2017 – 2021 Business Plan July/August 2016 Exhibit 99.1

Statement on Forward-Looking Information Certain statements included in this presentation are forward-looking as defined in the Private Securities Litigation Reform Act of 1995. The Company uses words such as “anticipate,” “believe,” “expect,” “may,” “forecast,” “project,” “should,” “estimate,” “plan,” “outlook,” “target,” “likely,” “will,” “to be” or other similar words to identify forward-looking statements. These forward-looking statements are made as of the date the presentation was filed and are based on numerous assumptions that the Company believes are reasonable, but these assumptions are open to a wide range of uncertainties and business risks that may cause actual results to differ materially from expectations. These factors are difficult to accurately predict and may be beyond the Company’s control. Factors that could affect the Company’s results include, but are not limited to: the Company’s ability to obtain bankruptcy court approval with respect to motions or other requests made to the bankruptcy court in connection with the Company’s voluntary petitions for reorganization under Chapter 11 of Title 11 of the U.S. Code (the Chapter 11 Cases), including maintaining strategic control as debtor-in-possession; the Company’s ability to negotiate, develop, confirm and consummate a plan of reorganization; the effects of the Chapter 11 Cases on the operations of the Company, including customer, supplier, banking, insurance and other relationships and agreements; bankruptcy court rulings in the Chapter 11 Cases as well as the outcome of all other pending litigation and the outcome of the Chapter 11 Cases in general; the length of time that the Company will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings; risks associated with third-party motions in the Chapter 11 Cases, which may interfere with the Company’s ability to confirm and consummate a plan of reorganization and restructuring generally; increased advisory costs to execute a plan of reorganization; the impact of the New York Stock Exchange’s delisting of the Company’s common stock on the liquidity and market price of the Company’s common stock and on the Company’s ability to access the public capital markets; the Company’s ability to continue as a going concern including the Company’s ability to confirm a plan of reorganization that restructures the Company’s debt obligations to address liquidity issues and allow emergence from the Chapter 11 Cases; the Company’s ability to access adequate debtor-in-possession financing (DIP Financing) or use cash collateral; the effect of the Chapter 11 Cases on the Company’s relationships with third parties, regulatory authorities and employees; the potential adverse effects of the Chapter 11 Cases on the Company’s liquidity, results of operations, or business prospects; the Company’s ability to execute its business and restructuring plan; increased administrative and legal costs related to the Chapter 11 Cases and other litigation and the inherent risks involved in a bankruptcy process; the cost, availability and access to capital and financial markets, including the ability to secure new financing after emerging from the Chapter 11 Cases; the risk that the Chapter 11 Cases will disrupt or impede the Company’s international operations, including the Company’s business operations in Australian; competition in the coal industry and supply and demand for the Company’s coal products, including the impact of alternative energy sources, such as natural gas and renewables, global steel demand and the downstream impact on metallurgical coal prices, and lower demand for the Company’s products by electric power generators; the Company’s ability to successfully consummate planned divestitures; the Company’s ability to appropriately secure its obligations for reclamation, federal and state workers’ compensation, federal coal leases and other obligations related to the Company’s operations, including its ability to utilize self-bonding and/or successfully access the commercial surety bond market; customer procurement practices and contract duration; the impact of weather and natural disasters on demand, production and transportation; reductions and/or deferrals of purchases by major customers and the Company’s ability to renew sales contracts; credit and performance risks associated with customers, suppliers, contract miners, co-shippers, and trading, bank and other financial counterparties; geologic, equipment, permitting, site access, operational risks and new technologies related to mining; transportation availability, performance and costs; availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires; impact of take-or-pay arrangements for rail and port commitments for the delivery of coal; successful implementation of business strategies, including, without limitation, the actions the Company is implementing to improve its organization and respond to current industry conditions; negotiation of labor contracts, employee relations and workforce availability, including, without limitation, attracting and retaining key personnel; the Company’s ability to comply with financial and other restrictive covenants in various agreements, including the DIP Financing credit agreement; changes in postretirement benefit and pension obligations and their related funding requirements; replacement and development of coal reserves; effects of changes in interest rates and currency exchange rates (primarily the Australian dollar); effects of acquisitions or divestitures; economic strength and political stability of countries in which the Company has operations or serves customers; changes in global consumer confidence and impacts to various foreign currency exchange rates as a result of the June 24, 2016 UK electorate vote to withdraw from the European Union; legislation, regulations and court decisions or other government actions, including, but not limited to, new environmental and mine safety requirements, changes in income tax regulations, sales-related royalties, or other regulatory taxes and changes in derivative laws and regulations; the Company’s ability to obtain and renew permits necessary for the Company’s operations; litigation or other dispute resolution, including, but not limited to, claims not yet asserted; any additional liabilities or obligations that the Company may have as a result of the bankruptcy of Patriot Coal Corporation, including, without limitation, as a result of litigation filed by third parties in relation to that bankruptcy; terrorist attacks or security threats, including, but not limited to, cybersecurity threats; impacts of pandemic illnesses; and other risks detailed in the Company’s reports filed with the SEC. The Company does not undertake to update its forward-looking statements except as required by law. It is uncertain at this stage of our Chapter 11 Cases if any proposed plan of reorganization would allow for distributions with respect to our equity or other securities. It is likely that our equity securities will be cancelled and extinguished upon confirmation of a plan of reorganization by the bankruptcy court, and that the holders thereof would not be entitled to receive, and would not receive or retain, any property or interest in property on account of such equity interests.

Peabody Energy Business Plan As part of Peabody’s Debtor-in-Possession (DIP) financing facilities, the company is required to meet certain milestones throughout the Chapter 11 process, including the approval of the U.S. and Australia business plans. These business plans will form the basis for the Plan of Reorganization, which will outline Peabody’s long-term plan for a successful emergence from Chapter 11. The following slides provide key highlights from the business plans, Peabody’s long-term view of the industry and the actions the company is taking to remain a key contributor of an essential industry. Introduction

Table of Contents Section One: Executive Summary 5 Section Two: Business Plan Industry Fundamentals/Outlook 18 Methodology and Assumptions 28 Americas Business Plan 32 Australia Business Plan 37 Consolidated Business Plan 41

Section one: EXECUTIVE Summary

Peabody Energy Business Plan As Peabody Energy focuses on emerging stronger from the Chapter 11 process, we provide this business plan to continue to shape the future state of the company. We look to capitalize on our strengths, build upon our strong operating performance, reduce our overall debt and fixed charges, and pursue additional improvements for long-term success. Despite operating in an industry with unprecedented challenges, Peabody has opportunities to not only survive but to thrive for the long-term benefit of its many stakeholders. Peabody Energy consists of a strong asset base and skilled workforce intent on creating maximum value in an essential industry. Current State

Current State: Largest Private-Sector Coal Company Serving Thermal and Metallurgical Coal Customers in 25 Countries Target operating model includes: Two business units (Americas, Australia) Marketing/Trading services function Lean and scalable corporate structure offering strategy, compliance, shared services Core sectors include PRB, Illinois Basin, Asia-Pacific met and thermal Significant diversity across regions, demand centers, products, customers A leader in sustainable mining, energy access and clean coal solutions 26 mines in U.S. and Australia 6.3 billion Tons of proven/probable reserves $5.6 billion 2015 revenues 500,000 Acres of surface lands ~7,000 Skilled employees worldwide

Platform Benefits from Size, Geographic and Product Diversity, Customer Access Located in the Best Mining Regions in the U.S. and Australia Trend toward aggregating large supply centers / complexes to lower costs and better compete

Highlights: Safety – Leading Measure of Operational Excellence Global Safety Rate Improves to New Company Record in 2015 Vision to operate safe and healthy workplaces that are incident free Safety – A Way of Life Management System sets clear and consistent expectations for safety and health across business Global incidence rate superior to coal industry average and nearly every other major industry sector Incidence rate per 200,000 hours worked. 2011 to 2013 figures do not include Discontinued Operations, JVs, office employees or Americas contractors. 2016 YTD actuals through July 8, 2016. Peabody Global Incidence Rate 2013 2014 2015

Highlights: Americas – Strong Asset Base and Margins Diversified product and geographic mix in best U.S. regions Strong average 2016 YTD EBITDA margins of 25% Margins reflect layered contracting strategies and 8% per ton cost reductions from 2012 (despite 35% lower volumes) Largest coal producer and reserve holder in Powder River Basin Nearly 3 billion tons of proven and probable reserves Three mines are most productive large mines in America Operates largest coal mine – North Antelope Rochelle Source: Public company reports. Gross margin benchmarkings reflect average of 2014 and 2015. 2016 comparisons on six-month YTD basis. Gross Margins of PRB Producers Other Coal Producers Avg. 2015 Gross Margin YTD 2016 Gross Margin Powder River Basin 26% 24% Midwestern U.S. 27% 29% Western U.S. 27% 22%

Highlights: Australia – Major Reductions in Capital and Costs $750 $41 ~5,900 ~3,800 Australian capital investment declines more than 90% while workforce decreases over 35% from peak in 2012 even with owner-operator conversions and rising volumes Average cost per ton declines 47% from 2012, aided by currency, fuel, owner-operator conversions and major process improvements Project Excellence underway to capture additional cost improvements following initial successes

Peabody Q1 16 Other U.S. Coal Producer Average: 5.5% Source: Public SEC filings of peers; Note: YTD 2016 through June 2016. Note: Other U.S. coal producers include: Alliance Resource Partners, Arch Coal, Cloud Peak Energy, Consol Energy, Foresight Energy and Westmoreland Coal. SG&A remains constant as percent of revenue since 2012 despite $4 billion in lower revenues in 2016 Lowest SG&A ratio at 3.3% of revenue Actions include: Eliminating over 45% of corporate positions Closing international and regional U.S. offices Streamlining reporting relationships and increasing manager span of control Implementing shared services group to serve global operations and eliminate duplication First Quarter 2016 SG&A (Percentage of Revenue) Highlights: SG&A – Best Among Peers Despite Global Nature

Where We Are Going: Key Drivers of Future Value Creation Aggressive pursuit of safe, low-cost operations Constant drive down cost curve Protect social license to operate Excellence in land restoration Emphasis on best products, regions and customers within essential industry In U.S., best asset base in core industry In Australia, mid-tier met assets, top tier thermal Capital discipline with sharp return orientation Focus on EBITDA margins, ROI in excess of cost of capital Management team with major value focus Capitalizing on excellent asset base, quality team and sustainable capital structure for value creation A leading voice for responsible mining, energy access and advanced coal technologies Focus on high-efficiency, low-emissions technology and CCUS Social License & Leadership Voice Return Orientation & Investment Focus Operational & Marketing Excellence

Financial Overview: EBITDAR Rises to $631 Million in 2021 on Stable Revenues Australia BU Americas BU Coaltrade/Corporate

U.S. Plan PRB and ILB – Drive lower costs through synergies, provide greater value Southwest and Colorado – Manage for cash Australia Plan Improve/optimize strategic assets Divest, sell or suspend non-strategic assets Restructure or mitigate take-or-pay agreements to improve cash flows Continue to drive enhancements for platform Chapter 11 Restructuring Emerge quickly and effectively Implement sustainable capital structure with sufficient access to capital Advance further cost/operational improvements Work with states and other parties to provide adequate assurance for reclamation obligations post-emergence Future State: Diversified Platform Capable of Generating Positive Cash Flow in All Cycles Desired Future State Transform Portfolio to Unlock Value Americas Unmatched portfolio of assets in PRB and ILB that continues to create value despite lower coal demand Australia Smaller, more profitable platform focused on high-quality products to take advantage of higher growth in Asia and positioned for future growth Capital Structure Structure that enables sustainable performance through all cycles and generates returns to support future growth initiatives

How We Will Get There: Peabody Mission, Values and Strategy To create superior value as the leading global supplier of coal, which enables economic prosperity and a better quality of life. Our Mission Our Values Safety: We commit to safety and health as a way of life. People: We offer an inclusive work environment and engage, recognize and develop employees. Customer Focus: We provide customers with quality products and excellent service. Excellence: We are accountable for our own success. We operate cost-competitive mines by applying continuous improvement and technology-driven solutions. Leadership: We have the courage to lead, and do so through inspiration, innovation, collaboration and execution. Sustainability: We take responsibility for the environment, benefit our communities and restore the land for generations that follow. Integrity: We act in an honest and ethical manner. A leading position in U.S. PRB and ILB basins Australian metallurgical and thermal coal platform to capture higher growth Asian markets Operational Excellence: Drive safety, productivity, cost efficiency and reclamation performance. Financial Strength: Build a capital structure that enables sustainable performance through all market cycles and generates returns to support future growth initiatives. Strategic Portfolio Management: Continually enhance the value of our portfolio; high- quality assets in the right markets. Advance Coal Mining and Use: Protect our license to operate, advocate favorable energy policy and advances in generation technology including HELE and CCUS. People: Employ the best people in the industry and align their talents to maximize their full potential. Our Strategy

Section TWO: BUSINESS PLAN

Industry Fundamentals

Industry Highlights UNITED STATES U.S. coal demand declines sharply in first half of 2016 on ~15-year-low natural gas prices and competition from other fuel sources; prices begin to show improvement in mid-2016 U.S. coal demand for generation expected to grow 20 to 25 million tons between 2016 and 2021 PRB and Illinois Basin expected to increase SEABORNE Seaborne prices at multi-year lows in beginning of 2016 Supply-demand show early signs of balance in 2016 with prices starting to rebound driven by China Seaborne met demand expected to increase by 50 to 55 million tonnes through 2021 driven by India and China Seaborne thermal demand expected to rise modestly by 50 to 60 million tonnes as 375 GW of new generation capacity is added primarily in Asia-Pacific Source: Peabody Energy Global Analytics; industry reports. Industry Fundamentals

Pressured U.S. Coal Industry Expected to Modestly Rebound in 2017 Challenging start to 2016 with YTD demand decreasing approximately 20%; shipments fall nearly 30% Full-year utility demand projected to fall approximately 85 to 105 million tons to nearly 635 to 655 million tons driven by lower gas prices, competition from other fuel sources and coal plant retirements 2016 production cuts assumed to significantly outpace reduced demand, with shipments declining 185 to 215 million tons to approximately 695 to 725 million tons Even with significant production response, record high stockpiles expected to remain an overhang in 2017 U.S. utility coal demand anticipated to rebound in 2017 by 50 to 55 million tons on higher gas prices before stabilizing, but unlikely to return to 2015 levels in plan period PRB and ILB best-positioned both in near term and longer term 50 GW of coal plant retirements over 5-year plan reduces coal fleet capacity by approximately 20%, offset by higher capacity utilization at remaining plants Regulatory landscape influencing long-term utility planning Source: Peabody Global Energy Analytics.

PRB 8800 Pricing Assumptions ($ per Ton) Lower Natural Gas Prices Dictating U.S. Coal Demand Overabundance of natural gas resulting in ~15-year-low prices in early 2016 Low production costs, sufficient reserves adversely affect coal prices and limit pricing upside Near-term U.S. coal prices expected to remain subdued across all basins GDP, weather, renewables, gas exports are all variables impacting stockpiles and gas prices Coal demand model based on expected economics and utility behavior ~50 GW of plant retirements expected over 5-year plan; plants still not running at full capacity utilization because of competition with all fuel sources Source: EIA, Bloomberg, PIRA, Peabody Global Energy Analytics and third-party analysts. Note: Price point estimates are for planning purposes only and are prone to major swings based on actual supply-demand fluctuations. Natural Gas Pricing Assumptions ($ per mmBtu)

PRB and Illinois Basin Best Positioned in U.S. Coal Industry PRB and ILB are most competitive on average against natural gas and other electricity generating fuels PRB: $2.50 – $3.00 per mmBtu ILB: $3.50 – $3.75 per mmBtu CAPP: $4.00 – $4.50 per mmBtu Demand to stabilize as expected coal plant retirements are partially offset by higher capacity utilization By 2021, coal expected to continue to supply ~30% of U.S. electricity generation Fundamentals projected to rebalance 2H 2017, with utility stockpiles returning to around normal levels Source: Peabody Global Energy Analytics and EIA. PRB and ILB Projected to Supply 55% of U.S. Coal by 2021

New Coal Generating Capacity Supports Seaborne Thermal Long-Term Demand Source: Platts, IHS, Wood Mackenzie, Country / Government Data and Peabody Global Energy Analytics. Represents potential new coal consumption of ~1 billion tonnes Over 85% of additions concentrated in Asia-Pacific ASEAN capacity forecasted to surge ~75% by 2021 Transition towards lower carbon-emitting coal fleet Majority of new capacity expected to be ultra or supercritical boiler types Shift toward enhanced boilers results in stronger demand for higher quality coal ~375 GW of Coal Capacity Additions Expected by 2021 New Coal Generating Capacity 2016 – 2021 (GW)

Seaborne Thermal Demand Recovery Expected from Recent Lows Seaborne thermal demand projected to modestly increase from 2016 through 2021 by 50 to 60 million tonnes Growth driven by Asia-Pacific as power and coal demand expected to increase with new coal capacity Australia well-positioned to supply increased demand; projected to lead growth in exports Colombia and Indonesia also positioned to grow Source: IHS, Country / Government Data and Peabody Global Energy Analytics. Seaborne Thermal Demand Growth 2016 – 2021 (Mmt)

Seaborne Thermal Pricing Projected to Rise Modestly; Remains Muted Q1 2016 seaborne thermal prices reach multi-year lows from oversupply, reduced China demand and lower costs Seaborne thermal coal demand has recently shown signs of improvement, with spot-prices currently above $60 per tonne Assumptions reflect potential for several exporting countries to grow supply via existing infrastructure that will constrain price recovery Indonesia likely to serve as ceiling on long-term seaborne thermal prices Source: AME, Peabody Global Energy Analytics and third-party analysts. Note: Price point estimates are for planning purposes only and are prone to major swings based on actual supply-demand fluctuations. Newcastle Pricing Assumptions (US$ per tonne)

Seaborne Metallurgical Coal Demand on Course for Stabilization Signs of improvement in pricing, with coking coal benchmark settling higher for two consecutive quarters Has not happened since late 2010/early 2011 Low prices and capital constraints force some mine closures and defer new supply, bringing supply and demand closer to balance China imports grow modestly as it works off excess steel/coking coal capacity, but remain below 2013 peak levels Seaborne met coal demand expected to increase nearly 20% (4% CAGR) by 2021 Growth led by India and China, with India becoming the largest importer of seaborne metallurgical coal Export supply estimated to increase by ~15% through 2021 as industry works off overcapacity Growth led by Australia and Russia with approximately 20 to 25 million tons Source: Peabody Global Energy Analytics.

Seaborne Metallurgical Pricing Improving from Multi-Year Lows Q1 2016 HCC settlement $81 per tonne; rebounding in Q2 Moderate pricing growth assumed following supply/ demand balances Global average seaborne met coal cash costs decline 41% since 2012, further reductions likely limited Forecasted cost of greenfield developments also decline impacting incentive pricing Support from cost floor and significant deferral of capital expected to drive prices higher Current spot pricing >$95 per tonne; 3Q benchmark set at $92 per tonne Source: AME, Peabody Global Energy Analytics and third-party analysts. Note: Price point estimates are for planning purposes only and are prone to major swings based on actual supply-demand fluctuations. Metallurgical Pricing Assumptions (US$ per tonne)

Methodology & Assumptions

Process: Business Plan Assumptions Developed Using Bottom-Up Approach Macroeconomic assumptions developed for key variables, including country level GDP, industrial production and fixed asset investment, driving detailed supply / demand models Demand models focus on key regions for coal, generation and steel Seaborne thermal, seaborne met and U.S. thermal by country/region Supply models and cost curves concentrate on major supply regions/ countries that impact regions in which we operate USD-AUD exchange rate assumptions based on an econometric model Price forecasts, S/D models and other key assumptions are pressure tested against robust universe of credible third party research

2017 – 2021 Business Plan Key Assumptions & Sensitivities Increase in natural gas price drives higher U.S. pricing and volume over time Australia seaborne met and thermal pricing, along with A$ FX, increase steadily over the five-year plan Financial performance is highly sensitive to changes in assumptions A 10% change in seaborne met and thermal pricing from current levels would impact EBITDAR by ~$170M A 10% change in the A$ FX rate from current levels would impact EBITDAR by ~$135M Impact of met pricing and A$ FX decline over time in conjunction with reduction in met production profile Sensitivities on U.S. pricing increase over time as contracts roll off and uncommitted position grows Note: ILB pricing reflects a weighted average price based on uncommitted volumes. 2016 2017 2018 2019 2020 2021 Fuel Assumptions 1.61 $ ULSD $/Gallon 1.52 $ 1.58 $ 1.64 $ 1.68 $ 1.71 $ 2.37 $ U.S. Natural Gas $/mmbtu 3.01 $ 3.05 $ 3.20 $ 3.35 $ 3.50 $ 66 $ Singapore Gasoil per Barrel 60 $ 64 $ 65 $ 68 $ 70 $ 45 $ WTI Crude per Barrel 51 $ 52 $ 53 $ 55 $ 56 $ Seaborne Prices and FX 87 $ AUS - Met Headline Price / Tonne 95 $ 105 $ 115 $ 120 $ 123 $ 73 $ AUS - PCI Price / Tonne 76 $ 82 $ 90 $ 92 $ 95 $ 84% PCI-to-HCC Ratio 80% 78% 78% 77% 77% 49 $ AUS- Newcastle Price 52 $ 55 $ 58 $ 60 $ 65 $ 0.74 A$/US$ Exchange Rate 0.75 0.76 0.77 0.79 0.80 U.S. Prices per Short Ton PRB 8800 10.25 $ 11.25 $ 12.00 $ 13.00 $ 13.75 $ Illinois Basin* 38.00 $ 37.14 $ 37.39 $ 38.24 $ 39.03 $ Key Cost Escalations Australia Outside Services and M&S 2.0% 2.2% 2.3% 2.5% 2.5% Australia Wage & Salary Increase 2.0% 2.2% 2.3% 2.5% 2.5% U.S. Outside Services and M&S 1.8% 2.0% 2.2% 2.2% 2.2% U.S. Wage & Salary Increase 1.5% 2.0% 2.3% 2.3% 2.3% Sensitivities +/- ($ millions) Fuel ($10/barrel) 30 $ 30 $ 30 $ 30 $ 31 $ Met Pricing ($10/mt) 118 $ 106 $ 88 $ 70 $ 68 $ Thermal Pricing ($5/mt) 51 $ 51 $ 51 $ 54 $ 56 $ FX ($0.05) 90 $ 85 $ 75 $ 70 $ 70 $ PRB Pricing ($1/ton) 21 $ 61 $ 96 $ 100 $ 101 $ Midwest Pricing ($3/ton) - $ 27 $ 50 $ 63 $ 62 $

2017 – 2021 Business Plan 2016 Updated Forecast vs. DIP Budget Although PRB volumes are trending towards the initial DIP budget projections (100MT), repositioning efforts have driven segment margins higher to ~24% YTD 2016, nearly back to 2015 levels (~26%) despite a 30% loss of volume period-over-period (~28MT) In addition to cost containment across the U.S. platform, higher Midwest volume (~2MT) and higher gains on asset sales result in a ~$71M increase versus the DIP budget for the Americas Business Unit Australia forecast is in excess of the DIP budget primarily due to higher seaborne pricing assumptions for met (~$8/tonne) and thermal (~$3/tonne), in addition to cost repositioning efforts, partially offset by slightly higher A$ FX rates (~$0.74 vs. $0.71) ‘Coaltrade/Other’ primarily reflects higher non-cash, mark-to-market losses on financial hedges entered during recent thermal uptick to lock in pricing on small portion of Australia production (partially offsetting the pricing benefit included in Australia BU results) $ $ $ $ $ $ $ $ $ ($ in Millions) 2016 Forecast Improves on Seaborne Pricing and Cost Containment 2016 EBITDAR Forecast vs. DIP Budget Note: 2016 DIP EBITDAR modified to include March 2016 actual results.

Americas Business Plan

Plan Objectives Maintain safe and efficient operations while aggressively managing costs Continue to maximize profitability through cost reductions and cash preservation through execution of mine-level initiatives to maintain or improve cost metrics and productivity Focus on reclamation activities to maximize opportunities for bond releases from states Commercial Outlook SPRB demand forecasted to increase in 2017 (37MT) and 2018 (27MT) following dramatic 2016 declines as demand improves; 2018-2021 demand relatively flat at ~325MT as increasing plant utilization is assumed to partially offset retirements Americas sales of 143MT in 2017 expected to increase 11MT from 2016; volume levels increase to ~165MT in 2018 and then remain flat through 2021   88% of 2017 volume and 57% of 2018 volume is committed (80% and 44% priced in 2017 and 2018, respectively) Key Trends & Takeaways Consistent cash flow generation through 2021 totaling ~$2.5B with all active mining locations maintaining positive cash flow throughout entire five-year plan Continued cost containment initiatives and mine plan optimization result in reduction in clean cash costs (cash costs excluding sales-related costs) in 2017 of ~$0.51/ton across the Business Unit in 2017, with minimal increases expected through 2021 EBITDAR margins remain robust over the plan, ranging from 18% - 27% every year across each of the three U.S. segments Final ~$250M LBA payment is made in 2016, while sustaining capital remains relatively flat across the plan Plan includes one new mine project in Midwest requiring only ~$11M of start-up capital Resource Management expected to contribute ~$10M EBITDAR gains per year with ~$13M-$20M in yearly cash proceeds 2017 – 2021 Business Plan Americas Overview

2017 – 2021 Business Plan Americas Financial Summary EBITDAR Volume improves in 2017 and 2018 on expected increase in natural gas prices and normalization of inventory stockpiles EBITDAR generation totals ~$2.9B over the five-year plan EBITDAR declines in 2018 and 2019 as volume benefit is offset by lower expected pricing as higher-priced legacy contracts roll off Platform is well capitalized in near term with ~40% of sustaining capital dedicated to lease buyouts or critical land purchases over the plan All mines are cash flow positive over five-year plan Net Capital / LBAs Tons in Millions $ in Millions $ in Millions Tons Sold

2017 – 2021 Business Plan Americas Costs and Margins Cost Containment Efforts in U.S. Lead to Sustainable Margins Despite losing over 30% of U.S. volume since 2014 (~60MT), the U.S. platform has successfully managed costs through right-sizing operations and ongoing productivity improvements 2016 – 2021 clean cost per ton CAGR is expected to be under 2% in all regions, reflecting the platform’s continued commitment to cost containment to offset general cost and commodity escalations and higher strip ratios Despite impact of lower domestic pricing, margins are expected to remain relatively stable and sustainable over the course of the plan in all U.S. segments due to Peabody’s high-quality assets and continued strong operating performance Note: Clean cash costs exclude sales-related costs such as royalties and taxes that fluctuate based on changes in sales prices. '16-'21 2014A 2015A 2016F 2017 2018 2019 2020 2021 CAGR Powder River Basin Clean Cash Cost $/ton 6.23 $ 6.29 $ 6.70 $ 6.40 $ 5.91 $ 5.98 $ 6.21 $ 6.72 $ 0.1% Margin $/ton 3.57 $ 3.48 $ 2.90 $ 2.79 $ 2.31 $ 2.06 $ 2.50 $ 2.54 $ Margin % 26% 26% 22% 22% 20% 18% 21% 20% U.S. Midwest Clean Cash Cost $/ton 31.92 $ 30.01 $ 28.15 $ 28.69 $ 27.77 $ 27.64 $ 28.49 $ 28.89 $ 0.5% Margin $/ton 12.29 $ 12.69 $ 11.91 $ 10.70 $ 9.48 $ 8.47 $ 6.78 $ 7.48 $ Margin % 26% 27% 28% 25% 24% 22% 18% 19% U.S. West Clean Cash Cost $/ton 19.63 $ 20.46 $ 23.16 $ 22.34 $ 21.22 $ 22.38 $ 24.19 $ 24.73 $ 1.3% Margin $/ton 11.21 $ 10.31 $ 9.81 $ 10.04 $ 9.03 $ 7.24 $ 7.24 $ 7.84 $ Margin % 30% 27% 26% 27% 25% 21% 20% 21% 5 Year Plan

Land restoration essential part of coal mining process Peabody restored ~4,700 acres of mined land in 2015 $185 million spent to restore ~48,000 acres of land over past decade $560 million paid to federal abandoned mined lands (AML) program for others’ reclamation AML reclaims no Peabody lands Peabody recognized with 90 environmental honors since 2000 Peabody Continues to Progress Toward Solutions for Reclamation Assurance Peabody reaches superpriority settlement in multiple states to support coal mine restoration States entitled to percentage of company’s $200 million bonding accommodation facility $1.14 billion of self-bonding and $320 million of surety bonds as of June 30 Requirements reduced over $250 million since January 1 Continuing discussions with states and other parties regarding long-term solution Pursing significant bonding reduction through restoration, bond release and accurate measurements Targeting additional $300 million in reductions by mid-2017 Peabody Approach Current Status

Australia Business Plan

Business Plan Objectives Maintain safe and efficient operations while aggressively managing costs Maximize profitability through cost reductions and cash preservation through execution of mine-level initiatives to maintain or improve cost metrics and productivity Continue to meet rehabilitation obligations at all mine sites including mines transitioned to care and maintenance Proactively manage rail and port contracts to reduce infrastructure obligations and mitigate excess commitments Operate the platform so that no capital infusions in excess of $250 million intercompany loan are necessary Enhance liquidity through monetization of non-strategic assets to optimize portfolio for long-term success Commercial Outlook Near term deferral of capital expenditure and investment will moderate supply growth over the next 5 years as the incentive to commit to new projects remains low at current prices and A$ FX rates Demand expected to recover in mid to longer-term with price improving by ~25% for thermal coal and ~30% for metallurgical coal over the 5-year period Key Trends & Takeaways Continued low-price environment and increasing strip ratios could drive early suspension of mining activities at certain metallurgical mines by 2021 and has been reflected in the plan; met coal production by 2021 is expected to be less than 50% of 2016 levels Sustaining capital remains manageable over the plan, but multiple mines require recapitalization to extend mine lives, primarily after 2017 Near-term cash flows are approximately breakeven; the $250 million intercompany loan is expected to provide sufficient liquidity for the Australia business during the pendency of the bankruptcy unless conditions materially deteriorate Thermal segment margins average ~17% over the plan, while margins at metallurgical mines require further optimization 2017 – 2021 Business Plan Australia Overview

Tons Sold EBITDAR Net Capital Declining metallurgical production profile anticipated over time Near-term EBITDAR will be challenged although results improve over the plan due to increasing Met ($95/t in 2017 to $123/t in 2021) and Thermal ($52/t in 2017 to $65/t in 2021) price assumptions, partially offset by increasing A$ FX ($0.75 in 2017 to $0.80 in 2021) While sustaining capital remains relatively flat, total capital increases over the plan primarily due to selected mine life extension projects Plan also includes ~$100M of capital for other life extension projects to ensure the business unit maintains sufficient supply in the post-plan period 2017 – 2021 Business Plan Australia Financial Summary $ in Millions Tons in Millions $ in Millions

2017 – 2021 Business Plan Australia Costs and Margins Australia Cost Containment Actions Continue; Met Margins Lag 2016 – 2021 clean cash cost per ton CAGR is expected to be under 2% in both thermal and met segments, reflecting continued Project Excellence efforts to drive costs out of the mining operations While the Australia thermal platform continues to produce suitable margins, the met platform continues to lag despite the assumed pricing uplift over plan, reinforcing the need for strategic optimization of the segment Note: Australia costs stated in A$ to eliminate impact of FX. Note: Clean cash costs exclude sales-related costs such as royalties and taxes that fluctuate based on changes in sales prices. '16-'21 2014A 2015A 2016F 2017 2018 2019 2020 2021 CAGR AUS Thermal Clean Cash Cost A$/metric tonne 33.47 $ 33.09 $ 30.53 $ 33.51 $ 35.00 $ 32.64 $ 33.52 $ 33.32 $ 1.8% Margin $/short ton 12.59 $ 9.64 $ 6.53 $ 4.95 $ 4.55 $ 7.47 $ 7.30 $ 9.90 $ Margin % 25% 24% 19% 14% 12% 19% 18% 23% AUS Met Clean Cash Cost A$/metric tonne 99.75 $ 87.98 $ 84.66 $ 84.18 $ 82.91 $ 85.91 $ 86.64 $ 91.78 $ 1.6% Margin $/short ton (8.79) $ (1.16) $ (5.23) $ (2.12) $ 4.28 $ 8.60 $ 9.65 $ 7.89 $ Margin % -9% -2% -8% -3% 5% 10% 11% 8% 5 Year Plan

consolidated Business plan

Mining Volumes Following a sharp decline in U.S. volume in 2016, 2017 mining volume rebounds, primarily in the PRB (10MT) due to expectations of higher natural gas prices and lower utility stockpiles U.S. volume also increases in 2018 from improving demand, although sales do not return to 2015 levels in any year of the plan 2017 Australia volume declines due to 2016 suspension of Burton operation (2MT), with other anticipated reductions in met production profile in later years of plan Met volumes total only 7MT by 2021 (vs. 15MT in 2016) Mining Revenues Revenues remain flat across the plan as higher pricing in Australia is more than offset by lower met volume, while U.S. revenues grow with improving demand 2017 U.S. revenues improve slightly from 2016 due to higher volume, although average pricing declines due to the roll off of higher-priced legacy contracts 2017 Australia revenues decline from lower volume (2MT), partially offset by higher average met pricing ($95/t vs. $87/t) 2017 – 2021 Business Plan Consolidated Financial Summary Mining Volumes Sold Mining Revenues ($ in Billions) (Tons in Millions)

EBITDAR 2017 EBITDAR increases $93M (or 24%) as higher Australia pricing, U.S. volume, and Coaltrade earnings more than offset lower U.S. pricing EBITDAR increases in 2018 and beyond primarily due to higher Americas volumes and Australia pricing, partially offset by lower average U.S. pricing from roll off of legacy contracts Consistent with past practice, a nominal operational contingency of $25M included in each year of the plan reflecting risks inherent in mining Net Cash Flows Excl. Restructuring and Borrowings 2017 cash flow improves ~$700M compared to 2016 primarily due to higher EBITDAR, roll off of final PRB LBA payment (~$250M), and favorable working capital post-filing from expected recapture of trade terms 2018 cash flow declines due to higher pension funding requirements ($30M) and higher capex ($27M), in addition to 2017 non-recurring items 2019 – 2022 cash declines despite higher EBITDA due to increasing capex, cash taxes (~$55M per year), and pension funding (~$50M per year) 2017 – 2021 Business Plan Consolidated Financial Summary (Cont.) Net Cash Flow Excluding Restructuring & Borrowings* *Excludes revolver proceeds, DIP proceeds/interest/repayment, AR Securitization repayment, restructuring costs and adequate protection payments. EBITDAR* 479 637 386 636 895 953 557 555 579 631 548 538 529 608 * EBITDAR excludes restructuring –related costs and any impact of pre-filing hedge losses. ($ in Millions) ($ in Millions) Note: Plan does not include post-emergence assumptions on final capital structure and impact on interest or dividends, and does not include any accommodations for future collateral requirements for bonding/self-bonding.

2017 – 2021 Business Plan Consolidated EBITDAR Bridge: 2016 to 2021 EBITDAR steadily increases from 2016 to 2021 (~$250M), although improvement is primarily dependent on rebound in seaborne met and thermal pricing Lower Americas pricing from roll off of higher-priced legacy contracts shifting to uncommitted volume at lower average pricing Americas operations improve primarily from higher PRB volume from rebound in demand Higher assumed Australia seaborne pricing assumptions in 2021 (Met $123/t; Thermal $65/t) vs. 2016 (Met $87/t; Thermal $49/t) Unfavorable A$ currency impact due to higher projected FX assumption ($0.80 in 2021 vs. ~$0.74 in 2016) Australia operations reflect cost and commodity escalations and higher surface mine ratios Coaltrade assumed to recover from 2016 losses with a $5M earnings target each year of the plan Assumes key contract initiatives from Chapter 11 process provide ~$110 million of savings over plan from logistics, leases and other legacy liability savings Americas (excluding fuel): (26) Australia (excluding fuel): +263 ($ in Millions) EBITDAR Improvement Over Plan Dependent on Industry Conditions

2017 – 2021 Business Plan EBITDAR by Region Americas BU EBITDAR declines in 2018 primarily due to lower pricing from roll-off of higher-priced contracts and lower assumed pricing on uncommitted volume Resource Management contributes ~$10M EBITDAR gains per year, with ~$13M-$20M cash proceeds assumed PMO declines slightly due to reduced retiree healthcare amortization Company and advisors carefully reviewed legacy liabilities and concluded that it would not pursue retiree benefits (1113/1114 relief) based on current projections Australia results improve throughout the plan primarily driven by higher assumed pricing Consistent with past practice, an operational contingency of $25M is included in each year of the plan ($15M in Australia and $10M in Americas) for risks inherent in mining including longwall moves, geological issues, and weather disruptions Fuel and FX hedging losses relate to amortization of non-cash pre-petition losses in accordance with GAAP A portion of total net SG&A is included in both Americas Operations and Australia Operations 2016 Forecast ($'s in Millions) 220.4 $ Midwest 194.1 $ 176.5 $ 168.2 $ 137.8 $ 150.6 $ 135.4 West 152.6 149.0 119.4 105.0 113.6 288.8 Powder River Basin 306.8 298.1 266.2 328.0 333.2 (8.6) Americas Net SG&A / Other (6.4) (5.5) (5.7) (6.0) (8.7) - Americas Top Level Adjustment (10.0) (10.0) (10.0) (10.0) (10.0) 635.9 $ Americas Operations 637.1 $ 608.2 $ 538.0 $ 554.8 $ 578.7 $ (2.2) Domestic Liquidated Damages - - - - - (48.0) Past Mining Obligations (42.8) (39.8) (37.6) (42.0) (41.1) (128.8) Corporate Net SG&A / Other (128.7) (122.5) (122.0) (122.4) (120.1) 457.0 $ Total Debtor 465.6 $ 445.9 $ 378.4 $ 390.3 $ 417.5 $ 140.6 Total Thermal 104.1 92.9 154.1 152.9 210.0 (86.2) Total Metallurgical (40.3) 44.9 76.0 65.1 50.5 (74.3) Australia Net SG&A / Other (39.3) (43.1) (49.4) (40.0) (36.0) - Australia Top Level Adjustment (15.0) (15.0) (15.0) (15.0) (15.0) (19.9) $ Australia Operations 9.5 $ 79.6 $ 165.7 $ 163.1 $ 209.5 $ (48.1) $ Trading Operations 5.0 $ 5.0 $ 5.0 $ 5.0 $ 5.0 $ (2.8) Asia Operations (1.3) (1.3) $ (1.4) $ (1.4) $ (1.4) $ (70.7) $ Total Non-Debtor 13.2 $ 83.3 $ 169.3 $ 166.7 $ 213.1 $ 386.4 $ EBITDAR 478.8 $ 529.2 $ 547.8 $ 557.0 $ 630.6 $ (98.0) Fuel Hedging (1) (37.6) - - - - (143.0) FX Hedging (1) (55.0) - - - - (16.7) Internal Restructuring/KEIP/KERP (4.3) - - - - 68.1 VEBA Settlement Gain - - - - - 196.8 $ SEC-Reported Adjusted EBITDA 381.9 $ 529.2 $ 547.8 $ 557.0 $ 630.6 $ (131.2) Total Net SG&A (2) (123.4) (126.5) (130.9) (135.7) (135.1) (72.5) External Restructuring (58.2) - - - - 2021 Plan 2017 Plan 2018 Plan 2020 Plan 2019 Plan

2017 – 2021 Business Plan Consolidated Gross Capital Summary Operations continue to focus on cash preservation, with YTD 2016 annualized capital expenditures spending of ~$76M 2017 capital increases by $44M due to increase in Australia sustaining capital across multiple sites and project spend for thermal operations Sustaining capital remains relatively flat beyond 2017 in both Americas and Australia, with lease buyouts representing significant portion of sustaining spend in both platforms (Americas ~26%; Australia ~22%) Multiple Australia mines require recapitalization over the plan, reflected in ‘Projects’ with associated volume in the plan Australia plan includes other life extension capital totaling ~$100M for projects that deliver volume beyond 2021 and will be reassessed over time as industry conditions change ($ in Millions)

2017 – 2021 Business Plan 2016 and 2017 Cash Bridge ($ in Millions) 2017 Cash Usage 2016 Cash Usage 2016 cash from operations is not sufficient to cover capital ($112M), LBAs (~$250M), cash collateral needs ($94M) and other unfavorable working capital impacts primarily from tightening trade terms Cash generation turns positive in 2017 and improves ~$700M due to higher EBITDAR, lower fixed charges and assumed improvement in working capital Fixed charges other than capital are minimal in 2017 as LBA payments roll-off in 2016; interest or dividends post-emergence is not incorporated Restructuring activities include DIP extension and repayment ($523M), adequate protection payments ($83M), external fees ($58M), DIP interest ($38M) and KEIP/KERP ($7M) Cash Usage: ($254) Cash Generation: $455 ($ in Millions) Note: Plan reflects September 30, 2017 emergence, although management is targeting an earlier emergence.

Peabody Energy to Continue to Execute and Build Upon Business Plan Excellent workforce Safety, land restoration Geographic, product diversity U.S. asset base Thermal coal platform in Australia Lean, scalable operating model Asia-Pacific seaborne access Building on Strengths… …Targeting Improvements Ongoing operational improvements Optimizing met coal portfolio Achieve lower costs and synergies to compete with other fuels Advocacy of HELE and CCUS technologies …Positioning Post-Emergence