INVESTOR Presentation November 2015

1 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 measures of (1) Adjusted EBITDA (on a consolidated basis and for our reporting segments) and (2) Adjusted Earnings Per Share (“Adjusted EPS”). Adjusted EBITDA and Adjusted EPS are intended to provide additional information only and do not have any standard meaning prescribed by generally accepted accounting principles in the U.S. (“GAAP”). A quantitative reconciliation of historical net income (loss) to Adjusted EBITDA and EPS (as defined below) to Adjusted EPS is found in the tables accompanying this release. 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 updates to the tax agreement liability, including tax impacts of the 2009 IPO and 2010 Secondary Offering and the termination of the Tax Receivable Agreement in August 2014, (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 goodwill impairment charges, and (4) adjustments to exclude the gain from the sale of our 50% non-operating interest in the Decker Mine. 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. 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 GAAP measures or reconciliation to any forecasted GAAP measures. Adjusted EPS represents diluted earnings (loss) per common share (“EPS”) adjusted to exclude (i) the estimated per share impact of the same specifically identified non-core items used to calculate Adjusted EBITDA as described above, and (ii) the cash and non-cash interest expense associated with the early retirement of debt and refinancing transactions. All items are adjusted at the statutory tax rate of approximately 37%. 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). Our chief operating decision maker uses Adjusted EBITDA as a measure of segment performance. Consolidated Adjusted EBITDA is also used as part of our incentive compensation program for our executive officers and others. We believe Adjusted EBITDA and Adjusted EPS are 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. Similarly, we believe our use of Adjusted EPS provides an appropriate measure to use in assessing our performance across periods given that this measure provides an adjustment for certain specifically identified significant items that are not considered to directly reflect our core operations, the magnitude of which may vary significantly from period to period and, thereby, have a disproportionate effect on the earnings per share reported for a given period. Our management recognizes that using Adjusted EBITDA and Adjusted EPS as performance measures has inherent limitations as compared to net income (loss), EPS, or other GAAP financial measures, as these non-GAAP measures exclude certain items, including items that are recurring in nature, which may be meaningful to investors. Adjusted EBITDA and Adjusted EPS should not be considered in isolation and do not purport to be alternatives to net income (loss), EPS or other GAAP financial measures as a measure of our operating performance. Because not all companies use identical calculations, our presentations of Adjusted EBITDA and Adjusted EPS may not be comparable to other similarly titled measures of other companies. Moreover, our presentation of Adjusted EBITDA is different than EBITDA as defined in our debt financing agreements.

2 2 2 Cloud Peak Energy One of the largest U.S. coal producers 2014 coal shipments from three Owned and Operated Mines of 85.9 million tons 2014 proven & probable reserves of 1.1 billion tons Only pure-play PRB coal company Extensive NPRB base for long-term growth opportunities Employs approximately 1,600 people NYSE: CLD (11/2/15) $3.25 Market Capitalization (11/2/15) ~$199 million Total Available Liquidity (9/30/15) $669 million 2014 Revenue $1.3 billion Senior Debt (B3/BB-) (9/30/15) $500 million Market and Financial Overview Company Overview

3 Low-Risk Surface Operations Highly productive, non-unionized workforce at all of our mines 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

4 4 4 (1) Additional overburden as coal seams dip further down geologically moving west Haul distances increase as mining pits migrate further from load-out Require more equipment / personnel / resources to maintain steady production Helps impose production growth constraints in the PRB over time Increasing Workload – A Function of Surface Mining

5 5 5 5 Top Coal Producing Companies - 2014 Incident Rates (MSHA) Source: MSHA Note: Total Incident Rate = (total number of employee incidents x 200,000) / total man-hours. Good Safety Record Indicates Well-Run Operations Cloud Peak Energy Cloud Peak Energy 0.00 0.37 0.55 0.79 0.83 1.21 1.30 1.36 1.62 1.88 2.70 2.90 3.48 3.88 3.99 4.27 4.39 4.43 4.46 4.91 5.59 5.95 6.36 6.59 7.32

Extensive Coal Reserves and Significant Projects 6 Spring Creek Mine – MT 2014 Tons Sold 17.4M tons 2014 Proven & Probable Reserves 274M tons Average Reserve Coal Quality 9,350 Btu/lb Average lbs SO2 0.73/mmBtu Cordero Rojo Mine – WY 2014 Tons Sold 34.8M tons 2014 Proven & Probable Reserves 267M tons Average Reserve Coal Quality 8,425 Btu/lb Average lbs SO2 0.69/mmBtu Antelope Mine – WY 2014 Tons Sold 33.6M tons 2014 Proven & Probable Reserves 581M tons Average Reserve Coal Quality 8,875 Btu/lb Average lbs SO2 0.50/mmBtu 6 2014 Proven & Probable Reserves 1.1B Tons Antelope Mine 8M tons Cordero Rojo Mine 148M tons Spring Creek Mine 3M tons Youngs Creek Project 287M tons 446M tons 2014 Non-Reserve Coal Deposits(1) 0.4B Tons Source: SNL Energy (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) 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. Big Metal Project (2) 1,380M tons Additional Coal 1.4B Tons

(1) Total debt includes high yield notes and capital leases; TTM Adjusted EBITDA of $160.7 million as of 9/30/2015 Liquidity & Obligations (as of September 30, 2015) Strong Balance Sheet (in millions) 7 No Debt Maturities until 2019 (1) Revolver is undrawn. Cash and cash equivalents $ 124 $500M revolver capacity $500 A/R securitization 45 Available revolver & A/R securitization 545 Total available liquidity $669 8.5% High-Yield Notes due 2019 300 6.375% High-Yield Notes due 2024 200 Senior unsecured debt (B3/BB- rating) $500 Capital leases 8 Total Debt $508 Total Debt / Adjusted EBITDA(1) 3.2x Net Debt / Adjusted EBITDA(1) 2.4x Strong liquidity and cash balance Low leverage (Debt to Adjusted EBITDA) No near-term maturities (in millions) 2019 Bonds 2024 Bonds $0 $100 $200 $300 $400 $500 Revolver (1) 2019

8 Continued Execution of Consistent Business Strategy Solid Domestic Business in Best Positioned Basin Manage Export Exposure Address Challenging External Environment (Natural Gas Competition and Regulatory Pressures)

9 9 9 (1) Low natural gas prices Utilities encouraged/forced to not burn coal Renewable mandates Subsidies Excessive regulations CPP – Clean Power Plan ONRR – Office of Natural Resources Revenue (export royalty valuation methodology) Stream Protection Rule Industry under financial stress Challenging Domestic Environment

Natural Gas Storage and Pricing Storage Storage levels are up 421 Bcf or 12% from historic lows last year, and are quickly approaching highs set in 2012 The pace of injections into storage have increased as we entered into the mild fall demand period Pricing and Rig Count 2015 has been consistently below $3.00/MMBtu, and most recently has dropped below $2.50/MMBtu Even with low prices natural gas production has set monthly production records for 29 consecutive months 10 Source: EIA Source: EIA, Baker Hughes 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 BCF Week 5-Year Range 2015 2014 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $6.50 100 150 200 250 300 350 400 450 500 550 Price ($/MMBtu) Rig Count Rigs Price

EPA Summary CSAPR Ruling – SO2 and NOx Regulations Reinstated January 2015, customers in Group 1 and 2 states have agreed to sulfur adjustments, customers in non-CSAPR states have pushed for no sulfur adjustment MATS – Mercury and Air Toxics Commenced April 2015, remanded to lower court by the Supreme Court Many utilities are staying with original plans and are not adjusting to the Supreme Court decision CPP – Clean Power Plan – Rule Released 8/3/2015 Final rule grants a two-year extension from proposed regulations but targets coal generation reduction Electric grid reliability remains a concern, although the EPA added a “reliability safety-valve” that eases compliance with the restrictions in the event they threaten utilities’ ability to maintain reliability Legal battle to “stay” CPP is underway – 25 states, utilities, and industry groups have filed suit Stream Protection Rule New regulations would increase cost to mine coal Currently in public comment period 11

12 Domestic Strategy Consistent Forward Selling Strategy Focus on Matching Production to Market Demand Optimize Operational Focus on Cost Control and Improvement Programs Disciplined Capital Expenditures and Significant Reserve Base

Responding to Market Conditions 13 Actively managing export take-or-pay exposure during current depressed market conditions Reducing production and capacity at Cordero Rojo Mine from 38Mtpa to approximately 24Mtpa in 2015 Locked in diesel costs for 2015 and 2016 Moving dragline from Cordero Rojo Mine to Antelope Mine Reducing Capital Expenditures (1) Includes labor, repairs, maintenance, tires, explosives, outside services, and other mining costs Controlling Costs Reducing Shipments $65 $109 $54 $57 $20 $40 - $50 $64 $133 $129 $79 $69 $ 69 PAID $0 $50 $100 $150 $200 $250 2010 2011 2012 2013 2014 2015E (in millions) Capex LBA Payments $4.03 $4.24 $4.60 $5.24 $5.14 $5.42 $4.54 $4.88 $4.97 $4.99 $5.05 $4.48 $8.57 $9.12 $9.57 $10.23 $10.19 $9.90 $0 $2 $4 $6 $8 $10 $12 2010 2011 2012 2013 2014 2015 YTD (cash cost per ton) Core Cash Cost (1) Royalties/Taxes/Fuel/Lubricants 90.5 90.9 86.2 81.3 81.9 71 - 73 3.3 4.7 4.4 4.7 4.5 4 93.7 95.6 90.6 86.0 85.9 75 - 77 60 65 70 75 80 85 90 95 100 2010 2011 2012 2013 2014 2015E (in millions) North American Deliveries Asian Exports

14 Powder River Basin SPRB 8800 Btu Increasingly Favored Downward demand pressures focused on SPRB 8400 Btu mines Cloud Peak Energy’s Cordero Rojo Mine reduced from 35 million tons in 2014 to about 24 million tons in 2015 Other 8400 mines are also experiencing reduced demand, while 8800 volumes remain relatively stable Cloud Peak Energy’s NPRB Spring Creek Complex offers >9000 Btu The Spring Creek Mine’s high Btu and low sulfur coal has a wide group of domestic and international customers, but is constrained by higher sodium content for domestic customers Cloud Peak Energy’s Big Metal project may provide a low sodium opportunity to expand NPRB sales to higher Btu customers and exploit the Spring Creek Mine’s rail cost advantage to Northern tier destinations SPRB Production Trends - 8400 vs. 8800, 2007-2015 Est. - 50 100 150 200 250 300 350 400 450 2007 2008 2009 2010 2011 2012 2013 2014 2015 Est Million Tons 8400 Btu 8800 Btu 2014/ 34% 2014/ 66% 2007/ 57% 2007/ 43%

15 High Quality Customer Base Thousands of Tons 7,500 - 15,000 0 - 1,500 Appalachia Powder River Basin Illinois Basin Rocky Mountain Lignite WECC MIDWEST SPP ERCOT SERC NORTHEAST RFC-PJM FRCC Source: IHS CERA, SNL Coal Region / Type Cloud Peak Energy Deliveries to Power Plants in 2013

16 Continued Forward Sales Strategy 2015 has 78 million tons committed and fixed at weighted-average price of $12.73/ton 2016 has 57 million tons committed and fixed at weighted-average price of $12.95/ton 2017 has 29 million tons committed and fixed at weighted-average price of $13.14/ton Total Committed Tons (as of 10/19/15) (tons in millions) ~78 57 29 0.3 10 11 ~78 67 40 2015E 2016E 2017E Committed tons with variable pricing Committed tons with fixed pricing

17 Export Strategy – Managing Exposure Strong Long-term International Demand Spring Creek Geographic and Quality Advantages Youngs Creek and Big Metal Projects Partnered with SSA Marine and Crow Tribe to Develop Port Amended Export Obligation with Westshore from 2016-2018 Working with BNSF to Potentially Amend Commitment

18 Increasing International Demand Should Support PRB Exports Long-Term North America China Japan South Korea Taiwan India Australia Indonesia Asian utilities seeking diversity and surety of long-term supply Cloud Peak Energy was the largest U.S. exporter of thermal coal into South Korea in 2013 and 2014 Growing customer base with sales to Taiwan and Japan Thermal Exports Total 27Mt PRB 8Mt Total 34Mt PRB 11Mt Total 150Mt PRB 75Mt (1) 2007 2014 2020E Source: EIA and internal estimates (1) Assumes development of additional export capacity

Change in Primary Energy Consumption 19 Source: Macquarie Research September 2015, BP Statistical Review 2014, UBS Typical industry response to periods of over supply Are the seeds of next price spike being sown?? 2014-2025 Where will supply growth come from? 0 200 400 600 800 1000 1200 1400 1600 (million tons of oil equivalent) Asia is all that really matters! $0 $1 $2 $3 $4 $5 $6 $7 (in billions)

20 Source: Global Coal, HDR Salva, Company estimates International markets currently oversupplied – Chinese reduced imports Newcastle prices remain muted Amended agreement with Westshore to eliminate volume obligations and reduced take-or-pay charges from 2016-2018 Working with BNSF for potential modification to rail agreement If seaborne coal prices rebound – shipments could potentially resume Newcastle Price Curve Commodity Pricing Environment Is Cyclical $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200

21 Korea is Increasing Coal Use Coal consumption in South Korea increased by 55% between 2005 and 2012 According to the proposed new electricity plan, the country plans to raise coal capacity to 44.9 GW by 2027 Plans to install 15 more coal-fired facilities with 12.5 GW of capacity by 2017. Emission and performance levels comparable to U.S. strictest levels according to Cloud Peak Energy internal research. Dangjing Power Station in Korea owned by Korea East West Power Source: WoonBong Energy, KEPCO Natural Gas , 25% Petroleum and Other Liquids , 9% Nuclear , 25% Coal , 30% Hydroelectricity , 8% Other Renewables , 3% South Korea Installed Capacity by Type, 2012

Spring Creek Complex – Quality Advantage and Export Distance 22 22 4770-4850 4544 Average Source: SNL, Wood Mackenzie, Company estimates Higher Quality Product Location Spring Creek Complex is closer to export 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 competitor) is declining in quality Spring Creek Complex

Key Projects 23 Youngs Creek Project 287 million tons of non-reserve coal deposits at December 31, 2014(1) Royalty payments of 8% vs. 12.5% federal rate 38,800 owned 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 agreements in June 2013 Option period payments up to $10M over initial 5 year period – $6.8M already paid Sliding scale royalty payments to the Crow of 7.5% - 15% vs. 12.5% federal rate 23 (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.

24 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. Tonnage Opportunities Youngs Creek Project – 287M tons non-reserve coal deposits(1) Big Metal Project – 1.4B in-place tons(2) subject to exercise of options Big Metal Project

25 Cloud Peak Energy Terminal Position 25 25 Westshore Terminal – Existing lowest cost, cape-size port Capesize vessels – deep-water port Amended agreement to eliminate volume obligations and reduce take-or-pay commitments from 2016-2018 If seaborne thermal coal prices rebound exports could resume Proposed Gateway Pacific Terminal (multi-commodity) Capesize vessels – deep-water port We joined as partners with Crow Indian Tribe and SSA Marine to develop the port – August 2015 48 million tonnes of coal at planned full development We have an option for up to 17.6 million tons throughput, depending on ultimate terminal size EIS scope announced July 2013 – EIS process continues Initial opening expected ~2020 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 Initial opening expected ~2020

26 26 Appendix 26

27 2015 Updated Guidance (as of October 23, 2015) Inclusive of intersegment sales Non-GAAP financial measure (3) Excluding federal coal lease payments Coal shipments for our three operated mines(1) 75 – 77 million tons Committed sales with fixed prices Approximately 78 million tons Anticipated realized price of produced coal with fixed prices Approximately $12.73 per ton Adjusted EBITDA(2) $115 – $135 million Net interest expense Approximately $45 million Depreciation, depletion, amortization, and accretion Approximately $95 million Capital expenditures(3) $40 – $50 million Committed federal coal lease payments $69 million – PAID

28 Average Cost of Produced Coal Note: Represents average cost of product sold for produced coal for our three owned and operated mines. $10.23/ton $9.57/ton 2012 2013 2011 $9.12/ton 2014 $10.19/ton Royalties and taxes Labor Repairs, maintenance, and tires Fuel and lubricants Explosives Outside services Other mining costs 2010 $8.57/ton 36% 20% 15% 13% 6% 4% 6% 40% 20% 14% 12% 5% 4% 5% 41% 18% 14% 12% 6% 4% 5% 37% 21% 15% 12% 6% 4% 5% 44% 19% 14% 9% 6% 4% 4%

Major Mine Equipment - 2015 29 29 Confidential (1) Dragline has been moved from Cordero Rojo Mine to Antelope Mine – expected operational ~2016 Antelope Mine 2 draglines (1) 7 shovels 22 830E haul trucks 15 930E haul trucks 18 dozers 3 excavators 6 drills Cordero Rojo Mine 2 draglines 8 shovels 34 830E haul trucks 20 dozers 4 excavators 4 drills Spring Creek Mine 2 draglines 4 shovels 12 830E haul trucks 7 dozers 2 excavators 3 drills

Operating Segments 30 Owned and Operated Mines - mine site sales from our three owned and operated mines Key metrics: Tons sold Realized price per ton Cost of product sold per ton Logistics and Related Activities – delivered sales from our logistics and transportation services business to international and domestic customers Key profitability drivers: Tons delivered Cost of transportation services contracted, including take-or-pay obligations and demurrage charges Benchmark price of Newcastle for international deliveries Newcastle hedging Corporate and Other Results from previously owned 50% interest in Decker Mine (through September 2014) Unallocated corporate costs Brokered coal sales

Owned and Operated Mines 31 Our Owned and Operated Mines segment comprises the results of mine site sales from our three owned and operated mines primarily to our domestic utility customers and also to our Logistics and Related Activities segment. Match production to demand Largely fixed cost business – as coal tons vary, costs per ton will vary Manage variable costs and capital expenditures Reduced use of contractors Matching hiring to market needs Using condition monitoring and maintenance programs to extend equipment lives safely (1) Reconciliation tables for Adjusted EBITDA are included in the Appendix (in millions, except per ton amounts) Q3 2015 Q3 2014 YTD 2015 YTD 2014 Tons sold 20.8 21.5 56.4 62.6 Realized price per ton sold $12.62 $ 13.12 $12.81 $ 13.07 Average cost of product sold per ton $ 9.15 $ 10.44 $ 9.90 $ 10.52 Adjusted EBITDA(1) $ 57.8 $ 43.6 $119.2 $ 126.7

Logistics and Related Activities 32 Our Logistics and Related Activities segment comprises the results of our logistics and transportation services to our domestic and international customers. Lower Newcastle prices resulting in reduced revenue At September 30, 2015, $4.1 million Newcastle derivatives mark-to-market asset in respect to 2015 deliveries (1) Reconciliation tables for Adjusted EBITDA are included in the Appendix (in millions) Q3 2015 Q3 2014 YTD 2015 YTD 2014 Total tons delivered 1.4 1.6 4.5 4.0 Asian export tons 0.9 1.2 3.3 3.2 Revenue $ 44.8 $ 65.6 $162.8 $ 178.8 Realized gains on financial instruments $ 2.8 $ 8.0 $ 10.2 $ 18.9 Total cost of product sold $ 65.2 $ 70.8 $205.0 $ 188.4 Adjusted EBITDA(1) $(19.0) $ 1.4 $(33.8) $ 4.5

33 Statement of Operations Data (in millions, except per share amounts) Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 Revenue $ 301.7 $ 342.3 $ 863.4 $ 982.3 Operating income 17.5 85.8 (25.4) 109.4 Net income (loss) 8.9 91.1 (48.7) 73.3 Earnings per common share Basic $ 0. 15 $ 1.50 $ (0.80) $ 1.21 Diluted $ 0.14 $ 1.49 $ (0.80) $ 1.20

34 Statement of Operations Data (in millions, except per share amounts) Revenue $1,324.0 $ 1,396.1 $ 1,516.8 $ 1,553.7 $ 1,370.8 Operating income 131.8 112.4 241.9 250.5 211.9 Net income 79.0 52.0 173.7 189.8 117.2 Net income attributable to controlling interest $ 79.0 $ 52.0 $ 173.7 $ 189.8 $ 33.7 Earnings per common share attributable to controlling interest Basic $ 1.29 $ 0.86 $ 2.89 $ 3.16 $ 1.06 Diluted $ 1.29 $ 0.85 $ 2.85 $ 3.13 $ 1.06 Year Ended December 31, 2014 2013 2012 2011 2010

35 Balance Sheet Data (in millions) Cash, cash equivalents and investments $ 123.5 $ 168.7 $ 312.3 $ 278.0 $ 479.4 $ 340.1 Restricted cash 65.9 2.0 — — 71.2 182.1 Property, plant and equipment, net 1,514.8 1,589.1 1,654.0 1,678.3 1,350.1 1,008.3 Total assets 1,998.7 2,151.2 2,348.5 2,341.0 2,307.7 1,890.6 Senior notes, net of unamortized discount 490.8 489.7 588.1 586.2 584.5 571.2 Federal coal lease obligations — 64.0 122.9 186.1 288.3 118.3 Asset retirement obligations, net of current portion 167.8 216.2 246.1 239.0 192.7 182.2 Total liabilities 954.5 1,063.3 1,346.5 1,410.0 1,557.3 1,359.4 Total equity 1,044.2 1,087.8 1,002.0 931.0 750.4 531.2 September 30, December 31, 2015 2014 2013 2012 2011 2010

36 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in millions) __________________________ (1) Changes to related deferred taxes are included in income tax expense (benefit). (2) Fair value mark-to-market (gains) losses reflected on the statement of operations. Cash amounts received and paid reflected within operating cash flows. Excludes premiums of $5.8 paid at contract inception during the nine months ended September 30, 2015. Excludes premiums of $9.8 paid at contract inception during the trailing twelve months ended September 30, 2015. Excludes premiums of $1.0 and $4.0 paid in prior periods for contracts settled during the three and nine months ended September 30, 2015, respectively. Excludes premiums of $4.0 paid in prior periods for contracts settled during the trailing twelve months ended September 30, 2015. Net income (loss) $ 8.9 $91.1 $(48.7) $73.3 $(43.0) Interest income — — (0.1) (0.2) (0.2) Interest expense 11.0 12.7 36.3 64.5 48.9 Income tax (benefit) expense (2.2) 40.7 (12.4) 30.7 (8.1) Depreciation and depletion 7.9 25.8 51.7 81.9 81.8 Amortization 0.9 — 2.8 — 2.8 EBITDA 26.4 170.2 29.6 250.2 82.2 Accretion 3.1 3.8 10.0 12.1 13.0 Tax agreement expense (benefit)(1) — (58.6) — (58.6) — Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains)(2) $ 10.2 $(0.5) $17.8 $(16.1) 26.0 Inclusion of cash amounts received (paid)(3)(4)(5)(6)(7) (0.7) 5.0 (1.6) 16.9 6.1 Total derivative financial instruments 9.5 4.5 16.2 0.8 32.1 Gain on sale of Decker Mine interest — (74.3) — (74.3) — Goodwill impairment — — 33.4 — 33.4 Adjusted EBITDA 39.0 $45.7 $89.1 $130.3 160.7 Three Months Ended September 30, Nine Months Ended September 30, Trailing Twelve Months Ended 2015 2014 2015 2014 Sept 30, 2015

37 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in millions) Year Ended December 31, 2014 2013 2012 2011 2010 Net income $ 79.0 $ 52.0 $ 173.7 $ 189.8 $ 117.2 Interest income (0.3) (0.4) (1.1) (0.6) (0.6) Interest expense 77.2 41.7 36.3 33.9 46.9 Income tax expense 34.9 11.6 62.6 11.4 32.0 Depreciation and depletion 112.0 100.5 94.6 87.1 100.0 Amortization — — — — 3.2 EBITDA $ 302.8 $ 205.3 $ 366.1 $ 321.6 $ 298.8 Accretion 15.1 15.3 13.2 12.5 12.5 Tax agreement (benefit) expense(1) (58.6) 10.5 (29.0) 19.9 19.7 Derivative financial instruments: Exclusion of fair value mark-to-market (gains) losses(2) (7.8) (25.6) (22.8) (2.3) — Inclusion of cash amounts received(3)(4) 24.7 13.0 11.2 — — Total derivative financial instruments 16.9 (12.6) (11.5) (2.3) — Gain on sale of Decker Mine interest (74.3) — — — — Expired significant broker contract — — — — (8.2) Adjusted EBITDA $ 201.9 $ 218.6 $ 338.8 $ 351.7 $ 322.7 ______________________________ (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. Cash amounts received and paid reflected within operating cash flows. Excludes premiums of $4.0 paid at contract inception during the year ended December 31, 2014.

38 Reconciliation of Non-GAAP Measures – Adjusted EPS ________________________ Excludes per share impact of $0.01 and $0.04 for premiums paid in prior periods for contracts settled during the three and nine months ended September 30, 2015, respectively . Excludes per share impact of $0.06 for premiums paid at contract inception during the nine months ended September 30, 2015. Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Diluted earnings per common share $0.14 $1.49 $(0.80) $1.20 Tax agreement expense including tax impacts of IPO and Secondary Offering — (0.73) — (0.73) Derivative financial instruments Exclusion of fair value mark-to market (gains) losses $0.11 $(0.01) $0.18 $(0.17) Inclusion of cash amounts received (paid) (1)(2) (0.01) 0.05 (0.02) 0.17 Total derivative financial instruments 0.10 0.05 0.17 0.01 Refinancing transaction Exclusion of cash for early retirement of debt — — — 0.15 Exclusion of non-cash interest for deferred financing fee write-off — — — 0.08 Total refinancing transaction — — — 0.23 Gain on sale of Decker Mine interest — (0.77) — (0.76) Goodwill impairment — — 0.55 — Adjusted EPS $0.24 $0.04 $(0.08) $(0.06) Weighted-average dilutive shares outstanding (in millions) 61.4 61.1 61.0 61.2

39 Diluted earnings per common share attributable to controlling interest $ 1.29 $ 0.85 $ 2.85 $ 3.13 $ 1.06 Tax agreement (benefit) expense including tax impacts of IPO and Secondary Offering (0.73) 0.01 (0.58) (0.63) 0.78 Derivative financial instruments: Exclusion of fair value mark-to-market gains (0.08) (0.27) (0.24) (0.02) — Inclusion of cash amounts received(1) 0.25 0.14 0.12 — — Total derivative financial instruments 0.17 (0.13) (0.12) (0.02) — Refinancing transaction 0.22 — — — — Gain on sale of Decker Mine interest (0.76) — — — — Expired significant broker contract — — — — (0.10) Adjusted EPS $ 0.19 $ 0.73 $ 2.15 $ 2.47 $ 1.74 Weighted-average shares outstanding (in millions) 61.3 61.2 60.9 60.6 31.9 Reconciliation of Non-GAAP Measures – Adjusted EPS Year Ended December 31, 2014 2013 2012 2011 2010 ________________________ (1) Excludes per share impact of $0.04 for premiums paid at contract inception during the year ended December 31, 2014.

Adjusted EBITDA by Segment ________________________ Excludes premiums of $1.0 and $4.0 paid in prior periods for contracts settled during the three and nine months ended September 30, 2014 respectively. Excludes premiums of $5.8 paid at contract inception during the nine months ended September 30, 2015. 40 Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Owned and Operated Mines Adjusted EBITDA $57.8 $43.6 $119.2 $126.7 Depreciation and depletion (7.4) (26.0) (49.9) (80.8) Accretion (2.9) (2.9) (9.5) (8.8) Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) (10.9) (3.5) (13.0) (2.0) Inclusion of cash amounts (received) paid (1) 3.5 2.9 11.8 2.0 Total derivative financial instruments (7.4) (0.6) (1.2) — Goodwill Impairment — — (33.4) — Other (0.3) 0.1 — (0.3) Operating income (loss) 39.8 14.2 25.2 36.8 Logistics and Related Activities Adjusted EBITDA (19.0) 1.4 (33.8) 4.5 Amortization (0.9) — (2.8) — Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) 0.7 4.0 (4.8) 18.1 Inclusion of cash amounts (received) paid (2) (2.8) (8.0) (10.2) (18.9) Total derivative financial instruments (2.1) (4.0) (15.0) (0.8) Other — — 0.1 — Operating income (loss) (22.0) (2.6) (51.5) 3.7 Corporate and Other Adjusted EBITDA 0.5 1.0 5.0 0.6 Depreciation and depletion (0.5) 0.2 (1.8) (1.1) Accretion (0.1) (0.9) (0.4) (3.3) Gain on sale of Decker Mine interest — 74.3 — 74.3 Other — (0.1) (0.4) — Operating income (loss) (0.1) 74.5 2.4 70.5 Eliminations Adjusted EBITDA (0.2) (0.3) (1.3) (1.5) Operating loss (0.2) (0.3) (1.3) (1.5) Consolidated operating income (loss) 17.5 85.8 (25.4) 109.4 Interest income — — 0.1 0.2 Interest expense (11.0) (12.7) (36.3) (64.5) Tax agreement (expense) benefit — 58.6 — 58.6 Other, net 0.3 — 0.2 (0.3) Income tax (expense) benefit 2.2 (40.7) 12.4 (30.7) Earnings from unconsolidated affiliates, net of tax (0.1) — 0.3 0.6 Net income (loss) $8.9 $91.1 $(48.7) $73.3

41 __________________________ Former non-operating interest divested by Cloud Peak Energy in September 2014. Represents only the three company-operated mines. Q3 Q2 Q1 Q4 Q3 Q2 Q1 Year Year Year Year 2015 2015 2015 2014 2014 2014 2014 2014 2013 2012 2011 Tons sold Antelope Mine 9,038 7,660 9,003 9,035 8,239 8,085 8,288 33,647 31,354 34,316 37,075 Cordero Rojo Mine 6,947 4,515 5,913 9,276 8,535 8,551 8,447 39,809 36,670 39,205 39,456 Spring Creek Mine 4,784 3,786 4,785 5,018 4,763 3,953 3,710 17,443 18,009 17,101 19,106 Decker Mine (50% interest)(1) — — — — 422 385 272 1,079 1,519 1,441 1,549 Total tons sold 20,769 15,960 19,701 23,329 21,959 20,974 20,716 86,978 87,552 92,063 97,186 Average realized price per ton sold(2) $12.62 $12.76 $13.05 $12.86 $13.12 $13.08 $13.02 $13.01 $13.08 $13.19 $12.92 Average cost of product sold per ton(2) $ 9.15 $10.75 $10.02 $ 9.32 $10.44 $10.48 $10.63 $10.19 $10.23 $ 9.57 $ 9.12 Other Data (in thousands)

42 42 42 Sulfur Content by Basin 42 Source: SNL U.S. Coal Consumption by Region Region/ Avg Btu Average lbs SO2 PRB/ 8,600 0.5 – 1.0/MMBtu Rocky Mountain 11,500 0.9 – 1.4/MMBtu Illinois Basin 11,500 2.5 – 6.0/MMBtu Appalachia 12,000 1.2 – 7.0/MMBtu Lignite 6,000 1.4 – 4.0/MMBtu Cloud Peak Energy Mines Antelope 8,875 0.50/MMBtu Cordero Rojo 8,425 0.69/MMBtu Spring Creek 9,350 0.73/MMBtu Source: Public record

43 Lease by Application and Modification Source: Cloud Peak Energy management. Note: Acquired tonnage is not classified as reserve until verified with sufficient technical and economic analysis. Maps not to scale. Tonnage amounts are not forecasts of any future production or sales. LBA/LBM Mined Area (2012/2013) Leased Coal LBM - estimated 15.8 million minable tons. Subject to pending challenges by certain environmental organizations against the BLM. Timing of the offer of LBM remains uncertain. Antelope Mine (8875 Btu) LBM LBA II – estimated 198 million minable tons as applied for. Final tract boundaries and tonnage to be determined by the BLM. Lease sale date to be determined by BLM. Timing remains uncertain but likely to be delayed past 2020 due to weak markets. LBM II – estimated 8 million minable tons as applied for. Final tract boundary and tonnage to be determined by the BLM. Timing remains uncertain. LBA II Spring Creek Mine (9350 Btu) LBM ll Cordero Rojo Mine (8425 Btu) Maysdorf II South Tract – 234 million minable tons – as estimated by the BLM (1) (1) The BLM delayed the lease sale on the Maysdorf II South Tract due to current weak markets. Maysdorf II South Tract