ubsconference-sept2025fi

1 UBS Global Materials Conference September 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 Peabody’s shareholder return framework, execution of Peabody's operating plans, market conditions, reclamation obligations, financial outlook, acquisitions and strategic investments, and liquidity requirements. They may include estimates of sales and other operating performance targets, 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 BTU: Compelling Investment Highlights Centurion Mine Highlights Growing Steelmaking Coal Platform Low-Cost Seaborne Thermal Coal Fuels Rising Asian Generation Fortress Balance Sheet and Returning Cash to Shareholders Managing Safe, Productive and Environmentally Sound Operations1 2 3 5 Peabody: Providing vital products for the production of affordable, reliable energy and essential steel Leading U.S. Thermal Position Grows with Power Rebound4

Managing Safe, Productive and Environmentally Sound Operations

5 Peabody Quick Facts (1) 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. Peabody operates 2 of 3 most productive mines in the U.S. Centurion expected to be among lowest-cost met coal mines

6 2024: 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 ab o d y P ro fe ss io n al / B u si n es s Se rv ic es M in in g R e al E st at e C o n st ru ct io n A ll Em p lo ye rs M an u fa ct u ri n g En te rt ai n m e n t & H o sp it al it y Fo re st ry a n d Lo gg in g C o al M in in g R e ta il Ed u ca ti o n & H ea lt h St at e & L o ca l G o ve rn e m en t C ro p P ro d u ct io n Tr an sp o rt at io n / W ar e h o u si n g Fo u n d ri es In ci d en t R at e 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 incidence rate below industry and even service sectors

7 Peabody’s Global Diversified Platform Capitalizes on Key Themes Benefitting from global reach, multi-region exposure and non-correlated market movements • Peabody’s low-cost seaborne thermal business serves growing Asia demand centers Seaborne Thermal Coal Demand Growth Driven by Rising Asian 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 to Ignite New Growth for U.S. Thermal Coal • Peabody is increasing premium hard coking coal production with Centurion Mine PLV HCC is Becoming Increasingly Scarce, Driving Supply Imbalance Over Time • Peabody is expected to grow steelmaking coal share of Adjusted EBITDA(1) from 25% in 2024 to 50%(2) in 2026 Growing Metallurgical Coal Demand for Steel Production Driven by Southeast Asia (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.

Centurion Mine Highlights Growing Steelmaking Coal Platform

9 Seaborne Met Coal Markets: Asia Steel Mills Drive Demand Source: Company Materials and Wood Mackenzie. Asia Constitutes >100% of Growth in Global Steel Demand in Past Decade India Leads Long-Term Global Growth in Met Coal Imports • Green shoots appearing • China implementing classic “playbook” – Reducing excess steel production; Trimming coal mines to 276 days/year; Building major infrastructure • Benchmark coking coal pricing rebounds from March 2025 four-year lows • Long-term price estimates remain largely unchanged despite weakness of H1 2025 • >25 million tons of met coal offline globally; much more in loss-making mode Near-Term Coal Pricing Rebounding from Recent Lows • Asia annual steel use increased 225 million tonnes 2013 – 2023; Rest-of-world declined 7 million tonnes in that decade • China’s rapid urbanization drove met coal consumption growth for past 15 years and produces 60% of global steel • India projected to drive next 25 years of demand; new blast furnaces coming online • Ton of steel in India uses 4x – 5x the imported met coal of a ton of steel in China 44 117 M ill io n T o n n es 2025 2050 Australia Nearly Triples Met Exports to India 2.7x 82 182 M ill io n T o n n es 2025 2050 +122% India Met Coal Demand to Grow 100Mt

10 Centurion Mine Longwall Startup Accelerated to February 2026 • Segment growing in quality and quantity in 2026 • Tier one premium hard coking coal complex utilizing $1+ billion of existing infrastructure • Mine life of 25+ years with ~140 million tons within integrated mine plan • Further weights Peabody’s long-term cash flows toward premium hard coking coal • Premium hard coking coal from Goonyella Middle Seam NPV $1.6B(1) NPV/Share $13.25/share ~121.6 million shares IRR ~25% Total project return Adj. EBITDA Margin(2) ~45% LOM average Capex $489M to 1st Longwall production (~$100M remaining as of 6/30) 100% Premium Hard Coking Coal Index Price Centurion Targets 3 Million Ton Increase in 2026 Note: Economics assume LT PHCC of $210/tonne. (1) At 08/2024 excludes $375M of previous capex (2) Adjusted EBITDA margin is a non-GAAP operating/statistical measure equal to segment Adjusted EBITDA divided by segment revenue. Due to the volatility and variability of certain items needed to reconcile this forward-looking measure to its nearest GAAP measure, no reconciliation can be provided without unreasonable cost or effort. 0.5 3.5 4.7 Forecasted 2025 2026 LOM 2028 + (Saleable Production; Million Short Tons) Steelmaking Coal Segment targeted to grow by >20% in 2026

Low-Cost Seaborne Thermal Coal Fuels Rising Asian Generation

12 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; Asia-Pac consumed 85% of global thermal imports • Australia is largest global exporter of high-Btu coal IEA Notes Global Coal Demand Reached Record Levels in 2024 Continued Shift in Seaborne Thermal Demand to Asia-Pacific Region • U.S. tariff situation incentivizes more China imports from Australia, home to Peabody’s seaborne thermal mines • Thermal supply adjusting with Indonesia and Colombia reducing exports • Summer coal use rebounds from H1 with weather- related demand in Northern Hemisphere • Newcastle product pricing 15 – 20% above lows of Q2 2025 Thermal Coal Landscape Improves from Softer First-Half Fundamentals • 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”

13 Seaborne Thermal Segment Marked by Low Costs, Strong Margins $1,654 $174 Seaborne Thermal Adjusted EBITDA (1) Outpaced Investment by 9-1 Margin Segment Adj EBITDA Capital Expenditures Cash Flow: $1,480 million (U S$ in m ill io n s) • Platform delivering high margins throughout the cycle driven by efficient operations, generating high levels of free cash flow • Wilpinjong Mine is one of Australia’s most productive operations benefitting from a low overburden profile that underpins costs efficiency; Wambo Open-Cut JV operations leverage Glencore’s established operational footprint and infrastructure. • 2025 shipments targeted to be 14.6 - 15.2 million tons (including 9.2 - 9.8 million export tons) with costs at $45 - $48 per ton 2022-2024 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)

Leading U.S. Thermal Position Grows With Power Rebound

15 U.S. Markets: Electricity Demand and Policy Landscape Create Tailwinds for Domestic Coal • U.S. electricity use forecast to reach all time high of 4,186 B kWh • 2026 again expected to set record • Warnings that U.S. reserve margins reaching dangerous lows • Fossil plants shoulder rising load as weather-dependent electricity struggles to meet demand Record Electricity Consumption as Fossil Plants Shoulder Growing Load Long Term Demand Drivers & Peak Demand Pressures U.S. Coal Supply-Demand Fundamentals Tightening • U.S. EIA projects coal consumption increase of 6% in 2025 • Coal generation up 15% in first half of 2025, taking share from other energy forms • Peabody supplying multiple plants that are deferring retirements • U.S. coal plants, running at higher capacity factors, represent best source of incremental power over next several years • Fundamentals setting up for strong 2026 Sources: EIA, Wood Mackenzie, Thomson Reuters. U.S. EIA Monthly Energy Report; Company analysis. • U.S. power demand expected to climb 25% by 2030 from 2023 levels • Growth fueled by: o AI & data center boom o EVs/Transportation o Manufacturing reshoring o Peak-load management • “Coal is going to be around for longer than people thought.” Outgoing FERC Chair to Washington Post

16 • Renewable buildout doesn’t solve need for reliable 24/7 non-intermittent generation • Many gas plants ordered today unlikely to be placed in service before 2030+ due to backlogs • Additional nuclear generation likely 10 – 15 years away given permitting, financing • Existing U.S. coal capacity factor just 42% in 2024 vs. 72% in 2008 • Operating coal plants at historic capacity factors represents additional 10% of total U.S. generation without needing to add new plants • Would translate to >250 million tons per year in additional coal demand U.S. Coal Plants With Spare Capacity Could Provide Substantial Incremental Generation in Coming Years Answering the Question: How to Meet the Growing U.S. Generation Needs Through 2030? The J.H. Campbell plant in Michigan, a Peabody coal customer, is one of a large number of U.S. coal plants whose lives are being extended due to dangerously low generation reserve margins in many regions. Source: U.S. EIA Monthly Energy Review; America’s Power; News reports and Peabody Analysis.

17 U.S. Thermal Business Well Positioned, Highly Cash Flowing • Platform generates substantial free cash flow with strong margins and low investments with 9 mines serving U.S. customers in 25 states • PRB 2025 volume guidance raised twice to meet growing demand • 2025 PRB targets of 80 - 84 million tons, with 83 million tons priced at $13.65 per ton; Costs targeted at $11.50 - $12.00 per ton • 2025 Other U.S. Thermal targets 13.4 - 14.4 million tons, with 13.8 million tons priced at $52.20 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: Largest U.S. Coal Mine Cash Flow: $724 million 2022-2024 Cumulative (1) Adjusted EBITDA and per ton metrics are non-GAAP financial measures. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. (1) (U S$ in m ill io n s)

Fortress Balance Sheet and Returning Cash to Shareholders

19 Fortress Balance Sheet and Returning Cash to Shareholders • Shareholder-first philosophy – Returning cash to shareholders is a high priority • Framework – Returning Available Free Cash Flow through share repurchases and dividends No Secured Debt $1 Billion of Liquidity Fortress Balance Sheet Free Cash Flow Generation Shareholder Returns & Strategic Investments Modest Reinvestment Shareholder Returns Shareholder Return Program $740 $633 $626 Centurion Development (2) Shareholder Returns(1) Reclamation Funding(3) Capital Allocation (2023-Present) (1) Reflects dividends declared and share buybacks made since April 2023. (2) Reflects capital expenditures at Centurion (including remaining ~$100 million to first longwall coal production as of 06/30/2025) and acquisition of Wards Well. (3) As of 06/30/2025A. US$ in Millions Mine Reclamation 100% Funded

20 BTU Offers an Attractive Investment Opportunity • Peabody is committed to increasing free cash flow per share • Increasing shareholder value via earnings growth (Centurion premium hard coking coal mine Q1 2026 start) and share repurchases • Shares of BTU trade at a sharp discount on a variety of metrics including price targets, peer multiples and average sector values Source: Company information and NYU/Stern School of Business Jan 2025. (1) Valuation based on EV/EBITDA. $19 $25 $25 $33 $39 BTU Share Price at Relative Valuations(1) Avg Analyst Targets Coal Co Avg Oil/Gas Co Avg Steel Co Avg Metals/Mining Co Avg $16 Recent BTU Share Price

Appendix

22 2025 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. Guidance Targets Third Quarter 2025 Outlook Seaborne Thermal • Volume is expected to be 3.9 million tons, including 2.7 million export tons. 0.6 million export tons are priced at approximately $82 per ton, and 1.0 million tons of Newcastle product and 1.1 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 $110-$120 per ton. U.S. Thermal • PRB volume is expected to be 23 million tons at an average price of $13.45 per ton and costs of approximately $11.00-$11.50 per ton. • Other U.S. Thermal volume is expected to be 3.7 million tons at an average price of $51.10 per ton and costs of approximately $45-$49 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 14.6 - 15.2 11.1 $52.25 $45.00 - $48.00 Seaborne Thermal (Export) 9.2 - 9.8 5.7 $77.12 NA Seaborne Thermal (Domestic) 5.4 5.4 $26.00 NA Seaborne Metallurgical 8.0 - 9.0 4.4 $121.00 $115.00 - 120.00 PRB U.S. Thermal 80.0 - 84.0 83.0 $13.65 $11.50 - $12.00 Other U.S. Thermal 13.4 -14.4 13.8 $52.20 $43.00 - $47.00 Other Annual Financial Metrics ($ in millions) 2025 Full Year SG&A $95 Total Capital Expenditures $420 Major Project Capital Expenditures $280 Sustaining Capital Expenditures $140 ARO Cash Spend $50 Supplemental Information Seaborne Thermal ~48% of unpriced export volumes are expected to price on average at Globalcoal “NEWC” levels and ~52% 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 June 30, 2025. Weighted average quality for the PRB segment 2025 volume is approximately 8,700 BTU.

23 Average Market Pricing by Quarter 06/30/2025 03/31/2025 12/31/2024 09/30/2024 06/30/2024 Premium low vol hard coking coal (Premium HCC) (1) $184.22 $185.08 $202.82 $210.67 $242.31 Premium low-vol pulverized coal injection (Premium PCI) coal (1) $137.77 $141.08 $157.59 $174.20 $163.36 Newcastle index thermal coal (NEWC) (1) $100.49 $105.37 $138.01 $140.80 $136.11 API 5 index thermal coal (1) $68.28 $76.34 $87.54 $87.45 $88.60 PRB 8,800 Btu/Lb coal (2) $14.10 $14.17 $14.03 $13.84 $13.52 Illinois Basin 11,500 Btu/Lb coal (2) $46.52 $43.91 $42.75 $41.12 $40.69 (1) Spot pricing expressed per metric tonne. (2) Prompt month pricing expressed per short ton

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 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 Life-Extension Projects Wilpinjong • Stage 1 (Pit 8 extension) will extend a current mining pit but will not change the intensity of mining or total production through to December 2033 with a rehabilitation period going into 2034. Our modified mine plan protects the Cumbo Creek corridor and the Rocky Hill cultural heritage complex as well as the jobs of our 570-strong local workforce until 2033. Ongoing applications and assessments, community consultation and department liaison. • Stage 2 (Pit 9/10 Extension) will extend the current mining area by approximately 670 ha and extend the life of the mine to the late 2030s. Ongoing detailed mining studies, planning and reporting, community consultation and government liaison. Coppabella – Humbug Gully • 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. A decision is expected in 2026/27. • 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 • Stage 1 (LW317 & 318) will extend the existing approved LW317 and add a new LW318. The application has been lodged, and ongoing community consultation and department liaison will be ongoing • Stage 2 (LW319~326) mining to the west within current exploration lease areas, this project will extend the life to 2036, ongoing mining studies, planning, and reporting consultation will continue on this project.

30 Opportunities to Create Alternative Value with Existing Assets • Peabody partnering with leading renewable energy supplier RWE to strategically advance renewable energy projects on reclaimed mine land • Brings together RWE’s renewable energy expertise with Peabody’s significant land and reclamation capabilities • Partnership projects have potential capacity of more than 5.5 Gigawatt of solar energy and battery storage across Indiana and Illinois • Peabody advancing second stage in our Rare Earth Element (REE) evaluation program in PRB; sampling and analysis set for this quarter • Building on initial study in collaboration with the University of Wyoming concluded last year • Preliminary data suggest roof/floor clays above and below current mining seams may contain elevated levels of REE at NARM and Rawhide at same or better concentrations than others reported in the PRB • Elements easily accessible and already uncovered in the current coal mining process • Activities aligned with recently announced U.S. government program supporting rare earths from mining and industrial activities Evaluating Rare Earth Elements in PRB

31 Sustainability Strategy We strive to be the coal producer of choice. This means maintaining financial strength, delivering a diversity of products to support our customers’ needs, practicing operational excellence and championing sustainability. We believe that good safety, sustainability, human capital and governance practices drive strong business practices. Safety • In 2024, achieved best safety record in company’s 142-year history • Three operations completed 2024 with no reportable injuries • Company maintains a far better safety record than U.S. averages for mining or industrial activities Sustainability • Member of U.N. Global Compact and aligned to U.N. Sustainable Development Goals • Reclamation commitment and 70% more acres restored versus disturbed • Fully funded final reclamation liabilities via $740 million in restricted cash • Proactive engagement and careful cultural heritage engagement Human Capital • Strong employee development and well- compensated workforce • Maintain talent pipelines in high schools, trade schools and universities, including programs focused on recruiting historically underrepresented groups into our workforce Governance • Strong focus on good governance • Sector-leading ranking in governance by ISS • Highly skilled management team and board with a diversity of backgrounds, specialties and perspectives

32 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 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

33 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 36 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

34 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 36 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

35 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slides 36 Year Ended Year Ended Year Ended Years Ended Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2024 Dec. 31, 2022 - Dec. 31 2024 Reconciliation of Non-GAAP Financial Measures (In Millions) Income from Continuing Operations, Net of Income Taxes $ 1,317.4 $ 816.0 $ 407.3 $ 2,540.7 Depreciation, Depletion and Amortization 317.6 321.4 343.0 982.0 Asset Retirement Obligation Expenses 49.4 50.5 48.9 148.8 Restructuring Charges 2.9 3.3 4.4 10.6 Transaction Costs Related to Business Combinations - - 10.3 10.3 Asset Impairment 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 Amortization of Basis Difference Related to Equity Affiliates (2.3) (1.6) (1.8) (5.7) Interest Expense, Net of Capitalized Interest 140.3 59.8 46.9 247.0 Net Loss on Early Debt Extinguishment 57.9 8.8 - 66.7 Interest Income (18.4) (76.8) (71.0) (166.2) Net Mark-to-Market Adjustment on Actuarially Determined Liabilities (27.8) (0.3) (6.1) (34.2) Unrealized Losses (Gains) on Derivative Contracts Related to Forecasted Sales 35.8 (159.0) - (123.2) Unrealized Losses (Gains) on Foreign Currency Option Contracts 2.3 (7.4) 9.0 3.9 Take-or-Pay Contract-Based Intangible Recognition (2.8) (2.5) (3.0) (8.3) Income Tax (Benefit) Provision (38.8) 308.8 108.8 378.8 Adjusted EBITDA (2) $ 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

36 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 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 equity method investment in renewable energy joint ventures; 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; and revenue of $25.9 million related to the assignment of port and rail capacity during 2023. (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.

2 37 Investor Relations Contact: Vic Svec / Kala Finklang ir@peabodyenergy.com