EX-99.1 2 brileyinvestorconference.htm EX-99.1
1 B. Riley Investor Conference May 2025

2 Important Information This presentation contains forward-looking statements within the meaning of the securities laws. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. They often include words or variation of words such as "expects,” "anticipates," "intends," "plans," "believes," "seeks," "estimates," "projects," "forecasts," "targets," "would," "will," "should," "goal," "could" or "may" or other similar expressions. Forward-looking statements provide the Company’s current expectations or predictions of future conditions, events or results. All statements that address operating performance, events, or developments that may occur in the future are forward-looking statements, including statements regarding the status of the acquisition of assets and businesses associated with Anglo American’s metallurgical coal portfolio in Australia, Peabody’s shareholder return framework, execution of Peabody's operating plans, market conditions, reclamation obligations, financial outlook, and other acquisitions and strategic investments, and liquidity requirements. They may include estimates of sales and other operating performance targets, potential synergies cost savings, capital expenditures, other expense items, actions relating to strategic initiatives, demand for the company’s products, liquidity, capital structure, market share, industry volume, other financial items, descriptions of management’s plans or objectives for future operations and descriptions of assumptions underlying any of the above. All forward-looking statements speak only as of the date they are made and reflect Peabody’s good faith beliefs, assumptions and expectations, but they are not guarantees of future performance or events. Furthermore, Peabody disclaims any obligation to publicly update or revise any forward-looking statement, except as required by law. By their nature, forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Factors that might cause such differences include, but are not limited to, a variety of economic, competitive, and regulatory factors, many of which are beyond Peabody's control, that are described in Peabody's periodic reports filed with the SEC including its Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2024 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2025 and other factors that Peabody may describe from time to time in other filings with the SEC. You may get such filings for free at Peabody's website at www.peabodyenergy.com. You should understand that it is not possible to predict or identify all such factors and, consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties. This presentation also contains non-GAAP financial measures. The Company has provided a reconciliation of such non-GAAP financial measures to the most directly comparable financial measures prepared in accordance with U.S. GAAP in the Appendix to this presentation.

3 Key Investment Themes Positioned to Benefit from Megatrends with Diverse Portfolio Increased Focus on Steelmaking Coal Asset Base Thermal Platform Provides Stable Baseload Cash Flows Disciplined Approach to Capital Allocation Through Cycle Managing Safe, Efficient and Environmentally Sound Operations1 2 3 4 5 Peabody: Providing vital products for the production of affordable, reliable energy and essential steel

Managing Safe, Efficient and Environmentally Sound Operations

5 2024 a Record Year for Safety and Environmental Performance 1.1 2.1 2 2.3 2.4 2.8 2.9 3.1 3.1 3.4 4.3 4.5 4.5 5.3 0.81 3.1 P e a b o d y P ro fe s s io n a l/ B u s in e s s S e rv ic e s M in in g R e a l E s ta te C o n s tr u c ti o n A ll E m p lo y e rs M a n u fa c tu ri n g E n te rt a in m e n t & H o s p it a lit y F o re s tr y a n d L o g g in g C o a l M in in g R e ta il E d u c a ti o n & H e a lt h S ta te & L o c a l G o v e rn e m e n t C ro p P ro d u c ti o n T ra n s p o rt a ti o n / W a re h o u s in g F o u n d ri e s In c id e n t R a te Peabody global reportable incident rate per 200,000 hours worked. Other sectors are U.S. for latest reportable year (2023) per U.S. Bureau of Labor Statistics. • Both U.S. and Australian operations had record years in 2024 with combined incident rate of 0.81 o Lowest incident rate in 140- plus year company history • Record bond release for U.S. in reclamation efforts of $110 million • Graded land exceeded disturbed land by 70% • Final reclamation fully funded Peabody incident rate below industry and even service sectors

6 Peabody Quick Facts1 Confidential 1 All statistics are for the year ended December 31, 2024. 2 Total Recordable Incident Frequency Rate (‘TRIFR’) equals recordable incidents per 200,000 hours worked. 3 Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix.

Positioned to Benefit from Megatrends with Diverse Portfolio

8 Peabody Capitalizing on Favorable Megatrends • Peabody is expected to grow its steelmaking coal Adjusted EBITDA(1) from 25% in 2024 to 50%(2) in 2026 Growing Metallurgical Coal Demand for Steel Production, Driven by SE Asia • Peabody increasing PLV HCC production with Centurion Mine PLV HCC is Becoming Increasingly Scarce, Driving Supply Imbalance • Peabody’s low-cost seaborne thermal business serves growing Asia demand centers Seaborne Thermal Coal Demand Continues to Grow to Serve Asia Generation • Peabody is the largest U.S. thermal coal producer with decades of mine life and significant reserves U.S. Policy and Data Center Demand May Ignite New Growth for U.S. Thermal Coal (1) Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. The percentage calculations proportionally allocate Adj. EBITDA for the Corporate and Other segment (which includes Middlemount) to the operating segments. (2) 2026 projections assume $225/tonne benchmark pricing.

Increased Focus on Steelmaking Coal Asset Base

10 Seaborne Met Coal Markets: Seaborne Asia Drives Demand Source: Company Materials. Asia Constitutes >100% of Growth in Global Steel Demand in Past Decade Long-Term Seaborne Met Coal Demand Expected to Grow • Pricing rebounds from March 2025 four-year lows; Low Vol PCI remains a tight market • Supplies impacted by challenged economics, wet weather and unscheduled production outages • Steel demand outside of China showing some signs of improvement • At recent spot prices, we estimate ~100 million tonnes of global seaborne met coal demand served by “loss- making” coal mines Near-Term Coal Pricing Rebounding from Recent Lows • Asia steel use increases 225 million tonnes 2013 – 2023 • Rest-of-world declines 7 million tonnes in that decade • China’s rapid urbanization drove met coal consumption growth for past 15 years • India projected to drive next 25 years of demand • Most new met coal supply projections from restarts and expansions; greenfield projects face multiple challenges New Supply of HCC Required New Supply of HCC Required 0 10 20 30 40 50 60 70 80 90 100 110 2035 2040 2045 2050 (M ill io n T o n n e s )

11 Centurion Transforms Peabody’s Seaborne Metallurgical Coal Segment Metallurgical Sales Volume By Grade Metallurgical Coal Sales 39% 29% 12% 13% 7% Premium LV HCC PCI High Vol A AUS Low Vol HCC Other 7.3 7.3 4.7 2024 2024PF Peabody Centurion LOM Avg 12 Short Tons in Millions (1) 2024A with Centurion LOM average of 4.7 million tons +64% (1) 47% 19% 21% 11% Premium LV HCC PCI High Vol A AUS Low Vol HCC Other +38% Premium LV HCC 2024 2024PF (1)

12 World-Class Centurion Mine on Pace for Q1 2026 Longwall Startup • Tier one premium hard coking coal mine complex located in the heart of Bowen Basin • Expecting 500,000 tons in 2025 and 3.5 million tons in 2026 • Mine life of 25+ years with ~140 million ton integrated mine plan • Projecting an average of ~4.7 million saleable tons per year at all-in costs of $105 per ton(1) • At March 31, 2025, approximately $145M capital remains to first longwall coal Longwall equipment awaits underground installation (1) Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. Q4 24 First coal shipment Four continuous miners in the South Q1 2026Q2 2025 2 continuous miners expected in the North First Longwall Coal

Thermal Coal Platform Provides Stable Baseload Cash Flows

14 Seaborne Thermal Markets: Fueling Growing Asian Generation Sources: IEA Coal Report Dec. 2024; Wood Mackenzie Data Service; McCloskey news reports; Company analysis. • World used 8.77 billion tonnes in 2024; Growth projected through 2027 • 68% used as thermal coal IEA Notes Global Coal Demand Reached Record Levels in 2024 Continued Shift in Seaborne Thermal Demand to Asia-Pacific Region • Coastal power plant stockpile levels comparable to prior year in India; higher than normal in China • U.S. tariff situation raises implied costs for China customers; incentivizes more China imports from Australia • India’s Green Tribunal considering limiting sulfur levels, which would benefit Australian exports • Some compression as higher grade thermal coals compete with semi-soft coking coals Upcoming Summer Demand Projected to Support Near-Term Thermal Supply/Demand Balance • China began construction on 94.5 GW of coal-fueled generation in 2024 – a 10-year high • China and India have grown their coal fleets by 317 GW since 2015 • More than 600 GW of coal- fueled generation are under construction or various stages of development • China calls coal “the backstop of supply security”

15 High Margin Seaborne Thermal Business with Low Costs $1,654 $174 Seaborne Thermal Adjusted EBITDA(1) Outpaced Investment by 9-1 Margin Segment Adj EBITDA Capital Expenditures Cash Flow: $1,480 million (U S $ i n m ill io n s ) • Platform delivers high margins throughout the cycle driven by efficient operations, delivering high levels of free cash flow • Wilpinjong Mine is one of Australia’s most productive operations with low overburden ratio; Wambo complex transitions to open- cut operations only • 2025 shipments targeted to be 14.2 – 15.2 million tons (including 8.8 – 9.8 million export tons) with costs in line with 2024 at $47 – $52 per ton 2022-2024 Actual (Cumulative) Wilpinjong Mine in New South Wales, a low-cost producer (1) Adjusted EBITDA and per ton metrics are non-GAAP financial measures. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. (1)

16 U.S. Markets: Policy and Electricity Demand Landscape Creates Tailwinds for Domestic Coal • After 15 years of flat load growth, data centers now fuel projections for 2-3% CAGRs in U.S. power demand Analysts Project Strong Growth in U.S. Power Demand • President Trump authorized his administration to ramp up production of energy from coal • Deferrals in coal plant retirements constituting 35 GW of power • Existing coal plants at 42% utilization can run harder, driving increased U.S. thermal demand • Peabody being approached by potential new investors into power generation seeking secure supplies Need for Generation Creating Major Pause in Coal Plant Retirements Near-Term U.S. Coal Demand Tightening • U.S. EIA projects coal generation up 4% while coal production down 4% • Since first of the year, coal burn up 20% over prior year • Cold weather, strong power demand has drawn down stockpiles at mines and power plants • “Requirements” contracts running higher than prior year • Peabody customers confirming data-center-driven demand growth narrative (1) EIA, McKinsey & Company, Public Power, Bernstein, KPMG, Wood Mackenzie, Thomson Reuters. Data based on January reports for each period and available at: https://kpmg.com/au/en/home/insights/2021/02/coal-price-fx-market-forecasts.html. Data as of December 31, 2023. JP Morgan and Goldman Sachs analysis; America’s Power “Coal Plant Retirement Delays Jan. 2025”; U.S. EIA Monthly Energy Report; U.S. Short-Term Energy Outlook Mar. 6, 2025; Company analysis. Data Centers could Ignite a Surge in Power Demand1 U.S. Power Demand and 2024 Generation Capacity, TWh Non-data Centers Data Centers '24 Generation

17 Highly Cash Flowing U.S. Thermal Business Well Positioned • U.S. Thermal platform generates substantial free cash flow with low investments and strong margins • Platform consists of 9 mines serving U.S. customers in 25 states • 2025 PRB shipments expected between 76 – 78 million tons, with 77 million tons priced at $13.85 per ton; Costs targeted at $12.00- $12.75 per ton • 2025 Other U.S. Thermal shipments expected between 13.4 – 14.4 million tons, with 13.6 million tons priced at $52.00 per ton. Costs targeted at $43-$47 per ton $961 $237 U.S. Thermal Adjusted EBITDA(1) Outpaced Investment by 4-1 Margin Segment Adj EBITDA Capital Expenditures North Antelope Rochelle, the Largest U.S. Coal Mine Cash Flow: $724 million 2022-2024 Actual (Cumulative) (1) Adjusted EBITDA and per ton metrics are non-GAAP financial measures. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. (1) (U S $ i n m ill io n s )

Disciplined Approach to Capital Allocation Through the Cycle

19 Strategic Capital Allocation Track Record Leverage Profile • Financial Policy: Maintain financial resiliency to ensure execution throughout price cycle US$ in Millions $710 $617 $633 $1,200 Centurion Development (2) Shareholder Returns (1) Debt Reduction (3) Reclamation Funding (3) Capital Allocation (2020-Present) Go-Forward Capital Allocation Strategy Growth Strategy • Developing and optimizing Centurion Liquidity Management • Maintain Strong Liquidity: $700(3) million cash on hand together with an unfunded $320 million Revolver enables Peabody to weather a variety of macroeconomic environments Shareholder Return Policy • Quarterly Dividend: Targeting regular dividend of $0.075 per share (4) • Proportionate Approach: Balancing shareholder returns with deleveraging the balance sheet and reinvesting in assets Net Leverage (2020-Present) (5) (1) Reflects dividends declared and share buybacks made since April 2023. (2) Reflects capital expenditures at Centurion (including remaining ~$145 million to first longwall coal production as of 03/31/2025) and acquisition of Wards Well. (3) As of 03/31/2025A. (4) Regular dividends of $0.075 per share commenced in 2Q 2023. (5) Net Leverage is equal to Net Debt divided by Adjusted EBITDA, which are non-GAAP financial measures. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix.

20 We Believe BTU Offers an Attractive Investment Opportunity • Peabody is committed to increasing long-term cash flow per share • Focus on expanding shareholder value proposition with long-term earnings growth, shareholder returns and a favorable rerating of the stock • Shares of BTU trade at a sharp discount on a variety of metrics including price targets, peer multiples and average sector values $25 $32 $55 $61 $71 BTU Share Price at Relative Valuations(1) $15 Recent BTU Share Price Source: Company information and NYU/Stern School of Business Jan 2025. (1) Valuation based on EV/EBITDA. Average Analyst Targets Coal Peer Average Oil/Gas Average Steel Average Metals/ Mining Average

Appendix

22 Moranbah North Centurion Coppabella Moorvale Middlemount Capcoal Grosvenor Aquila Wambo Underground Wilpinjong Wambo Open-Cut Metropolitan Anglo American Acquisition Update Seaborne Met Seaborne Thermal Surface Mine Underground Mine Anglo American Asset • On May 5, 2025, Peabody announced that it notified Anglo American Plc of a Material Adverse Change (MAC) impacting Peabody’s planned acquisition of steelmaking coal assets from Anglo • The MAC relates to issues involving the Moranbah North Mine, which remains inactive following what was described as a gas ignition event on March 31, 2025 • If the MAC is not resolved to Peabody’s satisfaction in the limited timeframe specified under the companies’ acquisition agreements, Peabody may elect to terminate the agreements

23 2025 Guidance Table Certain forward-looking measures and metrics presented are non-GAAP financial and operating/statistical measures. Due to the volatility and variability of certain items needed to reconcile these measures to their nearest GAAP measure, no reconciliation can be provided without unreasonable cost or effort. Guidance Targets (Excluding Contributions from Planned Acquisition) Second Quarter 2025 Outlook Seaborne Thermal • Volume is expected to be 4.0 million tons, including 2.5 million export tons. 0.8 million export tons are priced at approximately $77 per ton, and 1.0 million tons of Newcastle product and 0.7 million tons of high ash product are unpriced. Costs are anticipated to be $45-$50 per ton Seaborne Metallurgical • Volume is anticipated to be 2.2 million tons and is expected to achieve 70 to 75 percent of the premium hard coking coal price index. Costs are anticipated to be $120-$130 per ton U.S. Thermal • PRB volume is expected to be 19 million tons at an average price of $13.80 per ton and costs of approximately $12.50-$13.00 per ton • Other U.S. Thermal volume is expected to be 3.3 million tons at an average price of $52.00 per ton and costs of approximately $41-$45 per ton Segment Performance 2025 Full Year Total Volume (millions of short tons) Priced Volume (millions of short tons) Priced Volume Pricing per Short Ton Average Cost per Short Ton Seaborne Thermal 14.2 - 15.2 9.1 $48.14 $47.00 - $52.00 Seaborne Thermal (Export) 8.8 - 9.8 3.7 $78.85 NA Seaborne Thermal (Domestic) 5.4 5.4 $27.10 NA Seaborne Metallurgical 8.0 - 9.0 2.5 $121.00 $120.00 - 130.00 PRB U.S. Thermal 76 - 78 77 $13.85 $12.00 - $12.75 Other U.S. Thermal 13.4 -14.4 13.6 $52.00 $43.00 - $47.00 Other Annual Financial Metrics ($ in millions) 2025 Full Year SG&A $95 Total Capital Expenditures $450 Major Project Capital Expenditures $280 Sustaining Capital Expenditures $170 ARO Cash Spend $50 Supplemental Information Seaborne Thermal ~52% of unpriced export volumes are expected to price on average at Globalcoal “NEWC” levels and ~48% are expected to have a higher ash content and price at 80-95% of API 5 price levels Seaborne Metallurgical On average, Peabody's metallurgical sales are anticipated to price at 70-75% of the premium hard-coking coal index price (FOB Australia) PRB and Other U.S. Thermal PRB and Other U.S. Thermal volumes reflect volumes priced at March 31, 2025. Weighted average quality for the PRB segment 2025 volume is approximately 8,695 BTU

24 Operations Overview: Seaborne Metallurgical Segment Production is for full year 2024 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2024. Strategic Advantage: Multiple locations and products, positioned to serve Asia Pacific and Atlantic market Metropolitan Mine Production: 1.8 million tons Reserves: 11 million tons Type: Underground - Longwall Product: Hard/Semi-hard coking coal (60%), coking coal by-products (40%) Port: Port Kembla Coal Terminal (PKCT) Location: New South Wales, Australia Shoal Creek Mine Production: 2.1 million tons Reserves: 16 million tons Type: Underground - Longwall Product: Coking – High Vol A Port: Barge coal to McDuffie Terminal Location: Alabama CMJV (Coppabella Mine and Moorvale Mine) Production: 3.2 million tons Reserves: 44 million tons Type: Surface - Dragline, Dozer/Cast, Truck/Shovel Product: Premium Low Volatile PCI Port: Dalrymple Bay Coal Terminal (DBCT) Location: Queensland, Australia Centurion Mine Production: 0.2 million tons Reserves: 191 million tons Type: Underground - Longwall Product: Coking – Premium Hard Coking Coal Port: Dalrymple Bay Coal Terminal (DBCT) Location: Queensland, Australia

25 Operations Overview: Seaborne Thermal Segment Production is for full year 2024 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2024. Strategic Advantage: High margin operations positioned to serve Asia Pacific market Wilpinjong Mine Production: 12.6 million tons (export and domestic) Reserves: 46 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Export (5,000-6,000 kcal/kg NAR) Port: Newcastle Coal Infrastructure Group (NCIG) and Port Waratah Coal Services (PWCS) Location: New South Wales, Australia Wambo Open-Cut Production : 3.3 million tons Reserves: 29 million tons Type: Surface - Truck/Shovel Product: Premium Export (~6000 kcal/kg NAR) Port: NCIG and PWCS Location: New South Wales, Australia Wambo Underground Production: 1.4 million tons Reserves: 1 million tons Type: Underground - Longwall Product: Premium Export (~6000 kcal/kg NAR) Port: NCIG and PWCS Location: New South Wales, Australia

26 Operations Overview: PRB Segment Production is for full year 2024 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2024. Strategic Advantage: Low-cost operations, largest producer, significant reserves, shared resources, technologies North Antelope Rochelle Mine (NARM) Production: 59.7 million tons Reserves: 1,300 million tons Type: Surface - Dragline, Dozer/Cast, Truck/Shovel Product: Sub-Bit Thermal (~8,800 BTU/lbs., <0.50 lbs. SO2) Rail: BNSF and UP Location: Wyoming Caballo Mine Production: 10.8 million tons Reserves: 168 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Sub-Bit Thermal (~8,500 BTU/lb., 0.80 lbs. SO2) Rail: BNSF and UP Location: Wyoming Rawhide Mine Production: 9.1 million tons Reserves: 80 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Sub-Bit Thermal (~8,300 BTU/lb., 0.85 lbs. SO2) Rail: BNSF Location: Wyoming

27 Operations Overview: Other U.S. Thermal Segment Production is for full year 2024 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2024. Strategic Advantage: Located to serve regional customers in high coal utilization regions with competitive cost operations and ample reserves / resources Bear Run Mine Production: 5.0 million tons Reserves: 69 million tons Type: Surface - Dragline, Dozer/Cast, Truck/Shovel Product: Thermal ~11,000 Btu/lb., 4.5 lbs. SO2 Rail: Indiana Railroad to Indiana Southern/NS or CSX Location: Indiana Wild Boar Mine Production: 1.8 million tons Reserves: 12 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Thermal ~11,000 Btu/lb., 5.0 lbs. SO2 Rail: NS or Indiana Southern Location: Indiana Francisco Underground Production: 1.6 million tons Reserves: 2 million tons Type: Underground - Continuous Miner Product: Thermal ~11,500 Btu/lb., 6.0 lbs. SO2 Rail: NS Location: Indiana Gateway North Mine Production: 2.1 million tons Reserves: 22 million tons Type: Underground – Continuous Miner Product: Thermal ~11,000 Btu/lb., 5.4 lbs. SO2 Rail: UP Location: Illinois Twentymile Mine Production: 1.0 million tons Reserves: 9 million tons Type: Underground – Longwall Product: Thermal ~11,200 Btu/lb., 0.80 lbs. SO2 Rail: UP Location: Colorado El Segundo/Lee Ranch Mine Production: 2.4 million tons Reserves: 8 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Thermal ~9,250 Btu/lb., 2.0 lbs. SO2 Rail: BNSF Location: New Mexico

28 Peabody’s Business Segments(1) Mines Full Year 2024 Seaborne Metallurgical • Centurion • Shoal Creek • Metropolitan • Coppabella / Moorvale (CMJV) • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA Margin per Ton • Adjusted EBITDA (millions) 7.3 $144.97 $122.77 $22.20 $242.5 Seaborne Thermal • Wilpinjong • Wambo Underground • Wambo OC JV • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA Margin per Ton • Adjusted EBITDA (millions) 16.4 $73.88 $47.71 $26.17 $430.0 Powder River Basin • North Antelope Rochelle • Caballo • Rawhide • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA Margin per Ton • Adjusted EBITDA (millions) 79.6 $13.81 $12.07 $1.74 $138.6 Other U.S. Thermal • Bear Run • Francisco Underground • Wild Boar • Gateway North • Twentymile • El Segundo / Lee Ranch • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA Margin per Ton • Adjusted EBITDA (millions) 14.6 $56.38 $46.04 $10.34 $150.8 (1) All statistics are for the year ended December 31, 2024. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix.

29 Existing Assets Offer Additional Opportunities to Create Value • Centurion Mine in Queensland, Australia is in pre-development to construct a 5 MW power station that will utilize gas removed from the mine. This is a next step in reducing our emissions and will also help lower our energy costs by self-powering a portion of our operations. • Peabody is in pre-development of a large-scale solar project at Twentymile Mine (Colorado) and a wind project at Wilpinjong Mine (New South Wales), with both representing approximately 300 MW in battery storage Peabody has partnered with RWE, a leading renewable energy supplier, to strategically advance renewable energy projects on reclaimed mine land. This innovative partnership brings together RWE’s expertise in developing and operating renewable energy projects and Peabody’s significant land and industry leading reclamation capabilities. • Partnership projects have the potential capacity of more than 5.5 Gigawatt of solar energy and battery storage across Indiana and Illinois • Creates significant local jobs and regional economic benefits and potential energy production to power 850,000 homes

30 Defined Sustainability Targets “We believe that the investments and partnerships we make today will shape the energy economy of the future and create new opportunities for our operations and our products.” Source: Peabody 2025 Sustainability Report

31 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 34 Year Ended Dec. 31, 2024 Tons Sold (In Millions) Seaborne Thermal 16.4 Seaborne Metallurgical 7.3 Powder River Basin 79.6 Other U.S. Thermal 14.6 Total U.S. Thermal 94.2 Corporate and Other 0.1 Total 118.0 Revenue Summary (In Millions) Seaborne Thermal $ 1,213.9 Seaborne Metallurgical 1,055.6 Powder River Basin 1,098.8 Other U.S. Thermal 822.6 Total U.S. Thermal 1,921.4 Corporate and Other 45.8 Total $ 4,236.7 Total Segment Costs Summary (In Millions) (1) Seaborne Thermal $ 783.9 Seaborne Metallurgical 893.9 Powder River Basin 960.2 Other U.S. Thermal 671.8 Total U.S. Thermal 1,632.0 Corporate and Other 64.5 Total $ 3,374.3

32 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 34 Year Ended Year Ended Year Ended Years Ended Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2024 Dec. 31, 2022 - Dec. 31 2024 Adjusted EBITDA (In Millions) (2) Seaborne Thermal $ 647.6 $ 576.8 $ 430.0 $ 1,654.4 Seaborne Metallurgical, Excluding Shoal Creek Insurance Recovery 781.7 438.1 161.7 1,381.5 Shoal Creek Insurance Recovery - Business Interruption - - 80.8 80.8 Seaborne Metallurgical 781.7 438.1 242.5 1,462.3 Powder River Basin 68.2 153.7 138.6 360.5 Other U.S. Thermal 242.4 207.5 150.8 600.7 Total U.S. Thermal 310.6 361.2 289.4 961.2 Middlemount 132.8 13.2 13.1 159.1 Resource Management Results (3) 29.3 21.0 19.2 69.5 Selling and Administrative Expenses (88.8) (90.7) (91.0) (270.5) Other Operating Costs, Net (4) 31.5 44.3 (31.5) 44.3 Adjusted EBITDA (2) $ 1,844.7 $ 1,363.9 $ 871.7 $ 4,080.3 Capital Expenditures Summary (In Millions) Seaborne Thermal $ 38.8 $ 62.0 $ 73.2 $ 174.0 Seaborne Metallurgical 84.8 186.4 266.6 537.8 Powder River Basin 59.1 40.9 35.0 135.0 Other U.S. Thermal 35.3 47.6 18.6 101.5 Total U.S. Thermal 94.4 88.5 53.6 236.5 Corporate and Other 3.5 11.4 7.9 22.8 Total $ 221.5 $ 348.3 $ 401.3 $ 971.1

33 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 34 Year Ended Year Ended Year Ended Year Ended Year Ended Years Ended Dec. 31, 2020 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2024 Dec. 31, 2022 - Dec. 31 2024 Reconciliation of Non-GAAP Financial Measures (In Millions) (Loss) Income from Continuing Operations, Net of Income Taxes $ (1,859.8) $ 347.4 $ 1,317.4 $ 816.0 $ 407.3 $ 2,540.7 Depreciation, Depletion and Amortization 346.0 308.7 317.6 321.4 343.0 982.0 Asset Retirement Obligation Expenses 45.7 44.7 49.4 50.5 48.9 148.8 Restructuring Charges 37.9 8.3 2.9 3.3 4.4 10.6 Transaction Costs Related to Business Combinations and Joint Ventures 23.1 - - - 10.3 10.3 Asset Impairment 1,487.4 - 11.2 2.0 - 13.2 Provision for NARM and Shoal Creek Losses - - 40.9 3.7 44.6 Shoal Creek Insurance Recovery - Property Damage - - - - (28.7) (28.7) Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates 30.9 (33.8) (2.3) (1.6) (1.8) (5.7) Interest Expense, Net of Capitalized Interest 139.8 183.4 140.3 59.8 46.9 247.0 Net (Gain) Loss on Early Debt Extinguishment - (33.2) 57.9 8.8 - 66.7 Interest Income (9.4) (6.5) (18.4) (76.8) (71.0) (166.2) Net Mark-to-Market Adjustment on Actuarially Determined Liabilities (5.1) (43.4) (27.8) (0.3) (6.1) (34.2) Unrealized Losses (Gains) on Derivative Contracts Related to Forecasted Sales 29.6 115.1 35.8 (159.0) - (123.2) Unrealized (Gains) Losses on Foreign Currency Option Contracts (7.1) 7.5 2.3 (7.4) 9.0 3.9 Take-or-Pay Contract-Based Intangible Recognition (8.2) (4.3) (2.8) (2.5) (3.0) (8.3) Income Tax (Benefit) Provision 8.0 22.8 (38.8) 308.8 108.8 378.8 Adjusted EBITDA (2) $ 258.8 $ 916.7 $ 1,844.7 $ 1,363.9 $ 871.7 $ 4,080.3 Operating Costs and Expenses $ 3,420.9 Unrealized Losses on Foreign Currency Option Contracts (9.0) Take-or-Pay Contract-Based Intangible Recognition 3.0 Net Periodic Benefit Credit, Excluding Service Cost (40.6) Total Segment Costs (1) $ 3,374.3 Total Debt $ 1,547.8 $ 1,137.8 $ 333.8 $ 334.2 $ 348.1 Exclude: BUMA Loan Note - - - - (9.3) Exclude: Debt Issuance Costs 42.7 34.8 9.8 8.1 6.3 Exclude: Cash and Cash Equivalents (709.2) (954.3) (1,307.3) (969.3) (700.4) Net Debt (5) $ 881.3 $ 218.3 $ (963.7) $ (627.0) $ (355.3)

34 Reconciliation of Non-GAAP Measures Note: Management believes that non-GAAP measures are used by investors to measure our 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. Note: Certain forward-looking measures and metrics presented are non-GAAP financial and operating/statistical measures. Due to the volatility and variability of certain items needed to reconcile these measures to their nearest GAAP measure, no reconciliation can be provided without unreasonable cost or effort. 1) Total Segment Costs, which is a non-GAAP financial measure, is defined as operating costs and expenses adjusted for the discrete items that management excluded in analyzing each of our segment's operating performance as displayed in the reconciliation above. Total Segment Costs is used by management as a component of a metric to measure each of our segment's operating performance. 2) Adjusted EBITDA, which is a non-GAAP financial measure, 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 segment's operating performance as displayed in the reconciliation above. Adjusted EBITDA is used by our chief operating decision maker as the primary metric to measure each segment's operating performance against expected results and to allocate resources, including capital investment in mining operations and potential expansions. 3) Includes gains (losses) on certain surplus coal reserve, coal resource and surface land sales and property management costs and revenue. 4) 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 equity method investment in renewable energy joint ventures; costs associated with suspended operations including the Centurion Mine; the impact of foreign currency remeasurement; expenses related to our other commercial activities; and revenue of $25.9 million related to the assignment of port and rail capacity during 2023. 5) Net Debt is defined as total long-term debt, excluding the BUMA Loan Note and debt issuance costs, less cash and cash equivalents. Net Debt is reviewed by management as an indicator of our overall financial flexibility, capital structure and leverage. 6) EBITDA Margin per Ton refers to Adjusted EBITDA Margin per Ton which is an operating/statistical measure equal to Adjusted EBITDA by segment divided by segment tons sold. Management believes Adjusted EBITDA Margin per Ton best reflects controllable costs and operating results at the reporting segment level. 7) Costs refers to Costs per Ton which is an operating/statistical measure equal to Revenue per Ton (which is equal to revenue by segment divided by segment tons sold) less Adjusted EBITDA Margin per Ton. Management believes Costs per Ton best reflects controllable costs and operating results at the reporting segment level.