INVESTOR Presentation February 2018

Cautionary Note Regarding Forward-Looking Statements 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. Forward-looking statements are not statements of historical facts, and often contain words such as “may,” “will,” “expect,” “believe,” “anticipate,” “plan,” “estimate,” “seek,” “could,” “should,” “intend,” “potential,” 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, government regulations, energy policies and other factors. These statements are subject to significant risks, uncertainties and assumptions that are difficult to predict and could cause actual results to differ materially and adversely from those expressed or implied in the forward-looking statements. For a description of some of the risks and uncertainties that may adversely affect our future results, refer to the risk factors described from time to time in the reports and registration statements we file with the Securities and Exchange Commission, including those in Item 1A "Risk Factors" of our most recent Form 10-K and any updates thereto in our Forms 10-Q and Forms 8-K. There may be other risks and uncertainties that are not currently known to us or that we currently believe are not material. We make forward-looking statements based on currently available information, and we assume no obligation to, and expressly disclaim any obligation to, update or revise publicly any forward-looking statements made in our presentation, whether as a result of new information, future events or otherwise, except as required by law. Non-GAAP Financial Measures This presentation includes the non-GAAP financial measure of Adjusted EBITDA (on a consolidated basis and for our reporting segments). Adjusted EBITDA is intended to provide additional information only and does not have any standard meaning prescribed by accounting principles generally accepted in the U.S. (“GAAP”). A quantitative reconciliation of historical net income (loss) to Adjusted EBITDA (as defined below) is found in the tables accompanying this presentation. 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. For the periods presented herein, the specifically identified items are: (1) adjustments to exclude the changes in the Tax Receivable Agreement, (2) adjustments for derivative financial instruments, excluding fair value mark-to-market gains or losses and including cash amounts received or paid, (3) adjustments to exclude non-cash impairment charges, (4) adjustments to exclude debt restructuring costs, (5) non-cash throughput amortization expense and contract termination payments made to amend the BNSF and Westshore agreements, and (6) adjustments to exclude the gain from the sale of our 50% non-operating interest in the Decker Mine in September 2014. We enter into certain derivative financial instruments such as put options that require the payment of premiums at contract inception. The reduction in the premium value over time is reflected in the mark-to-market gains or losses. Our calculation of Adjusted EBITDA does not include premiums paid for derivative financial instruments; either at contract inception, as these payments pertain to future settlement periods, or in the period of contract settlement, as the payment occurred in a preceding period. In prior years the amortization of port and rail contract termination payments were included as part of EBITDA and Adjusted EBITDA because the cash payments approximated the amount of amortization being taken during the year. During 2017, management determined that the non-cash portion of amortization arising from payments made in prior years as well as the amortization of contract termination payments should be adjusted out of Adjusted EBITDA because the ongoing cash payments are now significantly smaller than the overall amortization of these payments and no longer reflect the transactional results. Because of the inherent uncertainty related to the items identified above, management does not believe it is able to provide a meaningful forecast of the comparable U.S. GAAP measures or reconciliation to any forecasted U.S. GAAP measure. Adjusted EBITDA is an additional tool intended to assist our management in comparing our performance on a consistent basis for purposes of business decision making by removing the impact of certain items that management believes do not directly reflect our core operations. Adjusted EBITDA is a metric intended to assist management in evaluating operating performance, comparing performance across periods, planning and forecasting future business operations and helping determine levels of operating and capital investments. Period-to-period comparisons of Adjusted EBITDA are intended to help our management identify and assess additional trends potentially impacting our company that may not be shown solely by period-to-period comparisons of net income (loss). Consolidated Adjusted EBITDA is also used as part of our incentive compensation program for our executive officers and others. We believe Adjusted EBITDA is also useful to investors, analysts and other external users of our consolidated financial statements in evaluating our operating performance from period to period and comparing our performance to similar operating results of other relevant companies. Adjusted EBITDA allows investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and depletion, amortization and accretion and other specifically identified items that are not considered to directly reflect our core operations. Our management recognizes that using Adjusted EBITDA as a performance measure has inherent limitations as compared to net income (loss), or other GAAP financial measures, as this non-GAAP measure excludes certain items, including items that are recurring in nature, which may be meaningful to investors. As a result of these exclusions, Adjusted EBITDA should not be considered in isolation and does not purport to be an alternative to net income (loss) or other GAAP financial measures as a measure of our operating performance. Because not all companies use identical calculations, our presentation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. 2

Cloud Peak Energy Profile 3

One of the largest U.S. coal producers and only PRB pure-play coal company 2017 coal shipments from our three mines of 57.4 million tons 2017 proven & probable reserves of 1.0 billion tons Approval received for LBM of approximately 14 million tons at Antelope Mine Extensive NPRB projects and options for long-term growth opportunities Employs approximately 1,300 people Company and Financial Overview NYSE: CLD (2/19/18) $3.35 Market Capitalization (2/19/18) $251.8 million Total Available Liquidity (12/31/17) $507.9 million 2017 Revenue $887.7 million Senior Debt Principal (12/31/17) $346.8 million 4

Good Safety Record = Well-Run Operations Source: Mine Safety and Health Administration Note: Total Incident Rate = (total number of employee incidents x 200,000) / total man-hours. 5 Top Coal Producing Companies – 2016 Incident Rates (MSHA) Cloud Peak Energy 2017 – 0.17 Cloud Peak Energy 2016 – 0.25 2017 2016 Company Best 0.17 0.00 0.25 0.55 0.62 0.85 0.87 1.28 1.29 1.30 1.56 2.16 2.63 3.79 3.82 3.93 4.30 4.34 4.42 4.52 4.67 5.18 5.88 6.21 7.19 Cloud Peak Energy Global Mining Group Cloud Peak Energy Vistra Energy NACCO Industries Bowie Resources Kiewit Peter Sons Peabody Energy Western Fuels Allete Arch Coal Westmoreland Alpha Natural Resources Coronado Coal CONSOL Energy Armstrong Energy Coalfield Transport Alliance Resource Brent K Bilsland Contura Energy Alpha Natural Resources Foresight Energy Labor (Murray) Prairie State Energy Robert E Murray Blackhawk Mining

Low-Risk Surface Operations One of the best safety records in the industry Surface mining allows for high-quality reclamation Strong environmental compliance programs are ISO-14001 certified Highly productive, non-unionized workforce at all of our mines 6

Increasing Workload A Function of Surface Mining in the PRB 7 Additional overburden as coal seams dip moving west. For 2018, our mine plans indicate that the strip ratio will increase more than recent years resulting in higher costs. Haul distances increase as mining pits progress further from the load-out. More equipment, personnel, resources required to maintain production.

Extensive Coal Reserves and Projects Source: SNL Energy7 Assumes production at the 2017 level. Does not include a recently approved Lease by Modification that is expected to add approximately 14 million tons of recoverable coal, once finalized. (3) 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. (4) Subject to exercise of options. 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 exercise of options and significant risk and uncertainty. 8 2017 Proven & Probable Reserves (as of 12/31/17) 1.0B Tons Spring Creek Mine – MT 2017 Tons Sold 12.6M tons 2017 Proven & Probable Reserves 235.2M tons Average Reserve Coal Quality 9,350 Btu/lb Mine Life (1) 19 years Cordero Rojo Mine – WY 2017 Tons Sold 16.4M tons 2017 Proven & Probable Reserves 299.0M tons Average Reserve Coal Quality 8,425 Btu/lb Mine Life (1) 18 years Antelope Mine – WY 2017 Tons Sold 28.4M tons 2017 Proven & Probable Reserves (2) 489.7M tons Average Reserve Coal Quality 8,875 Btu/lb Mine Life (1) 17 years 2017 Non-Reserve Coal Deposits (3) 0.35B Tons Antelope Mine 7.9M tons Cordero Rojo Mine 53.2M tons Spring Creek Mine 3.9M tons Youngs Creek Project (non-federal coal) 283.6M tons 348.6M tons Additional Non-Federal Coal (4) 1.4B Tons Big Metal Project 1,387M tons

9 Spring Creek Complex Potential Development Options (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. (2) 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 exercise of options and significant risk and uncertainty. Youngs Creek Project 284 million tons of non-reserve coal deposits at December 31, 2017(1) Contracted royalty payments of 8% vs. 12.5% federal rate 48,000 controlled acres of surface land connecting Youngs Creek, Spring Creek, and Big Metal deposits Big Metal Project Options to lease up to 1.4 billion tons(2) of in-place coal on the Crow Indian Reservation. BIA issued approval of option agreements in June 2013 Option avoids significant upfront bonus payments as compared to federal LBAs. Sliding scale royalty rate to the Crow Tribe of 7.5% - 15% vs. 12.5% federal rate

10 Spring Creek Complex High Btu Coal Resources 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, financial challenges facing the industry, and federal regulatory pressures. Currently leased 8800 Btu coal reserves in the PRB are expected to decline at current production rates over the next 5-7 years absent new LBAs. 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. Cloud Peak Energy 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.

11 Spring Creek Complex Export Quality and Rail Haul Advantage Source: SNL, Wood Mackenzie, Company estimates 4770-4850 4544 In decline Average Higher Quality Product Location Spring Creek Complex is closer to the West Coast export terminals than SPRB mines resulting in lower rail costs. Quality Spring Creek Mine is a premium subbituminous coal for many Asian utilities valued for its consistent quality and higher heat content. Indonesian coal (the primary international competitor) has a wide quality range. Spring Creek Complex Indonesian average export coal quality has been declining within the band shown above, creating concerns for fuel buyers. Higher quality Indonesian coal is increasingly withheld to meet growing domestic demand. 3700 3900 4100 4300 4500 4700 4900 Indonesian Coal 8800 Btu Spring Creek Kcal/kg NAR

Positioned to Capitalize on Improving Export Sales Optionality to Grow Exports We exported 4.2 million tons through Westshore in 2017 and plan to increase to 5.5 million tons in 2018 At January 31, we had already contracted to ship 45% of our 2018 planned sales volumes Entered into a long-term agreement with JERA Trading to supply new IGCC plants currently under construction in Japan. (million tons) Export Tons $123 $103 $85 $71 $59 Avg. annual Newcastle benchmark ($/metric ton) 12 $66 $89 4.7 4.4 4.7 4.0 3.6 0.4 4.2 2011 2012 2013 2014 2015 2016 2017

13 Cloud Peak Energy-JERA Trading Agreement Export coal supply agreement with JERA Trading JERA Trading is responsible for procuring the coal for two integrated gasification combined cycle coal power plants under construction in Fukushima Prefecture, Japan. Shipments are scheduled to start at the end of 2019 and grow up to 1.1 million tons by the 2022-2023 Japanese Fiscal Year. Cloud Peak Energy Export Capacity Position Back-to-back agreements with Westshore and BNSF in support of the JERA agreement, together with recently negotiated extensions through 2020 under the base Westshore and BNSF agreements, provide Cloud Peak Energy with a firm export capacity foundation for many years. 0 1 2 3 4 5 6 2018 2019 2020 2021 2022 2023 (million tons) JERA Trading Extended Westshore and BNSF Agreements Amended Westshore and BNSF Agreements Westshore and BNSF base export agreements in blue extended from year - end 2018 to year - end 2020 JERA Trading (estimates)

14 Cloud Peak Energy Terminal Position Westshore Terminal – Existing lowest cost, Cape-size port Capesize vessels – deep-water port 5.5 million tons of port capacity extended through 2020 Additional volumes for JERA business through the first quarter of 2023 Proposed Millennium Bulk Terminals (MBT) Potential capacity to load up to Panamax size vessels CPE option for up to 3 million metric tons per year at Stage 1 development and an additional 4 million metric tons per year at Stage 2 Permitting process continues, including active legal challenges by MBT for certain denied State-level permits

Domestic Coal Environment Conditions and Regulations 15

Domestic Environment Coal production in the U.S. increased 6% in 2017 over 2016, while PRB production was up almost 7% for the same period Coal burn was steadier in 2017 as natural gas prices were around $3.00 MMBtu for much of the year The mild weather in 2017 reduced additional spot purchases for the year PRB stockpiles at utilities estimated at 68.1 million tons at end of January 2018 Regulatory Trump Administration – shorter-term impact positive Longer-term impact less certain Recent 45Q carbon capture tax credit amendments could help commercialize carbon capture for coal power plants Anti-fossil fuel campaigns remain active Activist NGO groups not going away More activity at state and local level Pacific Northwest challenges to fossil fuel exports 16 Source: Mine Safety and Health Administration, EVA

Natural Gas Storage and Pricing Natural Gas Storage Domestic consumption declines this year have been partially offset by increasing exports Storage levels down almost 6% at year-end 2017 vs. 2016 So far in 2018, withdrawals have been stronger than 2017 Natural Gas Pricing and Rig Count Weather remains the primary pricing driver Rig count levels stabilized near 190 for second half of 2017 Prices remained within the $3.00 MMBtu range Projected 2018 production increase is a concern, while rising exports are a positive 17 Source: EIA Source: EIA, Baker Hughes 0 1,000 2,000 3,000 4,000 5,000 BCF Week 5-Year Range 2017 2016 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 0 50 100 150 200 250 300 350 400 450 Price ($/MMBtu) Rig Count Rigs Price

18 Powder River Basin 42% 58% 34% 66% Source: MSHA 2008 - 2016 and Company Estimates 2017 SPRB Production Volatility In 2016, production declined 78 million tons compared to 2015 MATS closures Mild weather Increased gas production 2017 volumes were 18 million tons higher than 2016 based on improved natural gas prices Colder winter weather in 2018 to date has increased coal burn, reducing customer inventories 0 50 100 150 200 250 300 350 400 450 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 (million tons) Southern PRB Production Trends 8400 vs. 8800, 2008 - 2017 8800 Btu 8400 Btu

19 CPE Forward Sales Position 2018 has 45 million tons committed and fixed at weighted-average price of $12.30/ton. The 45 million tons committed includes 2.5 million export tons. 6 million tons of domestic sales needed to meet the mid-point of our production guidance range. 2019 has 17 million tons committed and fixed at weighted-average price of $12.63/ton. 45 17 7 45 24 0 10 20 30 40 50 60 70 80 2018 2019 Committed tons with variable pricing Committed tons with fixed pricing Total Committed Tons (as of 2/16/18)

Export Environment 20

21 Export Demand Cold weather and supply disruptions in Asia are driving strong demand while positive longer-term fundamentals continue. Asian seaborne demand increased by 25 million metric tons in 2017 and is expected to grow at a similar pace in 2018. The commissioning of new coal-fired power plants and growing electric consumption are the primary drivers behind demand for seaborne thermal coal. Customer concerns about Indonesian coal quality and supply concentration are encouraging them to purchase U.S. coal. During the first quarter of 2018, below average temperatures across much of Asia have delayed the unloading of coal vessels, leading to reduced inventories. Source: Commodity Insights

22 Export Demand Over the next 5 years, new coal-fired generation in Asia, outside of China, is forecast to grow by 23 Gigawatts. This generation growth is expected to increase seaborne thermal coal demand by 20 to 25 million metric tons per annum. This growth assumes that Chinese import demand remains stable and that Chinese governmental policies remain constant. Pricing should be supported by demand growth. Any supply response is expected to be delayed by the past several years of low capital investment in Australia and Indonesia. Source: Woodmac, Commodity Insights, Company estimates 0 5 10 15 20 25 2018 2019 2020 2021 2022 GWs Estimated New Coal - Fired Capacity In Key Asian Countries Japan, South Korea, Taiwan, and Vietnam

23 Through December 2017, Chinese total electric generation increased by 7%, largely supported by coal. Total Chinese imports were up 6% in 2017, while thermal coal imports increased 11% year over year. Thermal imports into South Korea increased 17% year over year as new coal units have come online. Newcastle prompt month spot prices have been above $100 per metric ton since December 2017 on strong demand fundamentals. We exported 4.2 million tons of coal in 2017 and expect 5.5 million tons in 2018. Source: Global Coal, Platts, Company estimates Export Drivers are Cyclical $0 $20 $40 $60 $80 $100 $120 $140 (per metric ton) Newcastle & Kalimantan Price Curve NEWC Kalimantan

Finance 24

25 Managing Through Changing Environments Adjusted production to match demand, including export volumes that resumed in 2017. Reduced total costs as production declined, managed our core cash costs on a per ton basis. Successfully managed capital spend to a sustainably low level while keeping equipment fleet in good condition. Mine plans indicate that strip ratios will increase more in 2018 than in recent years, resulting in higher costs. Controlling Costs Reducing Capital Expenditures (1) Includes labor, repairs, maintenance, tires, explosives, outside services, and other mining costs. $4.99 $5.05 $4.45 $4.20 $4.45 $5.24 $5.14 $5.36 $5.55 $5.33 $10.23 $10.19 $9.81 $9.75 $9.78 $0 $2 $4 $6 $8 $10 $12 2013 2014 2015 2016 2017 (cash cost per ton) Royalties/Taxes/Fuel/Lubricants Core Cash Cost (1) 81.3 81.9 71.5 57.9 53.2 46.5 - 50.5 4.7 4.0 3.6 0.6 4.2 5.5 86.0 85.9 75.1 58.5 57.4 52 - 56 0 10 20 30 40 50 60 70 80 90 100 2013 2014 2015 2016 2017 2018E (tons in millions) North American Deliveries Asian Exports Reducing Shipments $57 $20 $39 $35 $13 $15 - 25 $79 $69 $69 $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 2013 2014 2015 2016 2017 2018E (in millions) Capex LBA Payments

26 Liquidity and Bonding Obligations Actively Managing Financial Obligations and Commitments December 31, 2017 Cash and cash equivalents $108 Credit Agreement capacity $400 A/R Securitization 22 Available borrowing capacity 422 Letters of credit issued (1) (23) Total Available Liquidity $507 Surety bonds outstanding Third-party surety bonds $398 Lease bonds 25 Total Bonding Obligation $423 Cash balance of $107.9 million increased $24.2 million during 2017. $400 million Credit Agreement has a minimum monthly liquidity covenant of $125 million. At December 31, 2017, the Company had the full available borrowing capacity under the Credit Agreement of $400 million. The A/R Securitization has a maturity date of 2020 and includes the capability to issue letters of credit. As of December 31, 2017, all undrawn letters of credit were issued under the A/R Securitization Program. The improved Company and coal industry conditions supported a lower amount of collateral for the reclamation bonding program. As of December 31, 2017, undrawn letters of credit were reduced to $23 million. (1) Letters of credit issued under our A/R Securitization Program provided approximately 5.4% collateral to sureties for reclamation bonds as of December 31, 2017. (in millions)

27 Maturity Profile – Debt and Transportation Commitments Actively Managing Financial Obligations and Commitments December 31, 2017 12% Second Lien Notes due 2021 $290 6.375% High-Yield Notes due 2024 56 Bonds Outstanding $346 Deferred gain and other (1) 59 Carrying Value of Debt $405 Capital leases 5 Total Debt on Balance Sheet $410 Total Debt / TTM Adjusted EBITDA (2) 3.4X Net Debt / TTM Adjusted EBITDA (2) 2.3X Transportation (3) 2018 Take-or-Pay Commitments $ 28 2019 Take-or-Pay Commitments $ 10 2020 Take-or-Pay Commitments $ 8 Through the exchange offer in Q4 2016 and equity raise in Q1 2017, accomplished total deleveraging of $153 million. Nearest principal maturity is 2021. Port and rail agreements were amended in late 2017 and early 2018 to better meet our future export needs while maintaining low overall take-or-pay commitments. Represents the deferred gain on the Q4 2016 bond exchange transaction less unamortized debt issuance costs and cash premium paid Total debt includes high-yield notes and capital leases Commitments represent replacement Westshore and BNSF agreements. Does not include back-to-back Westshore and BNSF agreements in support of the JERA Trading agreement. See Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” in our 2017 Form 10-K and Item 8—Note 9 “Transportations Agreements” of our Notes to Consolidated Financial Statements in our December 31, 2017 Form 10-K for additional information. (in millions) $0 $100 $200 $300 $400 Credit Facility A/R Securitization Bonds Take-or-Pay Commitments

28 2018 Guidance (as of February 15, 2018) Coal shipments for our three mines (1) 52 – 56 million tons Committed sales with fixed prices Approximately 45 million tons Anticipated realized price of produced coal with fixed prices Approximately $12.30 per ton Adjusted EBITDA (2) $75 – $100 million Net interest expense Approximately $37 million Cash interest paid Approximately $42 million Depreciation, depletion, amortization, and accretion $75 – $85 million Capital expenditures $15 – $25 million Inclusive of intersegment sales. Non-GAAP financial measure; please see definition below in this presentation. Management did not prepare estimates of reconciliation with comparable GAAP measures, including net income, because information necessary to provide such a forward-looking estimate is not available without unreasonable effort.

Appendix 29

Note: Represents average cost of product sold for produced coal for our three mines. $9.81/ton $10.19/ton 2014 2015 2013 $10.23/ton 2016 $9.75/ton Royalties and taxes Labor Repairs, maintenance, and tires Fuel and lubricants Explosives Outside services Other mining costs 2017 $9.78/ton Average Cost of Produced Coal 30 36% 20% 15% 13% 6% 4% 6% 38% 27% 13% 8% 6% 3% 5% 37% 28% 14% 7% 6% 2% 6% 37% 21% 15% 12% 6% 4% 5% 38% 24% 15% 8% 6% 4% 5%

2016 and 2017 Financial Progression Reclamation Bonds Credit Agreement Senior Notes Take-or-Pay Commitments Reclamation Bonds $197.4M lower reclamation bonding requirement, primarily a result of lower cost guidance issued by Wyoming DEQ. Exited self-bonding during Q1 2017. As of December 31, 2017, reduced collateral requirements from $67.5M to $23M. Credit Agreement Amended bank facility to replace EBITDA-based financial covenants with minimum liquidity covenant and provide flexibility to issue second-lien debt. Senior Notes Completed bond exchanges for a majority of the 2019 and 2024 senior notes into newly issued 2nd lien 2021 notes. Redeemed 2019 notes and moved nearest bond maturity to 2021. Equity Offering Issued 13.5M shares of common stock for net proceeds of $64.7M to fund the redemption of the remaining 2019 senior notes. Take-Or-Pay Commitments (1) In Q4 2016 and Q1 2017, port and rail agreements were amended and shortened to reduce the take-or-pay commitments by $493M over the remaining term of the agreements. 31 (1) See Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” in our 2016 Form 10-K and Item 1—Note 7 “Transportations Agreements” of our Notes to Unaudited Condensed Consolidated Financial Statements in our December 31, 2017 Form 10-K for additional information. Does not include back-to-back Westshore and BNSF agreements in support of the JERA Trading agreement. 2019 2019 2021 2021 2024 2024 2024 $0 $100 $200 $300 $400 $500 $600 (in millions) Self-Bonding Letters of Credit Surety Bonds Undrawn Borrowing Capacity

32 Major Mine Equipment - 2017 Antelope Mine 2 draglines 8 shovels 22 830E haul trucks 15 930E haul trucks 16 dozers 4 excavators 5 drills Cordero Rojo Mine 2 draglines 6 shovels 31 830E haul trucks 14 dozers 3 excavators 4 drills Spring Creek Mine 2 draglines 3 shovels 12 830E haul trucks 7 dozers 3 excavators 4 drills

33 Owned and Operated Mines Our Owned and Operated Mines segment comprises the results of mine site sales from our three mines primarily to our domestic utility customers and also to our Logistics and Related Activities segment. Calculated by subtracting the average cost per ton sold from the realized price per ton sold. (2) Non-GAAP measure. Reconciliation tables for Adjusted EBITDA are included in the Appendix. Quarter Ended Year Ended (in millions, except per ton amounts) 12/31/17 12/31/16 12/31/17 12/31/16 Tons sold 13.5 16.7 57.4 58.5 Revenue $ 165.7 $ 207.3 $ 715.9 $ 738.6 Cost of product sold $ 138.5 $ 153.4 $ 569.7 $ 582.5 Realized price per ton sold $ 11.98 $ 12.15 $ 12.17 $ 12.40 Average cost of product sold per ton $ 10.08 $ 8.96 $ 9.78 $ 9.75 Cash margin per ton sold (1) $ 1.90 $ 3.19 $ 2.39 $ 2.65 Segment operating income (loss) $ 11.1 $ 48.7 $ 65.5 $ 125.5 Segment Adjusted EBITDA (2) $ 26.8 $ 51.7 $ 142.8 $ 143.7

34 Logistics and Related Activities Our Logistics and Related Activities segment comprises the results of our logistics and transportation services to our domestic and international customers. (1) Non-GAAP measure. Reconciliation tables for Adjusted EBITDA are included in the Appendix. Quarter Ended Year Ended (in millions, except per ton amounts) 12/31/17 12/31/16 12/31/17 12/31/16 Total tons delivered 1.1 0.5 4.4 0.9 Asian exports (tons) 1.1 0.4 4.2 0.6 Domestic (tons) 0.1 0.1 0.2 0.3 Revenue $ 60.5 $ 23.0 $ 222.5 $ 43.6 Total cost of product sold $ 59.2 $ 28.0 $ 233.9 $ 72.6 Realized gain on financial instruments $ - $ 1.8 $ - $ 7.1 Segment operating income (loss) $ 1.3 $ (5.1) $ (11.4) $ (28.9) Segment Adjusted EBITDA (1) $ 6.4 $ (3.3) $ 8.6 $ (23.6)

Three Months Ended December 31, Year Ended December 31, 2017 2016 2017 2016 Revenue $ 213.9 $ 227.9 $ 887.7 $ 800.4 Operating income $ (2.4) $ 36.1 $ 4.9 $ 67.3 Net income (loss) $ 17.8 $ 24.5 $ (6.6) $ 21.8 Earnings per common share Basic $ 0.24 $ 0.40 $ (0.09) $ 0.36 Diluted $ 0.23 $ 0.39 $ (0.09) $ 0.35 Statement of Operations Data 35 (in millions, except per share amounts)

Year Ended December 31, 2017 2016 2015 2014 2013 Statement of Operations Data 36 (in millions, except per share amounts) (1) Net loss for 2015 was impacted by the $111.8 million non-cash valuation allowance adjustment on deferred tax assets based upon then-forecasted taxable earnings and a $58.2 million non-cash asset impairment recorded due to lower forecasted earnings as a result of the weak international coal prices at that time. Revenue $ 887.7 $ 800.4 $ 1,124.1 $ 1,324.0 $ 1,396.1 Operating income $ 4.9 $ 67.3 $ (81.4) $ 131.8 $ 112.4 Net income (loss) $ (6.6) $ 21.8 $ (204.9) $ 79.0 $ 52.0 Earnings per common share Basic $ (0.09) $ 0.36 $ (3.36) $ 1.30 $ 0.86 Diluted $ (0.09) $ 0.35 $ (3.36) $ 1.29 $ 0.85

December 31, 2017 2016 2015 2014 2013 Balance Sheet Data 37 (in millions) Cash, cash equivalents and investments $ 107.9 $ 83.7 $ 89.3 $ 168.7 $ 312.3 Restricted cash 0.7 0.7 8.5 2.0 - Property, plant and equipment, net 1,365.8 1,432.4 1,488.4 1,589.1 1,654.0 Total assets 1,698.7 1,714.8 1,802.2 2,151.2 2,348.5 Senior notes, net of unamortized discount 405.3 475.0 491.2 489.7 588.1 Federal coal lease obligations - - - 64.0 122.9 Asset retirement obligations, net of current portion 99.3 97.0 151.8 216.2 246.1 Total liabilities 690.9 763.1 914.3 1,063.3 1,346.5 Total equity 1,007.8 951.7 887.9 1,087.8 1,002.0

Reconciliation of Non-GAAP Measures Adjusted EBITDA 38 (1) Fair value mark-to-market (gains) losses reflected on the statements of operations. Cash amounts received and paid reflected within operating cash flows. (in millions) Three Months Ended December 31, Year Ended December 31, 2017 2016 2017 2016 (in millions) Net income (loss) $ 17.8 $ 24.5 $ (6.6) $ 21.8 Interest income (0.2) 0 (0.5) (0.1) Interest expense 9.0 12.1 41.4 47.4 Income tax expense (benefit) (29.5) 1.0 (29.5) (2.2) Depreciation and depletion 15.6 4.2 72.3 27.2 EBITDA $ 12.8 $ 41.7 $ 77.0 $ 94.1 Accretion 1.5 1.0 7.1 6.6 Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains) (1) (0.4) (2.9) 2.7 (8.2) Inclusion of cash amounts received (paid) (2) 0 (0.1) (1.9) (3.3) Total derivative financial instruments (0.4) (3.0) 0.8 (11.5) Impairments 0 0.1 0 4.6 Debt restructuring costs 0 0.2 0 4.7 Non-cash throughput amortization expense and contract termination payments 5.1 0 20.1 0 Adjusted EBITDA $ 19.0 $ 40.0 $ 104.9 $ 98.6

Year Ended December 31, 2017 2016 2015 2014 2013 (1) Changes to related deferred taxes are included in income tax expense. (2) Fair value mark-to-market (gains) losses reflected on the statement of operations. (3) Cash amounts received and paid reflected within operating cash flows. (4) Excludes premiums paid at option contract inception of $5.8 million and $4.0 million during the years ended December 31, in 2015 and 2014, respectively, for original settlement dates in subsequent years. (5) Non-cash impairments of $33.4 million related to goodwill at the Cordero Rojo Mine, $52.2 million of port access rights, and $6.0 million related to our investment in GPT during the year ended December 31, 2015. Reconciliation of Non-GAAP Measures Adjusted EBITDA 39 (in millions) Net income (loss) $ (6.6) $ 21.8 $ (204.9) $ 79.0 $ 52.0 Interest income (0.5) (0.1) (0.2) (0.3) (0.4) Interest expense 41.4 47.4 47.6 77.2 41.7 Income tax expense (benefit) (29.5) (2.2) 77.4 34.9 11.6 Depreciation and depletion 72.3 27.2 66.1 112.0 100.5 Amortization of port access rights — — 3.7 — — EBITDA $ 77.0 $ 94.1 $ (10.4) $ 302.8 $ 205.3 Accretion 7.1 6.6 12.6 15.1 15.3 Tax agreement expense (benefit) (1) — — — (58.6) 10.5 Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains) (2) 2.7 (8.2) 30.6 (7.8) (25.6) Inclusion of cash amounts received (paid) (3)(4) (1.9) (3.3) (0.6) 24.7 13.0 Total derivative financial instruments 0.8 (11.5) 30.0 16.9 (12.6) Impairments (5) — 4.6 91.5 — — Gain on sale of Decker Mine interest — — — (74.3) — Debt restructuring costs — 4.7 — — — Non-cash throughput amortization expense and contract termination payments 20.1 — — — — Adjusted EBITDA $ 104.9 $ 98.6 $ 123.8 $ 201.9 $ 218.6

Adjusted EBITDA by Segment 40 Three Months Ended Year Ended December 31, December 31, (in millions) 2017 2016 2017 2016 Net income (loss) $ 17.8 $ 24.5 $ (6.6) $ 21.8 Interest income (0.2) — (0.5) (0.1) Interest expense 9.0 12.1 41.4 47.4 Other, net 0.3 0.2 0.9 1.0 Income tax (benefit) expense (29.5) 1.0 (29.5) (2.2) Earnings from unconsolidated affiliates, net of tax 0.1 (1.7) (0.7) (0.7) Consolidated operating income (loss) $ (2.4) $ 36.1 $ 4.9 $ 67.3 Owned and Operated Mines Operating income (loss) $ 11.1 $ 48.7 $ 65.5 $ 125.5 Depreciation and depletion 14.9 7.0 71.0 29.1 Accretion 1.4 0.8 6.5 6.0 Derivative financial instruments: Exclusion of fair value mark-to-market (gains) losses (0.4) (2.9) 2.7 (8.1) Inclusion of cash amounts received (paid) — (1.9) (1.9) (10.4) Total derivative financial instruments (0.4) (4.8) 0.8 (18.5) Impairments — 0.1 — 2.6 Other (0.2) (0.1) (1.0) (1.0) Adjusted EBITDA $ 26.8 $ 51.7 $ 142.8 $ 143.7 Logistics and Related Activities Operating income (loss) 1.3 (5.1) (11.4) (28.9) Derivative financial instruments: Exclusion of fair value mark-to-market (gains) losses — — — (0.1) Inclusion of cash amounts received (paid) — 1.8 — 7.1 Total derivative financial instruments — 1.8 — 7.0 Non-cash throughput amortization expense and contract termination payments 5.1 — 20.1 — Other — — (0.1) (1.7) Adjusted EBITDA $ 6.4 $ (3.3) $ 8.6 $ (23.6) Other Unallocated Operating Income (Loss) Other operating income (loss) $ (15.1) $ (7.1) $ (49.3) $ (28.7) Elimination of intersegment operating income (loss) $ 0.3 $ (0.4) $ 0.1 $ (0.6)

Former non-operating interest divested by Cloud Peak Energy in September 2014. Represents only the three company-operated mines. Q4 Q3 Q2 Q1 Q4 Year Year Year Year Year 2017 2017 2017 2017 2016 2017 2016 2015 2014 2013 Tons sold Antelope Mine 6,540 7,813 6,711 7,375 8,069 28,439 29,807 35,167 33,647 31,354 Cordero Rojo Mine 3,955 3,770 4,227 4,441 5,562 16,394 18,332 22,872 34,809 36,670 Spring Creek Mine 3,047 3,959 3,390 2,210 3,111 12,606 10,348 17,027 17,443 18,009 Decker Mine (50% interest)(1) - - - - - - - - 1,079 1,519 Total tons sold 13,542 15,542 14,328 14,026 16,742 57,439 58,487 75,066 86,978 87,552 Average realized price per ton sold(2) $11.98 $12.32 $12.25 $12.10 $12.15 $12.17 $12.40 12.79 $13.01 $13.08 Average cost of product sold per ton(2) $10.08 $9.57 $9.72 $9.78 $8.96 $9.78 $9.75 9.81 $10.19 $10.23 Other Data 41 (in thousands)

High Quality Customer Base Our Deliveries to Power Plants in 2016 42

High Quality Customer Base U.S. Coal Consumption by Region in 2016 43