Scotia Howard Weil Energy Conference Colin Marshall, President & CEO Cloud Peak Energy March 25, 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 to Adjusted EBITDA and EPS (as defined below) to Adjusted EPS 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 updates to the tax agreement liability, including tax impacts of the IPO and Secondary Offering and the termination of the TRA 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 the gain from the sale of our 50% non-operating interest in the Decker Mine, and (4) adjustments to exclude a significant broker contract that expired in the first quarter of 2010. 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 a reconciliation to any forecasted GAAP measures. Adjusted EPS represents diluted earnings (loss) per common share attributable to controlling interest (“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 (3/19/15) $6.24 Market Capitalization (3/19/15) ~$380 million Total Available Liquidity (12/31/14) $720 million 2014 Revenue $1.3 billion Senior Debt (B1/BB-) (12/31/14) $500 million Market and Financial Overview Company Overview

3 Low-Risk Surface Operations Highly productive, non-unionized workforce at all company-operated mines 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 4 Top Coal Producing Companies - 2013 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

Extensive Coal Reserves and Significant Projects 5 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 5 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) 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. Crow Project (2) (subject to exercise of options) 1,380M tons Additional Coal 1.4B Tons

6 Continued Execution of Consistent Business Strategy Solid Domestic Business in Best Positioned Basin Balance Sheet Management Secure Long-Term Export Opportunities Optimizing Near-Term Exports

7 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

8 High Quality Customer Base Thousands of Tons 7,500 - 15,000 0 - 1,500 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

9 PRB – Forecast Growing Share of Smaller Pie CAPP coal production declining High operating costs Difficult regulatory environment Not economical for many customers relative to natural gas Source: Company estimates and industry sources PRB, ILB and natural gas are replacing CAPP production PRB coal has low sulfur and lower Btu ILB has higher Btu and higher sulfur 2007 2014 2020E Domestic Thermal Consumption Total 950Mt PRB 427Mt Total 860Mt PRB 410Mt Total 775Mt PRB 418Mt Overall U.S. coal burn is expected to decline ~18% or 175 million tons from 2007 to 2020 PRB burn is expected to remain relatively stable as it substitutes for declines in other basins

10 10 10 (1) Low natural gas prices Uneven rail performance Excessive regulations CSAPR impact is unclear Utilities responding to MATS Uncertainty around Clean Power Plan Challenging External Environment

Responding to Market Conditions 11 Reducing production and capacity at Cordero Rojo Mine from 38 Mtpa to approximately 28 Mtpa Locked in lower diesel costs for 2015 Asset management efforts control maintenance costs 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

12 Continued Forward Sales Strategy 2015 has 72 million tons committed and fixed at weighted-average price of $12.92/ton 2016 has 38 million tons committed and fixed at weighted-average price of $13.75/ton Total Committed Tons (as of 1/30/15) (tons in millions)

13 Active Balance Sheet Controls (as of December 31, 2014) 2014 Balance Sheet Transactions: Reduced long-term debt to $500 million from $600 million Decker divestment reduced Asset Retirement Obligations by $72 million and released $67 million of reclamation bonds Buy-out of Tax Receivable Agreement released $103 million undiscounted liability with quick payback Amended Revolver to relax covenants Solid Total Available Liquidity – $720 million No Near-Term Debt Maturity Until 2019 Total Debt/Adjusted EBITDA(1) – 2.5x Net Debt/Adjusted EBITDA(1) – 1.7x (1) Total debt includes high yield notes and capital leases: TTM Adjusted EBITDA of $201.9M as of 12/31/2014

14 Export Strategy Strong International Demand Spring Creek Geographic and Quality Advantages Youngs Creek Asset Acquisition Crow Exploration and Option Agreements Increased Existing Port Capacity Secured Options Over Potential Future Port Capacity of up to 23 Million Tonnes

15 Increasing International Demand Requires PRB Exports 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 2007 2014 2020E Source: EIA and internal estimates

U.S. And Asia Power Generation Growth 16 Source: EIA and Company Estimates

Asia’s Strong Demand Requires Increasing Thermal Imports 17 China Net Imports Coal fuels 41% of global electricity generation Coal reserves total 861 billion tonnes, 109 years at current production (World Energy Council) Coal is the lowest-cost energy source for many rapidly growing countries Source: Fenwel Energy Consulting and Industry Reports Source: AIE India Net Imports Estimated World Energy Consumption Quotes

18 South Korea Is Increasing Coal Use Coal consumption increased by 55% between 2005 and 2012, driven by growing electricity demand By 2018, an additional 12 GW of coal-fired generation is estimated to increase coal imports from 80 Mtpa to 120 Mtpa New coal plants in Japan, Taiwan, and Vietnam are expected to add ~100 Mtpa of demand by 2025 Dangjing Power Station in Korea owned by Korea East West Power Source: HDR | SALVA

Spring Creek Complex – Export Distance and Quality Advantage 19 4770-4850 4544 Average Source: SNL, Wood Mackenzie, Company estimates Higher Quality Product Location Spring Creek Complex is up to ~200 miles closer to export terminals than SPRB mines Fewer bottlenecks in NPRB Quality Spring Creek Mine is a premium subbituminous coal in the international market Indonesian coal (primary market competitor) is declining in quality Spring Creek Complex Up To 200 Miles Closer Kcal/kg NAR

20 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) Crow Project – 1.4B in-place tons(2) subject to exercise of options

21 Cloud Peak Energy Terminal Position 21 21 Westshore Terminal – Existing lowest cost, cape-size port Capesize vessels – deep-water port 2012 expanded to 33 million tonnes total annual capacity We have just increased the term and capacity of our ten-year throughput agreement to 6.6 million tons, increasing to 7.2 million tons in 2019 We expect to ship approximately 6 million tons in 2015 Proposed Gateway Pacific Terminal (multi-commodity) Capesize vessels – deep-water port 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 ~2019/2020 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 ~2019/2020

22 Improving “Pro-Coal” Environment 22 22 Northwest Clean Air Agency (an independent government agency) (March 2014) Results of 20 months of air monitoring conducted near a rail crossing in Bellingham, Washington showed there were no days when dust was at levels that would be expected to cause issues for people even those who are highly sensitive to respiratory problems Poll Finds Coal Export Supporters Outnumber Opponents for Pacific Northwest (July 2014) “It’s trade-related jobs in Washington State that are at stake here.” Kathryn Stenger with the Alliance for Northwest Jobs and Exports Cloud Peak Energy is working with others to support the expansion of existing ports and the construction of new ports as well as countering the opposition to these opportunities

23 Source: Global Coal, HDR | Salva, Company estimates Analysts estimate at $70 Newcastle, nearly 40% of Australian thermal coal production is at negative margins At AUD = ~0.80, the profitability of Australian thermal coal remains challenged Newcastle prices remain muted Strong US$ strains PRB pricing International markets still oversupplied Newcastle Price Curve Commodity Pricing Environment Is Cyclical

24 Continued Execution of Consistent Business Strategy Solid Domestic Business in Best Positioned Basin Balance Sheet Management Secure Long-Term Export Opportunities Optimizing Near-Term Exports

Scotia Howard Weil Energy Conference Colin Marshall, President & CEO Cloud Peak Energy March 25, 2015

26 26 Appendix 26

27 Average Cost of Produced Coal * Represents average cost of product sold for produced coal for our three owned and operated mines. Owned and Operated Mines* $10.23/ton Owned and Operated Mines* $9.57/ton 2012 2013 2011 Owned and Operated Mines* $9.12/ton 2014 Owned and Operated Mines* $10.19/ton Royalties and taxes Labor Repairs, maintenance, and tires Fuel and lubricants Explosives Outside services Other mining costs

Operating Segments 28 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 Benchmark price of Newcastle for international deliveries Newcastle hedging Corporate and Other Results from 50% interest in Decker mine Unallocated corporate costs

Owned and Operated Mines 29 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) Q4 2014 Q4 2013 Full Year 2014 Full Year 2013 Tons sold 23.3 21.7 85.9 86.0 Realized price per ton sold $ 12.86 $ 13.16 $ 13.01 $ 13.08 Average cost of product sold per ton $ 9.32 $ 10.04 $ 10.19 $ 10.23 Adjusted EBITDA(1) $ 70.2 $ 56.2 $ 197.0 $ 202.0

Logistics and Related Activities 30 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 December 31, 2014, $14.8 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) Q4 2014 Q4 2013 Full Year 2014 Full Year 2013 Total tons delivered 1.2 1.3 5.1 5.5 Asian export tons 0.8 1.1 4.0 4.7 Revenue $ 46.1 $ 62.7 $ 224.9 $ 265.9 Realized gains on financial instruments $ 8.1 $ 6.9 $ 27.0 $ 13.2 Cost of product sold (delivered tons) $ 53.6 $ 63.7 $ 242.0 $ 261.2 Adjusted EBITDA(1) $ (0.4) $ 5.2 $ 4.1 $ 11.4

31 Statement of Operations Data (in millions, except per share amounts) Three Months Ended December 31, Year Ended December 31, 2014 2013 2014 2013 Revenue $ 341.8 $ 353.2 $ 1,324.0 $ 1,396.1 Operating income 22.4 26.9 131.8 112.4 Net income (loss) 5.7 13.9 79.0 52.0 Earnings per common share Basic $ 0.09 $ 0.23 $ 1.30 $ 0.86 Diluted $ 0.09 $ 0.23 $ 1.29 $ 0.85

32 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 $ 1.30 $ 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

33 Balance Sheet Data (in millions) Cash, cash equivalents and investments $ 168.7 $ 312.3 $ 278.0 $ 479.4 $ 340.1 Restricted cash 2.0 — — 71.2 182.1 Property, plant and equipment, net 1,589.1 1,654.0 1,678.3 1,350.1 1,008.3 Total assets 2,159.9 2,357.4 2,351.3 2,319.3 1,915.1 Senior notes, net of unamortized discount 498.5 597.0 596.5 596.1 595.7 Federal coal lease obligations 64.0 122.9 186.1 288.3 118.3 Asset retirement obligations, net of current portion 216.2 246.1 239.0 192.7 182.2 Total liabilities 1,072.1 1,355.4 1,420.3 1,568.9 1,383.9 Total equity 1,087.8 1,002.0 931.0 750.4 531.2 December 31, 2014 2013 2012 2011 2010

34 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in millions) __________________________ (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 paid at contract inception during the period $ 4.0 $ — $ 4.0 $ — Net income (loss) $ 5.7 $ 13.9 $ 79.0 $ 52.0 Interest income — (0.1) (0.3) (0.4) Interest expense 12.7 11.8 77.2 41.7 Income tax expense 4.2 1.1 34.9 11.6 Depreciation and depletion 30.1 24.9 112.0 100.5 EBITDA $ 52.6 $ 51.7 $ 302.8 $ 205.3 Accretion 3.1 3.1 15.1 15.3 Tax agreement (benefit) expense(1) — — (58.6) 10.5 Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains)(2) $8.2 $0.0 $(7.8) $(25.6) Inclusion of cash amounts received (paid)(3)(4) 7.8 7.3 24.7 13.0 Total derivative financial instruments 16.0 7.3 16.9 (12.6) Gain on sale of Decker Mine interest — — (74.3) — Expired significant broker contract — — — — Adjusted EBITDA $ 71.6 $ 62.1 $ 201.9 $ 218.6 Three Months Ended December 31, Year Ended December 31, 2014 2013 2014 2013

35 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 paid at contract inception during the period $ 4.0 $ — $ — $ — $ —

Three Months Ended December 31, Year Ended December 31, 2014 2013 2014 2013 36 Reconciliation of Non-GAAP Measures – Adjusted EPS Diluted earnings per common share $ 0.09 $ 0.23 $ 1.29 $ 0.85 Tax agreement expense including tax impacts of IPO and Secondary Offering — — (0.73) 0.01 Derivative financial instruments Exclusion of fair value mark-to market (gains) losses $0.09 $ — $(0.08) $(0.27) Inclusion of cash amounts received (paid)(1) 0.08 0.08 0.25 0.14 Total derivative financial instruments 0.17 0.08 (0.17) (0.13) Refinancing transaction Exclusion of cash for early retirement of debt — — 0.14 — Exclusion of non-cash interest for deferred financing fee write-off — — 0.08 — Total refinancing transaction — — 0.22 — Gain on sale of Decker Mine interest — — (0.76) — Expired significant broker contract — — — — Adjusted EPS $ 0.26 $ 0.34 $ 0.19 $ 0.73 Weighted-average dilutive shares outstanding (in millions) 61.3 61.4 61.3 61.2 ________________________ Excludes per share impact of premiums paid at contract inception during the period $ 0.04 $ — $ 0.04 $ —

37 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 premiums paid at contract inception during the period $ 0.04 $ — $ — $ — $ —

Adjusted EBITDA by Segment Three Months Ended December 31, Year Ended December 31, 2014 2013 2014 2013 Owned and Operated Mines Adjusted EBITDA $ 70.2 $ 56.2 $ 197.0 $ 202.0 Depreciation and depletion (26.8) (26.7) (107.6) (98.9) Accretion (2.9) (2.6) (11.7) (11.0) Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) $ (11.5) $ 0.1 $ (13.6) $ (0.3) Inclusion of cash amounts (received) paid 0.4 (0.4) 2.3 0.3 Total derivative financial instruments (11.1) (0.3) (11.3) — Other (0.1) (0.1) (0.3) (2.6) Operating income 29.3 26.5 66.1 89.5 Logistics and Related Activities Adjusted EBITDA (0.4) 5.2 4.1 11.4 Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) 3.3 (0.2) 21.4 26.0 Inclusion of cash amounts (received) paid (8.1) (6.9) (27.0) (13.2) Total derivative financial instruments (4.8) (7.1) (5.6) 12.8 Other — — (0.1) (0.1) Operating income (loss) (5.2) (1.8) (1.6) 24.1 Corporate and Other Adjusted EBITDA 1.5 1.1 2.1 6.0 Depreciation and depletion (3.3) 1.8 (4.5) (1.6) Accretion (0.2) (0.5) (3.4) (4.3) Gain on sale of Decker Mine interest — — 74.3 — Other — 0.3 — (0.5) Operating income (loss) (2.0) 2.7 68.5 (0.4) Eliminations Adjusted EBITDA 0.3 (0.5) (1.2) (0.8) Operating income (loss) 0.3 (0.5) (1.2) (0.8) Consolidated operating income 22.4 26.9 131.8 112.4 Interest income — 0.1 0.3 0.4 Interest (expense) benefit (12.7) (11.8) (77.2) (41.7) Tax agreement (expense) benefit — — 58.6 (10.5) Other, net 0.1 (0.2) (0.2) 2.4 Income tax expense (4.2) (1.1) (34.9) (11.6) Earnings from unconsolidated affiliates, net of tax — — 0.6 0.6 Net income (loss) $ 5.7 $ 13.9 $ 79.0 $ 52.0 ________________________ Excludes premiums paid at contract inception during the period $ 4.0 $ — $ 4.0 $ — 38

39 __________________________ (1) Represents only the three company-operated mines. Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Year Year Year Year 2014 2014 2014 2014 2013 2013 2013 2013 2014 2013 2012 2011 Tons sold Antelope Mine 9,035 8,239 8,085 8,288 7,945 7,952 7,371 8,086 33,647 31,354 34,316 37,075 Cordero Rojo Mine 9,276 8,535 8,551 8,447 9,027 10,054 8,359 9,231 39,809 36,670 39,205 39,456 Spring Creek Mine 5,018 4,763 3,953 3,710 4,765 5,140 4,362 3,742 17,443 18,009 17,101 19,106 Decker Mine (50% interest) — 422 385 272 483 489 382 165 1,079 1,519 1,441 1,549 Total tons sold 23,329 21,959 20,974 20,716 22,220 23,635 20,473 21,224 86,978 87,552 92,063 97,186 Average realized price per ton sold (in millions)(1) $12.86 $13.12 $13.08 $13.02 $13.16 $13.03 $13.05 $13.09 13.01 $13.08 $13.19 $12.92 Average cost of product sold per ton(1) $ 9.32 $10.44 $10.48 $10.63 $10.04 $ 9.78 $10.81 $10.37 10.19 $10.23 $ 9.57 $ 9.12 Other Data (in thousands)

40 40 40 Sulfur Content by Basin 40 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 0.52/mmBtu Cordero Rojo 8,425 0.69/mmBtu Spring Creek 9,350 0.73/mmBtu Source: Public record

41 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. LBM II – estimated 8 million minable tons as applied for. Final tract boundary and tonnage to be determined by the BLM. Lease sale date for LBA II and lease offering of the LBM II, to be determined by BLM, are anticipated in 2017 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 is expecting to delay any future lease sales on the Maysdorf II South Tract due to current weak markets. Maysdorf II South Tract