B. Riley Institutional Investor Conference May 21, 2026
2 Forward Looking Statements 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 management's or the Board’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 shareholder return framework, execution of the Company’s operating plans, market conditions for the Company’s products, reclamation obligations, financial outlook, potential acquisitions and strategic investments, the development of the Company’s rare earth elements and critical minerals program, and liquidity requirements. 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, 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.
3 Peabody (NYSE: BTU) Key Investment Highlights Met Coal Earnings Power Increasing1 U.S. Thermal Business Cash Flows Extended as Load Growth Surges3 Low-Cost Seaborne Thermal Assets Feed Growing Asian Demand2 Robust Balance Sheet + Strong Liquidity + Increasing Free Cash Flow Outlook 5 Focus on Free Cash Flow Generation + Increasing Shareholder Returns 6 Peabody Development Targets Additional Value from Assets4
4 Company Snapshot – 2025 Overview Note: All statistics are for the year ended December 31, 2025. (1) Total Recordable Incident Frequency Rate (‘TRIFR’) equals recordable incidents per 200,000 hours worked. (2) Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix (3) Dollars in millions and excludes corporate and other Seaborne Metallurgical: 8.6 MT • Centurion • Shoal Creek • Metropolitan • Coppabella / Moorvale (CMJV) Seaborne Thermal: 15.4 MT • Wilpinjong • Wambo OC JV (Glencore) Powder River Basin: 84.5 MT • North Antelope Rochelle • Caballo • Rawhide Other U.S. Thermal 13.4 MT • Bear Run • Wild Boar • Gateway North • El Segundo / Lee Ranch • Twentymile • Francisco Underground $3.9B REVENUE $455M ADJUSTED EBITDA ~5,400 EMPLOYEES ~3,330 ACRES RESTORED 0.71 TRIFR $176 $71 $222 $56 2025 Adjusted EBITDA Powder River Basin Other U.S. Thermal Seaborne Thermal Seaborne Metallurgical (2,3) (1) (2) Global Headquarters Australia Regional Office
5 2025: Record Year for Safety and Environmental Performance Peabody’s global incidence rate of 0.71 better than coal industry and most other sectors Peabody global reportable incidence rate per 200,000 hours worked. Other sectors are U.S. for latest reportable year (2024) per U.S. Bureau of Labor Statistics. 1.0 1.3 1.4 2.0 2.2 2.6 2.7 2.8 3.0 3.9 4.1 4.4 4.4 5.1 0.71 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 … F o re s tr y a n d L o g g in g R e a l E s ta te M in in g 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 R e ta il C o a l M in in g E d u c a ti o n & H e a lt h C ro p P ro d u c ti o n S ta te & L o c a l G o v e rn e m e n t 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 c e R a te 57% improvement from 2020 • Reclaimed twice as many acres as disturbed • Only one notice-of-violation, tying all-time record Environmental Excellence Continues in 2025
6 Peabody at Center of Multiple Favorable Macro Trends Global Coal Use Continuing to Set All-Time Records Power Demand Boosted by US AI/Data Center Growth Metallurgical Coal Essential for Growing Indian Steel Production U.S. Coal Demand Strongly Rebounds from 2024 Lows World Shifts From Energy Transition to Addition
7 Peabody Provides Investors with Coal Sector Leading Diversification ● Higher-beta prices can result in outsized margins during up cycles (e.g. 56% Adjusted EBITDA1 margins in Q1 2022) ● $1.4 Billion Cash Flow2,3 in past five years ● Blend of market upside and strong cash flows through cycle ● $1.9 Billion Cash Flow2 in past five years ● “Fixed income” type base from longer-term contracts with good revenue visibility ● $1.1 Billion Cash Flow2 in past five years Seaborne Met Seaborne Thermal U.S. Thermal 1) Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix. 2) Cash Flow defined as Adjusted EBITDA less capex 3) excluding $0.6 billion capex related to Centurion
8 Seaborne Metallurgical Coal: Primarily Serving Asian Steelmaking Largest Seaborne Met Coal Importers India 78 China 60 J/K/T 89 Europe 36 Southeast Asia 26 Tata Steel commissions India’s largest blast furnace. India overtook China as the world’s largest metallurgical coal importing nation in 2025. Source: Wood Mackenzie, “Global Metallurgical Coal 10-Year Investment Horizon Outlook,” Nov. 2025; Peabody analysis. 2 0 2 5 T o n n es in M ill io n s Asia comprised 86% of metallurgical coal demand in 2025; Rest of World accounted for just 14%
9 Australia: Supplying Nearly Half of World’s Seaborne Met Coal 147 67 43 31 10 16 0 20 40 60 80 100 120 140 160 Rest of World Indonesia Canada USA Russia Australia 2025 Seaborne Met Exports (Tonnes in Millions) Australia Met Coal Serves Steelmakers in 29 Countries Source: Wood Mackenzie; Peabody Analysis.
10 Seaborne Met Segment Increasing Volume and Coal Quality ● Expected Q2 sales volume of approximately 300,000 tons as we ramp up production and inventories ● Second half sales volume is targeted at nearly 2 million tons ● Cost guidance reflects second half of 2026 at run-rate projections ● Commissioning at Centurion expected to be largely complete in second quarter of 2026 $2.1B(1) NPV 80% of benchmark Segment realizations expected to increase $105 per ton(2) Low-cost structure Premium Hard Coking Coal 100% of Index Price Mine Life 25+ year Annual Life of Mine Avg 4.7 Million Tons Note: (1) At 1/1/26, assumes LT PHCC of $225/tonne at 13.5% discount rate (2) Assumes LT PHCC of $210/tonne in 2024 dollars. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix. Centurion Mine Update
11 Seaborne Thermal: Asian Generation Continues Major Buildout 466 GW 252 GW 231 GW 265 GW Pre-Permit Announced Permitted Construction Coal generation buildout at fast pace globally More than 1,200 GW of coal-fueled generating units in development or construction Located in world’s fastest-growing manufacturing and population centers Source: Global Energy Monitor, Feb. 2026; Peabody analysis.. Coal-fueled generation in development globally would consume more than 4 billion tonnes of coal per year at optimal utilization rates with lifespans of multiple decades.
12 Seaborne Thermal Segment: Low Costs and Strong Margins • Surface operations deliver high margins throughout the cycle • Generated Cash Flow1 of $1.9 billion over past five years • Wambo Open-Cut JV operations leverage Glencore’s established operational footprint Note: Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix. 1) Cash Flow defined as Adjusted EBITDA less capex Wilpinjong Mine in New South Wales, a low-cost producer • Export shipments are expected to more than double by 2030 vs. 2026 • Planned Wilpinjong exports: • Pits 9 & 10 are next phase of long-term plan; environmental studies and approvals well-defined and progressing • New pits are expected to materially improve cost structure, productivity and mine life Wilpinjong Profile & Outlook 2026 2027 2028 2029 2030 4.8 4.2 6.0 8.5 10.4 (Tons in millions)
13 American Coal: World’s #1 Energy Reserve Energy in U.S. coal reserves greater than Russian gas, Saudi oil or other leading energy forms 4,990 3,462 1,749 1,550 626 261 0 1000 2000 3000 4000 5000 6000 U.S. Oil U.S. Natural Gas Saudi Oil Russia Natural Gas China Coal U.S. Coal Proven Reserves (Quadrillion BTUs) While China has 30% fewer coal reserves than the U.S., it produces ~10 times as much coal as America each year The United States has more energy in its coal than any nation has in any single energy source Source: U.S. Energy Information Administration; Worldometers; Worldmetrics; Peabody Analysis.
14 U.S. Power Demand: Soaring After Years of Stability “Electricity is one of the main barriers to hyperscalers’ AI buildout.” – WSJ Jan. 16, 2026 Source: WSJ Jan. 16, 2026: As Tech Giants Get More Hands-On With Energy, Their Risks Rise.” Projected 27% increase from 2020 to 2035
15 U.S. Coal Generation Surges in 2025, Tightening Fundamentals • U.S. coal burn up 13% in 2025 • Coal production up just 4% • Power plants reduced inventories ~15% • Natural gas generation off sharply at $3.62/ mmBtu average price Source: Energy Ventures Analysis, “The Financial Benefit of Coal Power Generation for U.S. Consumers in 2025,” February 2026; Peabody analysis. -48.4 -7.4 -2.6 1.9 4.3 9.7 68.3 80.7 -60 -40 -20 0 20 40 60 80 Change in Electricity Generation 2024-2025 (TWh) Coal Solar Wind Nuclear Oil Hydro Other Natural Gas
16 Sharp Cost Advantages of Existing Coal Fleet vs. New Renewables Coal kept power affordable, delivering $30-40B in 2024 consumer savings by keeping plants online Source: America’s Power: Energy Ventures Analysis, “One Way to Make Electricity More Affordable,” December 2025; Peabody analysis. Note: Battery Energy Storage Systems (BESS). • Study by Energy Ventures Analysis demonstrates major advantage from existing coal-fueled power plants • Replacing these coal units with new solar generation would be approximately 10X more expensive than continued coal operations o Coal (continued operations): ~$6 billion per year o New Solar (build + operate): ~$60 billion per year • Higher cost of renewable replacements would translate into dramatically higher electricity rates for customers, increasing affordability challenges $6.0 $10.9 $59.6 $9.0 $12.2 $9.7 $13.1 EXIST IN G COAL WIND- ONLY SOLAR - ONLY WIND + BESS SOLAR + BESS WIND + GAS SOLAR + GAS A n n u al C o st s (r ea l $ in b ill io n s) Average Annual Costs – Existing Coal Fleet Vs. New Renewable Energy
17 Peabody’s U.S. Thermal Platform: Leading Position & Contract Momentum Strong Demonstration that U.S. Utilities Recognize Longer-Term Value of Coal Generation 85 51 31 25 7 5 3 0 0 10 20 30 40 50 60 70 80 90 Peabody Core NTEC Eagle Specialty Kiewit Western Fuels Wyodak Ramaco 2025 PRB Production (Short Tons, Millions) Peabody is 41% of PRB production, up ~5M tons YoY Major Midwestern Utility (2026) ● More than 20 million tons of Illinois Basin coal over five years ● Contract exceeds $1 billion in total sales over time ● Sourcing flexibility from multiple mines ● High and medium sulfur qualities Associated Electric Cooperative Inc (2025) ● 7-8 million tons of coal per year for at least the next seven years at market linked pricing ● Peabody supplies all of Associated’s coal for New Madrid Plant and Thomas Hill Energy Center in Missouri from North Antelope Rochelle Mine Source: MSHA, Peabody analysis. Note: Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix. 1) Cash Flow defined as Adjusted EBITDA less capex Peabody’s well-capitalized U.S. Thermal business generated $1.1 billion of Cash Flow1 over past five years
18 Peabody Advancing Rare Earth/Critical Mineral Initiative Mineral Concentrations Targeted feedstocks indicate critical mineral oxide concentrations ranging from 428 – 1,669 ppm on a dry-ash basis 1 Heavy Rare Earths Heavy rare earths account for estimated 21% – 28% of concentrations 2 Critical Minerals Emphasis on germanium where we see good concentrations, strong end-market engagement and favorable supply- demand dynamics 3 Flowsheet Development Developing flowsheets in conjunction with partners to support technological and economic assessments 4 Government Partnership Discussions under way with multiple government agencies; Recently awarded $6.25 million matching funds from WEA for rare earth processing pilot plant 5 Rare earth/critical minerals initiative in early stages; Company encouraged by progress to date and expanding scope of activities Scale of Operations Peabody moves 470 million cubic yards of earth in PRB every year – enough to fill Empire State Building every single day 6
19 West Coast Thermal Coal Exports • Initiating test shipment of PRB coal from North Antelope Rochelle Mine to Vietnam via Union Pacific rail and Mexico’s Port of Guaymas • This test run reflects close coordination with U.S. and Mexican governments, port authorities, and logistics partners • Demonstrates Peabody’s ability to connect largest coal basin in the Western Hemisphere with largest demand centers in Asia • Peabody is also exploring opportunities to increase U.S. West Coast coal exports via partnership with new port build in Oakland, California set to be in operations in late 2028 The Port of Guaymas on the West Coast of Mexico, site of the first test shipment of Peabody thermal coal to Asia. Asia imports more than 80% of seaborne thermal coal in the world.
20 • Planned expansion of methane-to- power capacity at Centurion from 5MW to 20 MW • Integrated facility added to convert methane to LNG • Enhances safety, lowers costs and reduces emissions • Early operating performance of 5MW plant indicates an estimated $425K cost savings annually Peabody Development Targets Additional Value from Vast Holdings • 2.0 billion tons of proven/probable coal reserves1 • 3.5 billion tons of coal resources1 • 335,000 acres of surface lands controlled • Leases, rents, sales and swaps of land resulting in $116M of Adjusted EBITDA over last 5 years • Partnership with leading renewable energy company RWE • Advancing projects of more than 3 GW in solar, battery storage on former mine lands in Illinois and Indiana • Anticipated lease payments, and project success fees RESOURCE MANAGEMENT R3 RENEWABLES MINE SITE GENERATION Multiple Projects Being Advanced Leveraging Peabody’s Substantial Coal and Land Assets Peabody commences operations at 5 MW Centurion Power Station capturing methane that would have been previously flared and using power onsite to reduce emissions. 1) Reserve and resource estimate as of December 31, 2025. Note: Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix
21 Significant Improvement in Key Financial Metrics Financial Metric March 2020 → March 2026 Change Cash, Restricted Cash, and Collateral $682.5M → $1,303.8M +91% Debt $1,306.9M → $335.2M -74% Legacy Liabilities Net1 $1,389.8M → $74.0M -95% Share Price $2.90 → $32.95 +1,036% Market Value $283.3M → $4,013.3M +1,317% Proven Management Discipline – Returned $645 million to shareholders between 2023 through March 2026 1) Equals ARO, retiree healthcare and pension liabilities, net of restricted cash and collateral
22 Peabody’s Straightforward Financial Policy Fortress Balance Sheet Provides ample liquidity through cycle Low Debt Level Emphasis on low operating leverage Well-Funded Reclamation Avoids leading coal sector financial concern Strong Capital Discipline Generating higher returns from organic projects Shareholder Return Focused Anticipating increasing cash flows returned to shareholders
23 Peabody (NYSE: BTU) Offers Compelling Investment Favorable Macro Trends ● AI/data centers drive growing US power demand ● Existing US coal fleet generation has sharp cost advantages over alternatives ● U.S. policy framework highly supportive for coal ● Benchmark seaborne coal prices rise sharply from 2025 lows Operational Excellence ● Record safety and environmental performance ● Diverse strength from U.S. thermal, seaborne thermal and seaborne metallurgical coal ● Commissioning longwall operations at Centurion ● Leading low-cost thermal coal assets Built-For-All-Cycles Financial Strength ● Cash-positive net debt position and fortress balance sheet ● Well-funded final reclamation liabilities ● Lower 2026 capex and prospects of higher FCF in second half offer potential for larger shareholder returns
B U I L D I N G B R I G H T E R F U T U R E S Thank You!
2 25 Appendix
26 2026 Guidance 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. Second Quarter 2026 Outlook Seaborne Thermal • Volume is expected to be 3.0 million tons, including 1.9 million export tons. 0.3 million export tons are priced at approximately $64.60 per ton, and 1.0 million tons of Newcastle product and 0.6 million tons of high ash product are unpriced. Costs are anticipated to be $57—$62 per ton. Seaborne Metallurgical • Seaborne met volumes are expected to be 2.3 million tons and are expected to achieve approximately 75 percent of the premium hard coking coal price index. Costs are anticipated to be $145—$150 per ton. U.S. Thermal • PRB volume is expected to be 19 million tons at an average price of $13.50 per ton and costs of approximately $13.00—$13.50 per ton. • Other U.S. Thermal volume is expected to be 3.4 million tons at an average price of $54.50 per ton and costs of approximately $45— $49 per ton. Segment Performance 2026 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 12.0 - 13.0 6.7 $48.93 $49.50 - $54.50 Seaborne Thermal (Export) 7.5 - 8.5 2.2 $82.94 N/A Seaborne Thermal (Domestic) 4.5 4.5 $32.31 N/A Seaborne Metallurgical 9.3 - 10.3 3.0 $138.84 $123.00 - $133.00 PRB U.S. Thermal 82.0 - 88.0 80.5 $13.50 $11.75 - $12.25 Other U.S. Thermal 13.2 - 14.2 13.4 $55.25 $45.00 - $49.00 Other Annual Financial Metrics ($ in millions) 2026 Full Year SG&A $115 Total Capital Expenditures $340 ARO Cash Spend $65 Supplemental Information Seaborne Thermal 50% of unpriced export volumes are expected to price on average at Globalcoal “NEWC” levels and 50% are expected to have a higher ash content and price at 85-95% of API 5 price levels. Seaborne Metallurgical On average, Peabody's metallurgical sales are anticipated to price at ~80% 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, 2026. Weighted average quality for the PRB segment 2026 volume is approximately 8,725 BTU.
27 Average Market Pricing by Quarter 03/31/2026 12/31/2025 09/30/2025 06/30/2025 03/31/2025 Premium low vol hard coking coal (Premium HCC) (1) $234.67 $200.13 $183.51 $184.22 $185.08 Premium low-vol pulverized coal injection (Premium PCI) coal (1) $161.15 $140.07 $143.24 $137.77 $141.08 Newcastle index thermal coal (NEWC) (1) $118.75 $107.66 $108.76 $100.49 $105.37 API 5 index thermal coal (1) $80.84 $77.57 $69.09 $68.28 $76.34 PRB 8,800 Btu/Lb coal (2) $15.12 $15.01 $14.21 $14.10 $14.17 Illinois Basin 11,500 Btu/Lb coal (2) $53.46 $50.55 $48.64 $46.52 $43.91 (1) Spot pricing expressed per metric tonne. (2) Prompt month pricing expressed per short ton
28 Operations Overview: Seaborne Metallurgical Segment Production is for full year 2025 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2025. Strategic Advantage: Multiple locations and products, positioned to serve Asia Pacific and Atlantic market Metropolitan Mine Production: 1.7 million tons Reserves: 9 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: 1.8 million tons Reserves: 13 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: 35 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: 0.6 million tons Reserves: 192 million tons Type: Underground - Longwall Product: Coking – Premium Hard Coking Coal Port: Dalrymple Bay Coal Terminal (DBCT) Location: Queensland, Australia
29 Operations Overview: Seaborne Thermal Segment Production is for full year 2025 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2025. Wilpinjong Mine Production: 10.5 million tons (export and domestic) Reserves: 79 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 : 3.5 million tons Reserves: 31 million tons Type: Surface - Truck/Shovel Product: Premium Export (~6000 kcal/kg NAR) Port: NCIG and PWCS Location: New South Wales, Australia Wambo Underground (Closed 2025) Production: 0.8 million tons Type: Underground - Longwall Product: Premium Export (~6000 kcal/kg NAR) Port: NCIG and PWCS Location: New South Wales, Australia Strategic Advantage: High margin operations positioned to serve Asia Pacific market
30 Operations Overview: PRB Segment Production is for full year 2025 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2025. Strategic Advantage: Low-cost operations, largest producer, significant reserves, shared resources, technologies North Antelope Rochelle Mine (NARM) Production: 65.0 million tons Reserves: 1,234 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: 11.7 million tons Reserves: 161 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: 7.8 million tons Reserves: 69 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Sub-Bit Thermal (~8,300 BTU/lb., 0.85 lbs. SO2) Rail: BNSF Location: Wyoming
31 Operations Overview: Other U.S. Thermal Segment Production is for full year 2025 at share. Reserves reflect estimated proven and probable reserves as of December 31, 2025. Strategic Advantage: Located to serve regional customers in high coal utilization regions with competitive cost operations and ample reserves / resources Bear Run Mine Production: 4.7 million tons Reserves: 62 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: 2.1 million tons Reserves: 11 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: 1.3 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: 2.0 million tons Reserves: 21 million tons Type: Underground – Continuous Miner Product: Thermal ~11,000 Btu/lb., 5.4 lbs. SO2 Rail: UP Location: Illinois Twentymile Mine Production: 1.8 million tons Reserves: 3 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: 1.8 million tons Reserves: 6 million tons Type: Surface - Dozer/Cast, Truck/Shovel Product: Thermal ~9,250 Btu/lb., 2.0 lbs. SO2 Rail: BNSF Location: New Mexico
32 Mines Full Year 2025 Seaborne Metallurgical • Centurion • Shoal Creek • Metropolitan • Coppabella / Moorvale (CMJV) • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA per Ton • Adjusted EBITDA (millions) 8.6 $120.88 $114.31 $6.57 $56.4 Seaborne Thermal • Wilpinjong • Wambo Underground (Closed) • Wambo OC JV • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA per Ton • Adjusted EBITDA (millions) 15.4 $58.97 $44.55 $14.42 $222.2 Powder River Basin • North Antelope Rochelle • Caballo • Rawhide • Tons Sold (millions) • Revenue per Ton • Costs per Ton • Adjusted EBITDA per Ton • Adjusted EBITDA (millions) 84.5 $13.64 $11.56 $2.08 $175.8 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 per Ton • Adjusted EBITDA (millions) 13.4 $52.82 $47.49 $5.33 $71.4 Business Segments(1) (1) All statistics are for the year ended December 31, 2025. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix.
33 Centurion Royalties • Centurion is subject to the Queensland Government Royalty charged on total revenue. Queensland Government royalties are based on coal prices per tonne (in $A). • Centurion South is subject to a special private royalty agreement established in relation to the sale of the property by a prior owner. This special royalty is limited to production from the Goonyella Middle Seam (GMS) within a defined area. The royalty, paid annually, amounts to 20% of the nominal before-tax cashflow attributable to sales from the defined area less capex, and any accumulated losses (since the original sale process was completed in CY2000). • Centurion North (Wards Well) tenements, is subject to a price-linked royalty payable to the prior owner on the first 120Mt of product coal mined from the area, capped at US$200M. Peabody will only commence making payments once it has recovered its upfront investment in the development of Centurion North. • All royalties have been considered in the financial analysis. Average price per tonne for period (A$) Rate Up to and including $100 7% Over $100 and up to and including $150 First $100: Balance: 7% 12.5% More than $150 and up to and including $175 First $100: Next $50: Balance: 7% 12.5% 15% More than $175 and up to and including $225 First $100: Next $50: Next $25: Balance: 7% 12.5% 15% 20% More than $225 and up to and including $300 First $100: Next $50: Next $25: Next $50: Balance: 7% 12.5% 15% 20% 30% More than $300 First $100: Next $50: Next $25: Next $50: Next $75: Balance: 7% 12.5% 15% 20% 30% 40% Queensland Government Royalty RatesCenturion Royalties
34 Additional Mine Life-Extension Projects Coppabella Continuation Project The Coppabella Continuation Project is progressing through key regulatory approvals, with EA amendment approval, EPBC assessment advancing toward 2028 approval, and Water Act licensing well underway in coordination with state agencies. •The Coppabella continuation project extends Coppabella’s East pit to the boundary of the current mining leases; the extension will add at least another 10 years of mine life and around 36 million ROM tonnes of metallurgical coal. •We have referred the project for approval under the Australian Government’s EPBC Act, primarily due to a creek diversion outside our lease. lease and clearing activities associated with additional mining and infrastructure areas not previously assessed under the Commonwealth legislation Controlled Action decision completed. •Assessment by Public Environment Report (PER) underway, with submission targeted for Q1 CY27. Public notification of the PER anticipated after adequacy review Q4 2027. Final approval expected around early 2028. •The project capital for the creek diversion is ~USD $30M. Other capital relates only to sustaining capital associated with the life extension that the continuation project provides. Metropolitan The Extension Project continues to advance with key approvals on track and a clear path to major milestones. MOD 4 remains well-positioned for determination in 2026, supporting continuity of operations. Work on the larger SSD package is progressing, with ongoing engagement to define project scope. Exploration licensing also remains on schedule, with Cabinet review anticipated this month. Overall, the project remains strategically important, with approvals tracking to support longer-term development timelines. •Stage 1: LW317 & 318 (MOD 4) extends the existing approved LW317 and add a new LW318 – project approvals progressing in line with expectations, with milestones tracking toward 2026 determinations. •Stage 2: LW319-327 & 401-413 (SSD) mining to the west within current exploration lease areas, extending the life to 2036 – stakeholder engagement in progress, including technical and environmental impact studies; targeting clarity on final scope and timing following upcoming consultations. •Exploration Licence Application – ELA 6929: NSW Resources assessment completed with recommendation to proceed; NSW Cabinet endorsement required for next step; Cabinet consideration expected Q2 2026, in line with plan.
35 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 38. Quarter Ended Year Ended Mar. 31, 2022 Dec. 31, 2025 Tons Sold (In Millions) Seaborne Thermal 15.4 Seaborne Metallurgical 8.6 Powder River Basin 84.5 Other U.S. Thermal 13.4 Total U.S. Thermal 97.9 Corporate and Other 0.1 Total 122.0 Revenue Summary (In Millions) Seaborne Thermal $ 251.2 $ 908.5 Seaborne Metallurgical 321.3 1,036.6 Powder River Basin 251.2 1,153.0 Other U.S. Thermal 203.1 707.3 Total U.S. Thermal 454.3 1,860.3 Corporate and Other (335.4) 56.1 Total $ 691.4 $ 3,861.5 Total Segment Costs Summary (In Millions) (1) Seaborne Thermal $ 686.3 Seaborne Metallurgical 980.2 Powder River Basin 977.2 Other U.S. Thermal 635.9 Total U.S. Thermal 1,613.1 Corporate and Other 32.6 Total $ 3,312.2
36 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 38. Quarter Ended Year Ended Year Ended Year Ended Year Ended Year Ended Years Ended Mar. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2024 Dec. 31, 2025 Dec. 31, 2021 - Dec. 31 2025 Adjusted EBITDA (In Millions) (2) Seaborne Thermal $ 90.5 $ 353.1 $ 647.6 $ 576.8 $ 430.0 $ 222.2 $ 2,229.7 Seaborne Metallurgical, Excluding Shoal Creek Insurance Recovery 181.0 178.2 781.7 438.1 161.7 56.4 1,616.1 Shoal Creek Insurance Recovery - Business Interruption - - - - 80.8 - 80.8 Seaborne Metallurgical 181.0 178.2 781.7 438.1 242.5 56.4 1,696.9 Powder River Basin 7.6 134.9 68.2 153.7 138.6 175.8 671.2 Other U.S. Thermal 50.0 164.2 242.4 207.5 150.8 71.4 836.3 Total U.S. Thermal 57.6 299.1 310.6 361.2 289.4 247.2 1,507.5 Middlemount 45.1 48.2 132.8 13.2 13.1 (10.9) 196.4 Resource Management Results (3) 3.5 6.9 29.3 21.0 19.2 39.5 115.9 Selling and Administrative Expenses (23.1) (84.9) (88.8) (90.7) (91.0) (105.0) (460.4) Other Operating Costs, Net (4) (27.1) 116.1 31.5 44.3 (31.5) 5.5 165.9 Adjusted EBITDA (2) $ 327.5 $ 916.7 $ 1,844.7 $ 1,363.9 $ 871.7 $ 454.9 $ 5,451.9 Capital Expenditures Summary (In Millions) Seaborne Thermal $ 88.6 $ 38.8 $ 62.0 $ 73.2 $ 39.8 $ 302.4 Seaborne Metallurgical 25.1 84.8 186.4 266.6 309.4 872.3 Powder River Basin 41.4 59.1 40.9 35.0 33.1 209.5 Other U.S. Thermal 24.2 35.3 47.6 18.6 24.0 149.7 Total U.S. Thermal 65.6 94.4 88.5 53.6 57.1 359.2 Corporate and Other 3.8 3.5 11.4 7.9 5.1 31.7 Total $ 183.1 $ 221.5 $ 348.3 $ 401.3 $ 411.4 $ 1,565.6
37 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 38. Quarter Ended Year Ended Year Ended Year Ended Year Ended Year Ended Years Ended Mar. 31, 2022 Dec. 31, 2021 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2024 Dec. 31, 2025 Dec. 31, 2021 - Dec. 31 2025 Reconciliation of Non-GAAP Financial Measures (In Millions) (Loss) Income from Continuing Operations, Net of Income Taxes $ (119.8) $ 347.4 $ 1,317.4 $ 816.0 $ 407.3 $ (42.3) $ 2,845.8 Depreciation, Depletion and Amortization 72.9 308.7 317.6 321.4 343.0 384.5 1,675.2 Asset Retirement Obligation Expenses 15.0 44.7 49.4 50.5 48.9 36.5 230.0 Restructuring Charges 1.6 8.3 2.9 3.3 4.4 9.5 28.4 Costs Related to Terminated Acquisition - - - - 10.3 78.9 89.2 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 (0.6) (33.8) (2.3) (1.6) (1.8) (2.7) (42.2) Other Operating Loss - - 11.2 42.9 3.7 5.6 63.4 Interest Expense, Net of Capitalized Interest 39.4 183.4 140.3 59.8 46.9 43.9 474.3 Net Loss (Gain) on Early Debt Extinguishment 23.5 (33.2) 57.9 8.8 - - 33.5 Interest Income (0.5) (6.5) (18.4) (76.8) (71.0) (55.4) (228.1) Net Mark-to-Market Adjustment on Actuarially Determined Liabilities - (43.4) (27.8) (0.3) (6.1) (5.4) (83.0) Unrealized Losses (Gains) on Derivative Contracts Related to Forecasted Sales 301.0 115.1 35.8 (159.0) - - (8.1) Unrealized (Gains) Losses on Foreign Currency Option Contracts (3.3) 7.5 2.3 (7.4) 9.0 (6.0) 5.4 Take-or-Pay Contract-Based Intangible Recognition (0.7) (4.3) (2.8) (2.5) (3.0) (1.0) (13.6) Income Tax (Benefit) Provision (1.0) 22.8 (38.8) 308.8 108.8 8.8 410.4 Adjusted EBITDA (2) $ 327.5 $ 916.7 $ 1,844.7 $ 1,363.9 $ 871.7 $ 454.9 $ 5,451.9 Operating Costs and Expenses $ 3,334.9 Unrealized Gains on Foreign Currency Option Contracts 6.0 Take-or-Pay Contract-Based Intangible Recognition 1.0 Net Periodic Benefit Credit, Excluding Service Cost (29.7) Total Segment Costs (1) $ 3,312.2
38 Reconciliation of Non-GAAP Measures Note: Management believes that non-GAAP financial 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 reportable 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 segment's operating performance. (2) Adjusted EBITDA, which is a non-GAAP financial measure, is defined as (loss) income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses and depreciation, depletion and amortization. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing the reportable segments' operating performance as displayed in the reconciliation above. Adjusted EBITDA is used by the chief operating decision maker as the primary financial metric to measure each segment's operating performance against expected results and to allocate resources, including capital investment in mining operations and potential expansions. (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 other equity method investments; costs associated with suspended operations; holding costs associated with the Centurion Mine; the impact of foreign currency remeasurement; expenses related to our other commercial activities; revenue of $25.9 million related to the assignment of port and rail capacity during 2023; and a gain of $26.1 million recognized on the sale of the Millennium Mine during 2021. (5) 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. (6) 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. (7) Adjusted EBITDA Margin is an operating/statistical measure equal to segment Adjusted EBITDA divided by segment revenue. Management believes Adjusted EBITDA Margin best reflects operating results at the reporting segment level.
2 39 Investor Relations Contact: Kala Finklang ir@peabodyenergy.com