.3 million and $55.2 million, respectively) and lower costs related to the terminated acquisition ($16.5 million and $15.9 million, respectively).
31
Table of Contents
Adjusted EBITDA for the three and six months ended June 30, 2026 reflected a year-over-year decrease of $69.3 million and $130.8 million, respectively.
Tons Sold
The following table presents tons sold:
Three Months Ended June 30, (Decrease) Increase to Volumes Six Months Ended June 30, (Decrease) Increase to Volumes
2026 2025 Tons % 2026 2025 Tons %
(Tons in millions) (Tons in millions)
Seaborne Thermal 3.0 3.6 (0.6) (17) % 6.0 8.0 (2.0) (25) %
Seaborne Metallurgical 2.5 2.2 0.3 14 % 4.5 4.0 0.5 13 %
Powder River Basin 16.4 20.0 (3.6) (18) % 37.6 39.6 (2.0) (5) %
Other U.S. Thermal 3.0 2.9 0.1 3 % 6.3 6.0 0.3 5 %
Total tons sold from reportable segments 24.9 28.7 (3.8) (13) % 54.4 57.6 (3.2) (6) %
Corporate and Other — — — n.m. 0.1 — 0.1 n.m.
Total tons sold 24.9 28.7 (3.8) (13) % 54.5 57.6 (3.1) (5) %
Supplemental Financial Data
The following table presents supplemental financial data by reportable segment:
Three Months Ended June 30, Increase (Decrease) Six Months Ended June 30, Increase (Decrease)
2026 2025 $ % 2026 2025 $ %
Revenue per Ton (1)
Seaborne Thermal $ 74.85 $ 53.22 $ 21.63 41 % $ 70.81 $ 57.25 $ 13.56 24 %
Seaborne Metallurgical 148.04 114.79 33.25 29 % 143.57 119.40 24.17 20 %
Powder River Basin 13.63 13.82 (0.19) (1) % 13.64 13.92 (0.28) (2) %
Other U.S. Thermal 55.26 54.08 1.18 2 % 55.54 54.20 1.34 2 %
Costs per Ton (1)(2)
Seaborne Thermal $ 57.93 $ 44.10 $ 13.83 31 % $ 54.17 $ 42.61 $ 11.56 27 %
Seaborne Metallurgical 155.08 118.97 36.11 30 % 148.96 118.39 30.57 26 %
Powder River Basin 14.06 11.66 2.40 21 % 13.20 11.92 1.28 11 %
Other U.S. Thermal 46.13 49.39 (3.26) (7) % 45.20 46.43 (1.23) (3) %
Adjusted EBITDA Margin per Ton (1)(2)
Seaborne Thermal $ 16.92 $ 9.12 $ 7.80 86 % $ 16.64 $ 14.64 $ 2.00 14 %
Seaborne Metallurgical (7.04) (4.18) (2.86) (68) % (5.39) 1.01 (6.40) (634) %
Powder River Basin (0.43) 2.16 (2.59) (120) % 0.44 2.00 (1.56) (78) %
Other U.S. Thermal 9.13 4.69 4.44 95 % 10.34 7.77 2.57 33 %
(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.
32
Table of Contents
Revenue
The following table presents revenue by segment:
Three Months Ended June 30, Increase (Decrease) to Revenue Six Months Ended June 30, (Decrease) Increase to Revenue
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
Seaborne Thermal $ 230.6 $ 195.1 $ 35.5 18 % $ 428.1 $ 460.2 $ (32.1) (7) %
Seaborne Metallurgical 358.3 252.2 106.1 42 % 641.3 472.3 169.0 36 %
Powder River Basin 223.8 275.7 (51.9) (19) % 513.3 551.3 (38.0) (7) %
Other U.S. Thermal 163.2 155.1 8.1 5 % 347.7 323.8 23.9 7 %
Corporate and Other 27.3 12.0 15.3 128 % 46.1 19.5 26.6 136 %
Revenue $ 1,003.2 $ 890.1 $ 113.1 13 % $ 1,976.5 $ 1,827.1 $ 149.4 8 %
Seaborne Thermal. Segment revenue increased during the three months ended June 30, 2026 compared to the same period in the prior year due to favorable realized prices ($63.6 million), offset by unfavorable volume ($28.1 million) driven by reductions at the Wilpinjong Mine due to mine sequencing and the closure of the Wambo Underground Mine in September 2025. Segment revenue decreased during the six months ended June 30, 2026 compared to the same period in the prior year due to unfavorable volume, as previously described ($118.2 million), offset by favorable realized prices ($86.1 million).
Seaborne Metallurgical. Segment revenue increased during the three and six months ended June 30, 2026 compared to the same periods in the prior year due to favorable realized prices ($77.3 million and $96.9 million, respectively) and favorable volume ($28.8 million and $72.1 million, respectively) driven largely by the start-up of the Centurion Mine.
Powder River Basin. Segment revenue decreased during the three and six months ended June 30, 2026 compared to the same periods in the prior year due to unfavorable volume ($48.8 million and $26.2 million, respectively) resulting from decreased demand driven by mild weather in the U.S. and unfavorable realized prices ($3.1 million and $11.8 million, respectively) 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 and six months ended June 30, 2026 compared to the same periods in the prior year due to favorable volume ($4.4 million and $14.4 million, respectively) driven by increased demand and favorable realized prices ($3.7 million and $9.5 million, respectively).
Corporate and Other. The increase in revenue during the three and six months ended June 30, 2026 compared to the same periods in the prior year was primarily driven by higher revenue from trading activities.
Segment Costs
The following table presents costs by segment:
Three Months Ended June 30, Increase (Decrease) to Total Segment Costs Six Months Ended June 30, (Decrease) Increase to Total Segment Costs
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
Seaborne Thermal $ 178.5 $ 161.6 $ 16.9 10 % $ 327.5 $ 342.5 $ (15.0) (4) %
Seaborne Metallurgical 375.3 261.4 113.9 44 % 665.3 468.3 197.0 42 %
Powder River Basin 230.9 232.7 (1.8) (1) % 496.7 472.0 24.7 5 %
Other U.S. Thermal 136.3 141.6 (5.3) (4) % 283.0 277.4 5.6 2 %
Corporate and Other 28.7 (10.9) 39.6 363 % 41.8 (6.5) 48.3 743 %
Total Segment Costs (1) $ 949.7 $ 786.4 $ 163.3 21 % $ 1,814.3 $ 1,553.7 $ 260.6 17 %
(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.
33
Table of Contents
Seaborne Thermal. Segment Costs increased during the three months ended June 30, 2026 compared to the same period in the prior year primarily due to increased commodities expense ($17.1 million) which was driven by higher fuel pricing. Segment Costs decreased during the six months ended June 30, 2026 compared to the same period in the prior year due to decreased volume (2.0 million tons) which drove both lower sales related costs ($17.2 million) and variable costs ($10.7 million). These decreases were offset by increased commodities expense ($19.1 million).
Seaborne Metallurgical. Segment Costs increased during the three and six months ended June 30, 2026 compared to the same periods in the prior year due to higher costs for labor, repairs and outside services ($73.6 million and $136.8 million, respectively) driven by longwall commissioning activities at the Centurion Mine; higher sales related costs ($34.4 million and $49.4 million, respectively) resulting from increased volume (0.3 million tons and 0.5 million tons, respectively) and higher realized pricing; and increased commodities expense ($15.9 million and $15.7 million, respectively) which was primarily driven by higher fuel pricing.
Powder River Basin. Segment Costs decreased during the three months ended June 30, 2026 compared to the same period in the prior year due to lower sales related costs ($25.3 million) which were largely driven by the federal royalty rate reduction on coal production included in the OBBBA and lower volume (3.6 million tons), offset by increased commodities expense ($17.0 million) driven by higher fuel pricing and increased leasing expense ($3.9 million). Segment Costs increased during the six months ended June 30, 2026 compared to the same period in the prior year due to increased commodities expense ($29.2 million) driven by higher fuel pricing; higher costs for labor, repairs and outside services ($23.3 million) as the result of planned equipment outages and increased in-pit inventory; and increased leasing expense ($6.5 million). These increases were offset by lower sales related costs ($36.8 million) which were largely driven by the federal royalty rate reduction on coal production included in the OBBBA and lower volume (2.0 million tons).
Other U.S. Thermal. Segment Costs decreased during the three months ended June 30, 2026 compared to the same period in the prior year primarily due to lower costs for repairs and outside services ($11.7 million), offset by increased commodities expense ($7.8 million) driven by higher fuel pricing. Segment Costs increased during the six months ended June 30, 2026 compared to the same period in the prior year due to higher commodities expense ($11.2 million), higher variable operational costs ($5.1 million) and higher sales related costs ($4.7 million) driven by increased volume (0.3 million tons), offset by lower costs for repairs and outside services ($16.5 million).
Corporate and Other. The increase to Segment Costs during the three and six months ended June 30, 2026 compared to the same periods in the prior year was primarily driven by higher expenses related to trading and brokerage activities ($16.4 million and $23.4 million, respectively), the unfavorable remeasurement of foreign currency ($15.1 million and $8.5 million, respectively) and lower net periodic benefit credit, excluding service cost due to the final amortization in the prior year of a previously established prior service credit ($7.1 million and $14.1 million, respectively).
Adjusted EBITDA
The following table presents Adjusted EBITDA for each of the Company’s segments:
Three Months Ended June 30, Increase (Decrease) to Segment Adjusted EBITDA Six Months Ended June 30, (Decrease) Increase to Segment Adjusted EBITDA
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
Seaborne Thermal $ 52.1 $ 33.5 $ 18.6 56 % $ 100.6 $ 117.7 $ (17.1) (15) %
Seaborne Metallurgical (17.0) (9.2) (7.8) (85) % (24.0) 4.0 (28.0) (700) %
Powder River Basin (7.1) 43.0 (50.1) (117) % 16.6 79.3 (62.7) (79) %
Other U.S. Thermal 26.9 13.5 13.4 99 % 64.7 46.4 18.3 39 %
Corporate and Other (30.9) 12.5 (43.4) (347) % (51.4) (10.1) (41.3) (409) %
Adjusted EBITDA (1) $ 24.0 $ 93.3 $ (69.3) (74) % $ 106.5 $ 237.3 $ (130.8) (55) %
(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.
34
Table of Contents
Seaborne Thermal. Segment Adjusted EBITDA increased during the three months ended June 30, 2026 compared to the same period in the prior year due to higher realized prices net of sales sensitive costs ($64.3 million), offset by unfavorable production costs ($20.3 million) driven by mine sequencing at the Wilpinjong Mine, higher commodities expense as described above and the unfavorable impact of higher foreign exchange rates on expenses ($8.5 million). Segment Adjusted EBITDA decreased during the six months ended June 30, 2026 compared to the same period in the prior year due to unfavorable production costs ($49.4 million) primarily driven by mine sequencing at the Wilpinjong Mine, unfavorable volume ($28.8 million), higher commodities expense as described above and the unfavorable impact of higher foreign exchange rates on expenses ($19.0 million). These decreases were offset by higher realized prices net of sales sensitive costs ($94.5 million).
Seaborne Metallurgical. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2026 compared to the same periods in the prior year due to unfavorable production costs ($61.4 million and $102.3 million, respectively) primarily driven by longwall commissioning activities at the Centurion Mine, the unfavorable impact of higher foreign exchange rates on expenses ($16.4 million and $28.6 million, respectively) and higher commodities expense as described above. These decreases were offset by higher realized prices net of sales sensitive costs ($54.0 million and $69.6 million, respectively) and favorable volume ($26.3 million and $41.5 million, respectively).
Powder River Basin. Segment Adjusted EBITDA decreased for the three and six months ended June 30, 2026 compared to the same periods in the prior year due to unfavorable volume ($28.0 million and $14.8 million, respectively), higher commodity pricing and usage as described above, increased in-pit inventory as the workforce focused on preparatory efforts in light of reduced customer demand ($11.4 million and $14.9 million, respectively) and higher leasing expense and costs for labor, repairs and outside services as described above. These decreases were offset by lower sales related costs as described above.
Other U.S. Thermal. Segment Adjusted EBITDA increased during the three and six months ended June 30, 2026 compared to the same periods in the prior year primarily due to lower costs for repairs and outside services as described above and favorable volume ($10.4 million and $16.5 million, respectively), offset by higher commodity pricing and usage as described above.
Corporate and Other Adjusted EBITDA. The following table presents a summary of the components of Corporate and Other Adjusted EBITDA:
Three Months Ended June 30, (Decrease) Increase to Adjusted EBITDA Six Months Ended June 30, Decrease to Adjusted EBITDA
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
Middlemount (1) $ (10.1) $ (1.3) $ (8.8) (677) % $ (15.1) $ (8.2) $ (6.9) (84) %
Resource management activities (2) 8.3 17.3 (9.0) (52) % 22.3 22.8 (0.5) (2) %
Selling and administrative expenses (23.3) (23.5) 0.2 1 % (54.9) (47.1) (7.8) (17) %
Other items, net (3) (5.8) 20.0 (25.8) (129) % (3.7) 22.4 (26.1) (117) %
Corporate and Other Adjusted EBITDA $ (30.9) $ 12.5 $ (43.4) (347) % $ (51.4) $ (10.1) $ (41.3) (409) %
(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.
Corporate and Other Adjusted EBITDA decreased during the three months ended June 30, 2026 compared to the same period in the prior year due to unfavorable variances in Middlemount’s results driven by lower production and higher fuel costs, partially offset by higher sales pricing; and lower gains on equipment and land sales ($10.4 million). The decrease in other items was driven by unfavorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($15.1 million) and lower net periodic benefit credit, excluding service cost, as described above ($7.1 million).
35
Table of Contents
Corporate and Other Adjusted EBITDA decreased during the six months ended June 30, 2026 compared to the same period in the prior year due to unfavorable variances in Middlemount’s results driven by lower production and higher fuel costs, partially offset by higher sales pricing; and higher selling and administrative expenses. The decrease in other items was driven by lower net periodic benefit credit, excluding service cost, as described above ($14.1 million) and the unfavorable remeasurement of foreign currency denominated monetary assets, substantially comprised of Australian dollar denominated restricted cash and cash collateral ($8.5 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 June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
Adjusted EBITDA (1) $ 24.0 $ 93.3 $ (69.3) (74) % $ 106.5 $ 237.3 $ (130.8) (55) %
Depreciation, depletion and amortization (107.5) (93.4) (14.1) (15) % (217.0) (185.5) (31.5) (17) %
Asset retirement obligation expenses (13.8) (13.8) — — % (27.4) (27.4) — — %
Restructuring charges (2.3) (3.5) 1.2 34 % (3.4) (5.2) 1.8 35 %
Costs related to terminated acquisition (2.3) (18.8) 16.5 88 % (5.3) (21.2) 15.9 75 %
Changes in amortization of basis difference related to equity affiliates 0.7 0.8 (0.1) (13) % 1.3 1.4 (0.1) (7) %
Interest expense, net of capitalized interest (12.7) (11.1) (1.6) (14) % (23.4) (22.6) (0.8) (4) %
Induced conversion expense (17.2) — (17.2) n.m. (17.2) — (17.2) n.m.
Interest income 12.1 13.8 (1.7) (12) % 25.2 29.2 (4.0) (14) %
Unrealized (losses) gains on foreign currency option contracts (3.9) 4.1 (8.0) (195) % (3.6) 8.4 (12.0) (143) %
Take-or-pay contract-based intangible recognition — 0.3 (0.3) (100) % — 0.5 (0.5) (100) %
Income tax benefit (provision) 37.0 2.7 34.3 1,270 % 53.0 (2.2) 55.2 2,509 %
(Loss) income from continuing operations, net of income taxes $ (85.9) $ (25.6) $ (60.3) (236) % $ (111.3) $ 12.7 $ (124.0) (976) %
(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 June 30, Increase (Decrease) to Income Six Months Ended June 30, Increase (Decrease) to Income
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
Seaborne Thermal $ (22.9) $ (31.0) $ 8.1 26 % $ (44.7) $ (64.4) $ 19.7 31 %
Seaborne Metallurgical (50.9) (30.4) (20.5) (67) % (106.1) (59.2) (46.9) (79) %
Powder River Basin (13.9) (14.6) 0.7 5 % (29.3) (27.4) (1.9) (7) %
Other U.S. Thermal (14.7) (15.8) 1.1 7 % (30.7) (31.5) 0.8 3 %
Corporate and Other (5.1) (1.6) (3.5) (219) % (6.2) (3.0) (3.2) (107) %
Total depreciation, depletion and amortization $ (107.5) $ (93.4) $ (14.1) (15) % $ (217.0) $ (185.5) $ (31.5) (17) %
36
Table of Contents
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 June 30, Six Months Ended June 30,
2026 2025 2026 2025
Seaborne Thermal $ 1.05 $ 2.00 $ 1.05 $ 2.00
Seaborne Metallurgical 3.85 3.23 4.55 3.00
Powder River Basin 0.33 0.32 0.31 0.32
Other U.S. Thermal 1.47 1.81 1.62 1.82
Depreciation, depletion and amortization expense increased during the three and six months ended June 30, 2026 compared to the same periods 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 and six months ended June 30, 2026 compared to the same periods in the prior year reflects the increased quantity of proven and probable coal reserves at the Wilpinjong Mine 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 and six months ended June 30, 2026 compared to the same periods in the prior year reflects the impact of volume and mix variances across the segment. The decrease in the weighted-average depletion rate per ton for the Other U.S. Thermal segment during the three and six months ended June 30, 2026 compared to the same periods in the prior year reflects the impact of volume and mix variances across the segment.
Costs Related to Terminated Acquisition. These costs relate to the terminated acquisition of certain assets and businesses associated with Anglo’s metallurgical coal portfolio. In addition to typical costs, such as legal and professional fees, the prior year charges included a $10.4 million duration fee on a now-terminated bridge loan facility. Refer to Note 13. “Commitments and Contingencies” to the accompanying unaudited condensed consolidated financial statements for further information.
Induced Conversion Expense. During the current year, the Company repurchased $241.2 million aggregate principal amount of its outstanding 3.250% Convertible Senior Notes due March 2028 for consideration of $386.8 million. The repurchase of the existing notes was accounted for as an induced conversion, and a portion of the consideration in excess of the amount issuable pursuant to the original conversion terms, $17.2 million, was recognized as expense. Refer to Note 9. “Long-term Debt” to the accompanying unaudited condensed consolidated financial statements for additional information.
Interest Income. The decrease in income during the three and six months ended June 30, 2026 compared to the same periods in the prior year was driven by lower average cash balances during the current period.
Unrealized (Losses) Gains on Foreign Currency Option Contracts. Unrealized (losses) gains primarily relate to mark-to-market activity on foreign currency option contracts. For additional information, refer to Note 6. “Derivatives and Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements.
Income Tax Benefit (Provision). The increase in the income tax benefit during the three months ended June 30, 2026 compared to the same period in the prior year was primarily due to lower expected pretax income. The increase in the income tax benefit recorded during the six months ended June 30, 2026 compared to the same period in the prior year was driven by expected pretax losses in the current year compared to expected pretax income in the prior year. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information.
37
Table of Contents
Net (Loss) Income Attributable to Common Stockholders
The following table presents net (loss) income attributable to common stockholders:
Three Months Ended June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income
2026 2025 $ % 2026 2025 $ %
(Dollars in millions) (Dollars in millions)
(Loss) income from continuing operations, net of income taxes $ (85.9) $ (25.6) $ (60.3) (236) % $ (111.3) $ 12.7 $ (124.0) (976) %
Loss from discontinued operations, net of income taxes (0.3) (0.4) 0.1 25 % (0.5) (0.7) 0.2 29 %
Net (loss) income (86.2) (26.0) (60.2) (232) % (111.8) 12.0 (123.8) (1,032) %
Less: Net income attributable to noncontrolling interests 4.4 1.6 2.8 175 % 11.2 5.2 6.0 115 %
Net (loss) income attributable to common stockholders $ (90.6) $ (27.6) $ (63.0) (228) % $ (123.0) $ 6.8 $ (129.8) (1,909) %
Net Income Attributable to Noncontrolling Interests. The increase in net income attributable to noncontrolling interests during the three and six months ended June 30, 2026 compared to the same periods 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 June 30, (Decrease) Increase to EPS Six Months Ended June 30, Decrease to EPS
2026 2025 $ % 2026 2025 $ %
Diluted EPS attributable to common stockholders:
(Loss) income from continuing operations $ (0.74) $ (0.22) $ (0.52) (236) % $ (1.00) $ 0.06 $ (1.06) (1,767) %
Loss from discontinued operations — (0.01) 0.01 100 % (0.01) — (0.01) n.m.
Net (loss) income attributable to common stockholders $ (0.74) $ (0.23) $ (0.51) (222) % $ (1.01) $ 0.06 $ (1.07) (1,783) %
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 121.7 million for the three months ended June 30, 2026 and 2025, respectively, and 122.0 million and 122.3 million for the six months ended June 30, 2026 and 2025, respectively.
38
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 June 30, Six Months Ended June 30,
2026 2025 2026 2025
(Dollars in millions)
(Loss) income from continuing operations, net of income taxes $ (85.9) $ (25.6) $ (111.3) $ 12.7
Depreciation, depletion and amortization 107.5 93.4 217.0 185.5
Asset retirement obligation expenses 13.8 13.8 27.4 27.4
Restructuring charges 2.3 3.5 3.4 5.2
Costs related to terminated acquisition 2.3 18.8 5.3 21.2
Changes in amortization of basis difference related to equity affiliates (0.7) (0.8) (1.3) (1.4)
Interest expense, net of capitalized interest 12.7 11.1 23.4 22.6
Induced conversion expense 17.2 — 17.2 —
Interest income (12.1) (13.8) (25.2) (29.2)
Unrealized losses (gains) on foreign currency option contracts 3.9 (4.1) 3.6 (8.4)
Take-or-pay contract-based intangible recognition — (0.3) — (0.5)
Income tax (benefit) provision (37.0) (2.7) (53.0) 2.2
Total Adjusted EBITDA $ 24.0 $ 93.3 $ 106.5 $ 237.3
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 June 30, Six Months Ended June 30,
2026 2025 2026 2025
(Dollars in millions)
Operating costs and expenses $ 953.9 $ 789.4 $ 1,818.6 $ 1,559.6
Unrealized (losses) gains on foreign currency option contracts (3.9) 4.1 (3.6) 8.4
Take-or-pay contract-based intangible recognition — 0.3 — 0.5
Net periodic benefit credit, excluding service cost (0.3) (7.4) (0.7) (14.8)
Total Segment Costs $ 949.7 $ 786.4 $ 1,814.3 $ 1,553.7
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.
39
Table of Contents
The following tables present tons sold, revenue, Total Segment Costs and Adjusted EBITDA by reportable segment:
Three Months Ended June 30, 2026
Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold 3.0 2.5 16.4 3.0
Revenue $ 230.6 $ 358.3 $ 223.8 $ 163.2
Total Segment Costs 178.5 375.3 230.9 136.3
Adjusted EBITDA $ 52.1 $ (17.0) $ (7.1) $ 26.9
Revenue per Ton $ 74.85 $ 148.04 $ 13.63 $ 55.26
Costs per Ton 57.93 155.08 14.06 46.13
Adjusted EBITDA Margin per Ton $ 16.92 $ (7.04) $ (0.43) $ 9.13
Three Months Ended June 30, 2025
Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold 3.6 2.2 20.0 2.9
Revenue $ 195.1 $ 252.2 $ 275.7 $ 155.1
Total Segment Costs 161.6 261.4 232.7 141.6
Adjusted EBITDA $ 33.5 $ (9.2) $ 43.0 $ 13.5
Revenue per Ton $ 53.22 $ 114.79 $ 13.82 $ 54.08
Costs per Ton 44.10 118.97 11.66 49.39
Adjusted EBITDA Margin per Ton $ 9.12 $ (4.18) $ 2.16 $ 4.69
Six Months Ended June 30, 2026
Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold 6.0 4.5 37.6 6.3
Revenue $ 428.1 $ 641.3 $ 513.3 $ 347.7
Total Segment Costs 327.5 665.3 496.7 283.0
Adjusted EBITDA $ 100.6 $ (24.0) $ 16.6 $ 64.7
Revenue per Ton $ 70.81 $ 143.57 $ 13.64 $ 55.54
Costs per Ton 54.17 148.96 13.20 45.20
Adjusted EBITDA Margin per Ton $ 16.64 $ (5.39) $ 0.44 $ 10.34
40
Table of Contents
Six Months Ended June 30, 2025
Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal
(Amounts in millions, except per ton data)
Tons sold 8.0 4.0 39.6 6.0
Revenue $ 460.2 $ 472.3 $ 551.3 $ 323.8
Total Segment Costs 342.5 468.3 472.0 277.4
Adjusted EBITDA $ 117.7 $ 4.0 $ 79.3 $ 46.4
Revenue per Ton $ 57.25 $ 119.40 $ 13.92 $ 54.20
Costs per Ton 42.61 118.39 11.92 46.43
Adjusted EBITDA Margin per Ton $ 14.64 $ 1.01 $ 2.00 $ 7.77
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.
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 µg/m3 to 9.0 µg/m3. The revised PM 2.5 standard was challenged in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in Kentucky v. EPA, (D.C. Cir., No. 24-1050) and subsequently upheld by that court on June 26, 2026. Under the CAA, once a NAAQS is revised states are required to take several actions to implement the revised standards. Such actions could require fossil fuel-fired 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.
Mercury and Air Toxic Standards (MATS). In 2012, the 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 EGUs under CAA section 112, including the regulation of HAPs from EGUs after considering cost. 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 and lowered the mercury emission standard for lignite-fired EGUs. The EPA, however, subsequently repealed both the lower filterable PM emission limits and the lower mercury standards for lignite plants. 91. Fed. Reg 9088 (February 24, 2026). This rule became effective on April 27, 2026. The rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. Air Alliance Houston v. EPA, No. 26-1070 (and consolidated case) (D.C. Cir. filed March 30, 2026).
41
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 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); due to the reconsideration process currently ongoing, however (see below), the proceedings are currently being held in abeyance. 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 Deadline Extensions Rule has been challenged by multiple parties, with the litigation consolidated in the U.S. Court of Appeals for the Second Circuit. A motion to transfer the consolidated petitions to the Eighth Circuit is pending. If the Deadline Extensions Rule is vacated, the 2024 rule’s deadlines could become operative again. 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. On May 18, 2026, the EPA published a proposed rule to clarify applicability of unmanaged combustion residual leachate limitations. 91 Fed. Reg. 28487 (May 18, 2026).
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.
42
Table of Contents
SEC Climate-Related Disclosures. On March 6, 2024, the SEC adopted final rules intended to enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules required 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 Eighth Circuit. On April 4, 2024, the SEC voluntarily stayed implementation of the final rules pending such judicial review. On May 29, 2026, the SEC proposed to rescind the final rules, and is accepting comments for 60 days following Federal Register Publication.
Complaints Filed Against “Climate Superfund Laws” and Announced State Actions. On April 30 and May 1, 2025, respectively, the U.S. Department of Justice (DOJ) filed complaints for declaratory and injunctive relief against the states of Michigan and Hawaii regarding alleged liability of fossil fuel companies for past GHG emissions and against New York and Vermont for “climate superfund” laws. On May 4, 2026, the DOJ filed a complaint against the state of Minnesota to halt that state’s climate lawsuit against major energy companies with parallels to the Michigan and Hawaii suits. These complaints allege that existing litigation and state laws interfere with federal law, including the CAA, and with interstate and foreign commerce. The Company will monitor this litigation and its potential impact on the U.S. coal mining industry, its mining operations and customers.
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.
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, the return of collateral 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.
43
Table of Contents
Liquidity
As of June 30, 2026, the Company’s cash and cash equivalents balances totaled $526.3 million, including approximately $420 million held by Australian subsidiaries, approximately $100 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 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 six months ended June 30, 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 increased from $942.1 million as of December 31, 2025 to $959.1 million as of June 30, 2026. Available liquidity was comprised of the following:
June 30, 2026 December 31, 2025
(Dollars in millions)
Cash and cash equivalents $ 526.3 $ 575.3
Revolving credit facility availability 341.8 270.8
Accounts receivable securitization program availability 91.0 96.0
Total liquidity $ 959.1 $ 942.1
Capital Returns to Shareholders
The Company paid dividends of $18.3 million during the six months ended June 30, 2026.
Australian Surety Bond Facilities
On June 12, 2026, certain of the Company’s Australian subsidiaries (collectively, the Australian Surety Bond Facility Obligors), each an indirect subsidiary of PEC, established new Australian dollar-denominated surety bond facilities with an aggregate combined principal amount of $700.0 million Australian dollars in commitments by entering into agreements with surety bond providers (the Australian Surety Bond Facilities). The Australian Surety Bond Facilities have been established to, among other things, establish a surety bonding facility, primarily to support reclamation bonding requirements, to replace the Australian Surety Bond Facility Obligors’ existing 100% cash collateralized programs.
The surety bond commitments established under the Australian Surety Bond Facilities terminate on June 12, 2031 (the Maturity Date). Surety bonds issued under the Australian Surety Bond Facilities may be issued with or without an expiration date, but any surety bond that does not have an expiration date or that has an expiration date occurring after the Maturity Date, must be repaid, prepaid in full or otherwise satisfied on or prior to the Maturity Date.
The Australian Surety Bond Facilities contain customary covenants that, among other things and subject to certain exceptions (including compliance with financial ratios), may limit the Australian Surety Bond Facility Obligors and their respective subsidiaries’ ability to incur additional financial indebtedness, make certain distributions or loans, sell or otherwise dispose of assets, enter into certain affiliate transactions, create or incur liens, and enter into mergers or other significant corporate transactions. The Australian Surety Bond Facilities are secured by substantially all of the assets of the Australian Surety Bond Facility Obligors.
Surety Agreement Termination
On June 12, 2026, the Company terminated that certain Transaction Support Agreement and Surety Resolution Term Sheet, each dated as of November 6, 2020 (as amended, supplemented or otherwise modified to the date hereof, the TSA), by and among the Company, certain subsidiaries of the Company party thereto and certain providers of its surety program (collectively, the Sureties). In connection with the termination of the TSA, on June 12, 2026, the Company terminated that certain Collateral Agency and Security Agreement, dated as of May 3, 2022 (as amended, supplemented or otherwise modified to the date hereof, the TSA Security Agreement), by and among the Company, certain subsidiaries of the Company party thereto, the Sureties party thereto and Bank of New York Mellon Trust Company, N.A., as collateral agent (the TSA Collateral Agent). All obligations of the Company to the Sureties and the TSA Collateral Agent, as applicable, under the TSA and the TSA Security Agreement have been satisfied. The termination of the TSA allowed for the overall reduction of collateral pledged to the Sureties.
44
Table of Contents
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 June 30, 2026, letters of credit of $77.9 million were outstanding under the agreement.
In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements. During the second quarter of 2026, the Australian Surety Bond Facilities, as described above, were established, which reduced the utilization of the cash-backed bank guarantee facilities during the three months ended June 30, 2026. At June 30, 2026, guarantees of $11.8 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 by entering into a credit agreement, dated as of January 18, 2024, as amended, (the 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. On June 9, 2026, the Company amended the Credit Agreement to, among other things, permit the Australian Surety Bond Facilities. On June 30, 2026, the Company further amended the Credit Agreement to, among other things, (i) increase the revolving commitments under the Credit Agreement from an aggregate principal amount equal to $320.0 million to an aggregate principal amount equal to $400.0 million; (ii) extend the maturity date of the revolving commitments and any related loans (any such loans, the Revolving Loans) from January 18, 2028 to June 30, 2030; and (iii) decrease the interest rate applicable to the Revolving Loans from a rate equal to 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 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option, to a rate equal to SOFR plus an applicable margin ranging from 3.25% to 4.00%, depending on the Company’s total net leverage ratio or a base rate plus an applicable margin ranging from 2.25% to 3.00%, at the Company’s option. After the June 30, 2026 amendment, letters of credit issued under the Credit Agreement incur a combined fee equal to an applicable margin ranging from 3.25% to 4.00% plus a fronting fee equal to 0.125% per annum. Prior to the amendment, the combined fee was 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 Credit Agreement bears a commitment fee of 0.50% per annum.
During the second quarter of 2026, the Company borrowed and repaid $110.0 million under the revolving credit facility. At June 30, 2026, the Credit Agreement was only utilized for letters of credit of $58.2 million. 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 revolving credit facility was $341.8 million at June 30, 2026.
The 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 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.
45
Table of Contents
Indebtedness
The Company’s total indebtedness as of June 30, 2026 and December 31, 2025 is presented in the table below.
Debt Instrument (defined below, as applicable) June 30, 2026 December 31, 2025
(Dollars in millions)
3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) $ 78.8 $ 320.0
0.50% Convertible Senior Notes due June 2031 (2031 Convertible Notes) 250.0 —
Finance lease obligations 17.7 20.8
Less: Debt issuance costs (7.5) (4.4)
339.0 336.4
Less: Current portion of long-term debt 13.5 15.2
Long-term debt $ 325.5 $ 321.2
The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at June 30, 2026, of approximately $12 million in 2026, $10 million in 2027, $85 million in 2028, $2 million in both 2029 and 2030, and $251 million thereafter.
The Company paid cash of $33.3 million and $24.1 million during the six months ended June 30, 2026 and 2025, respectively, for interest, net of capitalized interest, related to the Company’s indebtedness and financial assurance instruments.
Partial Repurchase of 2028 Convertible Notes
On June 2, 2026, through a private offering, the Company issued $250.0 million in aggregate principal amount of 2031 Convertible Notes, as described below. The Company used the proceeds of the offering of the 2031 Convertible Notes, together with available cash, to repurchase $241.2 million aggregate principal amount of its outstanding 2028 Convertible Notes for consideration of $386.8 million. The repurchase of the existing notes was accounted for as an induced conversion in accordance with Accounting Standards Codification 470-20 and Accounting Standards Update 2024-04. A portion of the consideration in excess of the amount issuable pursuant to the original conversion terms, $17.2 million, was recognized as “Induced conversion expense” in the unaudited condensed consolidated statements of operations during the three and six months ended June 30, 2026. The remaining excess of the consideration over the carrying value of the repurchased 2028 Convertible Notes on the date of repurchase of $131.1 million, which included unamortized debt issuance costs of $2.7 million, was recorded as “Additional paid-in capital” in the condensed consolidated balance sheets.
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, dated as of March 1, 2022 (the 2028 Indenture), between the Company and Wilmington Trust, National Association, as trustee. During the second quarter of 2026, in connection with the issuance of the 2031 Convertible Notes, the Company used the proceeds therefrom and available cash to repurchase $241.2 million in aggregate principal amount of the 2028 Convertible Notes as discussed above.
The remaining 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 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 second quarter of 2026, for which no conversion requests were received. During the second quarter of 2026, 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 during the third quarter of 2026.
46
Table of Contents
2031 Convertible Notes
On June 2, 2026, through a private offering, the Company issued the 2031 Convertible Notes in the aggregate principal amount of $250.0 million. The 2031 Convertible Notes are senior unsecured obligations of the Company and are governed under an indenture, dated June 2, 2026 (the 2031 Indenture), between the Company and Wilmington Trust, National Association, as trustee.
The Company used the proceeds of the offering of the 2031 Convertible Notes to fund $16.7 million of capped call transactions, as discussed below, and together with available cash, to repurchase $241.2 million of its outstanding 2028 Convertible Notes, as described above.
The 2031 Convertible Notes will mature on June 1, 2031, unless earlier repurchased, redeemed or converted in accordance with their terms. The 2031 Convertible Notes will bear interest from June 2, 2026 at a rate of 0.50% per year payable semi-annually in arrears on June 1 and December 1 of each year, beginning on December 1, 2026.
The 2031 Convertible Notes will be convertible at the option of the holders only in the following circumstances: (1) during any calendar quarter commencing after the calendar quarter ending on September 30, 2026, if the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price for each of at least 20 trading days during the 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter; (2) during the five consecutive business days immediately after any five consecutive trading day period (such five consecutive trading day period, the Measurement Period) in which the trading price per $1,000 principal amount of 2031 Convertible Notes for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price per share of the Company’s common stock on such trading day and the conversion rate on such trading day; (3) upon the occurrence of certain corporate events or distributions on the Company’s common stock; (4) if the Company calls such 2031 Convertible Notes for redemption; and (5) at any time from, and including, December 1, 2030 until the close of business on the second scheduled trading day immediately before the maturity date.
Upon conversion, the Company may satisfy its conversion obligation by paying or delivering, as applicable, cash, shares of the Company’s common stock or a combination of cash and shares of the Company’s common stock, at the Company’s election, in the manner and subject to the terms and conditions provided in the 2031 Indenture. The initial conversion rate for the 2031 Convertible Notes will be 26.0970 shares of the Company’s common stock per $1,000 principal amount of 2031 Convertible Notes, which represents an initial conversion price of approximately $38.32 per share of the Company’s common stock. The initial conversion price represents a premium of approximately 32.5% over the U.S. composite volume weighted average price of Peabody’s common stock from 9:30 a.m. through 4:00 p.m. Eastern Daylight Time on May 28, 2026, which was $28.9197 per share. The conversion rate and conversion price are subject to adjustment under certain circumstances in accordance with the terms of the 2031 Indenture. If certain corporate events described in the 2031 Indenture occur prior to the maturity date, or the Company delivers a redemption notice (as described below), the conversion rate will be increased for a holder who elects to convert its 2031 Convertible Notes in connection with such corporate event or redemption notice, as the case may be, in certain circumstances.
The Company may not redeem the 2031 Convertible Notes prior to June 5, 2029, except in the event of a cleanup redemption (as defined below). The Company may redeem the 2031 Convertible Notes in whole or in part (subject to certain limitations), at its option at any time, and from time to time, on or after June 5, 2029 and on or before the 31st scheduled trading day immediately before the maturity date, at a cash redemption price equal to 100% of the principal amount of the 2031 Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, if (i) the 2031 Convertible Notes are “freely tradable” (as defined in the 2031 Indenture), and all accrued and unpaid additional interest, if any, has been paid in full, as of the date the Company sends the related redemption notice; and (ii) the last reported sale price per share of the Company’s common stock exceeds 130% of the conversion price on (1) each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date the Company sends the related redemption notice; and (2) the trading day immediately before the date the Company sends such notice. However, the Company may not redeem less than all of the outstanding 2031 Convertible Notes unless at least $75 million aggregate principal amount of 2031 Convertible Notes are outstanding and not called for redemption as of the time the Company sends the related redemption notice. No sinking fund is provided for the 2031 Convertible Notes.
47
Table of Contents
Peabody may redeem for cash all, but not less than all, of the 2031 Convertible Notes at any time if (i) the 2031 Convertible Notes are “freely tradable” (as defined in the 2031 Indenture), and all accrued and unpaid additional interest, if any, has been paid in full, as of the date Peabody sends the related redemption notice; and (ii) the amount of the 2031 Convertible Notes that remains outstanding is less than 15% of the aggregate principal amount of the 2031 Convertible Notes initially issued under the 2031 Indenture at a redemption price equal to 100% of the principal amount of the 2031 Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date (a cleanup redemption).
If the Company undergoes a fundamental change (as defined in the 2031 Indenture), noteholders may require the Company to repurchase their 2031 Convertible Notes at a cash repurchase price equal to 100% of the principal amount of the 2031 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date.
Capped Call Transactions
In connection with the offering of the 2031 Convertible Notes, the Company entered into privately negotiated capped call transactions (the Capped Call Transactions) with certain financial institutions. The Capped Call Transactions are expected generally to reduce the potential dilution to the Company’s common stock upon any conversion of the 2031 Convertible Notes prior to May 30, 2030, and/or offset any potential cash payments the Company is required to make in excess of the principal amount of such converted 2031 Convertible Notes, as the case may be, with such reduction and/or offset subject to a cap based on the cap price. The cap price of the Capped Call Transactions will initially be $50.6095 per share, which represents a premium of approximately 75.0% over the U.S. composite volume weighted average price of the Company’s common stock from 9:30 a.m. through 4:00 p.m. Eastern Daylight Time on May 28, 2026 (which was $28.9197 per share), and is subject to certain adjustments under the terms of the Capped Call Transactions. The Capped Call Transactions will expire over a period of trading days beginning on April 17, 2030.
The Capped Call Transactions are accounted for as equity instruments in “Additional paid-in capital” in the condensed consolidated balance sheet and are not subsequently remeasured as long as they continue to meet the conditions for equity classification. Accordingly, the premiums paid for the Capped Call Transactions are recorded as a reduction to additional paid-in capital and do not affect the Company’s basic or diluted earnings per share, although they are expected to reduce the potential economic dilution from any conversion of the 2031 Convertible Notes, subject to the cap.
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 June 30, 2026, the Company had no outstanding borrowings and $62.0 million of letters of credit outstanding under the program. The Company was not required to post cash collateral under the securitization program at June 30, 2026.
The accounts receivable securitization program was amended in January 2025 to extend its maturity to January 2028.
Covenant Compliance
The Company was compliant with all relevant covenants under its debt and other finance agreements at June 30, 2026.
48
Table of Contents
Cash Flows
The following table summarizes the Company’s cash flows for the six months ended June 30, 2026 and 2025, as reported in the accompanying unaudited condensed consolidated financial statements.
Six Months Ended June 30,
2026 2025
(Dollars in millions)
Net cash provided by operating activities $ 28.6 $ 143.1
Net cash used in investing activities (184.1) (180.7)
Net cash used in financing activities (202.0) (44.9)
Net change in cash, cash equivalents and restricted cash (357.5) (82.5)
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 $ 927.0 $ 1,300.1
Operating Activities. The decrease in net cash provided by operating activities for the six months ended June 30, 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 ($95.1 million), partially offset by the return of $75.8 million of cash collateral during the six months ended June 30, 2026.
Investing Activities. The increase in net cash used in investing activities for the six months ended June 30, 2026 compared to the prior year was driven by higher net contributions to joint ventures ($19.4 million) and lower proceeds from disposal of assets ($7.1 million). These variances were partially offset by lower capital expenditures and payments of capital accruals ($24.2 million).
Financing Activities. The increase in net cash used in financing activities for the six months ended June 30, 2026 compared to the same period in the prior year was driven by higher repayments of long-term debt ($494.1 million), purchases of capped calls ($16.7 million) and payments of debt issuance and other deferred financing costs ($12.5 million). These variances were partially offset by proceeds from long-term debt ($360.0 million) and 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-sheet risk and are not reflected in the accompanying condensed consolidated balance sheets. Such financial instruments provide support for the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees. The Company periodically evaluates the instruments for on-balance-sheet treatment based on the amount of exposure under the instrument and the likelihood of required performance. The Company does not expect any material losses to result from these guarantees or off-balance-sheet instruments in excess of liabilities provided for in the accompanying condensed consolidated balance sheets.
The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk.
June 30, 2026
Reclamation Support Other Support (1) Total
(Dollars in millions)
Surety bonds $ 1,194.0 $ 82.4 $ 1,276.4
Letters of credit (2) 62.3 57.9 120.2
1,256.3 140.3 1,396.6
Less: Letters of credit in support of surety bonds (3) (62.3) (1.9) (64.2)
Obligations supported, net $ 1,194.0 $ 138.4 $ 1,332.4
(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.
49
Table of Contents
Not presented in the above table is $459.8 million of restricted cash and collateral which are included in the accompanying condensed consolidated balance sheets at June 30, 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 $384.3 million during the six months ended June 30, 2026 substantially due to the release of cash collateral as a result of the establishment of the Australian Surety Bond Facilities and the termination of the TSA.
At June 30, 2026, the Company had total asset retirement obligations of $754.3 million. Bonding requirement amounts may differ significantly from the related asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date.
At June 30, 2026, the Company’s reclamation bonding requirements were supported by $1.2 billion of surety bonds and approximately $355 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 June 30, 2026, the Company identified certain assets with an aggregate carrying value of approximately $57 million in its Other U.S. Thermal reportable 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 June 30, 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.