Form 8-K CLOUD PEAK ENERGY INC. For: May 01

Delaware

001-34547

26-3088162

(State or other Jurisdiction of
Incorporation)

(Commission File Number)

(IRS Employer Identification No.)

505 S. Gillette Ave., Gillette, Wyoming

82716

(Address of Principal Executive Offices)

(Zip Code)

INVESTOR Presentation May 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 (4/28/15) $6.05 Market Capitalization (4/28/15) ~$369 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 (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

1 1 1 5 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

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) 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

7 Continued Execution of Consistent Business Strategy Optimizing Near-Term Exports Our capacity at the fully-utilized Westshore port capitalizes on Spring Creek’s export advantages with no significant mine development capital expenditure required Strengthening Asian marketing capability via expanding sales into South Korea, Taiwan, and Japan Secure Long-Term Export Opportunities Option for up to 7.7 million tons export capacity at proposed Millennium Bulk Terminal Option for up to 17.6 million tons export capacity at proposed Gateway Pacific Terminal Extensive coal position at Spring Creek Complex with Youngs Creek and Crow projects; offering multiple development options Solid Domestic Business in Best Positioned Basin Large reserve position and no LBA obligations beyond 2015 Low cost and low capex surface operations Stable customer base, supported by contracted sales strategy Active Balance Sheet Management (as of March 31, 2015) Long-dated maturities (earliest 2019) Available liquidity of $726.1 million Net debt of $322.4 million Cash balance of $186.2 million

(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) 8 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

9 9 9 (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 65% 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 23 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 $2.75 $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 11

Announced Coal Plant Retirements Some forecasts have retirements up to 50 GWs Retirements will mostly be old, smaller and less efficient plants – where capital costs of environmental equipment is not economical Retirement total underpinned by weak demand and natural gas pricing Total coal demand lost estimated between 20 to 50 million tons (PRB 10 to 20 Mt) Some PRB plants will close but expected to be offset by increased utilization at other plants Capacity to be closed ~ 26GWs 12 Source: SNL

Responding to Market Conditions 13 Reducing production and capacity at Cordero Rojo Mine from 38 Mtpa to approximately 24 Mtpa in 2015 Locked in lower 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 $45 - $55 $64 $133 $129 $79 $69 $69 $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 $4.54 $4.88 $4.97 $4.99 $5.05 $8.57 $9.12 $9.57 $10.23 $10.19 $0 $2 $4 $6 $8 $10 $12 2010 2011 2012 2013 2014 (cash cost per ton) Core Cash Cost (1) Royalties/Taxes/Fuel/Lubricants 90.5 90.9 86.2 81.3 81.9 69.8 - 73.8 3.3 4.7 4.4 4.7 4.5 5.2 93.7 95.6 90.6 86.0 85.9 75.0 - 79.0 60 65 70 75 80 85 90 95 100 2010 2011 2012 2013 2014 2015E (in millions) North American Deliveries Asian Exports

14 2015 Updated Guidance Inclusive of intersegment sales Non-GAAP financial measure (3) Excluding federal coal lease payments Coal shipments for our three operated mines(1) 75 – 79 million tons Committed sales with fixed prices Approximately 73 million tons Anticipated realized price of produced coal with fixed prices Approximately $12.88 per ton Adjusted EBITDA(2) $110 – $150 million Net interest expense Approximately $46 million Depreciation, depletion and accretion $115 – $125 million Capital expenditures(3) $45 – $55 million Committed federal coal lease payments $69 million

15 2015 Adjusted EBITDA Offsets 15 15 Lower WTI Prices Result in Operational Savings in Diesel Expenditures For 2015, have locked in WTI/bbl of ~$64 with approximate savings of $24M from 2014: ~55% of our diesel fuel usage hedged with a collar ~45% fixed with forward instruments For our 2016 forecasted diesel fuel costs: Hedged 50% using forward instruments WTI/bbl ~$63 Hedged 50% using collars ranging from $54-$73 WTI/bbl Impact of Lower Newcastle Benchmark Pricing Has Been Reduced in 2015 Pricing for our delivered export sales into Asian market has been more resilient than other seaborne thermal coal Additional recent reduction in 2015 shipments (from ~5.8Mt to ~5.2Mt) Lower rail fuel surcharges from the BNSF due to current depressed oil prices Middle of 2015 Adjusted EBITDA guidance assumes export pricing in the second half of 2015 to be at similar levels to our average year-to-date contracted pricing

16 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

17 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

18 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 and chlorine 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

19 Continued Forward Sales Strategy 2015 has 73 million tons committed and fixed at weighted-average price of $12.88/ton 2016 has 41 million tons committed and fixed at weighted-average price of $13.61/ton Total Committed Tons (as of 4/20/15) (tons in millions) 73 41 6 9 79 50 2015E 2016E Committed tons with variable pricing Committed tons with fixed pricing

20 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

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

431 386 260 354 922 3,650 605 116 89 88 196 144 400-999 million tonnes 1,000+ million tonnes >400 million tonnes Global Coal Production Source: BP Statistical Review of World Energy June 2013 World Coal Production Totaled 8 Billion Tonnes in 2012 12.5% of world coal production is exported to countries that lack natural resources 200Mt 22 800Mt

U.S. And Asia Power Generation Growth 23 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

Asia’s Strong Demand Requires Increasing Thermal Imports 24 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 30 39 46 52 58 73 90 120 130 170 208 0 50 100 150 200 250 300 (million tonnes ) Thermal Met 350 400 450 500 550 600 650 700 750 2010 2015 2020 2025 2030 (quadrillion btu) ROW China India 3% 1% 3.5% CAGR (68) (46) (25) (5) (9) 103 146 175 279 320 286 -70 5 80 155 230 305 (million tonnes) Thermal & Lignite Other Met

Total Asian Coal Generation Additions and Estimated Incremental Import Coal Demand 25 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

26 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 GWs of coal-fired generation is estimated to increase coal imports from 80 Mtpa to 120 Mtpa Dangjing Power Station in Korea owned by Korea East West Power Source: HDR SALVA 0 20 40 60 80 100 120 140 160 (million tonnes) Annual Consumption

28 Source: Global Coal, HDR Salva, Company estimates Newcastle prices remain muted International markets still oversupplied Strong US$ helps non-U.S. producers At AUD = ~0.80, the profitability of Australian thermal coal remains challenged Analysts estimate at $70 Newcastle, nearly 40% of Australian thermal coal production is at negative margins Indonesian exports down 3.4% in 2014 Unprofitable mines closing Strong domestic demand growth Newcastle Price Curve Commodity Pricing Environment Is Cyclical $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200

29 Executing on our Export Strategy Strong International Demand Spring Creek Geographic and Quality Advantages Youngs Creek Project Crow Exploration and Option Agreements Existing Port Capacity at Westshore Other Asian countries seeking security and diversity of supply Australian and Indonesian supply being hit by increasing capital and operating costs and regulatory uncertainty U.S. PRB coal no longer at top of cost curve Additional coal-fired plants being built Geographic advantage of Spring Creek Complex, closer to ports Quality advantage compares well with seaborne competitive coal 287 million tons non-reserve coal deposits (1) 38,800 acres strategic land Multiple development options with Spring Creek Complex 1.4 billion in-place tons (2) Exploration agreement Option to lease agreement Multiple development options with Spring Creek Complex BIA approved agreements June 2013 Extended Westshore contract to 2024 Increased committed capacity from 2.75 million tons to ~5.2 million tons (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. Secured Options Over Potential Future Port Capacity of up to 25 Million Tons Gateway Pacific option for up to 17.6 million tons Millennium Bulk Terminal - up to 7.7 million tons

Spring Creek Complex – Quality Advantage and Export Distance 5 30 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

Key Projects 31 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 Crow Indian Tribe deposits Crow 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 – $5.25M already paid Sliding scale royalty payments to the Crow of 7.5% - 15% vs. 12.5% federal rate 31 (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.

32 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

33 Cloud Peak Energy Terminal Position 33 33 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

Exports Seen as Way of Life in the Pacific-Northwest Asia widely recognized as important strategic economic partner Asian-market realities (needs) resonate Asia will electrify rapidly and robustly Non-coal energy sources are insufficient to fuel growth Coal imports will be required U.S. west coast ports can provide Asia with an economically-viable new source of coal To deny Asia access to U.S. coal is to: Unnecessarily increase the cost of electricity to Asian citizens Unnecessarily increase the cost of goods and services produced/exported by Asia Deny Asia access to the same cheap energy advanced nations enjoyed during their development periods Ignore the reality that this market will use coal obstruction by denying ports from the U.S. will have no impact 34

35 Improving “Pro-Coal” Environment 35 35 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

36 36 Appendix 36

37 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 38 38 Confidential; Non-Public Information; Not for Disclosure 38 (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 39 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 40 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 41 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

42 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)

43 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

44 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

45 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

46 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 47 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 $ —

48 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 $ — 49

50 __________________________ 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)

51 51 51 Sulfur Content by Basin 51 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

52 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