INVESTOR Presentation May 2017

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 related to 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 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 2016 coal shipments from our three mines of 58.5 million tons 2016 proven & probable reserves of 1.1 billion tons Only pure-play PRB coal company Extensive NPRB projects and options for long-term growth opportunities Employs approximately 1,300 people Company and Financial Overview NYSE: CLD (4/21/17) $3.89 Market Capitalization (4/21/17) $292.0 million Total Available Liquidity (3/31/17) $454.6 million 2016 Revenue $800.4 million Senior Debt Principal (3/31/17) $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 - Incident Rates (MSHA) Cloud Peak Energy 2016 – 0.25 Cloud Peak Energy 2015 – 0.91 2016 March 31, 2017 MSHA AIFR 0.34 0.25 0.61 0.61 0.73 0.91 1.01 1.34 1.39 1.50 1.51 1.53 2.07 3.05 3.62 3.65 3.69 3.82 3.98 4.49 4.67 5.15 5.31 5.37 5.45 5.93 6.55 Cloud Peak Energy Global Mining Group Energy Future Holdings NACCO Industries Cloud Peak Energy Arch Coal Kiewit Peter Sons Bowie Resources Partners Navajo Nation Peabody Energy Westmoreland CONSOL Energy Walter Energy BHP Billiton Alliance Resource Partners Prairie State Energy Alpha Natural Resources IDACORP Brent K Bilsland JMP Coal Holdings Armstrong Energy J Clifford Forrest Coalfield Transport Western Fuels Robert E Murray Patriot Coal 2015

Low-Risk Surface Operations One of the best safety records in the industry Proportionately low, long-term operational liabilities Surface mining reduces liabilities and allows for high-quality reclamation Strong environmental compliance programs and 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 further down geologically moving west Haul distances increase as mining pits migrate further from load-out More equipment, personnel, resources required to maintain steady production Imposes production growth constraints in the PRB over time

Extensive Coal Reserves and Projects Spring Creek Mine – MT 2016 Tons Sold 10.3M tons 2016 Proven & Probable Reserves 248.5M tons Average Reserve Coal Quality 9,350 Btu/lb Mine Life (1) 24 years Cordero Rojo Mine – WY 2016 Tons Sold 18.3M tons 2016 Proven & Probable Reserves 315.9M tons Average Reserve Coal Quality 8,425 Btu/lb Mine Life (1) 17 years Antelope Mine – WY 2016 Tons Sold 29.8M tons 2016 Proven & Probable Reserves 516.9M tons Average Reserve Coal Quality 8,875 Btu/lb Mine Life (1) 17 years Antelope Mine 7.8M tons Cordero Rojo Mine 53.1M tons Spring Creek Mine 3.9M tons Youngs Creek Project (non-federal coal) 292.4M tons 357.2M tons 2016 Non-Reserve Coal Deposits(2) 0.36B Tons Big Metal Project 1,387M tons Additional Non-Federal Coal (3) 1.4B Tons 2016 Proven & Probable Reserves 1.1B Tons Source: SNL Energy7 (1) Assumes production at the 2016 level. (2) 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. (3) 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

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 292 million tons of non-reserve coal deposits at December 31, 2016(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 Exploration agreement and 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 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 Quality Advantage and Export Distance Source: SNL, Wood Mackenzie, Company estimates 4770-4850 4544 Average Higher Quality Product Location Spring Creek Complex is closer to export West Coast terminals than SPRB mines Fewer bottlenecks in NPRB Quality Spring Creek Mine is a premium subbituminous coal for many Asian utilities valued for its consistent quality Indonesian coal (primary international competitor) has wide variety of qualities Conversations and scheduled test burns for Spring Creek Complex coal with new potential domestic customers Spring Creek Complex

Finance 12

13 Managing Through Changing Environments Coal production in the U.S. down 19% in 2016 compared to 2015, while PRB production is down 21% for the same period (1) Aligned production to balance market demand Aligning cost structure with forecast production Restarting exports based on Q4 2016 seaborne coal price rise 8400 Btu volumes continue to be challenged by low 8800 Btu coal prices Controlling Costs Reducing Capital Expenditures (1) Source: Mine Safety and Health Administration (2) Includes labor, repairs, maintenance, tires, explosives, outside services, and other mining costs $4.97 $4.99 $5.05 $4.45 $4.20 $4.60 $5.24 $5.14 $5.36 $5.55 $9.57 $10.23 $10.19 $9.81 $9.75 $0 $2 $4 $6 $8 $10 $12 2012 2013 2014 2015 2016 (cash cost per ton) Royalties/Taxes/Fuel/Lubricants Core Cash Cost (2) 86.2 81.3 81.9 71.5 57.9 50 - 55 4.4 4.7 4.0 3.6 0.6 5.0 90.6 86.0 85.9 75.1 58.5 55 - 60 0 10 20 30 40 50 60 70 80 90 100 2012 2013 2014 2015 2016 2017E (in millions) North American Deliveries Asian Exports Reducing Shipments $54 $57 $20 $39 $35 $20 - 30 $129 $79 $69 $69 $0 $50 $100 $150 $200 $250 2012 2013 2014 2015 2016 2017E (in millions) Capex LBA Payments

14 2017 Guidance (as of April 27, 2017) Coal shipments for our three mines (1) 55 – 60 million tons Committed sales with fixed prices Approximately 55 million tons Anticipated realized price of produced coal with fixed prices Approximately $12.19 per ton Adjusted EBITDA (2) $80 – $110 million Net interest expense Approximately $40 million Cash interest paid Approximately $45 million Depreciation, depletion, amortization, and accretion $70 – $80 million Capital expenditures $20 – $30 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.

Financial Summary Cash and cash equivalents $101 Credit Agreement capacity $400 A/R Securitization 22 Available borrowing capacity 422 Letters of credit issued (1) (68) Total Available Liquidity $455 Reclamation Obligations (in millions) Surety bonds outstanding Third-party surety bonds $418 Lease bonds 30 Total Bonding Obligation $448 Debt and Commitments (in millions) 12% Second Lien Notes due 2021 290 6.375% High-Yield Notes due 2024 57 Bonds Outstanding $347 Deferred gain and other (2) 68 Carrying Value of Debt 415 Capital leases 7 Total Debt on Balance Sheet $422 Total Debt / Adjusted EBITDA (3) 2.9X Net Debt / Adjusted EBITDA (3) 2.1X Equity Issuance (in millions) 13.5M Shares $ 65 Liquidity & Obligations (as of March 31, 2017, in millions) 15 $400 million Credit Agreement, amended in 2016 to replace the EBITDA based financial covenants with a minimum monthly liquidity covenant of $125 million. At March 31, 2017, we had available borrowing capacity of $332 million, as $68 million undrawn letters of credit were outstanding. Successfully amended the A/R Securitization in January 2017, extending the maturity date until 2020 and including the capability to issue letters of credit. (1) Letters of credit issued under our Credit Agreement provide approximately 15% collateral to sureties for reclamation bonds (2) Represents the deferred gain on the transaction less unamortized debt issuance costs and cash premium paid (3) Total debt includes high-yield notes and capital leases Exited self-bonding. Eliminated $177 million in reclamation bonding obligations in 2016. Issuance of $290 million of 2021 secured bonds in exchange for 2019 and 2024 bonds, which resulted in de-leveraging of $91 million. Redemption of remaining 8.5% 2019 bonds, which resulted in a further deleveraging of $62 million. Accomplished total deleveraging of $153 million and moved maturity wall to 2021. Port and rail agreements were replaced and shortened to reduce the take-or-pay commitments by $488 million over the remaining term of the agreements. Issued 13.5 million shares in February 2017 for net proceeds of $64.7 million to fund the 2019 bond stub redemption.

16 Maturity Profile As of December 31, 2015 As of March 31, 2017 Actively Managing Financial Obligations and Commitments (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 March 31, 2017 Form 10-Q for additional information. (1)

Financial Progression Reclamation Bonds Credit Agreement Senior Notes Take-or-Pay Commitments Reclamation Bonds $177 million lower reclamation bonding requirement, primarily a result of lower cost guidance issued by Wyoming DEQ. Exited self-bonding during Q1 2017. 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 13.5 million shares of common stock for net proceeds of $64.4 million to fund the redemption of the remaining 2019 senior notes. Take-Or-Pay Commitments (1) Port and rail agreements were replaced and shortened to reduce the take-or-pay commitments by $488 million over the remaining term of the agreements. 17 (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 March 31, 2017 Form 10-Q for additional information. 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

Domestic Coal Environment Conditions and Regulations 18

Challenging Domestic Environment Current environment Early end to winter has kept coal inventories elevated Natural gas inventory levels continue to decline Natural gas prices currently stable around $3.00 MMBtu Uncertain impact of new presidential administration Initiatives/litigation Clean Power Plan, federal royalty rate review Renewable mandates and subsidies NGO anti-coal activities Peer companies emerged from Chapter 11 Reorganizations 19

Natural Gas Storage and Pricing Natural Gas Storage Even with mild winter heating demand, significantly declining production has reduced inventories Storage levels are down 368 Bcf or 14.8% from last year Since the start of December, storage levels have been well below 2016 record levels Natural Gas Pricing and Rig Count Financial pressure on oil and gas producers Rig count has increased since Q4 2016 in lowest cost basins Prices have currently maintained in the $3.00 MMBtu range 20 Source: EIA Source: EIA, Baker Hughes $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 0 1,000 2,000 3,000 4,000 5,000 BCF Week 5-Year Range 2017 2016

21 Powder River Basin SPRB Production Declined 78 MT in 2016 Downward demand pressures on 8800 Btu (54 MT) and 8400 Btu (24 MT) mines Cordero Rojo Mine reduced from 35 MT in 2014 to 19 MT in 2016 2017 volumes are expected to be around 10 million tons higher than 2016 as stockpiles are reduced Above normal summer weather and higher natural gas prices could increase 2017 coal volume expectation further 2008 42% 2008 58% 2017 32% 2017 68% Source: MSHA 2008 - 2016 and Company Estimates 2017 0 50 100 150 200 250 300 350 400 450 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E (million tons) Southern PRB Production Trends 8400 vs. 8800, 2008 - 2017 8800 Btu 8400 Btu

22 Continued Forward Sales Strategy 2017 has 55 million tons committed and fixed at weighted-average price of $12.19/ton. 2018 has 27 million tons committed and fixed at weighted-average price of $12.51/ton 55 27 1 2 56 29 0 10 20 30 40 50 60 70 80 2017 2018 Committed tons with variable pricing Committed tons with fixed pricing Total Committed Tons (as of 4/21/17)

Export Environment 23

24 International prices have stabilized on supply reductions Cyclone Debbie has created supply issues in Australia – mostly metallurgical This has reminded many end users in the Asian markets of 2011 and the importance of supply diversity Indications through Q1 2017 Chinese domestic production down 5 million tonnes and imports increasing 10 million tonnes Newcastle spot prices have stabilized around $80 per tonne for 2017 We have contracted approximately 3.3 million tons of coal for export in 2017 Replaced agreements with Westshore and BNSF Source: Global Coal, HDR Salva, Company estimates Export Drivers are Cyclical $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 (per tonne) Newcastle Price Curve

Positioned to Capitalize on Improving Export Sales Renegotiated Port Contract Provides Flexibility Optionality to Grow Exports Replaced and shortened agreements with Westshore and BNSF to adjust volume obligations and eliminate $488 million of take-or-pay commitments from 2017 – 2024 Remaining commitment assumes contract settlements in-lieu of physical shipments. Transportation payments are invoiced on a per ton/tonne basis. We currently retain ~5.0 million tons of export capacity at Westshore for 2017 - 2018 We have shipped 0.5 million tons in first quarter of 2017 and contracted 3.3 million tons of coal for export for the full year If all 5.0 million tons are exported, there would be no remaining take-or-pay payments. (million tons) Export Tons $123 $103 $85 $71 $59 Transportation Commitments Take-or-Pay Commitments(1) As of 3/31/17 2017 $25M 2018 $24M Total $49M Avg. annual Newcastle benchmark ($/tonne) 25 $66 (1) Commitments represent replacement Westshore and BNSF agreements. 4.7 4.4 4.7 4.0 3.6 0.4 5.0 2011 2012 2013 2014 2015 2016 2017E

26 Cloud Peak Energy Terminal Position Westshore Terminal – Existing lowest cost, cape-size port Capesize vessels – deep-water port Replaced agreement and shortened to reduce the contractual take-or pay-commitments over the remaining term of the agreement As seaborne thermal coal prices have recently rebounded, we exported 0.5 million tons during first quarter of 2017 and have contracted 3.3 million tons of Asian export sales to be delivered for the full year Proposed Millennium Bulk Terminal Panamax vessels CPE has an option for up to 3 million tonnes per year at Stage 1 of development (total throughput of at least 10 million tonnes per year) and option for an additional 4 million tonnes per year at Stage 2 of development (total throughput of at least 30 million tonnes per year) EIS scope announced February 2014 – EIS process continues

Appendix 27

Note: Represents average cost of product sold for produced coal for our three mines. $10.19/ton $10.23/ton 2013 2014 2012 $9.57/ton 2015 $9.81/ton Royalties and taxes Labor Repairs, maintenance, and tires Fuel and lubricants Explosives Outside services Other mining costs 2016 $9.75/ton Average Cost of Produced Coal 28 36% 20% 15% 13% 6% 4% 6% 40% 20% 14% 12% 5% 4% 5% 37% 28% 14% 7% 6% 2% 6% 37% 21% 15% 12% 6% 4% 5% 38% 24% 15% 8% 6% 4% 5%

29 Major Mine Equipment - 2016 (1) Dragline has been moved from Cordero Rojo Mine to Antelope Mine Antelope Mine 2 draglines (1) 8 shovels 24 830E haul trucks 15 930E haul trucks 18 dozers 3 excavators 5 drills Cordero Rojo Mine 2 draglines 6 shovels 32 830E haul trucks 15 dozers 2 excavators 4 drills Spring Creek Mine 2 draglines 3 shovels 13 830E haul trucks 7 dozers 2 excavators 4 drills

30 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. (in millions, except per ton amounts) Q1 2017 Q1 2016 Tons sold 14.0 13.0 Realized price per ton sold $ 12.10 $ 12.65 Average cost of product sold per ton $ 9.78 $ 11.15 Adjusted EBITDA(1) $ 33.7 $ 15.5 (1) Non-GAAP measure. Reconciliation tables for Adjusted EBITDA are included in the Appendix

31 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 (in millions) Q1 2017 Q1 2016 Total tons delivered 0.6 0.3 Asian export tons 0.5 0.2 Domestic tons 0.1 0.1 Revenue 28.2 14.0 Realized gains/(losses) on financial instruments — 1.8 Total cost of product sold 35.7 21.9 Segment Adjusted EBITDA(1) (2.6) (6.9)

Three Months Ended March 31, (in millions, except per share amounts) 2017 2016 Revenue $ 195.7 $ 181.2 Operating income $ (7.0) $ (25.6) Net income (loss) $ (20.1) $ (36.4) Earnings per common share Basic $ (0.30) $ (0.59) Diluted $ (0.30) $ (0.59) Statement of Operations Data 32

Statement of Operations Data 33 (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. (in millions, except per share amounts) Year ended December 31, 2016 2015 2014 2013 2012 Revenue $ 800.4 $ 1,124.1 $ 1,324.0 $ 1,396.1 $ 1,516.8 Operating income $ 67.3 $ (81.4) $ 131.8 $ 112.4 $ 241.9 Net income (loss) (1) $ 21.8 $ (204.9) $ 79.0 $ 52.0 $ 173.7 Earnings per common share Basic $ 0.36 $ (3.36) $ 1.30 $ 0.86 $ 2.89 Diluted $ 0.35 $ (3.36) $ 1.29 $ 0.85 $ 2.85

Cash, cash equivalents and investments $ 100.5 $ 83.7 $ 89.3 $ 168.7 $ 312.3 $ 278.0 Restricted cash 0.7 0.7 8.5 2.0 — 4.5 Property, plant and equipment, net 1,423.2 1,432.4 1,488.4 1,589.1 1,654.0 1,678.3 Total assets 1,714.5 1,714.8 1,802.2 2,151.2 2,348.4 2,341.0 Senior notes, net of unamortized discount 414.6 475.0 491.2 489.7 588.1 586.2 Federal coal lease obligations — — — 64.0 122.9 186.1 Asset retirement obligations, net of current portion 106.3 97.0 151.8 216.2 246.1 239.0 Total liabilities 718.8 763.1 914.3 1,063.3 1,346.5 1,410.0 Total equity 995.7 951.7 887.9 1,087.8 1,002.0 931.0 March 31, December 31, 2017 2016 2015 2014 2013 2012 Balance Sheet Data 34 (in millions)

Reconciliation of Non-GAAP Measures Adjusted EBITDA 35 (1) Fair value mark-to-market (gains) losses reflected on the statements of operations. Cash amounts received and paid reflected within operating cash flows. Three Months Ended Trailing Twelve March 31, Months Ended (in millions) 2017 2016 March 31, 2017 Net income (loss) $(20.1) $(36.4) $38.1 Interest income — — (0.1) Interest expense 12.9 11.1 49.3 Income tax (benefit) expense 0.3 (1.4) (0.5) Depreciation and depletion 18.6 19.1 26.8 EBITDA 11.7 (7.7) 113.5 Accretion 1.8 2.6 5.9 Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains) (1) 2.3 2.0 (7.8) Inclusion of cash amounts received (paid) (2) (0.3) (2.3) (1.3) Total derivative financial instruments 2.0 (0.3) (9.1) Impairments — 4.2 0.4 Debt Restructuring Costs — — 4.6 Non-cash amortization expense and one time contract termination payments 4.9 — 4.8 Adjusted EBITDA $20.4 $(1.3) $120.3

Year Ended December 31, 2016 2015 2014 2013 2012 (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 36 (in millions) Net income (loss) $ 21.8 $ (204.9) $ 79.0 $ 52.0 $ 173.7 Interest income (0.1) (0.2) (0.3) (0.4) (1.1) Interest expense 47.4 47.6 77.2 41.7 36.3 Income tax expense (benefit) (2.2) 77.4 34.9 11.6 62.6 Depreciation and depletion 27.2 66.1 112.0 100.5 94.6 Amortization of port access rights — 3.7 — — — EBITDA $ 94.1 $ (10.4) $ 302.8 $ 205.3 $ 366.1 Accretion 6.6 12.6 15.1 15.3 13.2 Tax agreement expense (benefit) (1) — — (58.6) 10.5 (29.0) Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains) (2) (8.2) 30.6 (7.8) (25.6) (22.8) Inclusion of cash amounts received (paid) (3)(4) (3.3) (0.6) 24.7 13.0 11.2 Total derivative financial instruments (11.5) 30.0 16.9 (12.6) (11.6) Impairments (5) 4.6 91.5 — — — Gain on sale of Decker Mine interest — — (74.3) — — Debt restructuring costs 4.7 — — — — Adjusted EBITDA $ 98.6 $ 123.8 $ 201.9 $ 218.6 $ 338.8

Adjusted EBITDA by Segment 37 (in millions) Three Months Ended March 31, 2017 2016 Net income (loss) $ (20.1) $ (36.4) Interest expense 12.9 11.1 Other, net 0.3 0.4 Income tax (expense) benefit 0.3 (1.4) Income (loss) from unconsolidated affiliates, net of tax (0.3) 0.7 Consolidated operating income (loss) $ (7.0) $ (25.6) Owned and Operated Mines Operating income (loss) $ 11.9 $ (5.4) Depreciation and depletion 18.5 18.8 Accretion 1.7 2.4 Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) 2.3 2.0 Inclusion of cash amounts (received) paid (0.3) (4.1) Total derivative financial instruments 2.0 (2.1) Impairments — 2.2 Other (0.4) (0.4) Adjusted EBITDA $ 33.7 $ 15.5 Logistics and Related Activities Operating income (loss) $ (7.4) $ (7.8) Derivative financial instruments: Inclusion of cash amounts (received) paid — 1.8 Total derivative financial instruments — 1.8 Non-cash throughput amortization expense and one time contract termination payments 4.9 — Other (0.1) (0.9) Adjusted EBITDA $ (2.6) $ (6.9) Other Operating income (loss) $ (11.0) $ (12.3) Depreciation and depletion 0.2 0.3 Accretion 0.2 0.2 Impairment — 2.0 Other 0.3 — Adjusted EBITDA $ (10.3) $ (9.8) Eliminations Operating income (loss) $ (0.4) $ (0.1) Adjusted EBITDA $ (0.4) $ (0.1) (in millions)

Former non-operating interest divested by Cloud Peak Energy in September 2014. Represents only the three company-operated mines. Q1 Q4 Q3 Q2 Q1 Q4 Year Year Year Year Year 2017 2016 2016 2016 2016 2015 2016 2015 2014 2013 2012 Tons sold Antelope Mine 7,375 8,070 8,612 6,273 6,853 9,467 29,807 35,167 33,647 31,354 34,316 Cordero Rojo Mine 4,441 5,562 5,492 3,608 3,670 5,497 18,332 22,872 34,809 36,670 39,205 Spring Creek Mine 2,210 3,111 2,854 1,946 2,437 3,672 10,348 17,027 17,443 18,009 17,102 Decker Mine (50% interest)(1) — — — — — — — — 1,079 1,519 1,441 Total tons sold 14,026 16,743 16,958 11,827 12,960 18,636 58,487 75,066 86,978 87,552 92,064 Average realized price per ton sold(2) $12.10 $12.15 $12.33 $12.60 $12.65 $12.72 $12.40 $12.79 $13.01 $13.08 $13.19 Average cost of product sold per ton(2) $ 9.78 $ 8.96 $ 8.95 $10.50 $11.15 $ 9.54 $ 9.75 $ 9.81 $10.19 $10.23 $ 9.57 Other Data 38 (in millions)

High Quality Customer Base Our Deliveries to Power Plants in 2015 Source: SNL 39

High Quality Customer Base U.S. Coal Consumption by Region Source: SNL 40