Peabody Energy (BTU) 8-K Investor Presentation August 2019

Exhibit 99.1

Investor Presentation August 2019

Statement on Forward-Looking 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 management’s current expectations or predictions of future conditions, events or results. All statements that address operating performance, events or developments that Peabody and Arch expect will occur in the future are forward-looking statements. They may include estimates of value accretion, joint venture synergies, closing of the joint venture, revenues, income, earnings per share, cost savings, capital expenditures, dividends, share repurchases, liquidity, capital structure, market share, industry volume, or other financial items, descriptions of management’s plans or objectives for future operations, or 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 and Arch’s good faith beliefs, assumptions and expectations, but they are not guarantees of future performance or events. Furthermore, each Peabody and Arch disclaim 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 and Arch’s control, including (i) risks that the proposed joint venture may not be completed, including as a result of a failure to obtain required regulatory approvals, (ii) risks that the anticipated synergies from the proposed joint venture may not be fully realized, including as a result of actions necessary to obtain regulatory approvals, (iii) other factors that are described in Peabody’s Annual Report on Form10-K for the fiscal year ended Dec. 31, 2018, (iv) other factors that are described in Arch’s Annual Report on Form10-K for the fiscal year ended Dec. 31, 2018 and (v) other factors that Peabody or Arch 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 and Arch’s website at www.archcoal.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

Peabody: Leading Global Pure-Play Coal Producer Note: Adjusted EBITDA and Free Cash Flow arenon-GAAP financial measures. Refer to the reconciliation to the nearest GAAP measures in the appendix. All metrics for calendar-year 2018, with the exception of awards received , 3 which cover the past decade.

Scale and Diversity Offer Significant Competitive Advantage Percentage of Total Revenue from Customer • Wide distribution Geographic Region in 2018 of revenue, Adjusted China South EBITDA contributions India Korea • Multi-regional exposure limits demand, logistics and Australia Other seasonal operational risks • Increased risk-adjusted Taiwan returns;Non-correlative demand drivers • No single exposure to currency and economic Japan fundamentals U.S. • Regulatory, political diversification Note: The company attributes revenue to individual regions based on the location of the physical delivery 4 of the coal. Revenue breakdown for FY 2018. Adjusted EBITDA isnon-GAAP financial measure.

Among Top Global Producers with Diverse Production Portfolio; Well-Positioned to Serve Long-Term Coal Demand Seaborne Thermal Coal Producers by Volume 1H 2019 Adjusted EBITDA 130 by Mining Portfolios (million tons) Global Producers U.S. Producers Seaborne BTU Met 35 32 32 $174.6M 19 15 11 8 5 3 Metallurgical Coal Producers by Volume 47 (million tons) U.S. Seaborne Peabody: largest Thermal 29 Thermal 24 $235.6M U.S.-Listed met $169.1M 18 coal producer 13 12 8 7 4 3 1 Source: Industry sources; 2018 production volume. BTU seaborne thermal production includes Australian domestic tons and met coal production includes ~2 million tons from Middlemount Mine. Includes only private-sector coal producers. Seaborne Met Adjusted EBITDA excludes net North Goonyella costs. Adjusted EBITDA is anon-GAAP financial measure. 5 Refer to the reconciliation to the nearest GAAP measures in the appendix.

Peabody Implementing Multiple Strategies in Support of Mission to Create Superior Value for Shareholders 1) Continuing to reweight our investments toward greater seaborne thermal and Creek excels seaborne metallurgical coal access t 6 months to capture higher-growth Asian demand 2) Optimizing our lowest-cost and highest-margin U.S. thermal RB/Colorado joint assets in alow-capital fashion ure expected to create to maximize cash generation ubstantial synergies 3) Executing our financial appr llion Returned generating cash, maintaining financial areholders in strength, investing wisely and returning cash to shareholders han 2 years 6

Seaborne Metallurgical Shoal Creek Mine

Seaborne Metallurgical: Shoal Creek Upgrades Portfolio; Opportunities for Development/Organic Growth Over Time • Metallurgical coal serves as HVA and HCC Index Price primary component for ~70% (USD per tonne) of world’s steel production $400 $300 • Strong demand growth Avg: $174 per tonne from China and India YTD $200 – India met coal imports expected $100 to surpass China over time $0 • Australia projected to supply majority of met coal growth Peabody Actions • Continuing to capture value from high-quality,low-cost Shoal Creek Mine • Progressing opportunities at Moorvale Mine to extend life beyond 2025 with increased quality as early as 2020 8 Source: Industry reports and Peabody Global Analytics.

Shoal Creek Acquisition Upgrades Seaborne Met Portfolio; Represents Multiple Strategic and Financial Benefits • YTD cash flows imply payback period of less than 2 years • Targeting ~2.5 million tons of high-quality HVA seaborne met coal shipments in 2019 • Mine well-capitalized – Includes two longwall kits, removing customary lag for longwall moves, improving production levels • Direct access to barge eliminates rail costs and performance issues • Proven and probable reserves total 55 million tons 9 Note: Proven and probable reserves as estimated as of Dec. 31, 2018.

Peabody Assessing Prospective Paths, Timetables and Costs for North Goonyella to Maximize Value All potential paths preserve opportunity to access more than 40 million tons of HCC in lower seam reserves over time 10 Note: Mine map not to scale. For illustration purposes only.

Seaborne Thermal Wilpinjong Mine

Seaborne Thermal: Well Positioned to Serve Higher-Growth Asia-Pacific Demand • Global coal generation capacity Global Coal Generation Capacity surpasses 2,000 GW for first time ~2,015 GW 62% increase from ever in 2018 per WoodMac 2000 to 2018 • ~45 gigawatts of new coal-fueled ~1,245 GW generation expected to come online in 2019 • IHS Markit projects Southeast Asia’s coal fleet to double in size by 2030 Peabody Actions 2000 2018 • 3.6 million tons priced at ~$83 per short ton for 2019 – 2.1 million tons priced for 2020 above the NEWC forward curve • United Wambo Joint Venture with Glencore anticipated to form later this year; Production expected in 2020 Source: Source: Industry Industry sources reports and and Peabody Peabody Global Global Energy Analytics. Analytics. Source: Wood Mackenzie: “Outlook and Benefits of an Efficient U.S. Coal Fleet.” © 2019 IHS Markit. All rights reserved. The use of this content was authorized in advance. Any 12 further use or redistribution of this content is strictly prohibited without prior written permission by IHS Markit.

Seaborne Thermal Coal Platform RepresentsTier-One Assets; Expected Costs of $32 – $36 Per Short Ton for 2019 Seaborne Thermal Coal Adjusted EBITDA Margins Margin % Average NEWC Price per Tonne 50% 48% 44% 45% 42% 40% $117 40% 38% 38% 37% $103 $104 $105 34% 35% $98 $93 31% $97 30% $80 $80 25% 20% 15% 10% 5% 0% Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Note: Adjusted EBITDA margins is anon-GAAP operating/statistical measure. Adjusted EBITDA margin is equal to segment Adjusted EBITDA divided by segment revenue. Refer to the reconciliation to the nearest GAAP measure in the appendix. 13

U.S. Thermal Rawhide Mine

U.S. Thermal:Two-Thirds of Shipments Go to Regions That Generate More than 40% of Electricity From Coal Positioning NYISO Coal: 1% essential Rockies SPP BTU: NW Power Coal: 51% Coal: 43% Pool Gas 0 mt given intense BTU: BTU: MISOISO-NE Coal: 33% 3 mt 30 mt Coal: 1% BTU: 1 mt Coal: 47%all-fuels BTU: PJM BTU: 68 mt Coal: 28% 0 mt BTU: competition CAISO Desert SW 13 mt Coal: 2% Coal: 32% BTU: BTU: 0 mt 13 mt SERC FRCC ERCOT Coal: 30% Coal: 25% Coal: 16% BTU: BTU: BTU: 9 mt 12 mt <1 mt >20% of electricity from coal <20% of electricity from coal Peabody Actions • Operating adjacent mines as complexes where possible • Advancing PRB/Colorado joint venture aimed at strengthening competitiveness against natural gas and renewables – Expected to benefit multiple stakeholders, including customers and shareholders Source: Industry reports and Peabody Global Analytics. 15

JV Expected to UnlockPre-Tax Synergies of ~$820 Million; Projected10-Year Average Synergies of ~$120 Million Per Year • Integration projected to lead to substantial synergies, including: of mine planning Progress Update – Optimization and sequencing and accessing • Advancing regulatory otherwise isolated reserves approval process – Improved efficiencies in deployment of combined equipment fleet • Early support from – More efficient procurement, warehousing multiple stakeholders – Enhanced blending capabilities to more closely meet customer requirements • Synergies continuing to – Improved utilization of combined rail be refined and evaluated loadout system, other rail efficiencies for further opportunities – Reductions in long-term capital requirements – Leveraging Peabody’s shared services • NARM and Black Thunder to operate as a single complex Note: Synergies of approximately $820 million represent the combined net present value of estimatedpre-tax synergies for the joint venture projected over standalonelife-of-mine plans assuming third-party price assumptions and a 10 percent 16 discount rate. Average combined synergies of approximately $120 million per year projected over initial 10 years.

Financial Approach

Peabody Taking Aggressive Steps to Return Cash to Shareholders Highly active share repurchase program Target to return amount greater than 2019 free cash flow Third increase to quarterly dividend per share in just one year Periodic review of supplemental dividends Actions move Peabody closer to liquidity target Maintaining debt athigh-end of targeted range Note: Free Cash Flow is anon-GAAP financial measure. Refer to the reconciliation to the nearest GAAP measure in 18 the appendix.

BTU Offers Significant Intrinsic Value; Generating 2018 Results Superior to Benchmarks SG&A as a Adjusted EBITDA Return on TEV/EBITDA % of Revenue Margin Equity 11.4x 25% 22% 18% 17% 16% 14% 6.2x 13% 5.4x 9% 6% 2.6x 4% 3% BTU Coal & Consumable Fuels S&P 400 -8% S&P 400—Energy Source: CapitalIQ; Coal and Consumable Fuel group per CapitalIQ includes 199 companies. TEV/EBITDA represents market capitalization as of May 6, 2019 plus net debt divided by 2018 EBITDA per CapitalIQ. Adjusted EBITDA (may not be calculated identically by all companies), return on equity and TEV/EBITDA arenon-GAAP financial measures. Refer to 19 the appendix for a reconciliation of these metrics.

Financial Approach: Peabody Intends to Return to Shareholders Amount Greater Than Free Cash Flow in 2019 Investment Filters Cumulative Shareholder Returns ($ in millions) ✓ Strategic portfolio fit $1,506 ✓ Maintains financial strength ✓ Generates returns above cost of capital ✓ Provides a reasonable payback period ✓ Provides tangible synergies $176 ✓ Creates significant value for our shareholders 2017 2018Jul-19 Share Repurchases Quarterly Dividend Supplemental Dividend Note: Share repurchases from August 2017 to July 30, 2019. 20

Commitment to Shareholder Returns Brings Liquidity Closer to Targeted Liquidity Levels; Operating at High End of Debt Range Debt & Liquidity June June • Reduced total liabilities since Change ($ in millions) 2017 2019mid-2017 by ~$1.19 billion Unrestricted Cash $1,096 $853 ($243) – $550 million voluntary & Cash Equivalents debt reduction Revolver Availability $0 $279 $279 Total debt within $1.2 billion • ARS Availability $78 $70 ($8) to $1.4 billion target range Total Liquidity $1,174 $1,202 $28 • ARO supported by $1.36 billion Total Funded Debt $1,957 $1,356 ($601) of surety bonds Net Debt $861 $503 ($358) – Targeting 2019 reclamation cash outlays of ~$50 million Other LT Liabilities June June Change ($ in millions) 2017 2019 • Liquidity in excess of OPEB $746 $521 ($225) $800 million target ARO $635 $699 $64 • EBITDA to cash conversion strong with substantial NOL position Pension $151 $13 ($138) – $3.2 billion in U.S. Other LT Liabilities $257 $315 $58 – A$3.3 billion in Australia Total LT Liabilities $3,746 $2,904 ($842) Note: Liability balances representnon-current balances. Adjusted EBITDA and Net Debt arenon-GAAP financial measures. Net Debt is equal to Total Debt less Cash and Cash Equivalents. Refer to the reconciliation to the nearest GAAP measures 21 in the appendix. NOL balances as of Dec. 31, 2018.

Peabody’s Emphasis on ESG Complements Financial Approach to Create Long-Term Value for Shareholders Environmental Social Governance • Restored 1.4 acres • Outperforms • Separation of CEO for every acre industry averages and Chairman disturbed in 2018 for safety • Independent and • Recycled/reused • Provided $11.5 billion diverse board skills 48% of total water in direct/indirect and experiences withdrawn; economic benefits • Exec compensation 61% of waste • Member of UN based on safety, free • Advocate for Global Compact cash flow per share,low-emissions Adjusted EBITDA, • Signatory to CEO technologies ROIC, TSR, Action for Diversity environmental & Inclusion® pledge performance Recognized with ~100 honors in past decade for Safety, Reclamation and Corporate leadership Note: All figures for 2018 calendar year. Peabody’s 2018 ESG Report is available on PeabodyEnergy.com. 22

Peabody Holds Favorable ESG Position Among Peers in ISS Ratings Environmental Social Governance Lower Score represents Reduced Governance risk and Better Environmental 3 and Social Disclosure 2 8 5 7 5 6 1 5 7 9 2 7 2 5 1 3 1 2 2 1 Peabody Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Note: ISS Governance, Environmental and Social QualityScores. Score of 1 represents lower governance risk and higher environmental and social disclosure. Peers include Arch, Consol Energy, Glencore, Teck, Warrior and Whitehaven as of 23 Aug. 5, 2019.    

Appendix

2019 Guidance Targets Sales Volumes (Short Tons in millions) PRB 105 – 115 Quarterly SG&A Expense ~$40 million ILB 17.5 – 18.5 Full-Year Capital Expenditures $350 – $375 million Western 11 – 12 Full-Year DD&A $600 – $650 million Seaborne Metallurgical 9.4 – 10.4 Full-Year Interest Expense4 ~$150 million HCC1: 40% – 50% Full-Year ARO Cash Spend ~$50 million PCI2: 50% – 60% Cost Sensitivities5 Seaborne Export Thermal 12.0 – 12.5 $0.05 Decrease in A$ FX Rate6 + ~$45 million NEWC: 60% – 70% $0.05 Increase in A$ FX Rate6—~$45 million API 5: 30% – 40% Fuel (+/- $10/barrel) +/- ~$15 million Australia Domestic Thermal 7 – 8 2019 Priced Position (Avg. Price per Short Ton) Revenues per Ton PRB $11.22 Total U.S. Thermal $17.10 – $18.10 ILB ~$43 Seaborne Export Thermal Volumes (Q3 – Q4) 7 ~$83 Costs Per Ton (USD per Short Ton) ~98% of Peabody’s 2019 U.S. thermal volumes are priced PRB $9.25 – $9.75 based on themid-point of 2019 volume guidance ILB $32 – $35 ~3.6 million short tons of seaborne export thermal coal priced (Q3 – Q4) 7 Total U.S. Thermal $13.95 – $14.95 2020 Priced Position (Avg. Price per Short Ton) ~50% and ~65% of Peabody’s 2020 U.S. thermal volumes are priced and Seaborne Thermal3 $32 – $36 committed, respectively, based on themid-point of 2019 volume (includes Aus. Domestic Thermal) guidance8 Seaborne Metallurgical3 $90 – $95 Seaborne Export Thermal Volumes ~$77 (excluding North Goonyella) ~2.1 million short tons of seaborne export thermal coal priced for 2020 25

2019 Guidance Targets 1 Peabody expects to realize~80%-90% of the premium HCC quoted index price on a weighted average across its HCC products. 2 Approximately 40% of Peabody’s seaborne metallurgical PCI sales are on a spot basis, with the remainder linked to the quarterly contract. Peabody expects to realize~80%-90% of the LV PCI benchmark for its PCI products. 3 Assumes 2019 average A$ FX rate of $0.70. Cost ranges include sales-related cost, which will fluctuate based on realized prices. 4 Interest expense includes interest on funded debt, surety bonds, commitment fees and letters of credit fees issued under the revolver and accounts receivable securitization program, andnon-cash interest related to certain contractual arrangements and amortization of debt issuance costs. 5 Sensitivities reflect approximate impacts of changes in variables on financial performance. When realized, actual impacts may differ significantly. 6 As of June 30, 2019, Peabody had outstanding average rate call options to manage market price volatility associated with the Australian dollar in aggregate notional amount of approximately AUD $1 billion with strike price levels ranging from $0.74 to $0.77 with settlement dates through March 31, 2020. Sensitivities provided are relative to an assumed average A$ FX exchange rate of ~$0.70 as of June 30, 2019. 7 Approximately40%-50% of Peabody’s unpriced seaborne thermal export volumes is NEWC-specification, with the remainder closer to an API5 product. 8 2019 U.S. volume guidance includes volumes associated with the Kayenta Mine, within the Western segment, which is scheduled to cease operations within the third quarter of 2019. Note 1: Peabody classifies its seaborne metallurgical or thermal segments based on the primary customer base and reserve type. A small portion of the coal mined by the seaborne metallurgical segment is of a thermal grade and vice versa. Peabody may market some of its metallurgical coal products as a thermal product from time to time depending on industry conditions. Per ton metrics presented arenon-GAAP 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. Note 2: A sensitivity to changes in seaborne pricing should consider Peabody’s estimated split of products and the weighted average discounts across all products to the applicable index prices, in addition to impacts on sales-related costs, and applicable conversions between short tons and metric tonnes as necessary. Note 3: As of July 30, 2019, Peabody had approximately 104.0 million shares of common stock outstanding. Including approximately 3 million shares of unvested equity awards, Peabody has approximately 107 million shares of common stock on a fully diluted basis. 26

Historical Seaborne Pricing ($/Tonne) Time HCC – HCC – LV PCI – LV PCI – NEWC – API 5 –Period Settlement Spot Settlement Spot Prompt Prompt Q2 2019 $208 $203 $138.50 $125 $80 $57 Q1 2019 $210 $206 $141 $126 $97 $60 Q4 2018 $212 $221 $139 $128 $105 $63 Q3 2018 $188 $189 $150 $128 $117 $69 Q2 2018 ~$197 $190 $155 $140 $104 $75 Q1 2018 $237 $228 $156.50 $149 $103 $82 Q4 2017 $192 $205 $127 $126 $98 $76 Q3 2017 $170 $189 $115/$127 $117 $93 $74 Q2 2017 $194 $190 $135 $124 $80 $67 Q1 2017 $285 $169 $180 $110 $82 $65 Q4 2016 $200 $266 $133 $159 $94 $73 Q3 2016 $93 $135 $75 $88 $66 $55 Q2 2016 $84 $91 $73 $72 $52 $43 Source: HCC, LV PCI, and NEWC spot prices per Platts; API5 spot prices per Platts through Q1 2019, and per 27 Argus/McCloskey Weekly Index for Q2 2019. Settlement prices per IHS Markit benchmark history.    

Advanced Technologies Offer Path for Significant Reduction in Emissions from Coal-Fueled Generation CO2 Reduction Potential of Advanced Coal Technologies Subcritical CO2 Reduction 30% 1,116g CO2/kWh Supercritical ISOGO Power Station, Japan 21% kWh 38% 33% 881g CO /kWh Gas OCGT per 2 45% 40% 700 CO2/kWh 743g CO2/kWh 50% 669g CO2/kWh Gas CCGT CCS Technology 450 CO /kWh Emissions (efficiency loss 2 2 CO Efficiency7-12% points) CO2 Emissions 90% + Boundary Dam, Canada • Nearly 1,000 GW of HELE plants Major coal consumers in use or under construction include advanced coal • Raising efficiency of coal-fueled plants to 40% technologies in NDCs from 35% today reduces global emissions by 2 to Paris agreement gigatons – or the equivalent of India’s annual total Source: World Coal Association/VGB PowerTech 2013 . 28

Proven Access to Capital Markets Strengthens Financial Position; Allows for Significant Cash Returns to Shareholders $500 million Second increase Third share Quarterly to quarterly increase repurchase dividend per dividend to quarterly program Quarterly share increased per share dividend authorized dividend Upsized $1.5 billion Share buyback per share initiated share Supplemental in equity authorization repurchase dividend raised expanded to program to declared $1.5 billion $1.0 billion 2017    2018    2019 $1.95 billion Securedfirst-of- Executed consent Reduced term debt raised;its-kind third-party solicitation for loan interest; Offering over- surety program Senior Notes to Increased ability subscribed in Australia expand restricted to execute share Extended buybacks payment capacity ARS program; $1.3 billion Further reduced Reduced third-party Reached term loan interest pricing U.S. bonding deleveraging rate; Extended facilities targets ahead maturity to 2025 secured of schedule 29

Reconciliation ofNon-GAAP Measures Apr. 2 through Quarter Ended Quarter Ended Jun. 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Tons Sold (In Millions) Seaborne Thermal Mining Operations 4.6 5.2 4.8 Seaborne Metallurgical Mining Operations 2.0 3.5 4.0 Powder River Basin Mining Operations 28.5 33.7 31.8 Midwestern U.S. Mining Operations 4.6 4.9 4.5 Western U.S. Mining Operations 3.2 4.0 4.1 Total U.S. Thermal Mining Operations 36.3 42.6 40.4 Corporate and Other 0.7 0.7 0.6 Total 43.6 52.0 49.8 Revenue Summary (In Millions) Seaborne Thermal Mining Operations $ 239.2 $ 265.8 $ 267.5 Seaborne Metallurgical Mining Operations 287.8 415.9 517.3 Powder River Basin Mining Operations 365.4 420.9 392.4 Midwestern U.S. Mining Operations 194.9 207.7 189.7 Western U.S. Mining Operations 125.4 155.7 159.6 Total U.S. Thermal Mining Operations 685.7 784.3 741.7 Corporate and Other 45.6 11.2 (9.4) Total $ 1,258.3 $ 1,477.2 $ 1,517.1 30

Reconciliation ofNon-GAAP Measures Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Mar. 31, 2018 Jun. 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Tons Sold (In Millions) Seaborne Thermal Mining Operations 3.8 5.0 4.8 5.5 19.1 Seaborne Metallurgical Mining Operations 3.0 2.9 2.8 2.3 11.0 Powder River Basin Mining Operations 32.4 26.2 31.7 30.0 120.3 Midwestern U.S. Mining Operations 4.7 4.7 4.9 4.6 18.9 Western U.S. Mining Operations 3.7 3.5 4.0 3.5 14.7 Total U.S. Thermal Mining Operations 40.8 34.4 40.6 38.1 153.9 Corporate and Other 0.7 0.8 0.9 0.3 2.7 Total 48.3 43.1 49.1 46.2 186.7 Revenue Summary (In Millions) Seaborne Thermal Mining Operations $    201.4 $    267.4 $    305.1 $    325.3 $    1,099.2 Seaborne Metallurgical Mining Operations 466.2 417.5 370.3 299.0 1,553.0 Powder River Basin Mining Operations 389.3 321.5 373.7 340.3 1,424.8 Midwestern U.S. Mining Operations 201.7 197.5 208.5 193.3 801.0 Western U.S. Mining Operations 143.7 139.6 156.1 152.6 592.0 Total U.S. Thermal Mining Operations 734.7 658.6 738.3 686.2 2,817.8 Corporate and Other 60.4 (34.1) (1.1) 86.6 111.8 Total $    1,462.7 $ 1,309.4 $ 1,412.6 $ 1,397.1 $    5,581.8

Reconciliation ofNon-GAAP Measures Quarter Ended Quarter Ended Six Months Ended Mar. 31, 2019 Jun. 30, 2019 Jun. 30, 2019 Tons Sold (In Millions) Seaborne Thermal Mining Operations 4.5 4.7 9.2 Seaborne Metallurgical Mining Operations 2.3 2.1 4.4 Powder River Basin Mining Operations 25.3 25.0 50.3 Midwestern U.S. Mining Operations 4.2 3.9 8.1 Western U.S. Mining Operations 3.7 3.3 7.0 Total U.S. Thermal Mining Operations 33.2 32.2 65.4 Corporate and Other 0.5 0.4 0.9 Total 40.5 39.4 79.9 Revenue Summary (In Millions) Seaborne Thermal Mining Operations $    251.0 $ 220.2 $    471.2 Seaborne Metallurgical Mining Operations 324.5 290.9 615.4 Powder River Basin Mining Operations 287.3 282.6 569.9 Midwestern U.S. Mining Operations 179.1 167.5 346.6 Western U.S. Mining Operations 155.7 142.1 297.8 Total U.S. Thermal Mining Operations 622.1 592.2 1,214.3 Corporate and Other 53.0 45.7 98.7 Total $ 1,250.6 $    1,149.0 $    2,399.6

Reconciliation ofNon-GAAP Measures Apr. 2 through Quarter Ended Quarter Ended Jun. 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Total Reporting Segment Costs (1) Summary (In Millions) Seaborne Thermal Mining Operations $ 133.3 $ 168.0 $ 164.6 Seaborne Metallurgical Mining Operations 215.9 272.8 317.4 Net North Goonyella Costs — -Seaborne Metallurgical Mining Operations, Excluding Net North Goonyella Costs 215.9 272.8 317.4 Powder River Basin Mining Operations 280.6 308.2 311.1 Midwestern U.S. Mining Operations 148.4 158.2 161.3 Western U.S. Mining Operations 80.5 121.2 107.2 Total U.S. Thermal Mining Operations 509.5 587.6 579.6 Corporate and Other 49.6 22.1 35.9 Total $ 908.3 $ 1,050.5 $ 1,097.5 Adjusted EBITDA (2) (In Millions) Seaborne Thermal Mining Operations $ 105.9 $ 97.8 $ 102.9 Seaborne Metallurgical Mining Operations 71.9 143.1 199.9 Net North Goonyella Costs — -Seaborne Metallurgical Mining Operations, Excluding Net North Goonyella Costs 71.9 143.1 199.9 Powder River Basin Mining Operations 84.8 112.7 81.3 Midwestern U.S. Mining Operations 46.5 49.5 28.4 Western U.S. Mining Operations 44.9 34.5 52.4 Total U.S. Thermal Mining Operations 176.2 196.7 162.1 Middlemount (3) 10.0 7.7 13.7 Resource Management Results (4) 1.2 0.4 0.9 Selling and Administrative Expenses (34.7) (33.7) (37.9) Transactions Costs Related to Business Combinations and Joint Ventures — -Other Operating Costs, Net (5) (12.7) (0.7) (25.4) Adjusted EBITDA (2) $ 317.8 $ 411.3 $ p Note: Refer to definitions and footnotes on slides 40 and 41. 33

Reconciliation ofNon-GAAP Measures Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Mar. 31, 2018 Jun. 30, 2018 Se . 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Total Reporting Segment Costs (1) Summary (In Millions) Seaborne Thermal Mining Operations $ 139.8 $ 159.8 $ 159.8 $ 187.8 $ 647.2 Seaborne Metallurgical Mining Operations 299.8 259.0 279.6 273.2 1,111.6 Net North Goonyella Costs — 9.0 49.0 58.0 Seaborne Metallurgical Mining Operations, Excluding Net North Goonyella Costs 299.8 259.0 270.6 224.2 1,053.6 Powder River Basin Mining Operations 314.8 259.5 285.5 280.5 1,140.3 Midwestern U.S. Mining Operations 170.5 155.5 169.8 160.0 655.8 Western U.S. Mining Operations 111.7 105.7 127.6 101.6 446.6 Total U.S. Thermal Mining Operations 597.0 520.7 582.9 542.1 2,242.7 Corporate and Other 31.6 19.5 35.8 28.3 115.2 Total $ 1,068.2 $ 959.0 $ 1,058.1 $ 1,031.4 $ 4,116.7 Adjusted EBITDA (2) (In Millions) Seaborne Thermal Mining Operations $ 61.6 $ 107.6 $ 145.3 $ 137.5 $ 452.0 Seaborne Metallurgical Mining Operations 166.4 158.5 90.7 25.8 441.4 Net North Goonyella Costs — 9.0 49.0 58.0 Seaborne Metallurgical Mining Operations, Excluding Net North Goonyella Costs 166.4 158.5 99.7 74.8 499.4 Powder River Basin Mining Operations 74.5 62.0 88.2 59.8 284.5 Midwestern U.S. Mining Operations 31.2 42.0 38.7 33.3 145.2 Western U.S. Mining Operations 32.0 33.9 28.5 51.0 145.4 Total U.S. Thermal Mining Operations 137.7 137.9 155.4 144.1 575.1 Middlemount (3) 14.6 17.2 11.2 8.1 51.1 Resource Management Results (4) 20.8 0.7 21.3 1.9 44.7 Selling and Administrative Expenses (37.0) (44.1) (38.6) (38.4) (158.1) Transactions Costs Related to Business Combinations and Joint Ventures — (2.5) (4.9) (7.4) Other Operating Costs, Net (5) (0.2) (8.2) (10.7) (0.4) (19.5) Adjusted EBITDA (2) $ 363.9 $ 369.6 $ 372.1 $ 273.7 $ 1,379.3 Note: Refer to definitions and footnotes on slides 40 and 41. 34

Reconciliation ofNon-GAAP Measures Quarter Ended Quarter Ended Six Months Ended Mar. 31, 2019 Jun. 30, 2019 Jun. 30, 2019 Total Reporting Segment Costs (1) Summary (In Millions) Seaborne Thermal Mining Operations $ 156.3 $ 145.8 $ 302.1 Seaborne Metallurgical Mining Operations 238.7 233.5 472.2 Net North Goonyella Costs 3.0 28.4 31.4 Seaborne Metallurgical Mining Operations, Excluding Net North Goonyella Costs 235.7 205.1 440.8 Powder River Basin Mining Operations 250.9 242.4 493.3 Midwestern U.S. Mining Operations 145.8 136.8 282.6 Western U.S. Mining Operations 113.1 89.7 202.8 Total U.S. Thermal Mining Operations 509.8 468.9 978.7 Corporate and Other 20.4 20.1 40.5 Total $ 925.2 $ 868.3 $ 1,793.5 Adjusted EBITDA (2) (In Millions) Seaborne Thermal Mining Operations $ 94.7 $ 169.1 Seaborne Metallurgical Mining Operations 85.8 57.4 143.2 Net North Goonyella Costs 3.0 28.4 31.4 Seaborne Metallurgical Mining Operations, Excluding Net North Goonyella Costs 88.8 85.8 174.6 Powder River Basin Mining Operations 36.4 40.2 76.6 Midwestern U.S. Mining Operations 33.3 30.7 64.0 Western U.S. Mining Operations 42.6 52.4 95.0 Total U.S. Thermal Mining Operations 112.3 123.3 235.6 Middlemount (3) 3.9 10.0 13.9 Resource Management Results (4) 2.0 1.7 3.7 Selling and Administrative Expenses (36.7) (38.9) (75.6) Transactions Costs Related to Business Combinations and Joint Ventures—(1.6) (1.6) Other Operating Costs, Net (5) (8.1) 1.7 (6.4) Adjusted EBITDA (2) $ 253.9 $ 228.0 $ 481.9 Note: Refer to definitions and footnotes on slides 40 and 41. 35

Reconciliation ofNon-GAAP Measures Apr. 2 through Quarter Ended Quarter Ended Jun. 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Reconciliation ofNon-GAAP Financial Measures (In Millions) Income from Continuing Operations, Net of Income Taxes $ 101.4 $ 233.7 $ 378.0 Depreciation, Depletion and Amortization 148.3 194.5 178.8 Asset Retirement Obligation Expenses 11.0 11.3 18.9 Provision for North Goonyella Equipment Loss — -North Goonyella Insurance Recovery—Equipment (6) — -Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates (4.3) (3.4) (9.6) Interest Expense 41.4 42.4 35.9 Loss on Early Debt Extinguishment—12.9 8.0 Interest Income (1.5) (2.0) (2.1) NetMark-to-Market Adjustment on Actuarially Determined Liabilities — (45.2) Reorganization Items, Net — -Gain on Disposal of Reclamation Liability — (31.2) Gain on Disposal of Burton Mine Assets — (52.2) Break Fees Related to Terminated Asset Sales (28.0) —Unrealized (Gains) Losses on Economic Hedges (9.4) 10.8 21.6 Unrealized (Gains) Losses onNon-Coal Trading Derivative Contracts (3.2) 1.7 3.0 Fresh Start Coal Inventory Revaluation 67.3 —Fresh StartTake-or-Pay Contract-Based Intangible Recognition (9.9) (6.5) (6.1) Income Tax Provision (Benefit) 4.7 (84.1) (81.6) Adjusted EBITDA (2) $ 317.8 $ 411.3 $ 416.2 Operating Costs and Expenses $ 927.9 $ 1,039.1 $ 1,085.7 Break Fees Related to Terminated Asset Sales 28.0 —Unrealized Gains (Losses) onNon-Coal Trading Derivative Contracts 3.2 (1.7) (3.0) Fresh Start Coal Inventory Revaluation (67.3) —Fresh StartTake-or-Pay Contract-Based Intangible Recognition 9.9 6.5 6.1 North Goonyella Insurance Recovery—Cost Recovery and Business Interruption (6) —-Net Periodic Benefit Costs, Excluding Service Cost 6.6 6.6 8.7 Total Reporting Segment Costs (1) $ 908.3 $ 1,050.5 $ 1,097.5 Net Cash Provided By Operating Activities $ 65.7 $ 248.0 $ 499.7 Net Cash Used In Investing Activities (18.5) (16.4) (58.5) Add Back: Amount Attributable to Acquisition of Shoal Creek Mine — -Free Cash Flow (7) $ 47.2 $ 231.6 $ 441.2 Note: Refer to definitions and footnotes on slides 40 and 41. 36

Reconciliation ofNon-GAAP Measures Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Mar. 31, 2018 Jun. 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Reconciliation ofNon-GAAP Financial Measures (In Millions) Income from Continuing Operations, Net of Income Taxes $ 208.3 $ 120.0 $ 83.9 $ 233.5 $ 645.7 Depreciation, Depletion and Amortization 169.6 163.9 169.6 175.9 679.0 Asset Retirement Obligation Expenses 12.3 13.2 12.4 15.1 53.0 Provision for North Goonyella Equipment Loss — 49.3 17.1 66.4 North Goonyella Insurance Recovery—Equipment (6) — — -Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates (7.6) (8.4) (6.1) 3.8 (18.3) Interest Expense 36.3 38.3 38.2 36.5 149.3 Loss on Early Debt Extinguishment—2.0 — 2.0 Interest Income (7.2) (7.0) (10.1) (9.3) (33.6) NetMark-to-Market Adjustment on Actuarially Determined Liabilities ——(125.5) (125.5) Reorganization Items, Net (12.8) ——(12.8) Gain on Disposal of Reclamation Liability — — -Gain on Disposal of Burton Mine Assets — — -Break Fees Related to Terminated Asset Sales — — -Unrealized (Gains) Losses on Economic Hedges (38.6) 48.1 26.8 (54.6) (18.3) Unrealized (Gains) Losses onNon-Coal Trading Derivative Contracts 1.8 (0.1) (0.3) (0.7) 0.7 Fresh Start Coal Inventory Revaluation — — -Fresh StartTake-or-Pay Contract-Based Intangible Recognition (8.3) (7.8) (5.4) (5.2) (26.7) Income Tax Provision (Benefit) 10.1 7.4 13.8 (12.9) 18.4 Adjusted EBITDA (2) $ 363.9 $ 369.6 $ 372.1 $ 273.7 $ 1,379.3 Operating Costs and Expenses $ 1,057.2 $ 946.5 $ 1,047.9 $ 1,021.0 $ 4,072.6 Break Fees Related to Terminated Asset Sales — — -Unrealized Gains (Losses) onNon-Coal Trading Derivative Contracts (1.8) 0.1 0.3 0.7 (0.7) Fresh Start Coal Inventory Revaluation — — -Fresh StartTake-or-Pay Contract-Based Intangible Recognition 8.3 7.8 5.4 5.2 26.7 North Goonyella Insurance Recovery—Cost Recovery and Business Interruption (6) — —-Net Periodic Benefit Costs, Excluding Service Cost 4.5 4.6 4.5 4.5 18.1 Total Reporting Segment Costs (1) $ 1,068.2 $ 959.0 $ 1,058.1 $ 1,031.4 $ 4,116.7 Net Cash Provided By Operating Activities $ 579.7 $ 335.7 $ 345.4 $ 228.9 $ 1,489.7 Net Cash Used In Investing Activities (6.4) (11.6) (47.5) (451.8) (517.3) Add Back: Amount Attributable to Acquisition of Shoal Creek Mine ——387.4 387.4 Free Cash Flow (7) $ 573.3 $ 324.1 $ 297.9 $ 164.5 $ 1,359.8 Note: Refer to definitions and footnotes on slides 40 and 41. 37

Reconciliation ofNon-GAAP Measures Quarter Ended Quarter Ended Six Months Ended Mar. 31, 2019 Jun. 30, 2019 Jun. 30, 2019 Reconciliation ofNon-GAAP Financial Measures (In Millions) Income from Continuing Operations, Net of Income Taxes $ 133.3 $ 42.9 $ 176.2 Depreciation, Depletion and Amortization 172.5 165.4 337.9 Asset Retirement Obligation Expenses 13.8 15.3 29.1 Provision for North Goonyella Equipment Loss 24.7—24.7 North Goonyella Insurance Recovery—Equipment (6) (91.1)—(91.1) Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates—0.3 0.3 Interest Expense 35.8 36.0 71.8 Loss on Early Debt Extinguishment — -Interest Income (8.3) (7.2) (15.5) NetMark-to-Market Adjustment on Actuarially Determined Liabilities — -Reorganization Items, Net — -Gain on Disposal of Reclamation Liability — -Gain on Disposal of Burton Mine Assets — -Break Fees Related to Terminated Asset Sales — -Unrealized (Gains) Losses on Economic Hedges (39.8) (22.4) (62.2) Unrealized (Gains) Losses onNon-Coal Trading Derivative Contracts (0.2) 0.3 0.1 Fresh Start Coal Inventory Revaluation — -Fresh StartTake-or-Pay Contract-Based Intangible Recognition (5.6) (5.6) (11.2) Income Tax Provision (Benefit) 18.8 3.0 21.8 Adjusted EBITDA (2) $ 253.9 $ 228.0 $ 481.9 Operating Costs and Expenses $ 948.4 $ 858.2 $ 1,806.6 Break Fees Related to Terminated Asset Sales — -Unrealized Gains (Losses) onNon-Coal Trading Derivative Contracts 0.2 (0.3) (0.1) Fresh Start Coal Inventory Revaluation — -Fresh StartTake-or-Pay Contract-Based Intangible Recognition 5.6 5.6 11.2 North Goonyella Insurance Recovery—Cost Recovery and Business Interruption (6) (33.9)—(33.9) Net Periodic Benefit Costs, Excluding Service Cost 4.9 4.8 9.7 Total Reporting Segment Costs (1) $ 925.2 $ 868.3 $ 1,793.5 Net Cash Provided By Operating Activities $ 197.6 $ 179.4 $ 377.0 Net Cash Used In Investing Activities (38.1) (25.9) (64.0) Add Back: Amount Attributable to Acquisition of Shoal Creek Mine 2.4—2.4 Free Cash Flow (7) $ 161.9 $ 153.5 $ 315.4 Note: Refer to definitions and footnotes on slides 40 and 41. 38

Reconciliation ofNon-GAAP Measures Reconciliation ofNon-GAAP Financial Measures (In Millions) Dec. 31, 2017 Dec. 31, 2018 Average Total Stockholders’ Equity $ 3,655.8 $ 3,451.6 $ 3,553.7 Jun. 30, 2017 Dec. 31, 2018 Mar. 31, 2019 Total Debt $ 1,957.1 $ 1,367.0 $ 1,361.7 Cash and Cash Equivalents 1,095.7 981.9 798.1 Net Debt (8) $ 861.4 $ 385.1 $ 563.6 May 6, 2019 Shares Outstanding 107.0 Share Price $ 29.20 Market Capitalization $ 3,124.4 Market Capitalization as of May 6, 2019 $ 3,124.4 Net Debt (8) as of Dec. 31, 2018 385.1 Noncontrolling Interests as of Dec. 31, 2018 56.0 Total Enterprise Value (9) $ 3,565.5 Note: Refer to definitions and footnotes on slides 40 and 41. 39

Reconciliation ofNon-GAAP Measures: Definitions Note: Total Reporting Segment Costs; Adjusted EBITDA; Free Cash Flow; Net Debt; Return on Equity and Total Enterprise Value arenon-GAAP financial measures. Return on equity is equal to income from continuing operations, net of income taxes, divided by average total stockholders’ equity. Management believes thatnon-GAAP performance measures are used by investors to measure our operating performance and lenders to measure our ability to incur and service debt. 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. (1)Total Reporting Segment Costs 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 Reporting Segment Costs is used by management as a metric to measure each of our segment’s operating performance. (2)Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expenses, depreciation, depletion and amortization and reorganization items, net. Adjusted EBITDA is also adjusted for the discrete items that management excluded in analyzing each of our segment’s operating performance as displayed in the reconciliation above. Adjusted EBITDA is used by management as the primary metric to measure each of our segment’s operating performance. (3)We account for our 50% equity interest in Middlemount Coal Pty Ltd. (Middlemount), which owns the Middlemount Mine, under the equity method. Middlemount’s standalone results exclude the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference recorded by the Company in applying the equity method. Middlemount’s standalone results include (on a 50% attributable basis): Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Quarter Ended Quarter Ended Six Months Ended Mar. 31, 2018 Jun. 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Mar. 31, 2019 Jun. 30, 2019 Jun. 30, 2019 (In Millions) Tons sold 0.5 0.5 0.5 0.6 2.1 0.4 0.6 1.0 Depreciation, depletion and amortization and asset retirement obligation expenses $ 3.9 $ 4.2 $ 3.7 $ 3.1 $ 14.9 $ 3.6 $ 3.5 $ 7.1 Net interest expense 3.6 3.6 2.8 3.9 13.9 2.2 1.8 4.0 Income tax provision 5.1 6.4 3.9 2.6 18.0 1.7 4.2 5.9 40

Reconciliation ofNon-GAAP Measures: Definitions (4)Includes gains (losses) on certain surplus coal reserve and surface land sales, property management costs and revenues and the Q1 2018 gain of $20.6 million on the sale of certain surplus land assets in Queensland’s Bowen Basin and the Q3 2018 gain of $20.5 million on the sale of surplus coal resources associated with the Millennium Mine. (5)Includes trading and brokerage activities, costs associated with post-mining activities, certain coal royalty expenses, minimum charges on certain transportation-related contracts and the Q1 2018 gain of $7.1 million recognized on the sale of our interest in the Red Mountain Joint Venture. (6)We recorded a $125.0 million insurance recovery during the six months ended June 30, 2019 related to losses incurred at our North Goonyella Mine. Of this amount, Adjusted EBITDA excludes an allocated amount applicable to total equipment losses recognized at the time of the insurance recovery settlement, which consisted of $24.7 million and $66.4 million recognized during the six months ended June 30, 2019 and the year ended December 31, 2018, respectively. The remaining $33.9 million, applicable to incremental costs and business interruption losses, is included in Adjusted EBITDA for the six months ended June 30, 2019. (7)Free Cash Flow is defined as net cash provided by operating activities less net cash used in investing activities and excludes cash outflows related to business combinations. Free Cash Flow is used by management as a measure of our financial performance and our ability to generate excess cash flow from our business operations. (8)Net Debt is defined as total debt less cash and cash equivalents. (9)Total Enterprise Value is defined as market capitalization plus Net Debt and noncontrolling interests. Market capitalization is as of May 6, 2019; Net Debt is as of Dec. 31, 2018. 41