Exhibit 99.1

Cloud Peak Energy Discussion Materials May 2019 1

Disclaimer The information contained herein includes proprietary information regarding Cloud Peak Energy Inc. and its corporate affiliates (jointly and severally, “Cloud Peak”, “CPE”, or the “Company”). The assumptions and financial projections contained herein are those of the management of the Company. While management believes that these assumptions and financial projections are reasonable, there can be no assurances that the action programs will be executed in a timely fashion and produce projected financial results within the projected time period. Moreover, there will usually be differences between projected and actual results, because events and circumstances frequently do not occur as expected, and those differences may be material. This presentation contains “forward-looking statements” within the meaning of the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 – that is, statements related to future, not past, events. In this context, forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “may,” “estimate,” “could,” “should,” “potential,” “will” or words of similar meaning. Forward-looking statements are based on management’s current expectations, beliefs, assumptions and estimates regarding our company, industry, economic conditions, governmental regulations, energy policies and other factors. Forward- looking statements by their nature address matters that are, to different degrees, uncertain. For us, particular risks and uncertainties arise, among other things, from our ability to continue as a going concern; from our ability to successfully complete a sale process under Chapter 11; from potential adverse effects of the Chapter 11 cases on our liquidity and results of operations; from our ability to obtain timely approval by the United States Bankruptcy Court for the District of Delaware (the “Court”) with respect to the motions filed in the Chapter 11 cases; from objections to our sale process, debtor-in-possession term loan facility (the “DIP Financing”) or other pleadings filed that could protract the Chapter 11 cases; from employee attrition and our ability to retain senior management and other key personnel due to the distractions and uncertainties, including our ability to provide adequate compensation and benefits during the Chapter 11 cases; from our ability to comply with the restrictions imposed by our Accounts Receivable Securitization Program (the “A/R Securitization Program”), DIP Financing and other financing arrangements; from our ability to maintain relationships with suppliers, customers, employees and other third parties and regulatory authorities as a result of the Chapter 11 filing; from the effects of the bankruptcy petitions on our company and on the interests of various constituents, including holders of our common stock; from the Court’s rulings in the Chapter 11 cases, including the approvals of a Sale and Plan Support Agreement, an amendment to the A/R Securitization Program and the DIP Financing, and the outcome of the Chapter 11 cases generally; from the length of time that we will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings; from risks associated with third party motions in the Chapter 11 cases, which may interfere with our ability to consummate a sale; and from increased administrative and legal costs related to the Chapter 11 process and other litigation and inherent risks involved in a bankruptcy process; from our ability to maintain, obtain and comply with the terms of required surety bonds; from liquidity constraints, access to capital and credit markets and availability and costs of credit, surety bonds, letters of credit and insurance; our liquidity, results of operations, and financial condition generally, including amounts of working capital that are available; from changes in the demand for our coal by the domestic electric generation industry; from legislation and regulations relating to the Clean Air Act and other environmental initiatives; from operational, geological, permit, labor and weather-related factors; from fluctuations in the amount of cash we generate from operations; from future integration of acquired businesses; from litigation against the Company; and from numerous other matters of national, regional and global scale, including those of a political, economic, business, competitive or regulatory nature. These risks and uncertainties may cause our actual future results to be materially different than those expressed in our forward-looking statements. We do not undertake to update our forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. For a description of some of the risks and uncertainties that may affect our future results, you should see the risk factors described from time to time in the reports we file with the Securities and Exchange Commission, including those in Item 1A “Risk Factors” of our most recent Form 10-K. This presentation includes certain non-GAAP financial measures, including Adjusted EBITDA and Unlevered Free Cash Flow. Definitions of these non-GAAP financial measures are included in the appendix section of this presentation. These non-GAAP financial measures are not measures of financial performance in accordance with generally accepted accounting principles and may exclude items that are significant in understanding and assessing our financial results. Therefore, these measures should not be considered in isolation or as an alternative to net income from operations, cash flows from operations, earnings per fully-diluted share or other measures of profitability, liquidity or performance under generally accepted accounting principles. You should be aware that our presentation of these measures may not be comparable to similarly-titled measures used by other companies. Because of the inherent uncertainty related to the items identified above, the Company does not believe it is able to provide a meaningful forecast of the comparable GAAP measures or reconciliation to any forecasted GAAP measure. 2

Table of Contents 1 Executive Summary 2 Sales and Marketing 3 Operations 4 Business Plan and Other Financial Information 5 Appendix 3

Executive Summary 1 4

Cloud Peak Snapshot Overview Cloud Peak Energy was formed through an IPO from Rio Tinto in 2009. Only PRB pure-play coal company. 2018 coal shipments from our three mines of 49.7 million tons with 4.6 million export tons. 2018 proven & probable reserves of approximately 975 million tons. Extensive NPRB projects and options. Approx. 1,250 employees. ■ ■ ■ ■ ■ ■ 5

Good Safety Record = Well-Run Operations Top Coal Producing Companies – 2017 All Injury Frequency Rates (MSHA) 7.16 5.90 4.59 3.57 Company 3.20 3.12 3.09 Best 2.79 Cloud Peak Energy 1.72 1.63 1.63 1.65 1.28 0.37 0.17 - Source: Mine Safety and Health Administration Note: All Injury Frequency Rate = (total number of employee injuries x 200,000) / total man-hours. 6 6.24 6.28 4.49 4.58 3.85 3.90 2.04 0.73 2018 MSHA AIFR 0.35

Summary of Active Mining Operations Overview of Key Mining Operations Map of Operations Spring Creek Cordero Rojo Antelope Domestic Export FY’18 Production (million tons) 23.2 13.8 12.6 Reserve Quality (Btu / lb) 8,875 9,350 8,425 Sulfur Content (%) 0.22% 0.34% 0.28% Proven & Probable Reserves (million tons) 472.4 219.6 285.4 Mine Life(1) 20 years 16 years 23 years The Company also has two development projects, Youngs Creek with ~284 million non-reserve coal deposits(2) and Big Metal with an estimated ~1,387 million tons of non-federal coal(3) Note: (1) (2) All tons in millions. Assumes production at the 2018 level. Non-reserve coal deposits are not reserves under SEC Industry Guide 7. Estimates of non-reserve coal deposits are subject to further exploration and development, are more speculative, and may not be converted to future reserves of the Company. Represents a current estimate of physical in-place coal tons. Does not represent proven and probable reserves, non-reserve coal deposits or a forecast of tons to be produced and sold in the future. Future production and sales of such tons, if any, are subject to regulatory approvals, completion of land access agreements, and significant risk and uncertainty, including coal demand and pricing in the U.S. and internationally. In addition, portions of the potential project remain subject to exercise of additional options. (3) 7 End Customer

Powder River Basin Demand Decline Southern PRB Production Trends Key Observation 8400 vs. 8800, 2009-2018 Domestic PRB demand has declined due to utilities generating less electricity from coal: 450 ■ ■ ■ ■ Stagnant electricity demand Ample low price Natural Gas Subsidized renewable energy Regulations increasing cost to operate coal mines Incentives to close plants Many coal power plants only run intermittently 400 350 300 250 200 ■ ■ 150 100 50 0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 8800 Btu 8400 Btu Source: MSHA 2009 – 2018. 8 (million tons) 41% 34% 59% 66%

CPE Production Decline Tons sold Antelope Mine Cordero Rojo Mine Spring Creek Mine Decker Mine(1) Tons Purchased and Resold Total tons sold Average realized price per ton sold(2) Average cost of product sold per ton(2) Average operating margin per ton(2) 31.4 36.7 18.0 1.5 33.6 34.8 17.4 1.1 35.2 22.9 17.0 - 29.8 18.3 10.4 - 28.4 16.4 12.6 - 23.2 12.6 13.8 - 24.1 10.0 14.0 - 28.0 10.0 14.0 - 1.5 0.1 0.3 0.3 0.3 - - - 89.1 87.1 75.3 58.8 57.8 49.7 48.1 52.0 $13.08 $10.19 $ 2.89 $13.01 $10.16 $ 2.85 $12.79 $12.40 $12.17 $12.11 $11.19 $11.98 $11.79 $12.24 $11.31 $ $ 9.78 3.01 $ $ 9.81 2.59 $ $ 9.87 2.30 $ 0.92 $ 0.19 $ 0.93 (1) (2) Represents the 50% share in a former non-operating interest divested by Cloud Peak Energy in September 2014. Represents only our three Owned and Operated Mines and excludes CPEL export sales prices and costs. 9 YearYearYearYearYearYearYearYear (in millions except per ton amounts)2013201420152016201720182019F2020F

Managing Through Changing Environments Controlling Costs  Adjusted production to match demand, including export volumes. Reduced total costs as production declined. $11.79 $11.19 $12 $10 $8 $6 $4 $2 $0 $9.78 $9.81 $9.87  The higher cost per ton in 2018 was primarily driven by lower production rates at our Antelope Mine caused by wet weather, spoil failures, and increased strip ratios.  Successfully managed capital spend to a sustainably low level while keeping equipment fleet in good condition. 2015 2016 2017 2018 2019E Core Cash Cost (1)(2) Royalties/Taxes/Fuel/Lubricants Reducing Shipments Reducing Capital Expenditures $120 $100 $80 $60 $40 $20 $0 100.0 80.0 58.8 57.8 60.0 49.7 48.1 40.0 20.0 0.0 2015 2016 2017 2018 2019E 2015 2016 2017 2018 Asian Exports 2019E Capex LBA Payments North American Deliveries (1) (2) Includes labor, repairs, maintenance, tires, explosives, outside services, and other mining costs. Core cash costs have been revised from prior period presentation due to the adoption of Accounting Standards Update 2017- 07. See Item 8 – Note 3 “Significant Accounting Policies” of our Notes to our Consolidated Financial Statements in the December 31, 2018 Form 10-K for additional information. 10 (tons in millions) (in millions) (cash cost per ton) 75.3 3.6 71.7 0.6 58.2 4.2 53.6 4.6 45.1 4.6 43.5 $69 $39 $35 $1$1 $13 $14 $16 $6.84 $6.36 $5.33 $5.61 $5.42 $4.95 $4.45 $4.45 $4.83 $4.20

Export Business Overview Overview of Export Businesses Cloud Peak exports Spring Creek coal via rail (BNSF) to Westshore Terminals in Vancouver, BC L5Y Export Volumes (million short tons) Average Annual Benchmark ($/metric tonne)(1) ■ $89 $71 $59 $66 $107 NEWC Kali. – Spring Creek benefits from relative proximity to West Coast export terminals Spring Creek coal is valued by many Asian utilities for its consistent quality and higher heat content relative to competing sub‐bituminous coals $53 $42 $46 $61 $60 – 4.6 4.2 4.0 ■ To support its export business, Cloud Peak has entered into take‐or‐pay agreements with BNSF and Westshore Terminals Export demand is affected by multiple factors, including Chinese regulation and Indonesian coal production 2014A 2015A 2016A 2017A 2018A ■ Export Capacity Position (million short tons) 10.5 10.5 2018A 2019E Westshore and 2020E 2021E 2022E 2023E Extended Westshore JERA Trading BNSF AgreementsAgreement Note: (1) All tons in millions. Newcastle pricing per Global Coal; Kalimantan pricing per Platts. Based on average weekly price, measured from January 1 to December 31 of each year. 11 5.55.56.1 0.3 3.6 0.6

Employee Overview Approximately 1,254 Employees as of March 31, 2019 Total Employees and Headcount (2014 – 2019) 12 Total Headcount 201420152016201720182019 1,6261,5711,3391,3071,2841,254 Operations Salaried555557574953 Hourly866820687662672674 Maintenance Salaried797265615756 Hourly385386332333339331 Support and Admin Salaried222232195192164138 Hourly1963232

Sales and Marketing 2 13

Powder River Basin (PRB) Trends and Players CPE Accounted for 20% of Total PRB Volume in 2010 and 15% in 2018 * “JL” = Joint Line (BNSF‐UP) / “NG” = North Gillette (BNSF only) “NPRB” = Northern PRB (Montana) *2016 downturn with MATS regulation impact on coal-fired power plants Source: Mine Safety and Health Administration. 14

Historical and Projected PRB Coal Demand Prospects Range Widely Depending Upon Assumed Natural Gas Prices PRB Coal Demand (Actual and Future Ranges) 450 400 350 Top end assumes $4.00/million Btu natural gas prices 300 250 200 Bottom end assumes $2.50/million Btu prices 150 100 50 0 2015 2016 2017 2018 2019 Internal Estimate 2021‐2022 2023‐2027 Doyle Trading Consultants Forecast Source: Mine Safety and Health Administration actuals, Coal Market Study (May 2018) prepared for CPE by Doyle Trading Consultants LLC. 15 Million Tons

Diversified Customer Base Our Deliveries to Power Plants in 2018 Note: Prepared by S&P/SNL from available public data; not from CPE company data. 16

CPE Sold‐to Position 2019 to 2023 (1) Note:Data as of May 3, 2019. (1) Assumes logistics extensions. 17

CPE Consolidated Customer Profile Key Observations Top 10 Customers by 2018 Volume CPE Top 10 Customers by Volume 2018 Customer 1 10%  No single customer accounts for more than 10% of total CPE tons Customer 2 CPEL (exports) 9%  58 total customers in 2018, including utilities, industrials, OTC trades, and individual export customers via Cloud Peak Energy Logistics (CPEL ‐ CPE’s export logistics affiliate) Other 40% Customer 3 8%  170 total sales contracts, including 36 OTC trades and 26 export sales Customer 4 7% Customer 5 5%  CPEL (CPE’s export logistics affiliate) accounted for 9% of total CPE sales and 34% of Spring Creek sales in 2018 Customer 10 4% Customer 6 5% Customer 9 Customer 8 Customer 7 4% 4% 4% 18

Spring Creek Domestic Sales w/o Increase in Export Sales Spring Creek domestic sales through 2023 based on actual 2018 deliveries to existing customers, with certain anticipated adjustments, and accounting for scheduled customer plant retirements. Does not reflect any other potential changes in demand at existing plants or the potential to secure new domestic customers. 10 9.3 8.9 9 8.5 7.8 8 6.9 7 6.0 6 5 4 3 2 1 0 2018 2019 2020 2021 2022 2023 19 Million Tons

Export Environment 20

Spring Creek Complex Export Quality and Rail Haul Advantage Key Observations Spring Creek Complex Location  Spring Creek Complex is ~130 miles closer to the West Coast export terminals than SPRB mines resulting in lower rail costs.  Rail haul loaded is ~1,500 miles Quality  Spring Creek Mine is a premium subbituminous coal for many Asian utilities valued for its consistent quality and higher heat content. Sodium can be blended. Higher Quality Product 4770‐4850 Spring Creek  Indonesian coal (the primary international competitor) has a wide quality range. 8800 Btu 4544 Average  Indonesian average export coal quality has been declining (see right hand side of page), creating concerns for fuel buyers. CPEL’s customers are increasingly interested in Spring Creek for diversity. Indonesian Coal 3700 3900 4100 43004500 4700 4900 Kcal/kg NAR Source: SNL, Wood Mackenzie, Company estimates. 21 In decline

Export Demand Key Observations  Asian seaborne thermal coal demand and pricing were strong through most of 2018.  Hot weather, overall electric generation growth, and strong coal‐fired power demand from China increased near‐term demand while positive longer‐term fundamentals continued.  Chinese import restrictions in Q4 2018 slowed the market, but these were lifted in Q1 2019.  Asian seaborne demand increased by 40 million tonnes in 2017 and is estimated to have grown by 25 million tonnes in 2018.  The commissioning of new coal‐fired power plants and growing electric consumption throughout Asia are the primary drivers increasing demand for seaborne thermal coal. Source: Commodity Insights. 22

Export Demand (Cont’d) Key Observations By 2025, Asian coal generated electricity capacity excluding China is estimated to grow to 240 Gigawatts.   This generation growth is expected to increase seaborne thermal coal demand by 20 to 25 million tonnes per annum.  This growth assumes that Chinese import demand remains stable and that Chinese governmental policies remain constant.  Any supply response is expected to be delayed by the past several years of low capital investment in Australia. Dangjing Power Station in South Korea Owned by Korea East West Power Source: IEA, Company estimates. 23

Newcastle and Kalimantan Index History  Kalimantan averaged 66% of Newcastle from January 2015‐May 2019, but hit a low 45% in September and December 2018. It has recovered to about 62% as of early May.  CPEL exports track more closely to Kalimantan than to Newcastle, but the latter is a more robust index. Newcastle 6000 and Kalimantan 5000 History (Jan. 2010 – May 2019) $160 $140 CPEL suspended exports in 2016 through October $120 $95.61 $100 (1) $86.91 $80 $60.00 $60 (1) $53.50 $40 Newcastle 6000 Kalimantan 5000 $20 $0 1/1/2010 1/1/2011 1/1/2012 1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018 1/1/2019 Source: Note: (1) Global Coal, Platts. Pricing as of May 3, 2019. Refers to pricing on January 8, 2010. 24 $ / Metric Tonne

CPE Terminal Position Westshore Terminal – Existing lowest cost, Capesize port  Capesize vessels – deep‐water port.  5.5 million tons of port capacity 2018 – 2020.(1)  10.5 million tons of port capacity 2021 – 2022. (2)  Additional volumes for JERA Trading business through the first quarter of 2023. Proposed Millennium Bulk Terminals (MBT)  Potential capacity to load up to Panamax size vessels.  Cloud Peak Energy option for up to 3.3 million tons per year at Stage 1 development and an additional 4.4 million tons per year at Stage 2.  Significant permitting challenges continue. (1) Excludes JERA Trading volumes. (2) Includes JERA Trading volumes. 25

CPEL Export Destinations  CPEL is actively developing sales into Japan. To date, CPEL has executed the JERA Trading agreement and sold coal for several “test” burns at Japanese utilities (JPU’s).  The Chinese tariff on U.S. coal is frustrating current sales. CPEL Exports by Country, 2016 – 2018 26

CPEL Export Logistics Agreements  CPEL holds contracts with (i) BNSF Railway to haul coal from the Spring Creek Mine to Westshore Terminals, Inc. at Delta, British Columbia, and (ii) Westshore Terminals to unload BNSF trains, stockpile coal, and load CPEL’s coal onto vessels (which is usually the point of sale for CPEL coal).  CPEL has agreements with both BNSF and Westshore for its base export business (the “base” agreements). The base BNSF agreement expires December 31, 2020. The base Westshore agreement expires December 31, 2022. These agreements provide for 5.5 million short tons of capacity in 2019 and 2020 and are not specific to CPEL customers. – CPEL has historically matched BNSF and Westshore terms (duration). The Westshore agreement was extended in July 2018.  CPEL entered into separate and distinct agreements with BNSF and Westshore for sales to JERA Trading. Negotiations with all parties were on a stand‐alone basis; i.e., allowing for the potential that JERA Trading might be CPEL’s only export sales. – CPEL could terminate its base agreements and continue with its JERA Trading agreements or vice versa. CPEL is party to the coal sale agreement with JERA Trading and is separately party to each of the BNSF and Westshore agreements in a back‐to‐back fashion. –  The only contractual nexus between the base logistics agreements and the JERA Trading logistics agreements is that JERA Trading tonnages are deducted from the maximum base rail and port capacity to determine capacity available for CPEL’s base export sales. 27

CPEL – Export Position  Amended and extended the existing Westshore agreement to December 31, 2022.  Increased volumes to 10.5 million tons per year in 2021 and 2022.  Retained the right to terminate the agreement at any time in exchange for a buyout payment.  JERA Trading volumes are in the new totals for 2021 and 2022, but fall under the separate logistics take‐or‐pay agreements. Export Capacity Position (million short tons) 10.5 10.5 2018A 2019E 2020E 2021E 2022E 2023E Westshore and BNSF Agreements Extended Westshore Agreement JERA Trading 28 5.55.56.1 0.3

JERA Trading: Nakoso and Hirono Projects  The Nakoso and Hirono power projects (IGCC plants) are being developed and co‐owned by Mitsubishi Corporation Power Ltd., Mitsubishi Heavy Industries, Ltd., Mitsubishi Electric Corporation, Tokyo Electric Power Company Holdings, Inc. and Joban Joint Power Co., Ltd. Nakoso would be the first plant on‐line, with scheduled plant commissioning in Q1 2020 and commercial operation mid‐2020. Shipments are expected to commence as early as the end of 2019 and continue for a period of between thirty to forty months, reaching up to 1.3 million metric tonnes in the final contract year, April 1, 2022 –March 31, 2023.   29 IGCC systems generate power using a combined cycle format incorporating coal gasification and both gas and steam turbines. IGCC systems offer enhanced generation efficiency, as well as reductions in carbon dioxide (CO2) emissions of about 15% in comparison with the latest, state‐of‐the‐art, conventional coal fired power plant designs and substantially lower than most plants in operation in the U.S.

Development Projects 30

Overview of Potential Development Options Overview of Potential Development Options Youngs Creek Project Map of Potential Development Options ■ 284 million tons of non‐reserve coal deposits as of December 31, 2018.(1) Contracted royalty payments of 8% vs 12.5% federal rate. Discussions underway with key customers for test burns. ■ ■ Big Metal Project ■ On June 7, 2018, Cloud Peak exercised its option to lease ~290 million in‐place tons of coal in the Upper Youngs Creek project area from the Crow Tribe. – The executed lease has been submitted to the Bureau of Indian Affairs for approval before the lease is effective. ■ Cloud Peak also extended the coal lease options for the Squirrel Creek and Tanner Creek project areas, which are estimated to have ~1.1 billion in‐place tons.(2) The exercised lease royalty rate for any future production is on a sliding scale between 10‐15%, depending on sales prices, vs. 12.5% federal rate. On June 7, 2019 certain bonus and option payments of $2.2 million will be payable at Cloud Peak’s discretion. ■ ■ (1) Non‐reserve coal deposits are not reserves under SEC Industry Guide 7. Estimates of non‐reserve coal deposits are subject to further exploration and development, are more speculative, and may not be converted to future reserves of the Company. Represents a current estimate of physical in‐place coal tons. Does not represent proven and probable reserves, non‐reserve coal deposits or a forecast of tons to be produced and sold in the future. Future production and sales of such tons, if any, are subject to regulatory approvals, completion of land access agreements, and significant risk and uncertainty, including coal demand and pricing in the U.S. and internationally. In addition, portions of the potential project remain subject to exercise of additional options. (2) 31

Spring Creek Complex Overview of SPRB 8800 Btu Depletion ■ No new federal coal LBAs have been issued in the PRB since 2012, and the Bureau of Land Management has no PRB leases scheduled for sale at this time. Prospects for new LBAs have been challenged in recent years by low coal prices and federal regulatory pressures. ■ Absent new LBAs, currently leased 8800 Btu coal reserves in the PRB will decline at current production rates over the next few years. The process to obtain, permit, and develop new LBA reserves has recently taken 7‐10 years. ■ The Spring Creek Complex offers an opportunity to incrementally develop lower ratio, >9000 Btu coal potentially in the 2020‐2021 timeframe by leveraging the existing Spring Creek Mine loadout and infrastructure. ■ CPE is actively seeking to develop new domestic and international customers for Spring Creek coal to provide a foundation for potential development of the Spring Creek Complex. 32

Operations 3 33

Average Strip Ratios by Mine 34 Mine 2018A 2019E 2020E 2021E 2022E 2023E Antelope 5.97 5.83 5.27 5.13 5.31 5.96 Cordero Rojo 3.39 4.54 4.63 4.74 4.86 5.04 Spring Creek 4.28 4.54 4.75 4.29 4.35 4.22

Asset Retirement Obligations (ARO) Summary ARO and Surety Bonding Summary by Mine (as of December 31, 2018) $150.2 (1) Antelope Cordero Rojo Spring Creek Bonded Amount Sequatchie Valley Discounted ARO The $93.6 million carrying amount of CPE’s AROs at December 31, 2018 exclude $4.9 million of concurrent reclamation obligations which are included in the above ARO amounts. Note:All $ in millions. ARO assumes blended average discount rate of approximately 6%. (1) Sequatchie Valley is a property in Tennessee that has been reclaimed and has continuous monitoring requirements. 35 $136.3 $114.0 $28.9 $30.4 $32.9 $6.3 $5.4

2018 Antelope Mine Performance Summary ■ Heavy rains during Q2 of 2018 prevented truck shovel pre‐stripping ahead of the draglines from being accomplished as planned. ■ Eagles nesting along the dragline walk route in Q2 delayed the 415 dragline move to the West Pit and kept the dragline digging in SMA impacting coal production by 1.7 million tons. ■ Spoil failures due to the Q2 rain starting in mid‐ August diverted significant truck/shovel fleet and the draglines’ capacity to re‐handle, further delaying the movement of prime overburden to uncover coal. ■ Long standing geotechnical design limits of spoil heights and spoil dig angles were not exceeded prior to the spoil failures. ■ Re‐handling spoil caused a delay in pre‐stripping at the NEMA and West Pit. This impacted the dragline production by 3 million tons of coal alone. 36

Antelope Mine Historic Rain Events ■ ■ ■ ■ 10 year average for the combined rainfall for May, June, and July is 6.97 inches of rain. 2016 combined rainfall for May, June and July is 4.57 inches of rain. 2017 combined rainfall for May, June, and July is 5.94 inches of rain. 2018 combined rainfall for May, June, and July is 10.20 inches of rain. 37

2018 Operational Update ■ Unusually heavy rain in second quarter impacted operations at Antelope Mine reducing shipments. ■ High levels of moisture caused spoil failures from mid‐August in both dragline pits. ■ Inventory was low in the fourth quarter as pre‐strip, which was delayed to rehandle spoil failures, has to be caught up in advance of the dragline progression. Dragline Coal Face Spoil Failure June 2018 September 2018 38 Highwall

Impacts from 2018 Rain Events on 2019 Business Plan ■ January 2019 15M BCY deficit in prime overburden removal was the result of rain delays in spring and the deployment of productive capacity to re‐handling unstable spoils from August continuing into January. ■ The resulting delay in pre‐stripping in NEMA and West Pit impacts dragline production due to not having blasted material the dragline could move, therefore not uncovering coal. ■ We are executing a plan to catch up the pre‐stripping in NEMA and West Pit, this will not be fully resolved until mid‐year 2019. ■ Approximately $20 million in costs to catch up pre‐stripping deficit resulting from 2018 rain events is reflected in the 2019 Budget. ■ Re‐establishing the pre‐stripping sequence as planned is critical to reliable coal delivery and developing the East Pit to be ready for the dragline move from NEMA in Q4 2019. 39

2019 Bomb Cyclone Overview Overview A March “bomb cyclone” brought severe weather to the Midwest region and has negatively impacted Union Pacific (UP) and BNSFs ability to provide trains to meet Cloud Peak’s coal shipment targets Train schedules have and will be negatively impacted until approximately mid‐May as UP and BNSF work to recover and repair rail lines washed away by the floods Shipments for March, April and May are expected to be down approximately 2 ‐ 3 million tons vs. budget, resulting in a significant cash flow reduction through mid‐June Select Images of Flooding ■ ■ ■ – Cordero and Spring Creek forecasted shipments can likely be recovered throughout the balance of the year However, the Antelope mine is expected to experience a permanent loss of ~2 million tons for the balance of the year (24.1 vs. 26.0 million ton budget) Company is continuing to refine its assessment of the overall financial impact – – ■ Approximately ~$17 million Adjusted EBITDA and cash flow impact in 2019 (assuming some recovery of lost March, April and May shipments) 40

Actions to Execute 2019 Plan ■ Increased effective cast blasting – higher explosive load. Focused on making sure truck load factors are at target levels on 830 fleet and 930 fleet. ■ ■ Truck availability is improving. – Refocused on defect elimination. – Reintroduced maintenance planning training. – Workforce specialty training. ■ Manpower. – Focus on maintaining production manpower requirements. – Continue to recruit skilled maintenance positions. ■ Mine schedule changed to a 28‐day schedule to improve communication with crews – same schedule as Cordero Rojo and Spring Creek. Maintenance organizational and reporting structure changes in 2018 have improved haul truck availability. Similar improvements in dozer fleet availability are expected in 2019. ■ ■ Operational Consultant performed review of operations areas and recommendations are being implemented. – Maintenance/warehouse/procurement interface. – Dispatch/Mine Monitoring and Control. 41

Business Plan and 4 Other Financial Information 42

Executive Summary Cloud Peak’s 5‐year financial forecast reflects a number of key assumptions, which have been outlined below ■ 2019 projections include impact of recent Bomb Cyclone as well as required work at Antelope resulting from heavy rainfalls and spoil instability in 2018 ■ Weather events are expected to negatively impact 2019 Antelope volumes by ~4M tons, resulting in total 2019 tons sold of 48M; Antelope volumes are projected to recover in 2020, resulting in 52M company‐wide tons sold – Volumes are projected to remain stable for remainder of forecast period (2020 – 2023) ■ Pricing assumptions reflect Cloud Peak internal estimates; export prices expected to recover from currently depressed levels around $51 / tonne in 2019 to about $65 / tonne in 2023 ■ SG&A assumes continuation of public company costs; cost projections do not include effect of recent optimization initiatives or benefits from initiatives identified by Marshall Miller & Associates – However, a cash flow profile including ~$10M in annualized savings has been included for reference (does not include potential benefits identified in Marshall Miller & Associates analysis) ■ Capex schedule reflects necessary investments to support business plan ■ Projections assume 0% inflation in 2019 and 2% annual inflation from 2020 – 2023; no wage increases aside from inflation effects assumed for 2019 – 2023 ■ Non‐cash LTIP costs have been removed ■ Projections are shown prior to effects of restructuring costs 43

5 Year Forecast (2019 – 2023) Summary Consolidated Statement of Operations and Cash Flows (in millions except per ton amounts) 1 2019 Adjusted EBITDA of $(29M) includes approximately $7M of OPEB related non‐cash gain. Removal of this deferred gain results in OPEB Adjusted EBITDA of approximately $(36M). Revenues Total revenue Less taxes and royalties Net revenue Operating Costs and Expenses Operating costs SG&A Total operating costs and expenses $ 751.4 (173.1) $ 869.2 (192.0) $ 1,091.1 (190.4) $ 1,119.7 (195.2) $ 1,162.5 (201.6) 578.3 677.2 900.8 924.5 960.9 572.8 34.5 622.4 34.3 839.8 35.0 854.3 35.8 890.1 36.5 2 Average cost per ton sold for Cordero Rojo rounded to the nearest dollar. 607.4 656.7 874.8 890.0 926.6 Capital Expenditures Working Capital Other (15.8) (23.4) (4.9) (21.4) ‐ 4.7 (19.7) ‐ (0.5) (21.2) ‐ (0.5) (21.0) ‐ (4.2) Unlevered Free Cash Flow $ (73.1) $ 3.9 $ 5.8 $ 12.8 $ 9.0 Plus: Cost Savings 6.2 9.7 9.9 9.9 9.9 Pro Forma Unlevered Free Cash Flow $ (66.9) $ 13.6 $ 15.7 $ 22.7 $ 18.9 Total Tons Sold Antelope Cordero Rojo Spring Creek Total Owned and Operated Mines Average Price Per Ton Sold Average Cost Per Ton Sold Memo: Average Cost Per Ton Sold (Cordero Rojo) CPEL Total tons sold (export) Average export price per ton sold Average export price per tonne sold Adjusted EBITDA Owned and operated CPEL Corporate and other 24.1 10.0 14.0 28.0 10.0 14.0 28.0 10.0 14.0 28.0 10.0 14.0 28.0 10.0 14.0 48.1 52.0 52.0 52.0 52.0 $ $ $ 11.98 11.79 10.00 $ $ $ 12.24 11.31 10.00 $ $ $ 12.35 11.37 10.00 $ $ $ 12.68 11.54 11.00 $ $ $ 13.15 11.99 11.00 2 4.6 46.46 51.21 5.5 53.52 59.00 10.5 55.13 60.77 10.5 56.41 62.18 10.5 58.66 64.66 $ $ $ $ $ $ $ $ $ $ $ 20.4 (17.4) (32.0) $ 55.3 (0.5) (34.4) $ 60.2 (0.7) (33.6) $ 69.6 (0.7) (34.3) $ 70.1 (0.7) (35.1) 44 Total Adjusted EBITDA 1$ (29.0) $ 20.5 $ 25.9 $ 34.5 $ 34.3 By Entity / Segment 2019E 2020E 2021E 2022E 2023E Adjusted EBITDA 1$ (29.0) $ 20.5 $ 25.9 $ 34.5 $ 34.3 Consolidated 2019E 2020E 2021E 2022E 2023E

Consolidated Monthly 2019 Financials 2019E Monthly Summary Total 2019E Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Deferred Gain Amortization Proceeds from Sale of Assets Equity Method Investment Income Capital Expenditures Land Lease Expenditures Net Income Tax Refunds (Payments) Distributions from Joint Venture A/R Securitization Program Collateral Working Capital (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ (4.2) (4.2) (0.5) 2.9 ‐ (1.3) (0.6) ‐ ‐ (7.4) 8.8 (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ (2.0) 0.5 (0.5) ‐ ‐ (1.3) ‐ ‐ 1.0 2.2 (12.9) (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ (2.4) (16.2) (0.5) ‐ ‐ (1.3) (2.6) ‐ ‐ 2.3 4.1 (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ (4.0) (3.0) (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ 3.0 2.6 (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ (4.5) 1.7 (0.5) ‐ ‐ (1.3) ‐ 14.2 ‐ 4.5 (1.2) (0.5) ‐ ‐ (1.3) ‐ ‐ ‐ ‐ (12.0) (0.5) ‐ (1.5) (1.3) ‐ ‐ ‐ ‐ 8.3 (5.8) 2.9 (1.5) (15.8) (3.2) 14.2 1.0 (12.5) (23.4) Capital Lease Obligations (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (1.8) Professional Fees KEIP / KERP Cost Savings(1) Operating Contingency (1.4) (0.1) ‐ ‐ (2.9) (7.9) (0.5) ‐ (2.8) (2.7) (0.7) (1.0) (7.6) ‐ 0.8 (1.0) (3.8) ‐ 0.8 (1.0) (3.8) ‐ 0.8 (1.0) (5.3) (2.7) 0.9 (1.0) (3.8) ‐ 0.8 (1.0) (8.8) ‐ 0.8 (1.0) ‐ (2.7) 0.9 (1.0) ‐ ‐ 0.8 ‐ ‐ ‐ 0.8 ‐ (40.2) (16.1) 6.2 (8.0) Beginning Cash Net Cash Flow 91.2 (17.4) 73.8 (12.9) 60.8 (23.7) 37.2 (24.1) 13.1 (24.2) (11.1) (2.2) (13.3) (19.7) (33.0) (1.0) (34.0) (13.3) (47.3) 12.0 (35.3) (14.5) (49.8) 8.0 91.2 (133.0) Note: All $ in millions. Represents estimates of monthly cash flows. Information has not been updated for actual results from January – April 2019. (1) Includes potential Public‐to‐Private Company savings, and other cost savings. 45 $(41.8) Ending Cash$73.8 $60.8 $37.2 $13.1 $(11.1) $(13.3) $(33.0) $(34.0) $(47.3) $(35.3) $(49.8) $(41.8) (133.0) Net Cash Flow(17.4)(12.9)(23.7)(24.1)(24.2)(2.2)(19.7)(1.0)(13.3)12.0(14.5)8.0 $(74.9) Net Cash Flow Prior to Ch. 11 Adj.$(16.0) $(1.7) $(16.5) $(16.3) $(20.1) $1.8 $(11.5) $3.0 $(4.3) $14.8 $(15.3) $7.2 (73.1) Unlevered Free Cash Flow(15.8)(1.5)(16.3)(16.2)(20.0)2.0(11.4)3.1(4.2)15.0(15.1)7.4 $(29.0) Adjusted EBITDA$(5.6) $(3.4) $(13.0) $(4.7) $0.4 $(0.0) $(2.5) $(0.7) $0.4 $(0.7) $(1.4) $2.3

Capital Expenditures Capital Expenditures (in millions) Antelope Cordero Rojo Spring Creek Corporate and Other Total $ 8.5 0.3 4.7 2.3 $ 12.1 3.5 3.2 2.6 $ 11.5 2.7 3.4 2.1 $ 11.9 5.7 1.4 2.2 $ 12.2 4.9 2.8 1.2 $ 15.8 $ 21.4 $ 19.7 $ 21.2 $ 21.0 46 Capital Expenditures 2019E 2020E 2021E 2022E 2023E

SG&A Summary Selling, General and Administrative Expenses (SG&A) (in millions) Labor Outside Services IT and Telecom Travel Other $ 16.6 10.0 1.6 0.9 5.5 $ 17.0 9.9 1.2 0.9 5.2 $ 17.4 10.1 1.3 0.9 5.2 $ 17.8 10.3 1.3 0.9 5.3 $ 18.2 10.5 1.4 0.9 5.4 Total $ 34.5 $ 34.3 $ 35.0 $ 35.8 $ 36.5 NOTE: Projected SG&A expenses for 2019 exclude OPEB adjustments. Projected SG&A expenses for 2019 – 2023 assume public company costs continue and do not reflect other cost reduction initiatives. 47 SG&A 2019E 2020E 2021E 2022E 2023E

EBITDA Sensitivity Analysis (Pricing) Domestic ‐ Owned and Operated Mines Price Increase $1.00 / Ton Price Increase $0.50 / Ton Base Case Price Decrease $(0.50) / Ton Price Decrease $(1.00) / Ton $ 5.2 2.6 ‐ (2.6) (5.2) $ 18.3 9.2 ‐ (9.2) (18.3) $ 32.6 16.3 ‐ (16.3) (32.6) $ 34.8 17.4 ‐ (17.4) (34.8) $ 36.7 18.3 ‐ (18.3) (36.7) CPEL ‐ Export Price Increase $5.00 / Ton Price Increase $2.50 / Ton Base Case Price Decrease $(2.50) / Ton Price Decrease $(5.00) / Ton $ 11.1 4.7 ‐ (6.7) (22.1) $ 13.0 6.6 ‐ (6.2) (12.6) $ 29.0 12.1 ‐ (12.4) (24.6) $ 25.0 12.8 ‐ (11.7) (28.6) $ 28.8 16.6 ‐ (12.6) (24.8) Note: (1) All $ in millions. Price increases and decreases applied to prices associated with “Committed and Unpriced” and “Uncommitted and Unpriced” tonnage volumes in each forecasted year. 48 Adjusted EBITDA Sensitivity Increase (Decrease) from Base Case Pricing Scenario(1) 2019E 2020E 2021E 2022E 2023E Adjusted EBITDA Sensitivity Increase (Decrease) from Base Case Pricing Scenario(1) 2019E 2020E 2021E 2022E 2023E

49 Extended Cash Flow Forecast With DIP (thru 08/30) $'s 000s FCST FCST FCST FCST Total Week Number Wks 1 - 5 Wks 6 - 9 Wks 10 - 13 Wks 14 - 18 Wks 1 - 18 Week Ending May June July August Receipts Coal Sales 52,269.2 33,183.2 47,931.8 57,664.8 191,049.0 Coal Sales (CPEL) 5,933.4 16,297.0 11,431.8 12,640.2 46,302.3 Other Receipts 184.7 100.0 100.0 100.0 484.7 Total Receipts 58,387.3 49,580.2 59,463.6 70,405.1 237,836.1 Operating Disbursements Operations (Core) (40,388.0) (33,298.9) (26,698.2) (56,171.0) (156,556.1) Operations (CPEL) (10,953.5) (9,996.8) (18,625.0) (4,959.3) (44,534.6) Employee Related (17,622.6) (12,258.8) (14,524.0) (14,081.1) (58,486.5) Total Operating Disbursements (68,964.1) (55,554.4) (59,847.2) (75,211.4) (259,577.1) Cash Flow From Operations (10,576.8) (5,974.3) (383.6) (4,806.4) (21,741.1) Other Disbursements Collateral Deposits (9,800.0) 8,600.0 100.0 1,800.0 700.0 Cash Interest and Bank Fees (178.3) (86.2) (83.9) (93.9) (442.4) DIP Interest and Fees (58.0) - - (350.0) (408.0) Restructuring and Other (6,568.0) (4,115.0) (4,785.0) (16,910.0) (32,378.0) Total Other Disbursements (16,604.3) 4,398.8 (4,768.9) (15,553.9) (32,528.4) Total Net Cash Flow (27,181.1) (1,575.5) (5,152.6) (20,360.3) (54,269.5) Beginning Cash Balance 38,506.1 21,117.7 44,542.2 39,389.7 38,506.1 Net Cash Flow (27,181.1) (1,575.5) (5,152.6) (20,360.3) (54,269.5) Change in O/S Check Float (207.2) - - - (207.2) DIP Funding 10,000.0 25,000.0 - - 35,000.0 Ending Cash Balance 21,117.7 44,542.2 39,389.7 19,029.4 19,029.4

13-Week Cash Flow Forecast With DIP 50 $'s 000s FCST FCST FCST FCST FCST FCST FCST FCST FCST FCST FCST FCST FCST Total Week Number Week 1 Week 2 Week 3 Week 4 Week 5 Week 6 Week 7 Week 8 Week 9 Week 10 Week 11 Week 12 Week 13 13-May Week Ending 17-May 24-May 31-May 7-Jun 14-Jun 21-Jun 28-Jun 5-Jul 12-Jul 19-Jul 26-Jul 2-Aug 9-Aug 9-Aug Receipts Coal Sales 16,327.5 7,944.5 17,560.4 3,075.4 9,849.4 9,102.3 11,156.2 13,045.8 11,183.1 13,305.2 10,397.7 11,605.4 8,676.3 143,229.1 Coal Sales (CPEL) 4,715.7 266.0 253.1 8,096.9 4,112.2 - 4,087.9 7,247.9 47.9 4,087.9 48.1 5,173.6 48.1 38,185.2 Other Receipts 82.2 - - - 100.0 - - - 100.0 - - - - 282.2 Total Receipts 1 21,125.5 8,210.6 17,813.4 11,172.3 14,061.5 9,102.3 15,244.1 20,293.7 11,331.0 17,393.1 10,445.8 16,778.9 8,724.3 181,696.5 Operating Disbursements Operations (Core) (6,719.4) (7,968.2) (16,961.8) (5,052.6) (8,806.7) (6,722.6) (12,717.0) (6,351.7) (5,134.4) (6,968.5) (8,243.5) (20,363.3) (5,066.9) (117,076.6) Operations (CPEL) (4,232.1) (1,327.5) (2,712.3) (1,859.8) (4,117.7) (1,859.8) (2,159.5) (2,500.0) (5,626.0) - (10,499.1) - (1,546.8) (38,440.4) Employee Related (5,299.1) (1,300.7) (5,302.1) (1,062.8) (5,148.7) (1,100.3) (4,947.0) (4,214.6) (4,705.4) (1,100.3) (4,503.7) (2,675.6) (4,587.0) (45,947.4) Total Operating Disbursements (16,250.6) (10,596.4) (24,976.2) (7,975.2) (18,073.0) (9,682.7) (19,823.5) (13,066.3) (15,465.8) (8,068.8) (23,246.3) (23,038.9) (11,200.6) (201,464.4) Cash Flow From Operations 4,874.8 (2,385.8) (7,162.7) 3,197.0 (4,011.5) (580.4) (4,579.4) 7,227.4 (4,134.8) 9,324.2 (12,800.5) (6,260.0) (2,476.3) (19,767.8) Other Disbursements Collateral Deposits 6,856.4 (4,600.0) (11,800.0) 11,200.0 (5,800.0) 9,900.0 (6,700.0) 6,900.0 (6,600.0) 5,800.0 (6,000.0) 7,000.0 (6,500.0) (343.6) Cash Interest and Bank Fees - (83.9) (5.0) - - (81.2) (5.0) - - - (83.9) (5.0) - (264.1) DIP Interest and Fees (58.0) - - - - - - - - - - - - (58.0) Restructuring and Other (740.0) (125.0) (960.0) (225.0) (1,220.0) (2,670.0) - (605.0) - (4,180.0) - (605.0) - (11,330.0) Total Other Disbursements 6,058.4 (4,808.9) (12,765.0) 10,975.0 (7,020.0) 7,148.8 (6,705.0) 6,295.0 (6,600.0) 1,620.0 (6,083.9) 6,390.0 (6,500.0) (11,995.7) Total Net Cash Flow 10,933.3 (7,194.7) (19,927.7) 14,172.0 (11,031.5) 6,568.4 (11,284.4) 13,522.4 (10,734.8) 10,944.2 (18,884.5) 130.0 (8,976.3) (31,763.6) Beginning Cash Balance 2 27,306.9 48,240.2 41,045.5 21,117.7 60,289.8 49,258.3 55,826.7 44,542.2 58,064.7 47,329.9 58,274.2 39,389.7 39,519.7 27,306.9 Net Cash Flow 10,933.3 (7,194.7) (19,927.7) 14,172.0 (11,031.5) 6,568.4 (11,284.4) 13,522.4 (10,734.8) 10,944.2 (18,884.5) 130.0 (8,976.3) (31,763.6) Change in O/S Check Float - - - - - - - - - - - - - - DIP Funding 10,000.0 - - 25,000.0 - - - - - - - - - 35,000.0 Ending Cash Balance 48,240.2 41,045.5 21,117.7 60,289.8 49,258.3 55,826.7 44,542.2 58,064.7 47,329.9 58,274.2 39,389.7 39,519.7 30,543.4 30,543.4 Note 1 : Includes projected receipts for Friday May 10, 2019 to be received in the post petition period. Note 2 : Beginning cash balance is the ending cash balance as of Thursday May 9, 2019.

AMT Credit Background ■ The Tax Cut and Jobs Act (“TCJA”) legislation, enacted in December 2017, made significant changes to U.S. tax laws, including: – – A reduction in the federal corporate tax rate and the imposition of limitations on the deductibility of interest expense. The elimination of the corporate alternative minimum tax (“AMT”) and the ability to offset regular tax liability or claim refunds for AMT credits carried forward for taxable years beginning after Dec. 31, 2017. ■ Cloud Peak has historically been subject to the AMT, under which taxes were imposed at a 20% rate on taxable income, subject to certain adjustments. – Prior to the TCJA, a corporation paying AMT received a “minimum tax credit” (AMT credit) that it would carry forward to future years to reduce its taxable income As of December 31, 2017, Cloud Peak had accumulated approximately $31.5 million in AMT credits – Refundable AMT Credit Under the TCJA ■ The immediate impact of the TCJA to Cloud Peak is the elimination of the AMT (effective for its 2018 taxable year) and the ability to offset its regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior periods. – Generally, 50% of a corporation’s AMT Credit carried forward to one of these years will be claimable and refundable for that year. ■ Cloud Peak has elected to claim a refund for its $31.5 million in accumulated AMT credits (versus carrying these credits forward to offset potential future tax liabilities), which it anticipates will be realized as follows: – – – – 2019: 2020: 2021: 2022: 50% of the total AMT credit ($31.50 million x 50% = $15.75 million) 50% of the remaining AMT credit ($15.75 million x 50% = $7.88 million) 50% of the remaining AMT credit ($7.88 million x 50% = $3.94 million) The remaining balance of the AMT credit ($3.94 million) ■ Cloud Peak filed a preliminary tax return (for the 2018 taxable year) during the week ended April 5th that included an election to receive a refund of accumulated AMT credits. 51

Equipment & Inventory Overview Net Book Value of Equipment Inventory Spring Creek Cordero Rojo(1) Category Cost % of Total Net Book Value Antelope Drives Tires Electrical Motors Electrical Buckets Undercarriage Parts Conveyor Parts Frames & Structural Bearings Engines Processing Plant Parts Wire Rope Hydraulic Fuel Other $11.8 7.9 5.3 4.9 4.4 3.7 3.2 3.2 2.5 2.4 2.3 2.3 2.0 1.1 6.2 18.7% 12.6% 8.4% 7.7% 7.0% 5.8% 5.1% 5.0% 4.0% 3.8% 3.6% 3.6% 3.1% 1.8% 9.8% Draglines Shovels Haul Trucks Dozers Light Vehicles Other $42.4 24.4 11.3 1.9 0.1 15.6 $15.6 18.0 0.2 0.8 0.0 16.5 $2.0 2.2 3.2 2.8 0.0 3.1 Note: All $ in millions. As of February 28, 2019, unless otherwise noted. (1) As of December 31, 2018. 52 Total$63.1100.0% Total Net Book Value$95.8$51.1$13.3

Surface Land Information Overview of Surface Land Acres Acres Inside Permit State Outside Permit Counties City Potential Use Wyoming Montana Tennessee West Virginia 38,412 11,289 1,337 – 18,777 28,421 3,907 10 Sheridan, Campbell Big Horn, Decker Sequatchie, Van Buren Clay, Nicolas Douglas N/A N/A N/A Agriculture Agriculture Agriculture Agriculture Note: As of February 28, 2019. 53 Total51,03851,115

International Accounts Receivable Projections Schedule of International Accounts Receivable (Projected) 54 $ in millions Week Ending 3‐May 10‐May 17‐May 24‐May 31‐May 7‐Jun 14‐Jun 21‐Jun 28‐Jun 5‐Jul 12‐Jul 19‐Jul 26‐Jul 2‐Aug 9‐Aug 16‐Aug 23‐Aug 30‐Aug Total Beginning Balance Billings Collections $ 4.7 $ 4.7 $ 12.7 $ 8.0 $ 8.0 $ 12.1 $ 4.0 $ 11.2 $ 11.2 $ 7.2 $ 4.0 $ 4.0 $ 5.1 $ 5.1 $ 7.3 $ 7.3 $ 4.0 $ 4.0 ‐8.0‐‐4.0‐11.2‐‐4.0‐5.1‐7.3‐4.0‐‐ ‐‐(4.7)‐‐(8.0)(4.0)‐(4.0)(7.2)‐(4.0)‐(5.1)‐(7.3)‐‐ $4.7 43.8 (44.5) Ending Balance $ 4.7 $ 12.7 $ 8.0 $ 8.0 $ 12.1 $ 4.0 $ 11.2 $ 11.2 $ 7.2 $ 4.0 $ 4.0 $ 5.1 $ 5.1 $ 7.3 $ 7.3 $ 4.0 $ 4.0 $ 4.0 $4.0

Appendix 5 55

Definitions of Certain Terms ■ Adjusted EBITDA – EBITDA represents Net income (loss) before: (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, and (4) amortization. Adjusted EBITDA represents EBITDA as further adjusted for accretion, which represents non‐cash increases in asset retirement obligation liabilities resulting from the passage of time, and specifically identified items that management believes do not directly reflect our core operations. ■ Unlevered Free Cash Flow – Unlevered Free Cash Flow represents Adjusted EBITDA less (1) non‐cash gains, (2) non‐cash equity method investment income, (3) capital expenditures, (4) land lease option payments, (5) certain cash tax payments, (6) collateral postings associated with the A/R Securitization Program, and (7) increases in net working capital, which includes inventory, accounts receivable and accounts payable, plus (1) proceeds from asset sales, (2) distributions from equity method investees, (2) tax refunds, (3) releases of A/R Securitization Program collateral and (4) decreases in net working capital. 56