Exhibit 99.1
Investor Presentation February 2019
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 we expect or anticipate will occur in the future are forward-looking statements. They may include estimates of 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 the company’s good faith beliefs, assumptions and expectations, but they are not guarantees of future performance or events. Furthermore, the company 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 the company’s control, that are described in our Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2017, as well as additional factors we may describe from time to time in other filings with the SEC. You may get such filings for free at our 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. Statement on Forward-Looking Information 2
Peabody: A unique company in an essential global industry Peabody Provides Compelling Investment Opportunity as Leading Global Pure-Play Coal Company 2 3 4 5 Seaborne thermal: Serving growing demand centers, delivering leading margins Seaborne metallurgical: Providing an essential product for steelmaking; targeting expanded quantity/quality in 2020 Financial strength: Enabling continued commitment to significant shareholder returns 1 U.S. thermal: Emphasizing lowest-cost, highest-margin operations to maximize cash generation 6 Sustainable business: Supported by ESG, “Coal Done Right”3
North Antelope Rochelle Mine ONE: Peabody: A Unique Company in an Essential Global Industry North Antelope Rochelle Mine
Peabody Advancing Comprehensive Strategy in Support of Mission to Create Superior Value for Shareholders Operational Excellence Financial Strength Portfolio Management Focused Engagement Best People Continuing financial approach of generating cash, maintaining financial strength, investing wisely and returning cash to shareholders Optimizing lowest-cost and highest-margin U.S. thermal operations to maximize cash generation Portfolio re-weighting towards greater seaborne thermal and seaborne metallurgical coal access to capture higher-growth Asian demand5
Note: Coal sales as of Dec. 31, 2018. Proven and probable reserves as of Dec. 31, 2018. Free Cash Flow is a non-GAAP metric. Refer to the reconciliation to the nearest GAAP measures in the appendix. Peabody: Significant Scale Offers Numerous Benefits Strong financial position Optimized mine planning Solid cost structure Flexible production and sourcing; Expansion optionality Access to financial markets Scalable SG&A Sharing of skills, best practices and equipment Operates 23 underground and surface mines in U.S. and Australia Proven and probable reserves total 4.9 billion tons Sold 187 million tons of coal to electric and industrial customers Generated $1.36 billion of free cash flow in 2018 6 Optimized mine planning Sharing of skills, best Solid cost practices and structure equipment Strong financial position Flexible production Scalable and sourcing; SG&A Expansion optionality Access to financial markets
Wide distribution of revenue, Adjusted EBITDA contributions Multi-regional exposure limits demand, logistics and seasonal operational risks Increased risk-adjusted returns; non-correlative demand drivers No single exposure to currency and economic fundamentals Regulatory, political diversification Note: The company attributes revenue to individual regions based on the location of the physical delivery of the coal. Revenue breakdown for FY 2018. Adjusted EBITDA is non-GAAP metric. Peabody: Diversity Offers Significant Competitive Advantage U.S. Japan Taiwan Australia India China South Korea Other Percentage of Total Revenue from Customer Geographic Region in 20187
IHS Markit projects 125 GW of coal-plant retirements through 2030, more than offset by 439 GW of planned new coal capacity in Asia-Pacific 300 GW of new coal-fueled generating plants currently under construction in Asia –Each GW can use 3 million tons per year Global coal generation capacity passes 2,000 GW for first time ever in 2018 –62% increase from 2000 to 2018 24 countries have included low emissions coal technologies in NDCs to the Paris agreement Source: World Coal Association Q1 2018 Presentation. © 2018 IHS Markit. All rights reserved. The use of this content was authorized in advance. Any further use or redistribution of this content is strictly prohibited without prior written permission by IHS Markit. Tachibanawan Station in Japan Global Coal-Fueled Generating Capacity Projected to Rise Dramatically in Coming Years Coal-fueled generation is increasingly clean from: 1) low-emissions technologies to remove traditional pollutants, 2) high-efficiency plants to reduce carbon emissions, and 3) carbon capture advancements, which leading organizations view as essential to meeting global climate goals.8
Metallurgical Coal a Primary Component for 70% of World’s Steel Production Met Coal Pricing Above $140 Per Tonne 6 of Last 8 Years Source: World Coal Association Q1 2018 Presentation, industry reports and Peabody Global Analytics. Total 2018 seaborne met coal demand totals 315 MTPY Supply tight with new sources largely offsetting natural declines, disruptions India becomes second largest met coal importer; expected to surpass China Australia projected to supply majority of met coal growth - 50 100 150 200 250 300 350 400 HCC Index Avg: $172 per tonne 9
India ASEAN Japan China Europe Brazil Other 0 5 10 15 20 25 30 35 Vast Majority of Seaborne Metallurgical Coal Demand from Asia-Pacific Expected Seaborne Metallurgical Coal Demand Growth 2018 -2023(tonnes in millions) 80% of total seaborne demand growth from Asia-Pacific Source: World Coal Association Q1 2018 Presentation, industry reports and Peabody Global Analytics. Beyond Electricity, Coal Helps Build Modern Cities, Economies10
Regional Strength, Reliability and Resilience of Coal Mitigates Secular Decline of U.S. Thermal Coal Demand Coal is, and expected to remain key contributor to U.S. power demand –Major source of electricity in 8 out 12 regions –Fuels 27% of U.S. power PRB, ILB expected to fuel nearly two-thirds of U.S. utility demand in 2023 Utility stockpiles at lowest levels since 2005 –Production declining more rapidly than use –Thermal exports rise 34% in 2018 Select U.S. Energy Markets: 2018 Electricity Generation (TWh) 0 50 100 150 200 250 300 350 MISO SPP ERCOT Coal Gas Nuclear Wind Other PRB ILB Other 2023 Expected Sources of U.S. Electric Power Sector Demand Source: Peabody Global Energy Analytics; Industry sources 11
Coal Maintains Leading Fuel Position in Numerous U.S. Regions Source: www.pjm.com; www.iiso-ne.com; www.misenergy.org; www.ercot.com; www.spp.org/; SNL, FERC Note: FY 2018 data not available yet for all regions; Peabody tons sold based on 2018 volumtes NW Power Pool Gas Coal: 36% BTU: 1 mt Desert SW Coal: 37% BTU: 13 mt ERCOT Coal: 32% BTU: 12 mt SERC Coal: 33% BTU: 9 mt MISO Coal: 49% BTU: 68 mt SPP Coal: 46% BTU: 30 mt Rockies Coal: 54% BTU: 3 mt ISO-NE Coal: 2% BTU: 0 mt FRCC Coal: 19% BTU: <1 mt CAISO Coal: 0% BTU: 0 mt NYISO Coal: 1% BTU: 0 mt PJM Coal: 32% BTU: 13 mt >20% of electricity from coal <20% of electricity from coal 12
TWO: Seaborne Thermal: Serving Growing Demand Centers, Delivering Leading Margins WilpinjongMine
14 Seaborne Thermal Coal Platform Represents Tier One Assets with Strong Margins; Positioned to Serve Asia-Pacific Demand 34% 44% 37% 38% 31% 40% 48% 42% $82 $80 $93 $98 $103 $104 $117 $105 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Seaborne Thermal Coal Adjusted EBITDA Margins Margin % Average NEWC Price Note: Adjusted EBITDA margins are non-GAAP metrics. Adjusted EBITDA margin is equal to segment Adjusted EBITDA divided by segment revenue. Refer to the reconciliation to the nearest GAAP measures in the appendix.
Advancing Attractive Seaborne Thermal Life Extension Projects to Maintain Export Thermal Coal Volumes Unincorporated joint venture with Glencore gives access to stratified reserves and extends life of Wambo open cut mine –Scheduled to begin production in early 2020 Wilpinjong extension project ensures long-term access to seaborne demand centers; extends life of mine to 2030 –Provides substantial returns with rapid payback period 2019 Target 11.5 million to 12.5 milliontons of export thermal coal Product Split 60% to 70% NEWC (6,000 spec) 30% to 40% API5 (5,500 spec) Wambo Mine 15
THREE: Seaborne Met: Providing Essential Product for Steel; Targeting Expanded Quality/Quantity in 2020 Shoal Creek Mine
17 Targeting Progressive Increase in Peabody’s Quality and Quantity of Met Coal Production 2019 2020 PCI HCC 9.4 –10.4 million tons PCI HCC +1.5milliontons North Goonyella base case -expected to produce 2 million tons of HCC in 2020 Equity-accounted JV, Middlemount, adds additional 2 million tons of economic coking coal exposure each year Note: 2019 mix assumes mid-point of guidance range; 2020 volume addition based on addition of 2 million tons of HCC from North Goonyella base case less 0.5 million tons from Millennium Mine closure in 2019.
18 Targeting 2.5 million tons of high-quality seaborne met coal shipments in 2019 Anticipating costs in the vessels of $85 –$95 per short ton Serves Asian and Atlantic steel customers Strategically positioned with direct access to transportation Well-capitalized longwall operation and 55 million tons of reserves Integration well under way “Asia Confidence” carries first Shoal Creek shipment following Peabody acquisition. Shoal Creek Acquisition Upgrades Seaborne Met Portfolio; Represents Multiple Strategic and Financial Benefits
Executing Multi-Phased Re-Ventilation and Re-Entry Plan at North Goonyella, Targeting Longwall Mining in Early 2020 Stage-gate approach allows periodic re-evaluation of progress, costs and investments Ramping up longwall production from North Goonyella in 2020 –Targeting modest sales in 2019 –Base case: 2 million tons of production expected in 2020…and more in 2021 Projected 2019 North Goonyella financial effects: –Idling and project costs: $30 to $35 million per quarter (Q1 19 higher due to additional drilling activities associated with segmenting of mine into zones) –Capital investments, including planned new longwall equipment for previously announced GM South extension: $110 million –Insurance proceeds: $125 million anticipated Active portfolio management includes: –Millennium Mine completing highwall mining in 2019 –Evaluating opportunities to further extend life of Moorvale Mine 19
Rawhide Mine FOUR: U.S. Thermal: Emphasizing Lowest-Cost, Highest-Margin Operations to Maximize Cash Generation
U.S. Thermal Operations Well Positioned to Deliver Results Location matters… Peabody is well positioned in the best, lowest-cost U.S. basins of the PRB and Illinois Basin Returns matter… Peabody focused on generating meaningful returns across the operations to maximize cash generation –Maximizing revenues through contracting strategy, blending techniques –Optimizing how we move overburden, mine coal to deliver lowest unit costs –Emphasizing lowest-cost, highest-margin U.S. thermal operations Reliability matters… Peabody provides reliability of supply and serves as strong cash generator Safety, environment and our people matter… Key components in ensuring successful business and culture 21
Continued Emphasis on Value Over Volume Across U.S. Thermal Operations Focused on larger-scale mines and complexes to extract value –Ability to move contracts, people, equipment between complexes to maximize margins Optimizing PRB mix to deliver highest-margin tons in response to lower demand –Entering 2019 with 90% to 95% of PRB volumes priced Likely closure of Kayenta Mine in Q3 2019 –Alternatively, working with Navajo agency on transition project involving Kayenta Mine –Owners contractually obligated to fund portion of certain reclamation, retiree healthcare liabilities; accelerated cash collections in 2018, 2019 2019 Targets PRB: 105 to 115 million tons ILB: 17.5 to 18.5 million tons Western: 11 to 12 million tons 22
FIVE: Financial Strength: Enabling Continued Commitment to Significant Shareholder Returns
Maintaining Financial Strength Through Optimal Liquidity, Debt Targets and Continued Liability Management Debt & Liquidity Dec. 2017 Dec. 2018 ($ in millions) Balance Balance Unrestricted Cash & Cash $1,012 $982 Equivalents Revolver Availability $194 $244 ARS Availability $38 $94 Total Liquidity $1,244 $1,320 Total Funded Debt $1,461 $1,367 Net Debt $449 $385 Other Liabilities Dec. 2017 Dec. 2018 ($ in millions) Balance Balance OPEB $783 $580 ARO $691 $750 Pension $98 $31 Total Liabilities $4,525 $3,972 Generated 2018 free cash flow of $1.36 billion Current liquidity of $1.3 billion well above $800 million target Total debt within $1.2 billion to $1.4 billion target range Targeting 2019 reclamation cash outlays of $75 million recognizing higher activity Peabody EBITDA to cash conversion very strong with substantial NOL position $3.2 billion in U.S. A$3.1 billion in Australia Note: Liability balances include current and non-current balances. Free Cash Flow is a non-GAAP financial measure. Refer to the reconciliation to the nearest GAAP measures in the appendix. 24
Substantial Operating Cash Flows Provide Opportunity for Shareholder Returns, Focused Capital Investment Continue to evaluate all investments using strict filters Repurchased $1.1 billion of common stock since August 2017 Dividend per share increases 13% since inception of program Targeting 2019 capex of $375 to $425 million –70% allocated to higher-growth seaborne-oriented portfolios 2018 Cash Allocation Shoal Creek$387M Seaborne MetCapex$88M Seaborne Thermal Capex $67M U.S. Thermal Capex $142M Share Repurchases$835M Dividends $60M 94% of Free Cash Flow Used for capital Returns to Shareholders and Shoal Creek Acquisition Note: Free Cash Flow is a non-GAAP metric. Refer to the reconciliation to the nearest GAAP measures in the appendix. 25
26 Stronger BTU…Continuing to Drive Returns Sept. 17 Dec. 17 March 18 June 18 Sept. 18 Dec. 18 Feb. 19 Cumulative Shareholder Returns($ in millions) Share Repurchases Quarterly Dividend $69 $176 $366 $580 $920 $1,070 $1,159 Note: Feb. 2019 cumulative cash returned to shareholders includes quarterly dividend of $14 million to be paid on March 6, 2019.
27 BTU Offers Significant Intrinsic Value; Generating 2018 Results Superior to Benchmarks Source: Capital IQ; Coal and Consumable Fuel group per Capital IQ includes 199 companies. Return on capital using a standard tax rate of 37.5% for all companies. TEV/EBITDA represents market capitalization as of Feb. 15, 2019 plus net debt divided by 2018 EBITDA estimates per Capital IQ. Adjusted EBITDA (may not be calculated identically by all companies) and return on capital are non-GAAP metrics. Refer to the appendix for a reconciliation of these metrics. 3% 25% 8% 6% 22% 7% 14% 16% 10% 4% 17% 4% SG&A % of Revenue Adjusted EBITDA Margin Return on Capital BTU Coal & Consumable Fuels S&P 400 S&P 400 - Energy 2.8x 5.2x 10.7x 6.9x TEV/EBITDA
North Antelope Rochelle Mine SIX: Sustainable Business: Supported by ESG,” Coal Done Right” North Antelope Rochelle Mine
Peabody’s Emphasis on ESG Complements Financial Approach to Create Long-Term Value for Shareholders Note: Restored acres for 2018 calendar year. Recycled/reused waste and direct/indirect economic benefits for 2017 calendar year. Peabody’s 2017 Corporate and Social Responsibility Report is available on PeabodyEnergy.com. Recognized with Nearly 100 honors in past decade for Safety, Reclamation and Corporate leadership Environmental Restored 1.4 acres for every acre disturbed Recycled/reused 72% of waste Sponsor of Global Clean Coal Awards; Advocate for advanced coal technologies Received 3 out of 4 national reclamation awards from OSM Social Outperforms industry averages for safety Provided $10.6B in direct/indirect economic benefits Signatory to CEO Action for Diversity & Inclusion® pledge Governance Separation of CEO and Chairman Independent and diverse board skills and experiences Exec compensation based on safety, free cash flow per share, EBITDA, ROIC, TSR, environmental performance 29
Appendix DELIVERING RESULTS GENERATING VALUE
2019 Guidance Targets Sales Volumes (Short Tons in millions) PRB 105 – 115 ILB 17.5 – 18.5 Western 11 – 12 Seaborne Metallurgical 9.4 – 10.4 HCC1: 40% – 50% PCI2: 50% – 60% Seaborne Export Thermal 11.5 – 12.5 NEWC: 60% – 70% API 5: 30% - 40% 7 – 8 Australia Domestic Thermal Revenues per Ton Total U.S. Thermal $17.10 – $18.10 Costs Per Ton (USD per Short Ton) PRB $9.25 – $9.75 ILB $32 – $35 $13.95 – $14.95 Total U.S. Thermal Seaborne Thermal3 (includes Aus. Domestic Thermal) $32 – $36 Seaborne Metallurgical3 $85 – $95 (excluding North Goonyella) Quarterly North Goonyella Costs $30 – $35 million Quarterly SG&A Expense $40 million Full-Year Capital Expenditures $375 – $425 million Interest Expense4 $150 million Cost Sensitivities5 $0.05 Decrease in A$ FX Rate6 + $80 million $0.05 Increase in A$ FX Rate6 - $80 million Fuel (+/- $10/barrel) +/- $30 million 2019 Priced Position (Avg. Price per Short Ton) PRB $11.24 ILB $42 Seaborne Export Thermal Volumes $82 90% -95% of Peabody’s 2019 U.S. thermal volumes are priced based on the mid-point of 2019 volume guidance 4.7 million short tons of seaborne export thermal coal priced for 2019 2020 Priced Position (Avg. Price per Short Ton) 35% and 55% of Peabody’s 2020 U.S. thermal volumes are priced and committed, respectively, based on the mid-point of 2019 volume guidance Seaborne Export Thermal Volumes $75 1.7 million short tons of seaborne export thermal 31 coal priced for 2020
2019 Guidance Targets 1 Peabody expects to realizes 80%-90% of the premium HCC quoted index price on a weighted average across all its products. 2 Approximately 40% of Peabody’s seaborne metallurgical PCI sales are on a spot basis, with the remainder linked to the quarterly contract. Peabody expects to realizes 80%-90% of the LV PCI benchmark for its PCI products. 3Assumes 2019 average A$ FX rate of $0.73. 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, and non-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 Dec. 31, 2018, Peabody had outstanding average rate call options to manage market price volatility associated with the Australian dollar in aggregate notional amount of approximately AUD $875 million with strike price levels averaging $0.77 and settlement dates through Sept. 30, 2019. Sensitivities provided are relative to an assumed average A$ FX exchange rate of $0.71 as of Dec. 31, 2018. 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 are non-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 Jan. 31, 2019 Peabody had approximately 108.1 million shares of common stock outstanding. Including approximately 3.7 million shares of unvested equity awards, Peabody has approximately 111.8 million shares of common stock on a fully diluted basis. 32
North Goonyella Mine: Segmenting of Multiple Zones North Goonyella Fan Installation 33
Peabody owns 50% equity interest in Middlemount Share of operations delivered 2.1 million tons in 2018 –Mix of semi-hard coking coal, LV PCI –Port capacity through Abbot Point, future capacity secured at DBCT Earned 2018 Adjusted EBITDA of $50 million, reflecting Peabody’s share of Middlemount’s net income –Peabody collected $107 million of loan and other cash repayments in 2018 Over 10 years of reserves at current production profile Middlemount Mine Note: Adjusted EBITDA is a non-GAAP metric. Refer to the reconciliation to the nearest GAAP measure in the appendix. All metrics reflect Peabody’s 50% ownership share in Middlemount. Middlemount Joint Venture Offers Economic Exposure to 2 Million Met Tons Annually 34
Historical Seaborne Pricing ($/Tonne) Time Period HCC – HCC – Spot LV PCI – LV PCI – Spot NEWC – API 5 -Settlement Settlement Spot Prompt Q4 2018 $212 $221 $139 $128 $105 $64 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 and LV PCI spot prices per Platts; NEWC spot price per ICE Futures; Settlement prices per IHS 35 Markit benchmark history.
Reconciliation of Non-GAAP Measures Predecessor Successor Successor Jan. 1 through Apr. 2 through Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Apr. 1, 2017 Jun. 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Mar. 31, 2018 Jun. 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Tons Sold (In Millions) Powder River Basin Mining Operations 31.0 28.5 33.7 31.8 32.4 26.2 31.7 30.0 120.3 Midwestern U.S. Mining Operations 4.5 4.6 4.9 4.5 4.7 4.7 4.9 4.6 18.9 Western U.S. Mining Operations 3.4 3.2 4.0 4.1 3.7 3.5 4.0 3.5 14.7 Total U.S. Thermal Mining Operations 38.9 36.3 42.6 40.4 40.8 34.4 40.6 38.1 153.9 Seaborne Metallurgical Mining Operations 2.2 2.0 3.5 4.0 3.0 2.9 2.8 2.3 11.0 Seaborne Thermal Mining Operations 4.6 4.6 5.2 4.8 3.8 5.0 4.8 5.5 19.1 Corporate and Other 0.4 0.7 0.7 0.6 0.7 0.8 0.9 0.3 2.7 Total 46.1 43.6 52.0 49.8 48.3 43.1 49.1 46.2 186.7 Revenue Summary (In Millions) Powder River Basin Mining Operations $ 394.3 $ 365.4 $ 420.9 $ 392.4 $ 389.3 $ 321.5 $ 373.7 $ 340.3 $ 1,424.8 Midwestern U.S. Mining Operations 193.2 194.9 207.7 189.7 201.7 197.5 208.5 193.3 801.0 Western U.S. Mining Operations 149.7 125.4 155.7 159.6 143.7 139.6 156.1 152.6 592.0 Total U.S. Thermal Mining Operations 737.2 685.7 784.3 741.7 734.7 658.6 738.3 686.2 2,817.8 Seaborne Metallurgical Mining Operations 328.9 287.8 415.9 517.3 466.2 417.5 370.3 299.0 1,553.0 Seaborne Thermal Mining Operations 224.8 239.2 265.8 267.5 201.4 267.4 305.1 325.3 1,099.2 Corporate and Other 35.3 45.6 11.2 (9.4) 60.4 (34.1) (1.1) 86.6 111.8 Total $ 1,326.2 $ 1,258.3 $ 1,477.2 $ 1,517.1 $ 1,462.7 $ 1,309.4 $ 1,412.6 $ 1,397.1 $ 5,581.8 Note: Refer to definitions and footnotes on last slide of the deck. 36
Reconciliation of Non-GAAP Measures Predecessor Successor Successor Jan. 1 through Apr. 2 through Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Apr. 1, 2017 Jun. 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Mar. 31, 2018 Jun. 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Total Reporting Segment Costs (1) Summary (In Millions) Powder River Basin Mining Operations $ 302.6 $ 280.6 $ 308.2 $ 311.1 $ 314.8 $ 259.5 $ 285.5 $ 280.5 $ 1,140.3 Midwestern U.S. Mining Operations 143.2 148.4 158.2 161.3 170.5 155.5 169.8 160.0 655.8 Western U.S. Mining Operations 99.7 80.5 121.2 107.2 111.7 105.7 127.6 101.6 446.6 Total U.S. Thermal Mining Operations 545.5 509.5 587.6 579.6 597.0 520.7 582.9 542.1 2,242.7 Seaborne Metallurgical Mining Operations 219.3 215.9 272.8 317.4 299.8 259.0 279.6 273.2 1,111.6 North Goonyella Costs - - - - - - 9.0 49.0 58.0 Seaborne Metallurgical Mining Operations, Excluding North Goonyella Costs 219.3 215.9 272.8 317.4 299.8 259.0 270.6 224.2 1,053.6 Seaborne Thermal Mining Operations 149.2 133.3 168.0 164.6 139.8 159.8 159.8 187.8 647.2 Corporate and Other 50.6 49.6 22.1 35.9 31.6 19.5 35.8 28.3 115.2 Total $ 964.6 $ 908.3 $ 1,050.5 $ 1,097.5 $ 1,068.2 $ 959.0 $ 1,058.1 $ 1,031.4 $ 4,116.7 Adjusted EBITDA (2) (In Millions) Powder River Basin Mining Operations $ 91.7 $ 84.8 $ 112.7 $ 81.3 $ 74.5 $ 62.0 $ 88.2 $ 59.8 $ 284.5 Midwestern U.S. Mining Operations 50.0 46.5 49.5 28.4 31.2 42.0 38.7 33.3 145.2 Western U.S. Mining Operations 50.0 44.9 34.5 52.4 32.0 33.9 28.5 51.0 145.4 Total U.S. Thermal Mining Operations 191.7 176.2 196.7 162.1 137.7 137.9 155.4 144.1 575.1 Seaborne Metallurgical Mining Operations 109.6 71.9 143.1 199.9 166.4 158.5 90.7 25.8 441.4 North Goonyella Costs - - - - - - 9.0 49.0 58.0 Seaborne Metallurgical Mining Operations, Excluding North Goonyella Costs 109.6 71.9 143.1 199.9 166.4 158.5 99.7 74.8 499.4 Seaborne Thermal Mining Operations 75.6 105.9 97.8 102.9 61.6 107.6 145.3 137.5 452.0 Resource Management Results (3) 2.9 1.2 0.4 0.9 20.8 0.7 21.3 1.9 44.7 Selling and Administrative Expenses (36.3) (34.7) (33.7) (37.9) (37.0) (44.1) (38.6) (38.4) (158.1) Acquisition Costs Related to Shoal Creek - - - - - - (2.5) (4.9) (7.4) Other Operating Costs, Net (4) (2.2) (2.7) 7.0 (11.7) 14.4 9.0 0.5 7.7 31.6 Adjusted EBITDA (2) $ 341.3 $ 317.8 $ 411.3 $ 416.2 $ 363.9 $ 369.6 $ 372.1 $ 273.7 $ 1,379.3 Note: Refer to definitions and footnotes on last slide of the deck. 37
Reconciliation of Non-GAAP Measures Predecessor Successor Successor Jan. 1 through Apr. 2 through Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended Quarter Ended Year Ended Apr. 1, 2017 Jun. 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Mar. 31, 2018 Jun. 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Dec. 31, 2018 Reconciliation of Non-GAAP Financial Measures (In Millions) (Loss) Income from Continuing Operations, Net of Income Taxes $ (195.5) $ 101.4 $ 233.7 $ 378.0 $ 208.3 $ 120.0 $ 83.9 $ 233.5 $ 645.7 Depreciation, Depletion and Amortization 119.9 148.3 194.5 178.8 169.6 163.9 169.6 175.9 679.0 Asset Retirement Obligation Expenses 14.6 11.0 11.3 18.9 12.3 13.2 12.4 15.1 53.0 Asset Impairment 30.5 - - - - - - - -Provision for North Goonyella Equipment Loss - - - - - - 49.3 17.1 66.4 Changes in Deferred Tax Asset Valuation Allowance and Reserves and Amortization of Basis Difference Related to Equity Affiliates (5.2) (4.3) (3.4) (9.6) (7.6) (8.4) (6.1) 3.8 (18.3) Interest Expense 32.9 41.4 42.4 35.9 36.3 38.3 38.2 36.5 149.3 Loss on Early Debt Extinguishment - - 12.9 8.0 - 2.0 - - 2.0 Interest Income (2.7) (1.5) (2.0) (2.1) (7.2) (7.0) (10.1) (9.3) (33.6) Net Mark-to-Market Adjustment on Actuarially Determined Liabilities - - - (45.2) - - - (125.5) (125.5) Reorganization Items, Net 627.2 - - - (12.8) - - - (12.8) Gain on Disposal of Reclamation Liability - - - (31.2) - - - - -Gain on Disposal of Burton Mine - - - (52.2) - - - - -Break Fees Related to Terminated Asset Sales - (28.0) - - - - - - -Unrealized (Gains) Losses on Economic Hedges (16.6) (9.4) 10.8 21.6 (38.6) 48.1 26.8 (54.6) (18.3) Unrealized (Gains) Losses on Non-Coal Trading Derivative Contracts - (3.2) 1.7 3.0 1.8 (0.1) (0.3) (0.7) 0.7 Fresh Start Coal Inventory Revaluation - 67.3 - - - - - - -Fresh Start Take-or-Pay Contract-Based Intangible Recognition - (9.9) (6.5) (6.1) (8.3) (7.8) (5.4) (5.2) (26.7) Income Tax (Benefit) Provision (263.8) 4.7 (84.1) (81.6) 10.1 7.4 13.8 (12.9) 18.4 Adjusted EBITDA (2) $ 341.3 $ 317.8 $ 411.3 $ 416.2 $ 363.9 $ 369.6 $ 372.1 $ 273.7 $ 1,379.3 Operating Costs and Expenses $ 950.2 $ 927.9 $ 1,039.1 $ 1,085.7 $ 1,057.2 $ 946.5 $ 1,047.9 $ 1,021.0 $ 4,072.6 Break Fees Related to Terminated Asset Sales - 28.0 - - - - - - -Unrealized Gains (Losses) on Non-Coal Trading Derivative Contracts - 3.2 (1.7) (3.0) (1.8) 0.1 0.3 0.7 (0.7) Fresh Start Coal Inventory Revaluation - (67.3) - - - - - - -Fresh Start Take-or-Pay Contract-Based Intangible Recognition - 9.9 6.5 6.1 8.3 7.8 5.4 5.2 26.7 Net Periodic Benefit Costs, Excluding Service Cost 14.4 6.6 6.6 8.7 4.5 4.6 4.5 4.5 18.1 Total Reporting Segment Costs (1) $ 964.6 $ 908.3 $ 1,050.5 $ 1,097.5 $ 1,068.2 $ 959.0 $ 1,058.1 $ 1,031.4 $ 4,116.7 Net Cash (Used In) Provided By Operating Activities $ (813.0) $ 65.7 $ 248.0 $ 499.7 $ 579.7 $ 335.7 $ 345.4 $ 228.9 $ 1,489.7 Net Cash Provided By (Used In) Investing Activities 15.1 (18.5) (16.4) (58.5) (6.4) (11.6) (47.5) (451.8) (517.3) Add Back: Acquisition of Shoal Creek Mine - - - - - - - 387.4 387.4 Free Cash Flow (5) $ (797.9) $ 47.2 $ 231.6 $ 441.2 $ 573.3 $ 324.1 $ 297.9 $ 164.5 $ 1,359.8 Note: Refer to definitions and footnotes on last slide of the deck. 38
Reconciliation of Non-GAAP Measures Note: Refer to definitions and footnotes on last slide of the deck. Year Ended Dec. 31, 2018Dec. 31, 2018Revenues5,581.8$ Operating Costs and Expenses4,072.6 Total Debt1,367.0$ Depreciation, Depletion and Amortization679.0 Cash and Cash Equivalents981.9 Asset Retirement Obligation Expenses53.0 Net Debt (9)385.1$ Selling and Administrative Expenses158.1 Income Tax Provision18.4 Feb. 15, 2019Earnings Before Interest (6)600.7$ Shares Outstanding108.1 Share Price31.17$ Revenues5,581.8$ Market Capitalization3,369.5$ Operating Costs and Expenses4,072.6 Depreciation, Depletion and Amortization679.0 Market Capitalization as of Feb. 15, 20193,369.5$ Asset Retirement Obligation Expenses53.0 Net Debt (9) as of Dec. 31, 2018385.1 Selling and Administrative Expenses158.1 Noncontrolling Interests as of Dec. 31, 201856.0 Income Tax Provision (Using Standard Tax Rate of 37.5% per Capital IQ) 232.2 Total Enterprise Value (10)3,810.6$ Earnings Before Interest, Using Standard Tax Rate (7)386.9$ Dec. 31, 2017Dec. 31, 2018AverageTotal Stockholders’ Equity3,655.8$ 3,451.6$ Total Debt1,460.8 1,367.0 Total Stockholders’ Equity and Debt (8)5,116.6$ 4,818.6$ 4,967.6$ 39
Reconciliation of Non-GAAP Measures: Definitions Note: Free Cash Flow; Adjusted EBITDA; Earnings Before Interest; Earnings Before Interest, Using Standard Tax Rate; Total Stockholders’ Equity and Debt; Net Debt and Total Enterprise Value are non-GAAP financial measures. Return on capital is equal to Earnings Before Interest dividend by the average Total Stockholders’ Equity and Debt. Management believes that non-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)Includes gains (losses) on certain surplus coal reserve and surface land sales, property management costs and revenues, the Q3 2018 gain of $20.5 million on the sale of surplus coal resources associated with the Millennium Mine and the Q1 2018 gain of $20.6 million on the sale of certain surplus land assets in Queensland’s Bowen Basin. 4)Includes income from equity affiliates (before the impact of related changes in deferred tax asset valuation allowance and reserves and amortization of basis difference), trading and brokerage activities, costs associated with post-mining activities, certain coal royalty expenses, minimum charges on certain transportation-related contracts, the Q1 2018 gain of $7.1 million recognized on the sale of our interest in the Red Mountain Joint Venture and the Q1 2017 gain of $19.7 million recognized on the sale of Dominion Terminal Associates. 40
Reconciliation of Non-GAAP Measures: Definitions (Continued) 5)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. 6)Earnings Before Interest is defined as revenues less operating costs and expenses, deprecation, depletion and amortization, asset retirement obligation expenses, selling and administrative expense and income tax provision. Due to Peabody’s NOL position in the U.S. and Australia, we currently pay minimal cash taxes. 7)Earnings Before Interest, Using Standard Tax Rate is defined as revenues less operating costs and expenses, deprecation, depletion and amortization, asset retirement obligation expenses, selling and administrative expenses and income tax provision calculated using a standard tax rate of 37.5% per Capital IQ. 8)Total Stockholders’ Equity and Debt is defined as total stockholders’ equity plus total debt. 9)Net Debt is defined as total debt less cash and cash equivalents. 10)Total Enterprise Value is defined as market capitalization plus Net Debt plus noncontrolling interests. Market capitalization is as of Feb. 15, 2019; debt balances are as of Dec. 31, 2018. 11)Note: Adjusted EBITDA margin is equal to Adjusted EBITDA divided by total Revenue; Segment Adjusted EBITDA margin is equal to Segment Adjusted EBITDA divided by Segment Revenues. 41