PEABODY ENERGY CORP 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. As used in this report, the terms “Peabody” or “the Company” refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Quarterly Report on Form 10-Q relate only to the Company’s continuing operations. When used in this filing, the term “ton” refers to short or net tons, equal to 2,000 pounds (907.18 kilograms), while “tonne” refers to metric tons, equal to 2,204.62 pounds (1,000 kilograms). Cautionary Notice Regarding Forward-Looking Statements This report includes statements of Peabody’s expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or Peabody’s future financial performance. The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements. Without limiting the foregoing, all statements relating to Peabody’s future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that Peabody believes are reasonable, but are subject to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. These factors are difficult to accurately predict and may be beyond the Company’s control. When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in the Company’s other Securities and Exchange Commission (SEC) filings, including, but not limited to, the more detailed discussion of these factors and other factors that could affect its results contained in Item 1A. “Risk Factors” of Part II of this Quarterly Report on Form 10-Q and Item 1A. “Risk Factors” and Item 3. “Legal Proceedings” of Part I of its Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 23, 2024. These forward-looking statements speak only as of the date on which such statements were made, and the Company undertakes no obligation to update these statements except as required by federal securities laws. Non-GAAP Financial Measures The following discussion of the Company’s results of operations includes references to and analysis of Adjusted EBITDA and Total Reporting Segment Costs, which are financial measures not recognized in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Adjusted EBITDA is used by the chief operating decision maker as the primary metric to measure each of the segments’ operating performance and allocate resources. Total Reporting Segment Costs is also used by management as a component of a metric to measure each of its segments’ operating performance. Also included in the following discussion of the Company’s results of operations are references to Revenue per Ton, Costs per Ton and Adjusted EBITDA Margin per Ton for each reporting segment. These metrics are used by management to measure each of its reporting segments’ operating performance. Management believes Costs per Ton and Adjusted EBITDA Margin per Ton best reflect controllable costs and operating results at the reporting segment level. The Company considers all measures reported on a per ton basis to be operating/statistical measures; however, the Company includes reconciliations of the related non-GAAP financial measures (Adjusted EBITDA and Total Reporting Segment Costs) in the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2. In its discussion of liquidity and capital resources, the Company includes references to Available Free Cash Flow (AFCF) which is also a non-GAAP financial measure. AFCF is used by management as a measure of its ability to generate excess cash flow from its business operations. The Company believes non-GAAP performance measures are used by investors to measure its operating performance. These measures are not intended to serve as alternatives to U.S. GAAP measures of performance and may not be comparable to similarly-titled measures presented by other companies. Refer to the “Reconciliation of Non-GAAP Financial Measures” section contained within this Item 2 for definitions and reconciliations to the most comparable measures under U.S. GAAP. 25 Table of Contents Overview Peabody is a leading producer of metallurgical and thermal coal. In 2023, the Company produced and sold 126.7 million and 126.2 million tons of coal, respectively, from continuing operations. At June 30, 2024, the Company owned interests in 17 active coal mining operations located in the United States (U.S.) and Australia. Included in that count is Peabody’s 50% equity interest in Middlemount Coal Pty Ltd (Middlemount), which owns the Middlemount Mine in Queensland, Australia. In addition to its mining operations, the Company markets and brokers coal from other coal producers; trades coal and freight-related contracts; and since 2022, is partnered in a joint venture with the intent of developing various sites, including certain reclaimed mining land held by the Company in the U.S., for utility-scale photovoltaic solar generation and battery storage. The Company reports its results of operations primarily through the following reportable segments: Seaborne Thermal, Seaborne Metallurgical, Powder River Basin, Other U.S. Thermal and Corporate and Other. Refer to Note 14. “Segment Information” to the accompanying unaudited condensed consolidated financial statements for further information regarding those segments and the components of its Corporate and Other segment. Spot pricing for premium low-vol hard coking coal (Premium HCC), premium low-vol pulverized coal injection (Premium PCI) coal, Newcastle index thermal coal and API 5 index thermal coal, and prompt month pricing for PRB 8,880 Btu/Lb coal and Illinois Basin 11,500 Btu/Lb coal during the three months ended June 30, 2024 is set forth in the table below. The seaborne pricing included in the table below is not necessarily indicative of the pricing the Company realized during the three months ended June 30, 2024 due to quality differentials and a portion of its seaborne sales being executed through annual and multi-year international coal supply agreements that contain provisions requiring both parties to renegotiate pricing periodically, with spot, index and quarterly sales arrangements also utilized. The Company’s typical practice is to negotiate pricing for seaborne metallurgical coal contracts on a quarterly, spot or index basis and seaborne thermal coal contracts on an annual, spot or index basis. In the U.S., the pricing included in the table below is also not necessarily indicative of the pricing the Company realized during the three months ended June 30, 2024 since the Company generally sells coal under long-term contracts where pricing is determined based on various factors. Such long-term contracts in the U.S. may vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure and termination and assignment provisions. Competition from alternative fuels such as natural gas and other fuel sources may also impact the Company’s realized pricing. High Low Average June 30, 2024 August 2, 2024 Premium HCC (1) $ 256.50 $ 223.50 $ 242.31 $ 234.00 $ 215.00 Premium PCI coal (1) 186.00 142.00 163.36 182.00 186.50 Newcastle index thermal coal (1) 146.77 125.54 136.11 132.03 140.82 API 5 index thermal coal (1) 92.16 85.32 88.60 86.92 87.83 PRB 8,800 Btu/Lb coal (2) 13.70 13.40 13.52 13.70 13.90 Illinois Basin 11,500 Btu/Lb coal (2) 41.50 40.00 40.69 40.00 41.50 (1) Prices expressed per metric tonne. (2) Prices expressed per short ton. Within the global coal industry, supply and demand for its products and the supplies used for mining continue to be impacted by the ongoing Russian-Ukrainian conflict. As future developments related to the Russian-Ukrainian conflict and geopolitical instability in key energy producing regions are unknown, the global coal industry data for the six months ended June 30, 2024 presented herein may not be indicative of their ultimate impacts. 26 Table of Contents Within the seaborne metallurgical coal market, coking coal prices have retreated from a high base during the six months ended June 30, 2024. Parts of the global steel market have reported tepid demand and thin profit margins during this period, restricting demand growth for metallurgical coal. In India, steel production was disrupted due to election activities and more recently the onset of the monsoon season; while in China, steel production was mixed with a weak property market slowing demand, partially offset by economic stimulus targeting the real estate sector. Australian high-quality coking coal showed signs of supply improvement during the six months ended June 30, 2024 which has weighed on coking coal prices, however periodic price support has been observed via various supply side disruptions, including rail and port maintenance curtailing exports in Queensland, the restriction of U.S. exports in Baltimore, Maryland and low domestic coal production in China. The June 2024 incident at the Grosvenor Mine in Queensland, Australia has further limited global exports. Despite these constraints, coking coal supply proved sufficient to meet demand during the period. In the PCI segment, prices were initially under pressure early in the year from reduced steel making productivity targets under thin margin conditions, but have since found support from shifting of trade flows from Russian to Australian supply amidst newly announced sanctions. In the coming period, seasonal restocking patterns and ongoing economic stimulus may lend support to metallurgical coal pricing. Overall, the market for metallurgical coal remains finely balanced and exposed to volatility, influenced by the rate of exports from Australia and economic performance in China, India and elsewhere. Within the seaborne thermal coal market, global thermal coal prices were rangebound during the six months ended June 30, 2024, driven by healthy supply meeting elevated demand in Asian markets. In China, overall total generation demand has been elevated while domestic coal production has declined, which has driven stronger coal import demand year-over-year through the six months ended June 30, 2024. In India, strong growth in coal generation has supported increased import demand, despite elevated domestic coal production. Overall, global thermal coal markets remain turbulent amid ample supply and seasonal demand requirements in the Northern Hemisphere, as well as volatile global natural gas markets. In the U.S., overall electricity demand increased approximately 5% year-over-year. Through the six months ended June 30, 2024, electricity generation from thermal coal has increased slightly year-over-year driven by higher overall electricity demand and despite low natural gas prices and stronger renewable generation. Coal’s share of electricity generation has declined to approximately 14% for the six months ended June 30, 2024, while wind and solar’s combined generation share is at 19% and the share of natural gas generation has decreased slightly to 40%. U.S. coal inventories have declined through June 30, 2024, resulting in stockpiles slightly below levels seen at the end of 2023. During the six months ended June 30, 2024, utility consumption of PRB coal was unchanged compared to the prior year period. Centurion Mine Peabody’s redevelopment of the Centurion Mine, an underground longwall metallurgical coal mine in Queensland, Australia, continues to advance as planned. The first development coal was mined in June 2024, and a second continuous mine was commissioned in July 2024. The first coal shipments from the Centurion Mine are expected in the fourth quarter of 2024, and the Company is targeting the commencement of longwall production in the first quarter of 2026. Approximately $200 million of the $489 million of capital expenditures to reach longwall production has been completed as of June 30, 2024. The benchmark premium hard coking coal from Centurion is expected to receive a premium price relative to other metallurgical coals. Other Wards Well Acquisition. The Company entered into a definitive agreement dated October 26, 2023, to acquire the southern part of the Wards Well tenements (Wards Well) which are adjacent to the Company’s Centurion Mine in Queensland, Australia. The acquisition was completed on April 16, 2024 for total consideration of $153.4 million, consisting of cash consideration of $134.4 million, cash transaction costs of $9.4 million and the non-cash settlement of existing receivables with the acquiree of $9.6 million. The agreement also includes an initial contingent royalty of up to $200 million. The royalty will only be payable once the Company has recovered its investment and development costs of Wards Well and if the average sales price achieved exceeds certain thresholds. No royalty is payable if the Company does not commence mining Wards Well. Shoal Creek Insurance Recovery. On March 29, 2023, the Company’s Shoal Creek Mine experienced a fire involving void fill material utilized to stabilize the roof structure of the mine. On June 20, 2023, the Company announced that the Shoal Creek Mine, in coordination with the Mine Safety and Health Administration, had safely completed localized sealing of the affected area of the mine. 27 Table of Contents In October 2023, the Company filed an insurance claim against applicable insurance policies with combined business interruption and property loss limits of $125 million above a $50 million deductible. During June 2024, the Company reached a settlement with its insurers and various re-insurers and recognized a $109.5 million insurance recovery which the Company included in its results of operations for the three and six months ended June 30, 2024. Results of Operations Three and Six Months Ended June 30, 2024 Compared to the Three and Six Months Ended June 30, 2023 Summary The increase in income from continuing operations, net of income taxes for the three months ended June 30, 2024 compared to the same period in the prior year ($6.7 million) was driven by the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($58.1 million), and lower year-over-year provisions for taxes ($34.8 million) and the losses at the NARM and Shoal Creek Mines ($31.8 million). These favorable variances were offset by lower revenue ($226.8 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S. thermal segments. The decrease in income from continuing operations, net of income taxes for the six months ended June 30, 2024 compared to the same period in the prior year ($231.7 million) was driven by lower revenue ($607.2 million) due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year, lower seaborne coal pricing and volume decreases in the U.S. thermal segments. This unfavorable variance was partially offset by a lower tax provision ($132.7 million), the current year insurance recovery related to the 2023 event at the Shoal Creek Mine ($109.5 million), lower operating costs and expenses ($90.5 million) and lower year-over-year provision for losses at the NARM and Shoal Creek Mines ($30.0 million). Adjusted EBITDA for the three and six months ended June 30, 2024 reflected year-over-year decreases of $48.5 million and $278.6 million, respectively. Tons Sold The following table presents tons sold by operating segment: Three Months Ended June 30, Increase (Decrease) to Volumes Six Months Ended June 30, Increase (Decrease) to Volumes 2024 2023 Tons % 2024 2023 Tons % (Tons in millions) (Tons in millions) Seaborne Thermal 4.1 4.0 0.1 3 % 8.1 7.6 0.5 7 % Seaborne Metallurgical 2.0 2.0 — — % 3.4 3.3 0.1 3 % Powder River Basin 15.8 18.9 (3.1) (16) % 34.5 40.9 (6.4) (16) % Other U.S. Thermal 3.7 3.8 (0.1) (3) % 6.9 8.3 (1.4) (17) % Total tons sold from operating segments 25.6 28.7 (3.1) (11) % 52.9 60.1 (7.2) (12) % Corporate and Other — 0.2 (0.2) (100) % 0.1 0.3 (0.2) (67) % Total tons sold 25.6 28.9 (3.3) (11) % 53.0 60.4 (7.4) (12) % 28 Table of Contents Supplemental Financial Data The following table presents supplemental financial data by operating segment: Three Months Ended June 30, (Decrease) Increase Six Months Ended June 30, (Decrease) Increase 2024 2023 $ % 2024 2023 $ % Revenue per Ton (1) Seaborne Thermal $ 74.43 $ 100.59 $ (26.16) (26) % $ 72.86 $ 98.81 $ (25.95) (26) % Seaborne Metallurgical 149.29 190.13 (40.84) (21) % 159.10 202.33 (43.23) (21) % Powder River Basin 14.02 13.71 0.31 2 % 13.80 13.80 — — % Other U.S. Thermal 55.21 53.63 1.58 3 % 57.33 54.23 3.10 6 % Costs per Ton (1)(2) Seaborne Thermal $ 49.14 $ 50.88 $ (1.74) (3) % $ 48.44 $ 50.94 $ (2.50) (5) % Seaborne Metallurgical 117.47 137.78 (20.31) (15) % 126.46 143.14 (16.68) (12) % Powder River Basin 12.89 12.33 0.56 5 % 12.81 12.28 0.53 4 % Other U.S. Thermal 45.53 39.71 5.82 15 % 45.40 40.22 5.18 13 % Adjusted EBITDA Margin per Ton (1)(2) Seaborne Thermal $ 25.29 $ 49.71 $ (24.42) (49) % $ 24.42 $ 47.87 $ (23.45) (49) % Seaborne Metallurgical 31.82 52.35 (20.53) (39) % 32.64 59.19 (26.55) (45) % Powder River Basin 1.13 1.38 (0.25) (18) % 0.99 1.52 (0.53) (35) % Other U.S. Thermal 9.68 13.92 (4.24) (30) % 11.93 14.01 (2.08) (15) % (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; insurance recoveries; and certain other costs related to post-mining activities. Revenue The following table presents revenue by reporting segment: Three Months Ended June 30, (Decrease) Increase to Revenue Six Months Ended June 30, Decrease to Revenue 2024 2023 $ % 2024 2023 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal $ 307.5 $ 399.5 $ (92.0) (23) % $ 591.4 $ 746.0 $ (154.6) (21) % Seaborne Metallurgical 294.3 372.5 (78.2) (21) % 541.3 660.9 (119.6) (18) % Powder River Basin 221.9 259.7 (37.8) (15) % 476.0 565.0 (89.0) (16) % Other U.S. Thermal 202.0 199.9 2.1 1 % 393.6 449.3 (55.7) (12) % Corporate and Other 16.3 37.2 (20.9) (56) % 23.3 211.6 (188.3) (89) % Revenue $ 1,042.0 $ 1,268.8 $ (226.8) (18) % $ 2,025.6 $ 2,632.8 $ (607.2) (23) % Seaborne Thermal. Segment revenue decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable realized prices ($117.4 million and $217.8 million, respectively), partially offset by favorable export volumes ($25.4 million and $63.2 million, respectively). Seaborne Metallurgical. Segment revenue decreased during the three months ended June 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($56.8 million) and mix variances ($21.4 million). Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable realized prices ($181.1 million), offset by favorable volume and mix variances ($61.5 million) driven by increased production at the Shoal Creek Mine. Powder River Basin. Segment revenue decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($38.2 million and $85.7 million, respectively) resulting from decreased demand driven by low natural gas pricing and mild weather. 29 Table of Contents Other U.S. Thermal. Segment revenue increased during the three months ended June 30, 2024 compared to the same period in the prior year due to favorable realized prices ($3.2 million). Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable volumes ($69.4 million) resulting from decreased demand driven by low natural gas pricing and mild weather, partially offset by increased sales contract cancellation settlements ($13.1 million). Corporate and Other. Segment revenue decreased during the three months ended June 30, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($40.3 million) as all derivative contracts settled in 2023; offset by favorable results from trading activities ($19.0 million). Segment revenue decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to no unrealized mark-to-market gains from derivative contracts related to forecasted sales in the current year ($159.0 million); prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; and lower results from trading activities ($12.8 million). Adjusted EBITDA The following table presents Adjusted EBITDA for each of the Company’s reporting segments: Three Months Ended June 30, (Decrease) Increase to Segment Adjusted EBITDA Six Months Ended June 30, Decrease to Segment Adjusted EBITDA 2024 2023 $ % 2024 2023 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal $ 104.4 $ 197.5 $ (93.1) (47) % $ 198.2 $ 361.5 $ (163.3) (45) % Seaborne Metallurgical 143.6 102.5 41.1 40 % 191.9 193.3 (1.4) (1) % Powder River Basin 17.8 26.2 (8.4) (32) % 34.2 62.0 (27.8) (45) % Other U.S. Thermal 35.4 51.9 (16.5) (32) % 81.9 116.1 (34.2) (29) % Corporate and Other 8.5 (19.9) 28.4 143 % (36.0) 15.9 (51.9) (326) % Adjusted EBITDA (1) $ 309.7 $ 358.2 $ (48.5) (14) % $ 470.2 $ 748.8 $ (278.6) (37) % (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 and six months ended June 30, 2024 compared to the same periods in the prior year as a result of lower realized prices net of sales price sensitive costs ($106.0 million and $200.8 million, respectively), partially offset by favorable volume and mix variances ($15.4 million and $39.2 million, respectively). Seaborne Metallurgical. Segment Adjusted EBITDA increased during the three months ended June 30, 2024 compared to the same period in the prior year due to the Shoal Creek insurance recovery ($80.8 million) further discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements and favorable mix variances ($15.4 million) driven by increased production from the Shoal Creek Mine following the fire in the first quarter of 2023, despite the lock outages during 2024. These increases were offset by lower realized prices net of sales price sensitive costs ($41.3 million) and unfavorable operational costs ($24.3 million). Segment Adjusted EBITDA decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to lower realized prices net of sales price sensitive costs ($151.0 million) and unfavorable operational costs ($47.7 million). These decreases were offset by favorable volumes ($88.4 million) driven by increased production from the Shoal Creek Mine following the fire in the first quarter of 2023, despite the lock outages during 2024; and the Shoal Creek insurance recovery ($80.8 million). Powder River Basin. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($14.1 million and $44.9 million, respectively) and increased lease spend ($3.4 million and $5.4 million, respectively), offset by lower costs for materials, services, repairs and labor ($9.7 million and $22.3 million, respectively) and favorable commodity pricing ($1.4 million and $8.2 million, respectively). 30 Table of Contents Other U.S. Thermal. Segment Adjusted EBITDA decreased during the three and six months ended June 30, 2024 compared to the same periods in the prior year due to unfavorable volumes ($22.3 million and $59.7 million, respectively), offset by favorable mine sequencing ($2.4 million and $11.5 million, respectively) and increased sales contract cancellation settlements (six months, $13.1 million). 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) Increase to Adjusted EBITDA 2024 2023 $ % 2024 2023 $ % (Dollars in millions) (Dollars in millions) Middlemount (1) $ 1.9 $ 3.7 $ (1.8) (49) % $ 1.1 $ 6.0 $ (4.9) (82) % Resource management activities (2) 9.9 6.0 3.9 65 % 14.3 8.3 6.0 72 % Selling and administrative expenses (22.1) (21.7) (0.4) (2) % (44.1) (44.5) 0.4 1 % Other items, net (3) 18.8 (7.9) 26.7 338 % (7.3) 46.1 (53.4) (116) % Corporate and Other Adjusted EBITDA $ 8.5 $ (19.9) $ 28.4 143 % $ (36.0) $ 15.9 $ (51.9) (326) % (1) Middlemount’s results are before the impact of related changes in amortization of basis difference. (2) Includes gains (losses) on certain surplus coal reserve, coal resource and surface land sales and property management costs and revenue. (3) Includes trading and brokerage activities, costs associated with post-mining activities, gains (losses) on certain asset disposals, minimum charges on certain transportation-related contracts, costs associated with suspended operations including the Centurion Mine, the impact of foreign currency remeasurement and expenses related to the Company’s other commercial activities. Corporate and Other Adjusted EBITDA increased during the three months ended June 30, 2024 compared to the same period in the prior year due to favorable trading results ($14.7 million) and the favorable net impact of foreign currency rate changes ($9.4 million). Corporate and Other Adjusted EBITDA decreased during the six months ended June 30, 2024 compared to the same period in the prior year due to unfavorable trading results ($25.5 million); prior year revenue related to the Company’s assignment of rights to its excess port and rail capacity ($19.2 million) as discussed in Note 15. “Other Events” to the accompanying unaudited condensed consolidated financial statements; and the unfavorable net impact of foreign currency rate changes ($5.4 million). 31 Table of Contents Income From Continuing Operations, Net of Income Taxes The following table presents income from continuing operations, net of income taxes: Three Months Ended June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income 2024 2023 $ % 2024 2023 $ % (Dollars in millions) (Dollars in millions) Adjusted EBITDA (1) $ 309.7 $ 358.2 $ (48.5) (14) % $ 470.2 $ 748.8 $ (278.6) (37) % Depreciation, depletion and amortization (82.9) (80.6) (2.3) (3) % (162.7) (156.9) (5.8) (4) % Asset retirement obligation expenses (12.9) (15.5) 2.6 17 % (25.8) (30.9) 5.1 17 % Restructuring charges (0.1) (2.0) 1.9 95 % (0.2) (2.1) 1.9 90 % Asset impairment — — — n.m. — (2.0) 2.0 100 % Provision for NARM and Shoal Creek losses (1.9) (33.7) 31.8 94 % (3.7) (33.7) 30.0 89 % Shoal Creek insurance recovery - property damage 28.7 — 28.7 n.m. 28.7 — 28.7 n.m. Changes in amortization of basis difference related to equity affiliates 0.3 0.4 (0.1) (25) % 0.7 0.7 — — % Interest expense, net of capitalized interest (10.7) (13.3) 2.6 20 % (25.4) (31.7) 6.3 20 % Net loss on early debt extinguishment — (2.0) 2.0 100 % — (8.8) 8.8 100 % Interest income 16.8 23.1 (6.3) (27) % 36.0 36.2 (0.2) (1) % Unrealized gains on derivative contracts related to forecasted sales — 40.3 (40.3) (100) % — 159.0 (159.0) (100) % Unrealized gains (losses) on foreign currency option contracts 2.4 2.8 (0.4) (14) % (3.3) 0.6 (3.9) (650) % Take-or-pay contract-based intangible recognition 0.8 0.6 0.2 33 % 1.5 1.2 0.3 25 % Income tax provision (39.4) (74.2) 34.8 47 % (59.5) (192.2) 132.7 69 % Income from continuing operations, net of income taxes $ 210.8 $ 204.1 $ 6.7 3 % $ 256.5 $ 488.2 $ (231.7) (47) % (1) This is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section below for definitions and reconciliations to the most comparable measures under U.S. GAAP. Depreciation, Depletion and Amortization. The following table presents a summary of depreciation, depletion and amortization expense by reporting segment: Three Months Ended June 30, (Decrease) Increase to Income Six Months Ended June 30, (Decrease) Increase to Income 2024 2023 $ % 2024 2023 $ % (Dollars in millions) (Dollars in millions) Seaborne Thermal $ (28.7) $ (27.6) $ (1.1) (4) % $ (56.3) $ (51.4) $ (4.9) (10) % Seaborne Metallurgical (22.9) (22.9) — — % (44.7) (44.0) (0.7) (2) % Powder River Basin (12.8) (10.6) (2.2) (21) % (25.3) (22.3) (3.0) (13) % Other U.S. Thermal (16.6) (17.1) 0.5 3 % (30.6) (34.8) 4.2 12 % Corporate and Other (1.9) (2.4) 0.5 21 % (5.8) (4.4) (1.4) (32) % Total $ (82.9) $ (80.6) $ (2.3) (3) % $ (162.7) $ (156.9) $ (5.8) (4) % 32 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 operating segments: Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 Seaborne Thermal $ 2.08 $ 2.09 $ 2.09 $ 2.13 Seaborne Metallurgical 2.47 1.82 2.60 1.96 Powder River Basin 0.35 0.30 0.36 0.30 Other U.S. Thermal 1.69 1.33 1.62 1.26 The increases in the weighted-average depletion rate per ton for both the Seaborne Metallurgical and the Other U.S. Thermal segments during the three and six months ended June 30, 2024 compared to the same periods in the prior year reflect the impact of volume and mix variances across the segments. Provision for NARM and Shoal Creek Losses. The provision recorded during the prior year periods was for losses related to the events at the NARM and Shoal Creek Mines, as discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements. Incremental repair costs related to the tornado damage at NARM were recorded during the current year. Shoal Creek Insurance Recovery - Property Damage. During June 2024, the Company reached a settlement with its insurers and various re-insurers related to the Shoal Creek losses and recorded a $109.5 million insurance recovery, as discussed in Note 15. “Other Events” in the accompanying unaudited condensed consolidated financial statements. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery, which consisted of $28.7 million recognized during the year ended December 31, 2023. The remaining $80.8 million, applicable to incremental costs and business interruption recoveries, is included in Adjusted EBITDA for the three and six months ended June 30, 2024. Interest Expense, Net of Capitalized Interest. The decrease in expense during the three and six months ended June 30, 2024 compared to the same periods in the prior year was driven by lower interest and fees for financial assurance instruments and the capitalization of interest related to the redevelopment of the Centurion Mine. Net Loss on Early Debt Extinguishment. The loss recognized during the prior year was primarily related to the Company’s terminated letter of credit facility as further discussed in Note 12. “Financial Instruments and Other Guarantees” to the accompanying unaudited condensed consolidated financial statements. Interest Income. The decrease in interest income during the three months ended June 30, 2024 was primarily due to lower average cash balances, including restricted cash balances on which the Company earns interest, in the current year. Unrealized Gains on Derivative Contracts Related to Forecasted Sales. The prior year unrealized gains primarily relate to mark-to-market activity on derivative contracts related to forecasted coal sales. As further described in Note 6. "Derivatives and Fair Value Measurements" to the Annual Report on Form 10-K for the year ended December 31, 2023, all derivative contracts related to forecasted coal sales settled in 2023. Income Tax Provision. The decrease in the income tax provision during the three and six months ended June 30, 2024 compared to the same periods in the prior year was primarily due to lower pretax income. Refer to Note 8. “Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional information. 33 Table of Contents Net Income Attributable to Common Stockholders The following table presents net income attributable to common stockholders: Three Months Ended June 30, Increase (Decrease) to Income Six Months Ended June 30, (Decrease) Increase to Income 2024 2023 $ % 2024 2023 $ % (Dollars in millions) (Dollars in millions) Income from continuing operations, net of income taxes $ 210.8 $ 204.1 $ 6.7 3 % $ 256.5 $ 488.2 $ (231.7) (47) % Loss from discontinued operations, net of income taxes (1.6) (1.3) (0.3) (23) % (2.3) (2.6) 0.3 12 % Net income 209.2 202.8 6.4 3 % 254.2 485.6 (231.4) (48) % Less: Net income attributable to noncontrolling interests 9.8 23.6 (13.8) (58) % 15.2 37.9 (22.7) (60) % Net income attributable to common stockholders $ 199.4 $ 179.2 $ 20.2 11 % $ 239.0 $ 447.7 $ (208.7) (47) % Net Income Attributable to Noncontrolling Interests. The decrease in the results attributable to noncontrolling interests during the three and six months ended June 30, 2024 compared to the same periods in the prior year was primarily due to a decline in the financial results of Peabody’s majority-owned Wambo operations in which there is an outside non-controlling interest. Diluted Earnings per Share (EPS) The following table presents diluted EPS: Three Months Ended June 30, Increase to EPS Six Months Ended June 30, Decrease to EPS 2024 2023 $ % 2024 2023 $ % Diluted EPS attributable to common stockholders: Income from continuing operations $ 1.43 $ 1.16 $ 0.27 23 % $ 1.72 $ 2.85 $ (1.13) (40) % Loss from discontinued operations (0.01) (0.01) — — % (0.02) (0.02) — — % Net income attributable to common stockholders $ 1.42 $ 1.15 $ 0.27 23 % $ 1.70 $ 2.83 $ (1.13) (40) % 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 142.8 million and 159.0 million for the three months ended June 30, 2024 and 2023, respectively, and 143.8 million and 160.2 million for the six months ended June 30, 2024 and 2023, respectively. 34 Table of Contents Reconciliation of Non-GAAP Financial Measures Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of its segment’s operating performance, as displayed in the reconciliations below. Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (Dollars in millions) Income from continuing operations, net of income taxes $ 210.8 $ 204.1 $ 256.5 $ 488.2 Depreciation, depletion and amortization 82.9 80.6 162.7 156.9 Asset retirement obligation expenses 12.9 15.5 25.8 30.9 Restructuring charges 0.1 2.0 0.2 2.1 Asset impairment — — — 2.0 Provision for NARM and Shoal Creek losses 1.9 33.7 3.7 33.7 Shoal Creek insurance recovery - property damage (28.7) — (28.7) — Changes in amortization of basis difference related to equity affiliates (0.3) (0.4) (0.7) (0.7) Interest expense, net of capitalized interest 10.7 13.3 25.4 31.7 Net loss on early debt extinguishment — 2.0 — 8.8 Interest income (16.8) (23.1) (36.0) (36.2) Unrealized gains on derivative contracts related to forecasted sales — (40.3) — (159.0) Unrealized (gains) losses on foreign currency option contracts (2.4) (2.8) 3.3 (0.6) Take-or-pay contract-based intangible recognition (0.8) (0.6) (1.5) (1.2) Income tax provision 39.4 74.2 59.5 192.2 Total Adjusted EBITDA $ 309.7 $ 358.2 $ 470.2 $ 748.8 Total Reporting Segment Costs is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of its segments’ operating performance, as displayed in the reconciliations below. Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (Dollars in millions) Operating costs and expenses $ 803.9 $ 862.0 $ 1,618.1 $ 1,708.6 Unrealized gains (losses) on foreign currency option contracts 2.4 2.8 (3.3) 0.6 Take-or-pay contract-based intangible recognition 0.8 0.6 1.5 1.2 Net periodic benefit credit, excluding service cost (10.2) (9.7) (20.3) (19.4) Total Reporting Segment Costs $ 796.9 $ 855.7 $ 1,596.0 $ 1,691.0 35 Table of Contents The following table presents Total Reporting Segment Costs by reporting segment: Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 (Dollars in millions) Seaborne Thermal $ 203.1 $ 202.0 $ 393.2 $ 384.5 Seaborne Metallurgical 231.5 270.0 430.2 467.6 Powder River Basin 204.1 233.5 441.8 503.0 Other U.S. Thermal 166.6 148.0 311.7 333.2 Corporate and Other (8.4) 2.2 19.1 2.7 Total Reporting Segment Costs $ 796.9 $ 855.7 $ 1,596.0 $ 1,691.0 Revenue per Ton and Adjusted EBITDA Margin per Ton are equal to revenue by segment and Adjusted EBITDA by segment (excluding insurance recoveries), respectively, divided by segment tons sold. Costs per Ton is equal to Revenue per Ton less Adjusted EBITDA Margin per Ton. The following tables present tons sold, revenue, Total Reporting Segment Costs and Adjusted EBITDA by operating segment: Three Months Ended June 30, 2024 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 4.1 2.0 15.8 3.7 Revenue $ 307.5 $ 294.3 $ 221.9 $ 202.0 Total Reporting Segment Costs 203.1 231.5 204.1 166.6 Adjusted EBITDA, excluding Shoal Creek insurance recovery $ 104.4 $ 62.8 $ 17.8 $ 35.4 Shoal Creek insurance recovery - business interruption — 80.8 — — Adjusted EBITDA $ 104.4 $ 143.6 $ 17.8 $ 35.4 Revenue per Ton $ 74.43 $ 149.29 $ 14.02 $ 55.21 Costs per Ton 49.14 117.47 12.89 45.53 Adjusted EBITDA Margin per Ton $ 25.29 $ 31.82 $ 1.13 $ 9.68 Three Months Ended June 30, 2023 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 4.0 2.0 18.9 3.8 Revenue $ 399.5 $ 372.5 $ 259.7 $ 199.9 Total Reporting Segment Costs 202.0 270.0 233.5 148.0 Adjusted EBITDA $ 197.5 $ 102.5 $ 26.2 $ 51.9 Revenue per Ton $ 100.59 $ 190.13 $ 13.71 $ 53.63 Costs per Ton 50.88 137.78 12.33 39.71 Adjusted EBITDA Margin per Ton $ 49.71 $ 52.35 $ 1.38 $ 13.92 36 Table of Contents Six Months Ended June 30, 2024 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 8.1 3.4 34.5 6.9 Revenue $ 591.4 $ 541.3 $ 476.0 $ 393.6 Total Reporting Segment Costs 393.2 430.2 441.8 311.7 Adjusted EBITDA, excluding Shoal Creek insurance recovery $ 198.2 $ 111.1 $ 34.2 $ 81.9 Shoal Creek insurance recovery - business interruption — 80.8 — — Adjusted EBITDA $ 198.2 $ 191.9 $ 34.2 $ 81.9 Revenue per Ton $ 72.86 $ 159.10 $ 13.80 $ 57.33 Costs per Ton 48.44 126.46 12.81 45.40 Adjusted EBITDA Margin per Ton $ 24.42 $ 32.64 $ 0.99 $ 11.93 Six Months Ended June 30, 2023 Seaborne Thermal Seaborne Metallurgical Powder River Basin Other U.S. Thermal (Amounts in millions, except per ton data) Tons sold 7.6 3.3 40.9 8.3 Revenue $ 746.0 $ 660.9 $ 565.0 $ 449.3 Total Reporting Segment Costs 384.5 467.6 503.0 333.2 Adjusted EBITDA $ 361.5 $ 193.3 $ 62.0 $ 116.1 Revenue per Ton $ 98.81 $ 202.33 $ 13.80 $ 54.23 Costs per Ton 50.94 143.14 12.28 40.22 Adjusted EBITDA Margin per Ton $ 47.87 $ 59.19 $ 1.52 $ 14.01 Available Free Cash Flow is defined as operating cash flow less investing cash flow and distributions to noncontrolling interests; plus/minus changes to restricted cash and collateral and other anticipated expenditures. See the table below for a reconciliation of Available Free Cash Flow to its most comparable measure under U.S. GAAP. Six Months Ended June 30, 2024 (Dollars in millions) Net cash provided by operating activities $ 126.8 - Net cash used in investing activities (316.8) - Distributions to noncontrolling interests (18.5) +/- Changes to restricted cash and collateral (17.1) - Anticipated expenditures or other requirements — Available Free Cash Flow $ (225.6) Regulatory Update Other than as described in the following section, there were no significant changes to the Company’s regulatory or global climate matters subsequent to December 31, 2023. This section should be considered in connection with the Company’s regulatory and global climate matters as outlined in Part I, Item 1. “Business” in its Annual Report on Form 10-K for the year ended December 31, 2023. 37 Table of Contents Regulatory Matters - U.S. National Ambient Air Quality Standards (NAAQS) . The Clean Air Act (CAA) requires the U.S. Environmental Protection Agency (EPA) to review national ambient air quality standards every five years to determine whether revisions to current standards are appropriate. On March 6, 2024, the EPA revised the level of the primary standard for fine particulate matter (PM 2.5), lowering the annual standard from 12.0 ug /m 3 to 9.0 ug /m 3 . States are now required to take several actions to implement the standards which could require fossil fuel electric generating units (EGUs) and non-EGUs to install additional emission control technologies or operate in a different manner. Such actions could potentially increase the cost of utilizing fossil fuels for electric generation and industrial uses. The EPA is also in the process of reviewing the current ozone NAAQS. The level of the ozone NAAQS can also affect requirements to install new or improved emission control technologies at fossil fuel-fired EGUs and non-EGU industrial sources. Final New Source Performance Standards (NSPS) for Fossil Fuel-Fired EGUs . The EPA promulgated a final rule to limit carbon dioxide (CO 2 ) from new, modified and reconstructed fossil fuel-fired EGUs under Section 111(b) of the CAA on August 3, 2015, and published it in the Federal Register on October 23, 2015. The rule requires that newly-constructed fossil fuel-fired steam generating units achieve an emission standard for CO 2 (known as the Best System of Emission Reduction (BSER)) which is based on the performance of a supercritical pulverized coal boiler implementing partial carbon capture, utilization and storage (CCUS). Modified and reconstructed fossil fuel-fired steam generating units must implement the most efficient generation achievable through a combination of best operating practices and equipment upgrades, to meet an emission standard consistent with best historical performance. Reconstructed EGUs must implement the most efficient generating technology based on the size of the unit. Numerous legal challenges to the final rule were filed in the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit). Sixteen separate petitions for review were filed, and the challengers include 25 states, utilities, mining companies (including Peabody), labor unions, trade organizations and other groups. The cases were consolidated under the case filed by North Dakota (D.C. Cir. No. 15-1381). Four additional cases were filed seeking review of the EPA’s denial of reconsideration petitions in a final action published in the May 6, 2016 Federal Register entitled “Reconsideration of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Generating Units; Notice of final action denying petitions for reconsideration.” Pursuant to an order of the court, these cases remain in abeyance, subject to requirements for the EPA to file 90-day status reports. On December 20, 2018, the EPA proposed to revise the 2015 NSPS to modify the minimum requirements for newly constructed coal-fired units from partial CCUS to efficiency-based standards. (83 Fed. Reg. 65,424 (Dec. 20, 2018)). In contrast to the 2015 rule, the proposed rule defined BSER as the most efficient demonstrated steam cycle in combination with the best operating practices. The EPA indicated that the primary reason for revising BSER was the high cost and limited geographic availability of CCUS technology. On May 23, 2023, however, the EPA published a notice of proposed rulemaking addressing NSPS from new, modified and reconstructed fossil-fuel steam EGUs. In contrast to the 2018 proposed rule, the 2023 proposed rule did not propose to amend the 2015 NSPS for coal-fired EGUs. Status reports filed with the D.C. Circuit in North Dakota v. EPA indicate that litigation on the 2015 rule should remain in abeyance pending the EPA’s action on the 2018 proposed rule and the 2023 proposed rule. As indicated in the following section, on May 9, 2024, the EPA published the final rule in the Federal Register based on the 2023 proposed rule. This final rule did not amend the 2015 NSPS for coal-fired EGUs, but indicated that the EPA will continue to consider whether or not to make revisions to that rule in the future. EPA Regulation of Greenhouse Gas Emissions from New and Existing Fossil Fuel-Fired EGUs . On May 9, 2024, the EPA published a final rule for new, modified and reconstructed fossil fuel-fired EGUs in the Federal Register. The final rule consists of four elements: (1) revised NSPS for controlling CO 2 emissions from new and reconstructed stationary combustion turbines; (2) revised NSPS for fossil fuel-fired steam EGUs that undertake a large modification; (3) emission guidelines for existing fossil fuel-fired steam EGUs; and (4) repeal of the Affordable Clean Energy rule promulgated in 2019. 38 Table of Contents With respect to existing fossil fuel-fired steam EGUs (primarily coal-fired) the EPA determined that the BSER that is adequately demonstrated is carbon capture and sequestration (CCS) with 90% capture of CO 2 emissions. Pursuant to the final rule, existing fossil fuel-fired steam EGUs that intend to operate in the long-term will be required to comply with a CO 2 emission rate based on CCS with 90% capture by January 1, 2032. Existing fossil fuel-fired steam EGUs that will permanently cease operations by January 1, 2039 are not subject to emission standards based on 90% CO 2 capture, but will need to meet an emission rate based on co-firing with 40% natural gas by January 1, 2030. (This translates into a 16% reduction in CO 2 emissions determined from a unit-specific baseline). Existing fossil fuel-fired steam EGUs that permanently cease operations by January 1, 2032 are exempt from these requirements. All requirements related to existing affected units in the final rule – whether fired by coal or natural gas – will be imposed through state plans that are permitted to take into account the remaining useful life of a generating unit when determining appropriate controls. Under the final rule, such plans must provide for the implementation and enforcement of the NSPS, but states may apply less stringent standards of performance in certain conditions, as specified in EPA regulations. States are also permitted to impose more stringent standards. In addition, the final rule includes several “reliability” mechanisms to allow states to provide alternative emission limitations or compliance date extensions in order to maintain adequate electric generation resources and grid reliability. Finally, as part of the final rule, any newly constructed stationary combustion turbine (SCT), where construction or reconstruction of the unit was commenced after May 23, 2023, will be subject to CO 2 emission limits based on whether it is considered to be a low load, intermediate load or base load EGU. In addition, for affected base load SCTs, a second phase emission standard applies based on 90% CCS as of January 1, 2032. Any new fossil-fuel steam EGU (where construction or reconstruction was commenced after June 18, 2014) will need to comply with standards promulgated in 2015. The final rule is 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, as implemented by the EPA and states, it could have a substantial impact on the use of coal and natural gas for the generation of electricity. 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 establish more stringent standards for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate and legacy wastewater discharged from certain surface impoundments. The final revised effluent limitations guidelines would significantly increase costs for many coal-fueled steam electric power plants. In addition, the recently finalized final rule allows EGUs that commit to ceasing coal combustion by December 31, 2034, to comply with less stringent wastewater discharge requirements during the interim. The final rule is subject to numerous legal challenges that have been consolidated in the 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. Rules for Disposal of Coal Combustion Residuals (CCR) from Electric Utilities; Federal CCR Permit Program and Revisions to Closure Requirements. On February 20, 2020, as required by the Water Infrastructure Improvements for the Nation Act, the EPA proposed a federal permitting program for the disposal of CCR in surface impoundments and landfills. Under the proposal, the EPA would directly implement the permit program in Indian Country and at CCR units located in states that have not submitted their own CCR permit program for approval. The proposal includes requirements for federal CCR permit applications, content and modification, as well as procedural requirements. The comment period for the EPA’s proposal ended on April 20, 2020. Although the EPA had planned to finalize this rule in 2021, the EPA now expects to issue a final rule around October 2024. 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 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. Finally, the EPA is still considering whether to finalize additional revisions to the 2015 CCR Rule related to closure of CCR units. Cross State Air Pollution Rule (CSAPR) and CSAPR Update Rule . The CSAPR and related updates require numerous U.S. states and the District of Columbia to reduce power plant emissions that cross state lines and significantly contribute to ozone and/or fine PM pollution in other states. 39 Table of Contents On March 15, 2023, the EPA issued a final rule to address regional ozone transport by imposing new federal ozone season emission budgets for nitrogen oxide (NO x ) in 23 states, including California, Nevada, Oklahoma and Texas, as well as some Indian reservations. The rule includes state emission budgets for NO x affecting fossil fuel-fired power plants and a “backstop daily emissions rate” for large coal-fired power plants if they exceed specified limits. The rule also sets first-time limits on certain industrial sources that will apply starting with the 2026 ozone season in 20 states. The EPA estimates that annual compliance costs (for 2023 through 2042) will be $770 million to $910 million. These emission limitations would apply in addition to requirements contained in state implementation plans to control ozone precursors in affected states, although states have the option to replace these limits with equally strict or more stringent limitations. When implemented, this rule could influence the closure of some coal generating units that have not installed selective catalytic reduction technologies. Implementation of the rule for existing sources (accomplished through state implementation plans) was challenged in several U.S. Courts of Appeal, resulting in different court opinions and in requirements being implemented in some states, but stayed in others. On June 27, 2024, the U.S. Supreme Court issued a stay of the rule in 11 states pending the disposition of a petition for review of the rule in the D.C. Circuit and any subsequent timely petition for certiorari filed with and granted by the U.S. Supreme Court. Regional Haze. The CAA contains a national visibility goal for the “prevention of any future, and the remedying of any existing, impairment of visibility in Class I areas which impairment results from man-made air pollution.” The EPA promulgated comprehensive regulations in 1999 requiring all states to submit plans to address regional haze that could affect 156 national parks and wilderness areas, including requirements for certain sources to install the best available retrofit technology and for states to demonstrate “reasonable progress” towards meeting the national visibility goal. States are required to revise plans every 10 years. On March 29, 2024, the EPA published a proposed consent decree under which deadlines would be established for the EPA to take final action to approve, disapprove or conditionally approve, in whole or in part, state regional haze implementation plans for 34 states (at various dates from June 28, 2024 to December 31, 2026). The EPA subsequently filed a motion to approve the consent judgement in the U.S. District Court for the District of Columbia which remains pending. Federal Coal Leasing Moratorium . The Executive Order on Promoting Energy Independence and Economic Growth (EI Order), signed on March 28, 2017, lifted the Department of Interior’s federal coal leasing moratorium and rescinded guidance on the inclusion of social cost of carbon in federal rulemaking. Following the EI Order, the Interior Secretary issued Order 3349 ending the federal coal leasing moratorium. Environmental groups took the issue to court (District of Montana) and in April 2019, the court held the lifting of the moratorium triggered National Environmental Policy Act (NEPA) review. On May 22, 2020, the court held that the Department of Interior’s issuance of an Environmental Assessment and Finding of No Significant Impact (FONSI) remedied the prior NEPA violations. Thereafter, environmental groups amended their complaint to challenge the Environmental Assessment and FONSI. On August 12, 2022, the court invalidated the Environmental Assessment and FONSI and reinstated the moratorium until completion of a sufficient NEPA analysis. On appeal, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) reversed the district court on February 21, 2024, explaining that the lawsuit was mooted by the Department of Interior’s April 2021 order revoking Order 3349. The Ninth Circuit directed the district court to dismiss the case as moot. Endangered Species Act (ESA) . The ESA of 1973 and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. Changes in listings or requirements under these regulations could have a material adverse effect on Peabody’s costs or its ability to mine some of its properties in accordance with its current mining plans. During the Trump Administration, the Departments of Interior and Commerce finalized five rules aiming to streamline and update the ESA. But in June 2021, the agencies announced their plan to revise, rescind or reinstate the rules that were finalized (or withdrawn) during the Trump Administration that conflict with the Biden Administration’s objectives. The agencies issued proposed rules on June 22, 2023, and they published three final revised rules on April 5, 2024. SEC Climate-Related Disclosures . On March 6, 2024, the SEC adopted final rules it expects will enhance and standardize climate-related disclosures by public companies and in public offerings. Specifically, the final rules will require disclosure of, among other things, climate-related risks that have had or are reasonably likely to have a material impact on a public company’s business strategy, results of operations or financial condition; certain greenhouse gas (GHG) emissions associated with a public company along with, in many cases, an attestation report by a GHG emissions attestation provider; and certain climate-related financial metrics to be included in a company’s audited financial statements. The final rules were challenged by multiple parties, and the cases were consolidated into a judicial review by the Eighth Circuit. On April 4, 2024, the SEC voluntarily stayed implementation of the final rules pending such judicial review. The Company is assessing the potential impact of the final rules. 40 Table of Contents Regulatory Matters - Australia National Greenhouse and Energy Reporting Act 2007 (NGER Act). The NGER Act imposes requirements for corporations meeting a certain threshold to register and report greenhouse gas emissions and abatement actions, as well as energy production and consumption as part of a single, national reporting system. The Clean Energy Regulator administers the NGER Act. The federal Department of Environment and Energy is responsible for NGER Act-related policy developments and review. In May 2023, the Australian Parliament passed reforms to the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015. The reforms commenced on July 1, 2023 and introduced site specific baseline emissions for heavy emitting facilities as benchmarks for year-on-year improvement (proposed to be 4.9% each year to 2030) before transitioning to industry average emissions benchmarks by 2030. Proponents will earn tradeable credits (Safeguard Mechanism Credits) when emissions are below their baselines or can purchase credits to offset emissions. Access to existing Australian Carbon Credit Units will continue unchanged albeit with a price ceiling of $75 Australian dollars per tonne of CO 2 in 2023-24, increasing with the Consumer Price Index plus 2% each year. In June 2024 amendments to the NGER Act came into effect requiring open-cut mines covered by the Safeguard Mechanism that currently report fugitive methane emissions using a basic method with minimal data inputs (Method 1) to transition over a two-year period to a more complex method requiring site-level sampling and analysis (Methods 2 or 3). This change in reporting methods is expected to increase the Safeguard Mechanism liability position of open-cut mining operations in Queensland. The impacts of this change are currently being assessed. New South Wales (NSW) Environmental . Under the NSW Environmental Planning and Assessment Act 1979 (EPA Act), environmental planning instruments must be considered when approving a mining project development application. Decision makers review the significance of a resource and the state and regional economic benefits of a proposed coal mine when considering a development application on the basis that it is an element of the “public interest” consideration contained in the relevant legislation. Effective from March 1, 2018, the EPA Act was amended to introduce a number of changes to planning laws in New South Wales. The EPA Act was further amended in June 2018 to revoke a process for modifying development approvals under the former Section 75W of the EPA Act. As a result, new development approvals will need to be obtained unless the proposed project will be substantially the same development as it was when the development approval was last modified under Section 75W, in which case the existing development approval can be modified. If a new development approval is required then this could take additional time to achieve. On April 3, 2024, the Environment Protection Legislation Amendment (Stronger Regulation and Penalties) Bill 2024 was assented to by the Parliament of New South Wales. The bill increases the NSW Environment Protection Agency’s (NSW EPA) powers across a range of environmental legislation including increasing the NSW EPA’s maximum penalties for serious environmental offenses; increasing the NSW EPA’s on-the-spot maximum fines; providing the NSW EPA the power to issue what will be known as ‘Preliminary Investigation Notices’ which permit the NSW EPA to force a person to help the NSW EPA compile a criminal case against the person or against another person; extending the monetary benefits order so that it can apply to any ‘related entity’ as defined in the Corporations Act 2001; providing the NSW EPA the power to issue what will be known as ‘Recall Notices’ which order responsible entities to recall contaminated substances suspected of causing harm to the community and environment; and providing the NSW EPA the power to issue what will be known as ‘name and shame’ public warnings to call out poor and repeat environmental performers for the protection of communities. The reform also creates a new power in Australia for the NSW Land and Environment Court that empowers the court to ban offenders, upon the NSW EPA’s application, with a poor compliance history from seeking and obtaining environmental protection licenses. On August 25, 2017, the Biodiversity Conservation Act 2016 (BC Act) commenced in NSW and imposes a revised framework for the assessment of potential impacts on biodiversity that may be caused by a development, such as a proposed mining project. The BC Act requires these potential impacts on biodiversity to be offset in perpetuity, by one or more of the following means: securing land based offsets and retiring biodiversity credits, making a payment into a biodiversity conservation fund or in some cases through mine site ecological rehabilitation. The data collected from the biodiversity impact assessment process is inputted into a new offsets payment calculator in order to determine the amount payable by the proponent to offset the impacts. The proposed development can only proceed once the biodiversity offset obligations have been satisfied. On July 18, 2024, following an independent review of the BC Act, the NSW government announced it would amend the BC Act to reform the biodiversity offsets scheme by introducing a new statutory standard requiring mining proponents to demonstrate how they have genuinely avoided and minimized impacts to biodiversity and removing the option for major mining proponents to meet a credit obligation through a commitment to ecological mine site rehabilitation . When enacted, these and other proposed changes have the potential to affect approval processes for future NSW mining projects. 41 Table of Contents New South Wales Coal Directions . The State of New South Wales enacted the Energy and Utilities Administration Amendment Act 2022 granting the State Premier and Minister for Energy the ability to issue directions in the event of a coal market price emergency (among other powers). On December 22, 2022, the State Premier declared such an emergency, intended to control coal and electricity pricing. Subsequently, directions were issued to Peabody Energy Australia Pty Ltd and other coal producers with operations in NSW, which were amended at various dates. The most recent directions required Peabody Energy Australia Pty Ltd to reserve a portion of coal produced by Wambo Coal Pty Ltd and Wilpinjong Coal Pty Ltd for sale to NSW power generators at a capped price until June 30, 2024 and imposed additional reporting obligations to demonstrate compliance. The Australian Energy Regulator has confirmed that the directions have ended, and the last report was submitted on July 12, 2024. Risks Related to Global Climate Change There have been no significant changes to the Company’s global climate matters subsequent to December 31, 2023. Refer to Part I, Item 1. “Business” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 for information regarding the Company’s global climate matters. Liquidity and Capital Resources Overview The Company’s primary source of cash is proceeds from the sale of its coal production to customers. The Company has also generated cash from the sale of non-strategic assets, including coal reserves, coal resources and surface lands, and, from time to time, borrowings under its credit facilities and the issuance of securities. The Company’s primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs, finance and operating lease payments, postretirement plans, take-or-pay obligations, post-mining reclamation obligations, collateral and margining requirements, dividends, share repurchases and selling and administrative expenses. The Company has also used cash for early debt retirements. Any future determinations to return capital to stockholders, such as dividends or share repurchases, will depend on a variety of factors, including the Company’s net income or other sources of cash, liquidity position and potential alternative uses of cash, such as internal development projects or acquisitions, as well as economic conditions and expected future financial results. The Company’s ability to early retire debt, declare dividends or repurchase shares in the future will depend on its future financial performance, which in turn depends on the successful implementation of its strategy and on financial, competitive, regulatory, technical and other factors, general economic conditions, demand for and selling prices of coal and other factors specific to its industry, many of which are beyond the Company’s control. Liquidity As of June 30, 2024, the Company’s cash and cash equivalents balances totaled $621.7 million, including approximately $388 million held by U.S. subsidiaries, approximately $217 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 six months ended June 30, 2024, 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 $1,059.7 million as of December 31, 2023 to $940.8 million as of June 30, 2024. Available liquidity was comprised of the following: June 30, 2024 December 31, 2023 (Dollars in millions) Cash and cash equivalents $ 621.7 $ 969.3 Revolving credit facility availability 222.0 — Accounts receivable securitization program availability 97.1 90.4 Total liquidity $ 940.8 $ 1,059.7 42 Table of Contents Capital Returns to Shareholders The Company repurchased approximately 3.2 million shares of its common stock for $80.5 million, including commission fees, and paid dividends of $19.1 million during the six months ended June 30, 2024. Surety Agreement Amendment and Collateral Requirements In April 2023, the Company amended its existing agreement with the providers of its surety bond portfolio, dated November 6, 2020. Under the April 2023 amendment, the Company and its surety providers agreed to a maximum aggregate collateral amount of $721.8 million based upon bonding levels at the effective date of the amendment. This maximum collateral amount will vary prospectively as bonding levels increase or decrease. The amendment extended the agreement through December 31, 2026. In order to maintain the maximum collateral agreement, the Company must remain compliant with a minimum liquidity test and a maximum net leverage ratio, as measured each quarter. The minimum liquidity test requires the Company to maintain liquidity at the greater of $400 million or the difference between the penal sum of all surety bonds and the amount of collateral posted in favor of surety providers, which was $508.6 million at June 30, 2024. The Company must also maintain a maximum net leverage ratio of 1.5 to 1.0, where the numerator consists of its funded debt, net of cash, and the denominator consists of its Adjusted EBITDA for the trailing twelve months. For purposes of calculating the ratio, only 50% of the outstanding principal amount of the Company’s 3.250% Convertible Senior Notes due March 2028 (the 2028 Convertible Notes) is deemed to be funded debt. The Company’s ability to pay dividends and make share repurchases is also subject to the quarterly minimum liquidity test. The Company is in compliance with such requirements at June 30, 2024. To fund the maximum collateral amount, the Company deposited $566.3 million into trust accounts for the benefit of certain surety providers on March 31, 2023. The remainder was comprised of $140.5 million of existing cash-collateralized letters of credit and $15.0 million already held on behalf of a surety provider. The amendment became effective on April 14, 2023, when the Company terminated a then-existing credit agreement. Credit Support Facilities In February 2022, the Company entered into an agreement which provides up to $250.0 million of capacity for irrevocable standby letters of credit, primarily to support reclamation bonding requirements. The agreement requires the Company to provide cash collateral at a level of 103% of the aggregate amount of letters of credit outstanding under the arrangement (limited to $5.0 million total excess collateralization). Outstanding letters of credit bear a fixed fee in the amount of 0.75% per annum. The Company receives a variable deposit rate on the amount of cash collateral posted in support of letters of credit. The agreement has an initial expiration date of December 31, 2025. At June 30, 2024, letters of credit of $116.6 million were outstanding under the agreement, which were collateralized by cash of $120.1 million. In December 2023, the Company established cash-backed bank guarantee facilities, primarily to support Australian reclamation bonding requirements. The Company receives a variable deposit rate on the amount of cash collateral posted in support of the bank guarantee facilities, which mature at various dates between 2026 and 2029. At June 30, 2024, the bank guarantee facilities were backed by cash of $179.5 million. Revolving Credit Facility The Company established a new revolving credit facility with a maximum aggregate principal amount of $320.0 million in revolving commitments by entering into a credit agreement, dated as of January 18, 2024 (the 2024 Credit Agreement), by and among the Company, as borrower, certain subsidiaries of the Company party thereto, PNC Bank, National Association, as administrative agent, and the lenders party thereto. The revolving commitments and any related loans, if applicable (any such loans, the Revolving Loans), established by the 2024 Credit Agreement terminate or mature, as applicable, on January 18, 2028, subject to certain conditions relating to the Company’s outstanding 2028 Convertible Notes. The Revolving Loans bear interest at a secured overnight financing rate (SOFR) plus an applicable margin ranging from 3.50% to 4.25%, depending on the Company’s total net leverage ratio (as defined under the 2024 Credit Agreement) or a base rate plus an applicable margin ranging from 2.50% to 3.25%, at the Company’s option. Letters of credit issued under the 2024 Credit Agreement incur a combined fee equal to an applicable margin ranging from 3.50% to 4.25% plus a fronting fee equal to 0.125% per annum. Unused capacity under the 2024 Credit Agreement bears a commitment fee of 0.50% per annum. As of June 30, 2024, the 2024 Credit Agreement had only been utilized for letters of credit, including $98.0 million outstanding as of June 30, 2024. These letters of credit support the Company’s reclamation bonding requirements, lease obligations, insurance policies and various other performance guarantees as further described in Note 12. “Financial Instruments and Other Guarantees.” Availability under the 2024 Credit Agreement was $222.0 million at June 30, 2024. 43 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 June 30, 2024 and December 31, 2023 is presented in the table below. Debt Instrument (defined below, as applicable) June 30, 2024 December 31, 2023 (Dollars in millions) 3.250% Convertible Senior Notes due March 2028 (2028 Convertible Notes) $ 320.0 $ 320.0 Finance lease obligations 24.5 22.3 Less: Debt issuance costs (7.2) (8.1) 337.3 334.2 Less: Current portion of long-term debt 14.1 13.5 Long-term debt $ 323.2 $ 320.7 The Company’s indebtedness requires estimated contractual principal and interest payments, assuming interest rates in effect at June 30, 2024, of approximately $16 million in 2024, $18 million in 2025, $16 million in 2026, $13 million in 2027 and $326 million in 2028. Cash payments for interest related to the Company’s indebtedness and financial assurance instruments amounted to $24.1 million and $41.9 million during the six months ended June 30, 2024 and 2023, respectively. 2028 Convertible Notes On March 1, 2022, through a private offering, the Company issued the 2028 Convertible Notes in the aggregate principal amount of $320.0 million. The 2028 Convertible Notes are senior unsecured obligations of the Company and are governed under an indenture. The Company used the proceeds of the offering of the 2028 Convertible Notes and available cash to redeem its then-existing senior secured notes, and to pay related premiums, fees and expenses relating to the offering and redemptions. The 2028 Convertible Notes will mature on March 1, 2028, unless earlier converted, redeemed or repurchased in accordance with their terms. The 2028 Convertible Notes bear interest at a rate of 3.250% per year payable semi-annually in arrears on March 1 and September 1 of each year. During the first and second quarters of 2024, the Company’s reported common stock prices did not prompt the conversion feature of the 2028 Convertible Notes. As a result, the 2028 Convertible Notes were not convertible at the option of the holders during the second quarter of 2024, and will not be similarly convertible during the third quarter of 2024. Accounts Receivable Securitization Program As described in Note 12. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements, the Company entered into an accounts receivable securitization program during 2017. The securitization program was amended in February 2023 to increase the available funding capacity from $175.0 million to $225.0 million and adjust the relevant interest rate for borrowings to a SOFR plus an applicable margin. Funding capacity is limited to the availability of eligible receivables and is accounted for as a secured borrowing. Funding capacity under the program may also be utilized for letters of credit in support of other obligations, which has been the Company’s primary utilization. At June 30, 2024, the Company had no outstanding borrowings and $56.2 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, 2024. 44 Table of Contents Covenant Compliance The Company was compliant with all relevant covenants under its debt and other finance agreements at June 30, 2024. Cash Flows The following table summarizes the Company’s cash flows for the six months ended June 30, 2024 and 2023, as reported in the accompanying unaudited condensed consolidated financial statements. Available Free Cash Flow is a financial measure not recognized in accordance with U.S. GAAP. Refer to the “Reconciliation of Non-GAAP Financial Measures” section above for definitions and reconciliations to the most comparable measures under U.S. GAAP. Six Months Ended June 30, 2024 2023 (Dollars in millions) Net cash provided by operating activities $ 126.8 $ 739.7 Net cash used in investing activities (316.8) (120.0) Net cash used in financing activities (140.5) (225.4) Net change in cash, cash equivalents and restricted cash (330.5) 394.3 Cash, cash equivalents and restricted cash at beginning of period 1,650.2 1,417.6 Cash, cash equivalents and restricted cash at end of period $ 1,319.7 $ 1,811.9 Available Free Cash Flow $ (225.6) Operating Activities. The decrease in net cash provided by operating activities for the six months ended June 30, 2024 compared to the same period in the prior year was driven by a year-over-year decrease in operating cash flow from working capital ($461.9 million), primarily attributable to income tax payments and accruals ($191.3 million), an increase in accounts receivable due to timing of sales and overall higher price per ton ($176.6 million) and Shoal Creek inventories build due to the Demopolis Lock outage that continued through May 2024 ($55.0 million); the prior year receipt of cash related to variation margin requirements associated with derivative financial instruments ($198.0 million); and lower cash generated from mining operations. These unfavorable variances were partially offset by a decrease in cash used for collateral requirements ($266.5 million). Investing Activities. The increase in net cash used in investing activities for the six months ended June 30, 2024 compared to the same period in the prior year was driven by the acquisition of Wards Well ($143.8 million) and higher capital expenditures and payments of capital accruals ($53.0 million). Financing Activities. The decrease in net cash used by financing activities for the six months ended June 30, 2024 compared to the same period in the prior year was primarily driven by a decrease in common stock repurchases ($89.9 million), partially offset by an increase in dividends paid ($8.3 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. 45 Table of Contents The following table summarizes the Company’s financial instruments that carry off-balance-sheet risk. June 30, 2024 Reclamation Support Other Support (1) Total (Dollars in millions) Surety bonds $ 934.0 $ 108.1 $ 1,042.1 Letters of credit (2) 52.5 101.7 154.2 986.5 209.8 1,196.3 Less: Letters of credit in support of surety bonds (3) (52.5) (14.5) (67.0) Obligations supported, net $ 934.0 $ 195.3 $ 1,129.3 (1) Instruments support obligations related to pension and health care plans, workers’ compensation, property and casualty insurance, customer and vendor contracts and certain restoration ancillary to prior mining activities. (2) Amounts do not include cash-collateralized letters of credit. (3) Certain letters of credit serve as collateral for surety bonds at the request of surety bond providers. Not presented in the above table is $825.1 million of restricted cash and other balances serving as collateral which are included in the accompanying condensed consolidated balance sheets at June 30, 2024, as described in Note 12. “Financial Instruments and Other Guarantees” of the accompanying unaudited condensed consolidated financial statements. Such collateral is primarily in support of the financial instruments noted above, including in relation to the Company’s surety bond portfolio, its collateralized letter of credit agreement, its bank guarantee facilities and amounts held directly with beneficiaries which are not supported by surety bonds. The restricted cash and collateral balance at June 30, 2024 decreased from $957.6 million at December 31, 2023 due to collateral releases related to reductions in reclamation bonding requirements, replacement of cash-collateralized letters of credit with letters of credit under the new revolving credit facility and the impact of foreign currency rate changes. At June 30, 2024, the Company had total asset retirement obligations of $699.9 million. Bonding requirement amounts may differ significantly from the re lated asset retirement obligation because such requirements are calculated under the assumption that reclamation begins currently, whereas the Company’s accounting liabilities are discounted from the end of a mine’s economic life (when final reclamation work would begin) to the balance sheet date. As noted above, the Company’s reclamation bonding requirements decreased during the six months ended June 30, 2024 primarily due to an approximate $110 million reduction in U.S. reclamation bonding requirements. At June 30, 2024, the Company’s reclamation bonding requirements were supported by approximately $720 million of restricted cash and other balances serving as collateral, which exceeds the financial liability for final mine reclamation as calculated in accordance with U.S. GAAP. Critical Accounting Policies and Estimates The Company’s discussion and analysis of its financial condition, results of operations, liquidity and capital resources is based upon its financial statements, which have been prepared in accordance with U.S. GAAP. The Company is also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, the Company evaluates its estimates. The Company bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. At June 30, 2024, the Company identified certain assets with an aggregate carrying value of approximately $214 million in its Other U.S. Thermal segment whose recoverability is most sensitive to customer concentration risk. The Company’s critical accounting policies and estimates are discussed in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in its Annual Report on Form 10-K for the year ended December 31, 2023. The Company’s critical accounting policies remain unchanged at June 30, 2024, and there have been no material changes in the Company’s critical accounting estimates. 46 Table of Contents Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented See Note 2. “Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented” to the Company’s unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.