Exhibit 99.1

Investor Presentation May 2011

1 Cloud Peak Energy Inc. Financial Data Cloud Peak Energy Inc. is the sole owner of Cloud Peak Energy Resources LLC. Unless expressly stated otherwise in this presentation, all financial data included herein is consolidated financial data of Cloud Peak Energy Inc. 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 or beliefs, as well as 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 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 current reports on 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 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., or GAAP. A quantitative reconciliation of net income or net income from continuing operations (as applicable) to Adjusted EBITDA and EPS (as defined below) to Adjusted EPS is found in the tables accompanying this presentation. EBITDA represents net income or net income from continuing operations (as applicable) before (1) interest income (expense) net, (2) income tax provision, (3) depreciation and depletion, (4) amortization, and (5) accretion. Adjusted EBITDA represents EBITDA as further adjusted to exclude specifically identified items that management believes do not directly reflect our core operations. The specifically identified items are the income statement impacts, as applicable, of: (1) the Tax Receivable Agreement and (2) our significant broker contract that expired in the first quarter of 2010. Adjusted EPS represents diluted earnings (loss) per share attributable to controlling interest or diluted earnings (loss) per share attributable to controlling interest from continuing operations (as applicable) (“EPS”), adjusted to exclude the estimated per share impact of the same specifically identified items used to calculate Adjusted EBITDA and described above. 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 or other GAAP financial measures. 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 drastically 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, 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, 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 Cloud Peak Energy Profile NYSE: CLD (4/25/11) $20.29 Market Capitalization (4/25/11) ~$1.2 billion Total Available Liquidity (3/31/11) $785 million 2010 Revenue $1.4 billion Senior Debt (B1/BB-) $600 million Market and Financial Overview Company Overview Third largest U.S. coal producer 2010 coal production of 93.8 million tons 2010 proven & probable reserves of 970 million tons Only pure-play PRB coal company Headquartered in Gillette, WY Employs approximately 1,550 people $119 $160 $207 $321 $323 $335 0 50 100 150 200 250 300 350 2006 2007 2008 2009 2010 TTM (in millions) Adjusted EBITDA1 1 Reconciliation tables for Adjusted EBITDA are included in the Appendix Q1 11

First Quarter 2011 3 Revenues up 15% to $357 million Adjusted EBITDA1 up 18% to $82.6 million Asian exports up 12% to 887,000 tons Cash flow from operations $80.2 million Continued excellent safety record AIFR 0.28 vs. 0.58 FY10 1 Reconciliation tables for Adjusted EBITDA are included in the Appendix.

4 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 No Surface Mining Control & Reclamation Act environmental violations since October 2002

5 0.21 0.50 0.58 0.93 1.21 1.34 1.68 2.07 2.18 2.46 3.35 3.37 3.43 3.56 3.62 3.86 3.99 4.04 4.12 4.95 5.59 5.86 6.15 6.57 7.90 Top 25 Coal Producing Companies - 2010 Preliminary Incident Rates (MSHA) Source: MSHA. Note: Total Incident Rate = (total number of employee incidents x 200,000) / total man-hours. (1) Cloud Peak Energy has combined Kiewit and Level III Communications data as reported by MSHA. Good Safety Record Indicates Well-Run Operations A portion of all employees’ bonuses is tied to safety

6 Reliable and Productive Operations Improving Coal Load Per Haul Truck Improved asset utilization 4.0% 3.0% 2.0% 1.0% 2007 2010 Tons 300 280 260 240 220 200 180 160 140 120 Implemented fuel management system Tracks fuel consumption by equipment piece which enables identifying most cost effective engines and drive systems Developed condition monitoring efforts to intercept potentially catastrophic failures Allows for extended life of components and cost savings Implemented cost modeling tool to improve accuracy of maintenance planning Links to our Mine Monitoring & Control system for greater time efficiency Payload measurement supports increased payloads

PRB Has Extensive Coal Reserves 7 Spring Creek Mine – MT 2010 Tons Sold 19.3M tons 2010 Proven & Probable Reserves 329M tons Reserve Coal Quality 9,350 Btu/lb Antelope Mine – WY 2010 Tons Sold 35.9M tons 2010 Proven & Probable Reserves 252M tons Reserve Coal Quality 8,850 Btu/lb Cordero Rojo Mine – WY 2010 Tons Sold 38.5M tons 2010 Proven & Probable Reserves 385M tons Reserve Coal Quality 8,425 Btu/lb 0 100 mi Legend

Historic U.S. Coal Supply by Region Coal 45% Natural Gas 24% Nuclear 20% Hydroelectric Conventional 6% Other Energy Sources 4% Petroleum 1% 1990 1995 2000 2005 2010 est PRB CAPP NAPP ILL B Other 8 (million tons) 2010 U.S. Power Generation by Fuel Source Source: EIA Electric Power Monthly (November 2010) Total U.S. Coal Supply up 6% since 1990 Other basins – down 14% CAPP – down 39% NAPP – down 21% Illinois Basin – down 24% PRB - up 137% Source: MSHA/PIRA

9 Reach of PRB Coal is Growing Large reserve base Low-cost coal supply Surface mining More supportive local environment for coal mining Low sulfur content Ample rail capacity Source: SNL U.S. Coal Consumption by Region

10 0 100 200 300 400 500 600 700 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 Tons MMmt Other Asia Malaysia India Hong Kong China Taiwan S.Korea Japan Pacific Rim Thermal Coal Import Demand Source: PIRA Pacific Rim thermal import demand has experienced strong growth and it is forecasted to continue • Over the last 10 years, China went from net exporter to net importer • India imports increased by 80 million mt over last 10 years Pacific Rim thermal demand is forecasted to grow by one billion mt over next 10 years and imports are forecasted to supply 100 million mt of this growth

11 Increasing International Demand Supports Powder River Basin Pricing 2010 U.S. exports up 36% (60M tons 2009 to 81M tons 2010) Estimated 2011 U.S. exports • East 72M tons • West 7M tons • Canada 11M tons Sources: PIRA – PIRA Energy Group DTC – Doyle Trading Consultants

Spring Creek – Export Quality Advantage 3700 3900 4100 4300 4500 4700 4900 Indonesian Coal Typical PRB 8800 Btu Coal Spring Creek Mine 9350 Btu Coal Kcal/kg NAR Desired Calorific Values (CV) by South Korean Utilities Between 3700 - 5000 Kcal/kg NAR 12 Spring Creek Mine - Montana Coal quality - 9,350 Btu Converts to 4,850 Kcal/kg NAR Premium sub-bituminous coal in the international market. 4850 4544 Average Source: Company estimates

13 Spring Creek – Geographic Advantage Spring Creek Mine to Westshore ~1,600 miles, approx. 200 miles closer than SPRB Spring Creek to Ridley 1,902 Miles (CN) Spring Creek to Westshore 1,591 Miles (BNSF) SPRB to Spring Creek 235 Miles (BNSF/UP)

14 Brownfield and Greenfield West Coast Port Expansions and Developments Westshore terminal (Vancouver, BC) expansion from 24 to 33 million tons – currently underway Ridley terminal (Prince Rupert, BC) expansion from 12 to 24 million tons SSA Marine’s Gateway terminal (WA) – potential 24+ million tons Millennium’s Longview terminal (WA) of 5+ million tons Source: Media reports/releases

SSA Marine’s Proposed Gateway Pacific Terminal Proposed Bulk Commodity Terminal Grain, coal, potash Operational ~2015 Existing industrial site BNSF served Source: Media reports/releases 15

16 Export Driven Production Growth Manage production to meet demand Exports to Asia growing as a percent of total production Sales from Company Operated Mines (million tons) 90.7 92.8 89.3 90.4 ~ 90.5 ~ 4.0 0.9 3.3 1.6 2007 2008 2009 2010 2011E 93.7 90.7 93.7 90.9 ~ 94.5 Asian Exports Domestic Delivery

17 Powder River Basin Forward Coal Prices $12.00 $13.00 $14.00 $15.00 $16.00 $17.00 2011 2012 2013 2014 Q4-09 Q1-10 Q2-10 Q3-10 Q4-10 Q1-11 4/25/2011 U.S. PRB 8800 Btu Coal Price (per ton) Source: ICAP plc

18 Strong Contracted Position with Upside Potential (tons in millions) 1 Includes production from company operated mines. 2011 estimated average realized price per ton: $12.95 (assuming $12.75/ton for 8800 Btu and $11.00/ton for 8400 Btu for indexed sales) 2012 has 62 million tons committed @ $13.15 90.4 62 ~4.1 ~12 ~94.5 ~74 2011E 2012E Committed tons with variable pricing Committed tons with fixed pricing Contracted Coal - Total Committed Tons (as of 4/25/11)1

19 Strategy for Growth Demonstrated outstanding operating metrics Tightly managed cost structure Optimize investments in capital expenditures Generating liquidity for growth opportunities Build from Existing Foundation Optimize Organic Growth Seize Opportunities to Expand Acquire additional reserves for future production Customer demand drives production growth Leverage Spring Creek’s advantageous export position Target acquisition opportunities building on core strengths Develop opportunities to increase high-margin exports to Asia

20 Cloud Peak Energy Lease Acquisition Strategy Antelope Mine Cordero Rojo Mine Mine LBA Expected Bid Date Tonnage Estimates Antelope West Antelope II1 May – June 2011 407M2 Mineable tons Cordero Rojo Maysdorf II (Tract as applied for) 2011 – 2013 434M3 Recoverable tons 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. 1 North and South tracts; Subject to pending legal challenges filed against the BLM and the Secretary of the Interior by certain environmental groups. 2 Tonnage as estimated by BLM. Allows access to additional 80 million tons of non-reserve coal deposits controlled by Antelope. 3 Estimated tonnage for Maysdorf II as applied for. The BLM has determined that certain surface owners meet the criteria for being a “qualified surface owner.” Unless surface owner consent is obtained by July 1, 2011, the BLM has indicated it will reconfigure the nominated tract to exclude such lands, which would result in a significant reduction in the final tract delineation and tonnage.

21 Liquidity for Growth Unrestricted Cash $ 396 Revolver, net of Letters of Credit $ 390 Total Available Liquidity1 $ 785 Restricted Cash $ 161 $400M Revolver (Baa3- Rating) $ 0 8¼% Senior Notes due 2017 $ 300 (B1 / BB- rating) 8½% Senior Notes due 2019 $ 300 (B1 / BB- rating) Total Senior Debt $ 600 Total Borrowed Debt/TTM Adjusted EBITDA2 1.8x Liquidity and Obligations (as of March 31, 2011) ($ in millions) Positive Cash Generation Cash, Cash Equivalents and Restricted Cash Unrestricted cash Restricted cash ($ in millions) 80 177 218 218 182 161 268 255 250 288 340 396 $348 $432 $468 $506 $522 $557 Q4-09 Q1-10 Q2-10 Q3-10 Q4-10 Q1-11 1 Totals reflect rounding 2 Reconciliation tables for Adjusted EBITDA are included in the Appendix

22 Looking Forward (1) Efficient operations Indexed/unpriced sales provide opportunity for future pricing upside Continued strong contribution from export sales Strong balance sheet provides financial flexibility Significant cash generation Disciplined capital deployment Proportionally low, long-term operational liabilities

23 Appendices (Cloud Peak Energy Inc.)

24 Updated Guidance – 2011 Estimates and 2010 Actuals 2011 (estimated) 2010 (actual) 1 Assumes prices of $12.75 per ton for 8800 Btu coal and $11.00 per ton for 8400 Btu coal applied to indexed tons 2 Represents average Cost of Product Sold for produced coal for our three operated mines. 3 Includes capitalized interest. Coal production for our three operated mines 93 – 96 million tons 93.8 million tons Committed sales with fixed prices 90 million tons n/a Anticipated realized price of produced coal1 Approximately $12.95 per ton $12.32 per ton Average cost of produced coal 2 $9.00 - $9.40 per ton $8.57 per ton Additional operating margin $30 - $50 million n/a Selling, general and administrative expenses $55 - $65 million $63.6 million Interest expense $55 - $65 million $46.9 million Depreciation, depletion, amortization and accretion $115 - $125 million $115.7 million Effective income tax rate Approximately 35% 21.9% Capital expenditures (excludes federal coal leases) 3 $100 - $140 million $91.6 million Committed federal coal lease payments $63.8 million $63.8 million

25 2010 Average Cost of Produced Coal 1 Represents average Cost of Product Sold for produced coal for our three company-operated mines. $8.57/ton for company-operated mines1 44% 19% 14% 9% 6% 4% 4% Royalties and taxes Labor Repairs and maintenance Fuel and lubricants Explosives Outside services Other mining costs

26 Statement of Operations Data (in millions, except per share amounts) Revenues $ 356.5 $ 311.0 Operating income 53.9 47.8 Net income 26.8 28.8 Net income attributable to controlling interest $ 26.8 $ 11.6 Earnings per common share attributable to controlling interest – basic Net income $ 0.45 $ 0.38 Earnings per share attributed to controlling interest – diluted Net income $ 0.44 $ 0.38 Three Months Ended March 31, 2011 2010

27 Statement of Operations Data (in millions, except per share amounts) Revenues $ 1,370.8 $1,398.2 $1,239.7 $1,053.2 $ 942.8 Operating income 211.9 255.0 124.9 102.7 88.9 Income from continuing operations 117.2 182.5 88.3 53.8 40.5 Income (loss) from discontinued operations — 211.1 (25.2) (21.5) (2.6) Net income 117.2 393.6 63.1 32.3 37.9 Amounts attributable to controlling interest: Income from continuing operations 33.7 170.6 88.3 53.8 40.5 Income (loss) from discontinued operations — 211.1 (25.2) (21.5) (2.6) Net income $ 33.7 $ 381.7 $ 63.1 $ 32.3 $ 37.9 Earnings per share – basic Income from continuing operations $ 0.98 $ 3.01 $ 1.47 $ 0.90 $ 0.68 Income (loss) from discontinued operations — 3.73 (0.42) (0.36) (0.05) Net income $ 0.98 $ 6.74 $ 1.05 $ 0.54 $ 0.63 Earnings per share attributed to controlling interest – diluted Income from continuing operations $ 0.98 $ 2.97 $ 1.47 $ 0.90 $ 0.68 Income (loss) from discontinued operations — 3.52 (0.42) (0.36) (0.05) Net income $ 0.98 $ 6.49 $ 1.05 $ 0.54 $ 0.63 Year Ended December 31, 2010 2009 2008 2007 2006

28 Balance Sheet Data (in millions) Cash and cash equivalents $ 395.8 $ 340.1 $ 268.3 $ 15.9 $ 23.6 $ 19.6 Restricted cash 160.8 182.1 80.2 — — — Property, plant and equipment, net 998.4 1,008.3 987.1 927.9 719.7 703.7 Total assets 1,953.0 1,915.1 1,677.6 1,785.2 1,781.2 1,723.3 Senior notes, net of unamortized discount 595.8 595.7 595.3 — — — Federal coal lease obligations 118.3 118.3 169.1 206.3 67.7 79.0 Asset retirement obligations, net of current portion 184.4 182.2 175.9 164.2 159.1 161.0 Total liabilities 1,392.5 1,383.9 1,232.1 800.0 1,446.2 1,433.5 Controlling interest equity 560.6 531.2 252.3 985.2 335.0 289.9 Noncontrolling interest equity — — 192.6 — — — March 31, December 31, 2011 2010 2009 2008 2007 2006

29 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in thousands) Nine Months Ended September 30, 2010 2009 Net income $ 26,773 $ 28,762 $ 115,208 Interest income (135) (95) (605) Interest expense 12,218 12,776 46,380 Income tax provision 15,293 6,723 40,552 Depreciation and depletion 25,115 23,707 101,431 Amortization1 — 3,197 — Accretion 3,340 3,318 12,521 EBITDA 82,604 78,388 315,487 Tax Receivable Agreement expense — — 19,669 Expired significant broker contract1 — (8,324) 117 Adjusted EBITDA $ 82,604 $ 70,064 $ 335,273 Three Months Ended March 31, Trailing Twelve Months 2011 2010 1 The impact of the expired significant broker contract on the Statement of Operations is a combination of net income and the amortization expense related to the contract. All amortization expense for the periods presented was attributable to the significant broker contract.

30 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in thousands) Nine Months Ended September 30, 2010 2009 March 31, Year Ended December 31, 2011 2010 2009 2008 2007 2006 Net income $ 26,773 $ 117,197 $ * $ * $ * $ * Net income from continuing operations * * 182,472 88,340 53,789 40,537 Interest income (135) (565) (320) (2,865) (7,302) (3,604) Interest expense 12,218 46,938 5,992 20,376 40,930 38,785 Income tax provision 15,293 31,982 68,249 25,318 18,050 11,717 Depreciation and depletion 25,115 100,023 97,869 88,972 80,133 59,352 Amortization — 3,197 28,719 45,989 34,512 34,957 Accretion 3,340 12,499 12,587 12,742 12,212 10,088 EBITDA 82,604 311,271 395,568 278,872 232,324 191,832 Tax Receivable Agreement expense — 19,669 — — — — Expired long-term broker contract — (8,207) (74,986) (71,643) (72,479) (72,804) Adjusted EBITDA $ 82,604 $ 322,733 $ 320,582 $ 207,229 $ 159,845 $ 119,028 * For 2009 and prior periods, Cloud Peak Energy reported discontinued operations. Accordingly, for such periods, net income from continuing operations is the comparable U.S. GAAP financial measure for Adjusted EBITDA.

31 Diluted earnings (loss) per common share attributable to controlling interest $ 0.44 $ 0.98 $ * $ * $ * $ * Diluted earnings (loss) per common share attributable to controlling interest from continuing operations * * 2.97 1.47 0.90 0.68 Expired significant broker contract — (0.09) (0.49) (0.41) (0.44) (0.44) Tax Receivable Agreement expense — 0.57 — — — — Change in net value of deferred tax assets — 0.16 — — — — Adjusted EPS $ 0.44 $ 1.62 $ 2.48 $ 1.06 $ 0.46 $ 0.24 Weighted-average shares outstanding 60,662,657 34,305,205 60,000,000 60,000,000 60,000,000 60,000,000 Reconciliation of Non-GAAP Measures – Adjusted EPS March 31, Year Ended December 31, 2011 2010 2009 2008 2007 2006 * For 2009 and prior periods, Cloud Peak Energy reported discontinued operations. Accordingly, for such periods, diluted earnings (loss) per share attributable to controlling interest from continuing operations is the comparable U.S. GAAP financial measure for Adjusted EPS.

32 Reconciliation of Non-GAAP Measures – Adjusted EPS Nine Months Ended September 30, 2010 2009 Diluted earnings (loss) per common share attributable to controlling interest $ 0.44 $ 0.38 Expired significant broker contract — (0.06) Tax Receivable Agreement expense — — Change in net value of deferred tax assets1 — — Adjusted EPS $ 0.44 $ 0.32 Diluted weighted-average shares outstanding 60,662,657 60,086,558 Three Months Ended March 31, 2011 2010 1 Related adjustments to our deferred tax assets, net of valuation allowance, as a result of the increase in tax agreement liability are recorded through income tax expense.

33 Other Data Tons produced1 (in millions) 23.4 21.6 95.3 93.3 Total tons sold (in millions) 23.7 21.9 96.9 103.3 Average revenue per ton2 $12.73 $12.38 $12.32 $11.79 Average cost of product sold per ton2 $ 8.94 $ 8.52 $ 8.57 $ 7.94 1 Includes the three company-operated mines and our 50% share of the Decker mine. 2 Represents only the three company-operated mines. Three Months Ended March 31, Year Ended December 31, 2011 2010 2010 2009

34 Other Data (in millions) Tons produced – company owned and operated mines 23.1 21.4 93.8 91.0 93.8 90.7 88.1 Total tons sold– Decker mine (50% share) 0.3 0.2 1.5 2.3 3.3 3.5 3.5 Tons produced1 23.4 21.7 95.3 93.3 97.1 94.2 91.6 Tons purchased and resold 0.4 0.4 1.7 10.1 8.1 8.1 8.1 March 31, Year Ended December 31, 2011 2010 2010 2009 2008 2007 2006 1 Totals reflect rounding

Cloud Peak Energy Resources LLC 8-K