Annual Stockholders Meeting May 13, 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, and (3) adjustments to exclude the gain from the sale of our 50% non-operating interest in the Decker Mine, which was sold 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. 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 (“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 (5/8/15) $6.53 Market Capitalization (5/8/15) ~$398 million Total Available Liquidity (3/31/15) $726 million 2014 Revenue $1.3 billion Senior Debt (B1/BB-) (3/31/15) $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 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 0.59 1.02 1.04 1.21 1.31 1.33 1.39 1.39 1.42 1.64 1.96 2.41 2.83 3.16 3.77 4.15 4.38 4.65 4.72 5.63 5.96 6.42 6.73 6.78 7.06 Full Year 2014 MSHA AIFR 0.79

5 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

6 6 6 (1) Low natural gas prices pressures volumes and pricing Low benchmark Newcastle prices Excessive regulations CSAPR impact is unclear Utilities responding to MATS Uncertainty around proposed Clean Power Plan Challenging External Environment

Natural Gas Storage and Pricing Storage Storage levels are up 69% from historic lows last year, but about equal to the 5-year range Inventories could max out this summer Downward pressure on price until oversupply is corrected Pricing and Rig Count 2015 has been consistently below $3.00/MMBtu Even with low prices natural gas production has set record for 24 months 7 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 $2.75 $3.50 $4.25 $5.00 $5.75 $6.50 200 250 300 350 400 450 500 Price ($/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 Potential beneficial impact of $0.05 to $0.10 per ton to 2015 gross revenue price MATS – Mercury and Air Toxics Commenced April 2015 Approximately 10 GWs have been retired since 2012, announcements for a further 26 GWs to retire by 2020. Utilities are evaluating their decisions given volatile natural gas prices, reliability issues and proposed Clean Power Plan Much has been addressed by the scrubbers added by the utilities for the plants remaining in operations Clean Power Plan (CPP) Final rule expected by June 2015, states expected to present compliance plans by June 2016 Numerous questions remain on viability/legality of this proposed regulation 8

(1) Total debt includes high yield notes and capital leases; TTM Adjusted EBITDA of $202M as of 3/31/2015 Liquidity & Obligations (as of March 31, 2015) Strong Balance Sheet (in millions) 9 No Debt Maturities until 2019 (1) Revolver is undrawn. Cash and cash equivalents $186 $500M revolver capacity (Baa3- rating) $500 A/R securitization 40 Available revolver & A/R securitization 540 Total available liquidity $726 8.5% High-Yield Notes due 2019 300 6.375% High-Yield Notes due 2024 200 Senior unsecured debt (B1/BB- rating) $500 Capital leases 9 Total Debt $509 Total Debt / Adjusted EBITDA(1) 2.5x Net Debt / Adjusted EBITDA(1) 1.6x 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

10 Export Strategy Strong International Demand Spring Creek Geographic and Quality Advantages Youngs Creek Project Crow Exploration and Option Agreements Existing Port Capacity at Westshore Secured Options Over Potential Future Port Capacity of up to 25 Million Tons

U.S. And Asia Power Generation Growth 11 Source: EIA and Company Estimates (terawatt hours) 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 US Total Generation US Coal Fired Generation Asia Total Generation Asia Fossil Fuel Generation

Total Asian Coal Generation Additions and Estimated Incremental Import Coal Demand 12 India 100 GW / 110 MT S. Korea 22 GW / 53 MT Japan 6.5 GW / 15 MT Vietnam 16.5 GW / 55 MT Philippines 11 GW / 40 MT Malaysia 5 GW / 17 MT Approximately 150 GWs of new generation planned to come online by 2020 China projects 250 GWs of new capacity by 2020 Source: HDR SALVA and Company Estimates 0 2 4 6 8 10 12 14 16 2015 2016 2017 2018 2019 2020 (GWs) Asia – Estimated Incremental Coal - Fired Capacity SE Asia - Some Imports SE Asia - 100% Imports North Asia - 100% Imports

Spring Creek Complex – Quality Advantage and Export Distance 13 13 4770-4850 4544 Average Source: SNL, Wood Mackenzie, Company estimates Higher Quality Product Spring Creek Complex 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 in the international market valued for its consistent quality Indonesian coal (primary market competitor) is declining in quality

14 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

15 Cloud Peak Energy Terminal Position 15 15 Westshore Terminal – Existing lowest cost, cape-size port Capesize vessels – deep-water port 2012 expanded to 33 million tonnes total annual capacity In 2014, we 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 5.2 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 ~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

16 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

Annual Stockholders Meeting May 13, 2015

18 18 Appendix 18

19 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 20 20 Confidential; Non-Public Information; Not for Disclosure 20 (1) Dragline is moving from Cordero Rojo Mine to Antelope Mine – expected operational ~2016 Antelope Mine 1 dragline(1) 8 shovels 22 830E haul trucks 15 930E haul trucks 16 dozers 3 excavators Cordero Rojo Mine 2 draglines 7 shovels 32 830E haul trucks 20 dozers 4 excavators Spring Creek Mine 2 draglines 4 shovels 12 830E haul trucks 8 dozers 2 excavators

Operating Segments 21 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 previously owned 50% interest in Decker Mine (through September 2014) Unallocated corporate costs Brokered coal sales

Owned and Operated Mines 22 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) Q1 2015 Q1 2014 Full Year 2014 Full Year 2013 Tons sold 19.7 20.4 85.9 86.0 Realized price per ton sold $ 13.05 $ 13.02 $ 13.01 $ 13.08 Average cost of product sold per ton $ 10.02 $ 10.63 $ 10.19 $ 10.23 Adjusted EBITDA(1) $ 44.3 $ 41.2 $ 197.0 $ 202.0

Logistics and Related Activities 23 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 March 31, 2015, $12.4 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) Q1 2015 Q1 2014 Full Year 2014 Full Year 2013 Total tons delivered 1.7 1.2 5.1 5.5 Asian export tons 1.4 1.0 4.0 4.7 Revenue $ 69.4 $ 58.5 $ 224.9 $ 265.9 Realized gains on financial instruments $ 3.6 $ 3.4 $ 27.0 $ 13.2 Total cost of product sold $ 80.8 $ 59.7 $ 242.0 $ 261.2 Adjusted EBITDA(1) $ (8.3) $ 0.4 $ 4.1 $ 11.4

24 Statement of Operations Data (in millions, except per share amounts) Three Months Ended March 31, 2015 2014 Revenue $ 317.6 $ 319.1 Operating income 8.0 16.1 Net income (loss) (4.7) (15.6) Earnings per common share Basic $ (0.08) $ (0.26) Diluted $ (0.08) $ (0.26)

25 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

26 Balance Sheet Data (in millions) Cash, cash equivalents and investments $ 186.2 $ 168.7 $ 312.3 $ 278.0 $ 479.4 $ 340.1 Restricted cash 6.5 2.0 — — 71.2 182.1 Property, plant and equipment, net 1,557.3 1,589.1 1,654.0 1,678.3 1,350.1 1,008.3 Total assets 2,143.6 2,159.9 2,357.4 2,351.3 2,319.3 1,915.1 Senior notes, net of unamortized discount 498.5 498.5 597.0 596.5 596.1 595.7 Federal coal lease obligations 64.0 64.0 122.9 186.1 288.3 118.3 Asset retirement obligations, net of current portion 205.9 216.2 246.1 239.0 192.7 182.2 Total liabilities 1,060.2 1,072.1 1,355.4 1,420.3 1,568.9 1,383.9 Total equity 1,083.4 1,087.8 1,002.0 931.0 750.4 531.2 March 31, December 31, 2015 2014 2013 2012 2011 2010

27 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 Excludes premiums paid in prior periods for contracts settled during the period $ 2.0 $ — $ 2.0 Net income (loss) $ (4.7) $ (15.6) $ 89.9 Interest income — (0.1) (0.2) Interest expense 12.7 38.0 51.8 Income tax expense (0.3) (6.5) 41.1 Depreciation and depletion 24.5 26.9 109.6 Amortization 0.9 — 0.9 EBITDA $ 33.1 $ 42.7 $ 293.1 Accretion 3.5 4.1 14.6 Tax agreement (benefit) expense(1) — — (58.6) Derivative financial instruments: Exclusion of fair value mark-to-market losses (gains)(2) $4.8 $(12.7) $9.7 Inclusion of cash amounts received (paid)(3)(4)(5) (2.0) 5.3 17.4 Total derivative financial instruments 2.8 7.4 27.1 Gain on sale of Decker Mine interest — — (74.2) Adjusted EBITDA $ 39.4 $ 39.3 $ 202.0 Three Months Ended March 31, Trailing Twelve Months Ended March 31, 2015 2015 2014

28 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 March 31, 2015 2014 29 Reconciliation of Non-GAAP Measures – Adjusted EPS Diluted earnings per common share $ 0.08 $ (0.26) Tax agreement expense including tax impacts of IPO and Secondary Offering — — Derivative financial instruments Exclusion of fair value mark-to market (gains) losses $ 0.05 $ (0.13) Inclusion of cash amounts received (paid)(1) (0.02) 0.06 Total derivative financial instruments 0.03 (0.07) Refinancing transaction Exclusion of cash for early retirement of debt — 0.15 Exclusion of non-cash interest for deferred financing fee write-off — 0.07 Total refinancing transaction — 0.22 Gain on sale of Decker Mine interest — — Adjusted EPS $ (0.05) $ (0.11) Weighted-average dilutive shares outstanding (in millions) 60.9 60.7 ________________________ Excludes per share impact of premiums paid at contract inception during the period $ 0.02 $ —

30 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 March 31, 2015 2014 Owned and Operated Mines Adjusted EBITDA $ 44.3 $ 41.2 Depreciation and depletion (23.9) (26.4) Accretion (3.4) (3.0) Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) $ (6.8) $ 2.1 Inclusion of cash amounts (received) paid 5.6 (1.8) Total derivative financial instruments (1.2) 0.3 Other 0.4 (0.1) Operating income 16.2 12.0 Logistics and Related Activities Adjusted EBITDA (8.3) (0.4) Amortization (0.9) — Derivative financial instruments: Exclusion of fair value mark-to-market gains (losses) 2.0 10.6 Inclusion of cash amounts (received) paid (3.6) (3.4) Total derivative financial instruments (1.6) 7.2 Other (0.1) — Operating income (loss) (10.9) 7.5 Corporate and Other Adjusted EBITDA 4.1 (1.9) Depreciation and depletion (0.6) (0.5) Accretion (0.1) (1.2) Other (0.1) 0.5 Operating income (loss) 3.3 (3.1) Eliminations Adjusted EBITDA (0.7) (0.4) Operating income (loss) (0.7) (0.4) Consolidated operating income 8.0 16.1 Interest income — 0.1 Interest (expense) benefit (12.7) (38.0) Other, net (0.3) (0.5) Income tax expense 0.3 6.5 Earnings from unconsolidated affiliates, net of tax — 0.1 Net income (loss) $ (4.7) $ (15.6) ________________________ Excludes premiums paid in prior periods for contracts settled during the period $ 2.0 $ — 31

32 __________________________ 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 Q3 Q2 Q1 Year Year Year Year 2015 2014 2014 2014 2014 2013 2013 2013 2013 2014 2013 2012 2011 Tons sold Antelope Mine 9,003 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 5,913 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 4,785 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)(1) — — 422 385 272 483 489 382 165 1,079 1,519 1,441 1,549 Total tons sold 19,701 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(2) $13.05 $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(2) $10.02 $ 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)