Peabody posts 2025 $3.86B revenue, $455M EBITDA
BTU outlines 2025 results, safety gains, capital returns and 2026 operating guidance in a detailed conference presentation.
Rhea-AI Filing Summary
Peabody Energy Corporation (BTU) furnished an investor presentation in connection with the Jefferies Global Industrials Conference, outlining its diversified coal platform, 2025 performance, safety record and capital allocation strategy. For 2025, Peabody reported $3.86 billion in revenue and $454.9 million of Adjusted EBITDA, with segment contributions from Seaborne Thermal, Seaborne Metallurgical, Powder River Basin and Other U.S. Thermal operations.
The company emphasizes operational safety, with a 1H26 Total Recordable Incident Frequency Rate of 0.71, and highlights macro tailwinds from record global coal demand, rising U.S. power load and increasing Indian steel production. Management presents a balance-sheet-focused capital framework, citing zero net debt, more than $900 million of liquidity, and a policy to return 65–100% of Available Free Cash Flow to shareholders, including about $810 million returned since 2023. The deck also provides 2026 volume, pricing and cost guidance by segment and details recent refinancing, surety and revolver actions that lower interest cost and release restricted cash.
Positive
- $3.86 billion 2025 revenue and $454.9 million Adjusted EBITDA demonstrate sizable ongoing operations across diversified coal segments.
- Capital structure significantly improved, with zero net debt, >$900 million liquidity and a $351 million reduction in restricted cash and collateral.
- Shareholder-return framework targets 65–100% of Available Free Cash Flow back to investors, with about $810 million returned since 2023, roughly 29% of 2Q26 market cap.
- Strong 2021–2025 cash generation with cumulative $5.45 billion Adjusted EBITDA and segment cash flow metrics highlighting resilient margins, especially in seaborne businesses.
Negative
- After strong prior years, Adjusted EBITDA fell from $871.7 million in 2024 to $454.9 million in 2025, and 2025 showed a $42.3 million loss from continuing operations.
- U.S. thermal markets face near-term pressure, with industry PRB train loadings down about 12% versus 2025 and higher diesel prices lifting surface-mine costs.
Insights
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8-K Event Classification
2 items: 7.01, 9.01
2 items
Item 7.01
Regulation FD Disclosure
Disclosure
Material non-public information disclosed under Regulation Fair Disclosure, often investor presentations or guidance.
Item 9.01
Financial Statements and Exhibits
Exhibits
Financial statements, pro forma financial information, or exhibit attachments filed with this report.
Key Figures
2025 Revenue: $3.86 billion
2025 Adjusted EBITDA: $454.9 million
Cumulative Adjusted EBITDA 2021–2025: $5.45 billion
+5 more
8 metrics
2025 Revenue
$3.86 billion
Total revenue for the year ended December 31, 2025
2025 Adjusted EBITDA
$454.9 million
Adjusted EBITDA for the year ended December 31, 2025
Cumulative Adjusted EBITDA 2021–2025
$5.45 billion
Sum of Adjusted EBITDA from 2021 through 2025
Available Free Cash Flow 1H26
$145.3 million
Six months ended June 30, 2026
Cash Returned Since 2023
$810 million
Capital returned to shareholders since 2023, about 29% of 2Q26 market cap
Liquidity
Over $900 million
Cash and available liquidity as cited as of June 30, 2026
2026 Capital Expenditures Guidance
$340 million
Total capital expenditures full-year 2026 guidance
TRIFR 1H26
0.71
Total Recordable Incident Frequency Rate per 200,000 hours worked as of 1H26
Key Terms
Adjusted EBITDA, Available Free Cash Flow, Asset Retirement Obligation, Total Segment Costs, +2 more
6 terms
Adjusted EBITDA financial
"Adjusted EBITDA is a non-GAAP financial measure."
Adjusted EBITDA is a way companies measure how much money they make from their core operations, like running a business, by removing certain costs or income that aren’t part of regular business activities. It helps investors see how well a company is doing without distractions from unusual expenses or gains, making it easier to compare companies or track performance over time.
Available Free Cash Flow financial
"Available Free Cash Flow is a non-GAAP financial measure."
Asset Retirement Obligation financial
"Asset Retirement Obligation Expenses"
A liability recorded for the future cost to retire, dismantle or clean up a long-lived asset — for example removing an oil rig, closing a mine, or decommissioning a plant. Investors care because it reduces reported profit and ties up capital: companies must estimate and set aside money now for a known future expense, and changes to that estimate can swing earnings, debt ratios and the company’s cash needs much like setting aside savings to repair or return a rented property later.
Total Segment Costs financial
"Total Segment Costs, which is a non-GAAP financial measure, is defined as"
take-or-pay financial
"Take-or-Pay Contract-Based Intangible Recognition"
A take-or-pay clause is a contract term that requires a buyer to either take delivery of an agreed amount of a product or pay a penalty if they do not. For investors, it matters because it creates predictable revenue for the seller—like a subscription fee that must be paid whether fully used or not—reducing sales volatility but also introducing counterparty risk if the buyer’s ability to pay is uncertain.
FAQ
What 2025 financial performance did Peabody Energy (BTU) highlight?
Peabody reported $3.86 billion in 2025 revenue and $454.9 million of Adjusted EBITDA. Cumulative Adjusted EBITDA from 2021–2025 was $5.45 billion, reflecting strong multi-year cash generation across Seaborne Thermal, Seaborne Metallurgical, Powder River Basin and Other U.S. Thermal segments.
How strong is Peabody Energy’s (BTU) balance sheet and liquidity?
The company cites zero net debt, a strong cash position and more than $900 million of liquidity. Recent actions include a convertible note refinancing, a new A$700 million Australian bond facility and increased revolver commitments to $400 million with lower interest margins.
What safety performance did Peabody Energy (BTU) report?
For 1H26, Peabody reports a global Total Recordable Incident Frequency Rate of 0.71 per 200,000 hours worked, a stated 57% improvement from 2020. The company notes only one notice-of-violation in 2025 and an industry award for reclamation at its Wild Boar mine.
What 2026 operational guidance did Peabody Energy (BTU) provide?
For 2026, guidance includes Seaborne Thermal volumes of 12.4–13.0 million tons (average pricing $60.19 per ton), Seaborne Metallurgical volumes of 8.8–10.3 million tons (priced at $143.57 per ton), PRB volumes of 82–88 million tons, and total capital expenditures of $340 million.
How much Available Free Cash Flow did Peabody Energy (BTU) generate in 1H26?
For the six months ended June 30, 2026, Peabody reports $145.3 million of Available Free Cash Flow, based on operating cash flow, investing cash flow, distributions to noncontrolling interests and a $308.5 million favorable change in restricted cash and collateral.
What did Peabody Energy (BTU) disclose about its Centurion mine?
Centurion is described as a premium hard coking coal asset with $2.1 billion NPV at a long-term price assumption and a 25+ year mine life. Guidance shows 2026 Seaborne Met volumes of 8.8–10.3 million tons, with Centurion expected to reach a full longwall run rate in 4Q 2026.
AI-generated analysis. How Rhea-AI works. Not financial advice.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): September 9, 2026
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation) | (Commission File Number) | (I.R.S. Employer Identification No.) | |||||||||||||||||||||||||||||||||
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| Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions: | |||||||||||||||||||||||||||||||||||
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||||||||||||||||||||||||||||||||
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||||||||||||||||||||||||||||||||
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||||||||||||||||||||||||||||||||
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||||||||||||||||||||||||||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Item 7.01. Regulation FD Disclosure.
Representatives of Peabody Energy Corporation (the “Company”) will be attending the Jefferies Global Industrials Conference beginning on September 9, 2026. The Company’s representatives intend to share an overview of the Company’s strategic focus, business developments, and recent trends. A copy of the slides that will be discussed during the presentation is attached as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated herein by reference. These presentation materials should be read together with the information included in the Company’s other filings with the Securities and Exchange Commission, including the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025.
The information set forth in and incorporated into this Item 7.01 of this Current Report on Form 8-K is being furnished pursuant to Item 7.01 of Form 8-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference into any of the Company’s filings under the Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof and regardless of any general incorporation language in such filings, except to the extent expressly set forth by specific reference in such a filing. The filing of this Item 7.01 of this Current Report on Form 8-K shall not be deemed an admission as to the materiality of any information herein that is required to be disclosed solely by reason of Regulation FD.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits | |||||
| Exhibit No. | Description of Exhibit | ||||
| 99.1 | Investor Presentation, dated September 10, 2026. | ||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | ||||
2
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| PEABODY ENERGY CORPORATION | |||||
| September 9, 2026 | By: /s/ Scott T. Jarboe | ||||
| Name: Scott T. Jarboe | |||||
| Title: Chief Administrative Officer and Corporate Secretary | |||||
3
Jefferies Global Industrials Conference September 10, 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.
2 3 Business Overview
4 $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 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) • Wambo UG (Closed) 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 (2,3) (1) (2) Global Headquarters Australia Regional Office
5 1H26: Maintaining Record Safety 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 as of 1H26. 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 3.2 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 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 • Wild Boar mine recipient of the 2026 Distinction in Reclamation award – among the industry’s highest honors. • Only one notice-of-violation in 2025, tying all-time record. Environmental Excellence Continues
6 • “Fixed income” base from longer-term contracts with good revenue visibility. • $1.1 Billion Cash Flow2 in past five years. • Strong margins from low- cost tons, with excellent longevity and growth outlook. • $1.9 Billion Cash Flow2 in past five years. • Higher-beta prices can result in outsized margins during up cycles (e.g. 56% Adjusted EBITDA 1 margins in Q1 2022). • $1.4 Billion Cash Flow2,3 in past five years. Peabody Provides Leading Coal Sector Diversification 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.
7 The Peabody Platform: Strength, Growth, Returns ASSETS + MACRO TAILWINDS • Record global coal demand, surging US power load, rising Indian steel production. • Centurion: $2.1B NPV 1 , 1st quartile cost structure, 25+ year mine life. • Unlocking additional value from our vast reserves and land. FINANCIAL STRENGTH2 • Zero net debt, strong cash position, >$900M liquidity. • Debt reduced 74% and legacy liabilities 3 down 70% since March 2020. • Reduced annual funded debt interest cost $6.6 million. SHAREHOLDER RETURN PRIORITIZATION • ~$810M returned since 2023 2 — ~29% of market cap at end of 2Q26 4 . • 65–100% of Available FCF 5 returned (>100% YTD); buybacks strongly preferred. • As Centurion reaches steady state, free cash flow expected to increase. Balance Sheet Strength, Growth Optionality, Cash Returns 1) Net present value at 01/01/2026 assumes LT PHCC price of $225/tonne at 13.5% discount rate. 2) Financial metrics as of 6/30/2026 and shareholder returns includes dividends declared, not yet paid. 3) Equals ARO, retiree healthcare and pension liabilities, net of restricted cash and collateral. 4) Market cap at 6/30/2026 of $2.82 billion. 5) Available FCF is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix.
2 8 Key Macro Tailwinds and Assets
9 Peabody Sits at the Intersection of Powerful Macro Trends Record Global Coal Demand Global coal use keeps setting all-time records — more than 1,200 GW of new coal capacity is in development or construction, led by Asia. U.S. Power Load Surging AI and data centers are driving the first sustained U.S. load growth in decades — projected ~27% higher from 2020 to 2035. Indian Steel Production Rising India has overtaken China as the world's largest seaborne metallurgical- coal importer as blast-furnace capacity rapidly expands. Tailwinds across global coal, U.S. power demand and Asian steel Sources: S&P Global Energy; IEA; Energy Ventures Analysis; Peabody analysis.
10 Coal anchors energy security NO WARS ARE FOUGHT OVER COAL Abundant and widely distributed across many suppliers and insulated from the chokepoints that disrupt oil and gas. CONFLICT RENEWS THE RELIABILITY CASE Coal dispatches on command and stockpiles on site. The exact margin reliability-focused buyers rediscover in every crisis. SEABORNE SUPPLY IS TIGHTENING Indonesian export curbs, a decade of underinvestment in new capacity and declining quality at aging mines are constraining seaborne thermal supply. STRUCTURAL ASIAN RELIANCE Asia keeps building coal capacity at scale, anchoring durable long-term thermal demand. Sources: S&P Global; IEA; Peabody analysis. Peabody Sits at the Intersection of Powerful Macro Trends
11 Seaborne Met: Growing Demand for Centurion Product Source: Peabody Analysis; Platts (PLV HCC pricing), WoodMac (Indian met coal imports) 1) For committed volumes only. 2) Cost/Ton is a non-GAAP operating/statistical measure. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. Exiting seasonal softness; Structural Indian demand supports premium hard coking coal MARKET DRIVERS FY26 OUTLOOK VOLATILITY FACTORS • Exiting weakest period of seasonal conditions; demand expected to pick up post-monsoon season. • Chinese constrained mining, higher domestic prices and increased seaborne imports are constructive. • Middle East conflict increases “tyranny of distance” for met coal importers. • Sharp trade protectionism favors Australian met coal. • Post-safety-event recovery in Shanxi remains slow, reportedly pulling Chinese steelmakers toward Australian supply. • India represents 60% of global blast furnace development pipeline. • All Indian blast furnace steel relies on high-quality met coal imports. • India met coal imports increased 10% last year. • Coke from low-ash, high-CSR coals like Centurion is coveted by Indian steelmakers. M A R K E T S I G N A L Demand growth outpacing supply $233/tonne P L V H C C J U L 1 – A U G 3 1 A V G +33% growth E X P E C T E D I N D I A N M E T I M P O R T S T O 2 0 3 5 Tons (millions) Priced Volume/Ton1 Avg. Cost/Ton2 8.8-10.3 $143.57 $130-$145 • 3Q’26 volumes impacted by longwall move at Metropolitan and lock outage logistics at Shoal Creek.
12 117 222 200+ Q3 Sales Guidance 500-700 - 100 200 300 400 500 600 700 TRACKING TO Q3 SALES GUIDANCE Plant Production (tons in thousands) Sept Fcst August July Centurion: From Commissioning to Free Cash Flow LONGWALL STATUS Approaching full run rate Q4 2026 GUIDANCE 1M+ tons AUGUST UPDATE: • LW cycle times continue to improve; increasing production rates. • Q3 quarter-to-date yield improved to 69% from 59% in Q2. • Sustaining improved production rate clears known fault zone by mid-October. $270+ per tonne C U R R E N T H C C P R I C E 100% of Index Price P R E M I U M H A R D C O K I N G C O A L $15M NPV: $1 HCC Price S H A R E H O L D E R L E V E R A G E T O H C C Source: Peabody Analysis; Platts (PLV HCC pricing AS OF 09/01/2026). AUGUST PRODUCTION 222K tons
13 Seaborne Thermal: Supply Constraints Build Upside • Post-summer Asian demand and constrained supply remain supportive of seaborne thermal coal markets. • Higher LNG prices maximizing coal's role in regional generation stacks. Source: Peabody Analysis; Platts (Newcastle pricing), OPIS (Chinese thermal plants). Global Energy Monitor – CREA H1 2026. 1) Committed volumes only. 2) Cost/Ton is a non-GAAP operating/statistical measure. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. Mine disruptions and elevated LNG prices tighten the market into winter restocking MARKET DRIVERS FY26 OUTLOOK VOLATILITY FACTORS • Extended Middle East conflict supports elevated LNG pricing and coal competitiveness in Asia. • Higher oil prices have increased ocean freight costs, improving Australia’s competitiveness as a shorter-haul coal supplier to Asia. • El Niño-driven drought conditions could constrain Indonesian coal exports and reduce regional hydro generation, supporting Australian thermal coal demand. M A R K E T S I G N A L Tightening into 2H26 $130/tonne N E W C A S T L E J U L 1 – A U G 3 1 A V G 30 GW C H I N A A D D E D 1 H 2 6 Tons (millions) Priced Volume/Ton1 Avg. Cost/Ton2 Domestic 4.5 $34.00 $49.50- $54.50Export 7.9-8.5 $91.20 • European storage levels may drive pre- winter LNG buying, increasing competition with Asia for LNG cargoes and supporting seaborne thermal coal prices. • Chinese supply remains constrained following recent safety incidents, effecting upcoming winter restocking driving higher imports. • Global diesel supply disruptions could restrict coal production and logistics, especially Russian exports. • Indonesian production and export policy uncertainty supports higher coal prices.
14 Growing Low-Cost Export Tons into Asian Demand Wilpinjong export-priced volumes expected to more than double by 2030 PLANNED WILPINJONG EXPORT VOLUMES • Wilpinjong export priced tons are expected to more than double by 2030. • Pits 9 & 10 extend mine life to 2038; environmental studies and approvals are progressing. • New pits expected to further improve cost structure and productivity at one of Australia’s lowest-cost mines. W H Y I T M AT T E R S : NEWC6000 and API5 compete with LNG (JKM) for the same Asian power demand. When LNG spikes – Ukraine, the Middle East – it sends buyers back to coal. Two LNG crises in four years have driven fuel switching to coal and reinforced its role as reliable baseload. Note: Adjusted EBITDA is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix. 1) Peabody calculation using 2026 prices and cost guidance. 2026 2027 2028 2029 2030 4.8 4.2 6.0 8.5 10.4 +$150M Projected incremental 2030 Adj. EBITDA from increased exports1 Wilpinjong Outlook (Tons in Millions) 1,000 1,500 2,000 2,500 3,000 3,500 4,000 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 J P Y /M M B tu Seaborne Thermal and LNG Indices Newcastle 6000 API 5 JKM (Asian LNG)
15 U.S. Thermal: Load Growth Anchors Coal Demand Tons (millions) Priced Volume/Ton3 Avg. Cost/Ton4 PRB 82-88 $13.65 $12.00 - $12.50 Other U.S. 13.2-14.2 $56.70 $45 - $49 • PRB serves nearly one of every two tons of U.S. thermal demand; Peabody sold ~41% of total PRB output in 2025. Source: Peabody Analysis; 1) WoodMac projection 2) At 2026 midpoint as of 08/31/26. 3) Committed tons only. 4) Cost/Ton is a non-GAAP operating/statistical measure. Refer to the definitions and reconciliations to the nearest GAAP measures in the appendix. Steady, contract-driven demand as load growth supports coal generation MARKET DRIVERS FY26 OUTLOOK VOLATILITY FACTORS • Load growth returns: data center load growth is projected to grow at a >18% CAGR out to 2035 1 . • The operating life of 46 GW of the U.S. coal fleet has been extended. • Gas-to-coal switching: Expected increase in both power + industrial demand and LNG exports is expected to result in a firmer natural gas price which supports coal generation. • Ample stockpiles: roughly 124Mt held on-site at U.S. power plants, limiting restocking urgency. • EIA forecasts U.S. coal generation down about 6% in 2026 on gas and solar share gains. • Gas prices >$3/MMBtu resulted in coal powered generation rising 13% in 2025 as utilities switched to more economic thermal source. 2 0 2 7 Tons committed & priced 2 70% P R B 85% O T H E R U . S . T H E R M A L
16 Near-Term Factors = Crosscurrents for Summer U.S. Coal Burn Gas Prices Below Henry Hub in Coal-Heavy Regions Most coal-plant-heavy regions see localized natural gas prices well below Henry Hub levels, leading to some coal-to-gas switching. PRB Regional Train Loadings Down ~12% Industry-wide daily trains from May through late August 2026 running on average 5 shipments lower than comparable 2025 levels. High Oil Prices Pressure Margins at Surface Mines Persistently high oil prices and an expanded diesel crack spread elevates diesel prices and cost pressures at major surface mines. Industry-wide PRB volumes and costs expected to remain under near-term pressure Texas, $2.55 Illinois, $2.94 Henry Hub, $3.32 $2.00 $2.20 $2.40 $2.60 $2.80 $3.00 $3.20 $3.40 $3.60 March April May June $ /M c f U.S. Natural Gas Price – Select Hubs Coal preferred over natural gas above $3/MMBtu Loadings tracking below 2025 through the summer Increased diesel price lifts surface-mine costs Sources: U.S. Energy Information Administration; Bloomberg; Platts; STB rail loadings (through 08/26/2026). 36 38 39 41 31 32 35 37 May June July August PRB Train Loadings Daily Average 2025 Avg 2026 Avg $2.01 $2.19 $2.35 $2.20 $3.83 $3.33 $3.81 $4.17 May June July August US Diesel Benchmark $/gallon Daily Average 2025 2026
17 Coal Fuel Supply: Predictable Long-Term Pricing Stable PRB Coal Pricing vs. Volatile Natural Gas $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 $10.00 Ja n -1 6 Ju n -1 6 N o v- 1 6 A p r- 1 7 Se p -1 7 Fe b -1 8 Ju l- 1 8 D e c- 1 8 M a y- 1 9 O ct -1 9 M a r- 2 0 A u g- 2 0 Ja n -2 1 Ju n -2 1 N o v- 2 1 A p r- 2 2 Se p -2 2 Fe b -2 3 Ju l- 2 3 D e c- 2 3 M a y- 2 4 O ct -2 4 M a r- 2 5 A u g- 2 5 Ja n -2 6 H e n ry H u b $ /M M B tu P R B $ /M M B tu Prompt Month PRB Coal and Natural Gas Prices PRB 8800 Henry Hub • PRB coal delivers predictable and stable long-term pricing while natural gas price volatility and pipeline constraints introduce long-term risk for AI power. • Coal’s certainty translates into reliable, affordable 24/7 baseload power that is purpose-built for data center demand. • Potential material benefits from mine-mouth fuel economics: coal mine → power plant → data center colocation. North Antelope Rochelle: #1 Coal Mine Sources: OPIS; EIA; Peabody analysis.
2 18 New Opportunities for Peabody
19 Opening New West Coast Export Channels for PRB Coal Peabody successfully completed an initial test shipment through Mexico’s Port of Guaymas, loading a Panamax-sized vessel for delivery to an Asian customer. Port of Guaymas in Mexico and Port of Oakland in California PROVEN EXECUTION Loaded early June; delivered on time and to specification. DEMAND PULL Demonstrated interest from other Asian counterparties following initial shipment. NEXT STEPS Evaluating a second Guaymas test run and the new Port of Oakland project. Connecting the largest coal basin in the Western Hemisphere with the largest global demand center for thermal coal imports. North Antelope Rochelle, Wyoming Port of Oakland Port of Guaymas, Mexico Japan & Korea Taiwan Philippines Vietnam POTENTIAL MARGIN EXPANSION Opportunity to leverage seaborne markets to enhance margins
20 Unlocking Additional Value from Our Vast Reserves and Land Opportunistic capital-light approach to further enhance shareholder value METHANE-TO-POWER AT CENTURION Capturing methane that would otherwise be flared and converting to onsite power. Generating ~25% of Centurion’s power needs. R3 RENEWABLES ON FORMER MINE LANDS Partnering with RWE to develop solar and battery storage projects on formerly mined land in Illinois and Indiana. RARE EARTHS / CRITICAL MINERALS Developing flowsheets and commercialization plans for rare earths/critical minerals from coal mining operations. DATA CENTERS / MINE-MOUTH GENERATION Advancing potential development of mine-mouth generation and data center pairing. Project Next StepsValue Proposition • Planned expansion from 5 MW to 20 MW. • Improve safety, reduce costs and lower emissions. • Annualized cost savings of $425k from current 5MW plant. • Final stages of commercial advancement of first solar projects at Gateway, Bear Run and Francisco. • Upgrade land use, earn success fees and attractive ROI. • Potential success fees positioned to begin in 1H 2027. • Nearing agreement with major customer, processing partner based on promising germanium concentrations. • Peabody coal/overburden contains major REE/CMs. • 470 million cubic yards of PRB earth moved/year. • Continued coordination with U.S. Government, data center development partner and local/state stakeholders. • Garner income from higher- value land use, greater coal sales, project development fees. Peabody Development: Leveraging 2.0 billion tons of coal reserves1 and 335,000 acres of surface lands2 1) Proven and probable reserves as of 12/31/2025. 2) As of 12/31/2025.
2 21 The Investment Case
22 A Disciplined Shareholder-Return Framework REINVEST IN THE BUSINESS Sustaining capital plus high-return organic growth. BALANCE SHEET PROTECTION Net-cash position and maintain sufficient liquidity to execute strategy throughout price cycles. RETURN EXCESS CASH 65-100% of Available FCF 1 returned to shareholders. Capital allocation built to return excess cash, fund modest organic growth, and protect the balance sheet 143.9 128.7 121.4 121.6 121.9 95 105 115 125 135 145 12/31/2022 12/31/2023 12/31/2024 12/31/2025 6/30/2026 1H26 PAYOUT RATIO 100% $145.3M of Available Free Cash Flow1, including the reduction in restricted cash and collateral. $145.6M applied to the convertible note repurchase premium and $18.3M of cash dividends paid. Reduction of Outstanding Shares (shares in millions) 1H26 financial metrics as of 6/30/2026. 1) Available FCF is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix.
23 $811 $460 1Q 2Q Restricted Cash and Collateral Recent Financial Actions Further Strengthen Capital Structure CONVERTIBLE NOTE REFINANCE • Issued $250 million of 0.50% notes due 2031; repurchased $241.2 million of the 3.25% 2028 notes. • Reduced net potential share dilution by 6.2 million shares. • Capped call effectively increases new convertible dilution threshold to ~$51/share. STANDARD SURETY AGREEMENTS • Mutually terminated the U.S. surety support agreement. • New A$700 million asset backed Australian bond facility. • $351 million restricted cash and collateral returned to company. REVOLVING CREDIT FACILITY • Commitments increased to $400 million from $320 million; maturity extended to 2030. • Interest rate reduced by 25 bps to SOFR plus 3.25–4.00% (no borrowing). $320 $400 1Q 2Q Commitments (US$ in millions) ▼ $351M D E C R E A S E $10.4 $3.8 1Q 2Q Annual Interest ▼ $6.6M D E C R E A S E ▲ $80M I N C R E A S E
24 $20.82 $39.50 $28.85 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 2026 Low 2026 High Latest Close The Peabody Platform: The Diversified Choice + Material Upside Diversified exposure, Tier 1 growth and 65–100% of Available Free Cash Flow returned to owners Two Continents, Two Products Metallurgical and thermal coal mined from two continents — levered to global instability, AI power demand, Indian steel growth. Multiple macro trends, one investment Fortress Balance Sheet, Tier 1 Growth A well-capitalized balance sheet paired with Centurion entering full operating status selling premium metallurgical coal into a seaborne market currently pricing above $270 per tonne. Solid financial footing bolstered by tailwinds Free Cash Flow Returned to Owners Compounding tailwinds and a fortress balance sheet drive growing Available Free Cash Flow1, of which 65–100% is directed back to shareholders. Investors receive the lion’s share Sources: Platts premium low-vol HCC pricing; Peabody analysis. 1) Available FCF is a non-GAAP financial measure. Refer to the definitions and reconciliations to the nearest GAAP measure in the appendix. BTU Price Upside (January 1, 2026– September 4, 2026) 2026 high reached before Centurion commissioning challenges – which are now resolved 2026 Low: $20.82 (July 29) | 2026 High: $39.50 (March 27) | Latest Close: $28.85 (September 4)
25 Investor Relations Contact: Kala Finklang ir@peabodyenergy.com
2 26 Appendix
27 NARM Investor Site Visit & Presentation 2026 mine tour on September 23rd • Our investor and analyst community is invited to our 2026 Investor Site Visit at our North Antelope Rochelle Mine in Wyoming. • Following the tour, we will have a presentation and Q&A with Peabody executive leadership. • Space is limited and is first-come, first- served. • Contact the Peabody IR team for more information and to RSVP.
28 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. 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 12.4 - 13.0 8.3 $60.19 $49.50 - $54.50 Seaborne Thermal (Export) 7.9 - 8.5 3.8 $91.20 N/A Seaborne Thermal (Domestic) 4.5 4.5 $34.00 N/A Seaborne Metallurgical 8.8 - 10.3 4.5 $143.57 $130.00 - $145.00 PRB U.S. Thermal 82.0 - 88.0 80.8 $13.65 $12.00 - $12.50 Other U.S. Thermal 13.2 - 14.2 13.6 $56.70 $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 70-80% 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 June 30, 2026. Weighted average quality for the PRB segment 2026 volume is approximately 8,730 BTU.
29 Average Market Pricing by Quarter 06/30/2026 03/31/2026 12/31/2025 09/30/2025 06/30/2025 Premium low vol hard coking coal (Premium HCC)(1) $238.27 $234.67 $200.13 $183.51 $184.22 Premium low vol pulverized coal injection (Premium PCI) coal(1) $161.49 $161.15 $140.07 $143.24 $137.77 Newcastle index thermal coal (NEWC) (1) $135.86 $118.75 $107.66 $108.76 $100.49 API 5 index thermal coal(1) $96.51 $80.84 $77.57 $69.09 $68.28 PRB 8,800 Btu/Lb coal(2) $15.02 $15.12 $15.01 $14.21 $14.10 Illinois Basin 11,500 Btu/Lb coal(2) $55.14 $53.46 $50.55 $48.64 $46.52 (1) Spot pricing expressed per metric tonne. (2) Prompt month pricing expressed per short ton.
30 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
31 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
32 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
33 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
34 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.
35 Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on slide 40. 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 slide 40. 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 slide 40. 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: Refer to definitions and footnotes on slide 40. Six Months Ended June 30, 2026 Available Free Cash Flow (In Millions) (5) Net Cash Provided By Operating Activities $ 28.6 Net Cash Used In Investing Activities (184.1) Distributions to Noncontrolling Interests (7.7) Changes to Restricted Cash and Collateral (6) 308.5 Available Free Cash Flow (5) $ 145.3
39 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) Available Free Cash Flow, which is a non-GAAP financial measure, is defined as operating cash flow less investing cash flow and distributions to noncontrolling interests, plus/minus changes to restricted cash and collateral and other anticipated expenditures. Available Free Cash Flow is used by management as a measure of our ability to generate excess cash flow from our business operations. 6) This amount is equal to the total change in Restricted Cash and Collateral on the balance sheet, excluding partially offsetting amounts included in operating cash flow consisting of an inflow of $75.8 million for the six months ended June 30, 2026. 7) Adjusted EBITDA Margin per Ton 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. 8) Costs per Ton 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. 9) 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.