INVESTOR PRESENTATION February 2013

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, 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 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 (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, or 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 impacts, as applicable, of: (1) the updates to the tax agreement liability, including tax impacts of our 2009 initial public offering and 2010 secondary offering, (2) adjustments for derivative financial instruments including mark-to-market amounts and cash settlements realized, and (3) our significant broker contract that expired in the first quarter of 2010. Because of the inherent uncertainty related to the items identified above, management does not believe it is able to provide a meaningful forecast of the comparable GAAP measures or a reconciliation to any forecasted GAAP measures. Adjusted EPS represents diluted earnings (loss) per common share attributable to controlling interest, or diluted earnings (loss) per common 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 at the statutory rate of 36%. 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 income from continuing operations. 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 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, income from continuing operations, 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, income from continuing operations, 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 One of the largest U.S. coal producers 2012 coal shipments from Owned and Operated Mines of 90.6 million tons 2012 proven & probable reserves of 1.3 billion tons Only pure-play PRB coal company Extensive NPRB base for long-term growth opportunities Employs approximately 1,700 people NYSE: CLD (2/13/13) $16.95 Market Capitalization (2/13/13) ~$1 billion Total Available Liquidity (12/31/12) $778 million 2012 Revenue $1.5 billion Senior Debt (B1/BB-) (12/31/12) $600 million Market and Financial Overview Company Overview

3 Low-Risk Surface Operations Highly productive, non-unionized workforce at all company-operated mines Proportionately low, long-term operational liabilities Surface mining reduces liabilities and allows for high-quality reclamation Strong environmental compliance programs and ISO-14001 certified

4 Top Coal Producing Companies - 2011 Incident Rates (MSHA) Source: MSHA. Note: Total Incident Rate = (total number of employee incidents x 200,000) / total man-hours. Good Safety Record Indicates Well-Run Operations

Extensive Coal Reserves and Significant Projects 5 Spring Creek Mine – MT 2012 Tons Sold 17.2M tons 2012 Proven & Probable Reserves 293M tons Reserve Coal Quality 9,350 Btu/lb Average lbs SO2 0.73/mmBtu Antelope Mine – WY 2012 Tons Sold 34.3M tons 2012 Proven & Probable Reserves 649M tons Reserve Coal Quality 8,875 Btu/lb Average lbs SO2 0.52/mmBtu Cordero Rojo Mine – WY 2012 Tons Sold 39.2M tons 2012 Proven & Probable Reserves 331M tons Reserve Coal Quality 8,425 Btu/lb Average lbs SO2 0.69/mmBtu 2012 Proven & Probable Reserves 1.3B Tons Antelope Mine 9M tons Cordero Rojo Mine 160M tons Spring Creek Mine 8M tons Youngs Creek Project 287M tons Non-Reserve Coal Deposits Source: SNL Energy

Resilient Profitability 6 (1) Reconciliation tables for Adjusted EBITDA are included in the Appendix Adjusted EBITDA(1) Disciplined operations and marketing strategy Consistent cash generation Prudent approach to expansion and growth Judicious investments in additional coal

(1) Implemented February 2013 (2) Adjusted EBITDA of $338.8M for FY 2012 Liquidity & Obligations (as of December 31, 2012, except as otherwise noted) Attractive cash generation Ample liquidity with over $275 million in cash, cash equivalents and marketable securities, undrawn revolver of $500 million, and new A/R Securitization plan No near-term debt maturities – first bond maturity in 2017 Highlights Liquidity ($ in millions) 7 Cash and cash equivalents $198 Marketable securities 8 0 Revolver 500 Accounts receivable securitization (1) 75 Total available liquidity $853 $500m Revolver (Baa3-rating) $08.25% Senior Notes due 2017 (B1/BB-rating) 300 (2/15/13 yield 6.24 %) 8.5% Senior Notes due 2019 (B1/BB-rating) 300 (2/15/13 yield 6.78 %) Total senior debt $600 Total borrowed debt/Adjusted EBITDA (2) 1.77

8 Strong Forward Sales Position (tons in millions) (1) Production from Owned and Operated Mines. 2013 has 80.7 million tons committed at weighted-average price of $13.40/ton 2014 has 43.5 million tons committed at weighted-average price of $14.49/ton Coal - Total Committed Tons (as of 1/18/13)(1)

9 PRB Forward Coal Prices U.S. PRB 8800 Btu Coal Price (per ton) Source: ICAP plc $7.00 $8.00 $9.00 $10.00 $11.00 $12.00 $13.00 $14.00 $15.00 $16.00 $17.00 $18.00 $19.00 2012 2013 2014 2015 2016 Q1-11 Q4-11 Q1-12 Q4-12 2/22/2013

10 External Environment Low domestic coal prices due to mild 2011/12 winter and low natural gas prices High domestic utility stockpiles High natural gas inventories Potential excess production capacity in PRB Regulatory EPA regulations for MATS effective March 2015 Retiring coal plants Further unknown requirements by new EPA directives Low Newcastle benchmark pricing Long permitting process for terminals in Pacific Northwest

11 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

12 Cloud Peak Energy’s Strategy Focus on operational/financial performance Disciplined approach to capital expenditures Generating liquidity for growth opportunities Optimize demand for low-sulfur, pure-play PRB reserves Build from Existing Foundation Optimize Development Opportunities Business Development Evaluate numerous options to develop NPRB projects around Spring Creek complex Support low sodium domestic demand Support potential for expanded export demand Target acquisitions building on core operational strengths Aim to increase export exposure Develop opportunities through acquisition of complimentary operations or companies, e.g., Western U.S., Canada Maximize Exports Leverage NPRB’s advantageous location and coal quality Optimize export logistics (rails and ports) Expand/develop other port options (U.S. Pacific Northwest, Canada) Have established in-country Korean representative to build export opportunities for our Logistics business Foster relationships for new export opportunities in China and other Asian countries, including Taiwan

13 Export Strategy Strong International Demand Cloud Peak Energy Logistics established as the Primary Exporter of PRB Coal Youngs Creek Asset Acquisition Crow Exploration and Option Agreements Secured Port Throughput

14  Increasing International Demand Supports Powder River Basin Exports Sources: Company estimates

China’s Strong Demand Requires Increasing Thermal Imports 15 Chinese Thermal Coal Imports/Exports Importing coal essential for anticipated future electric generation growth Production costs in Australia and Indonesia rapidly increasing making PRB coal importing more financially viable Diversity of supply crucial +63% Source: Fenwei Consulting Co., Ltd. Estimated Asian Coal-Fired Generation (BkW) Source: AME

16 Spring Creek Complex Export Assets – Geographic Advantage Spring Creek Complex to Ridley - 1,893 or 2,697 Miles Spring Creek Complex to Westshore - 1,591 Miles SPRB to Spring Creek Complex - 235 Miles

Spring Creek Complex – Export Quality Advantage 17 Northern PRB (Spring Creek and Youngs Creek) coal: Coal quality ~ 9,200 – 9,350 Btu Converts to ~ 4,770 – 4,850 Kcal/kg NAR Premium subbituminous coal in the international market 4770-4850 4544 Average Source: Company estimates

18 Spring Creek Complex – Potential Development Options (1) (1) (1) (1) Crow Tribe options remain subject to BIA regulatory approval.

Youngs Creek – Coal Assets Acquired 19 Greenfield project seven miles south of Spring Creek Over 450 million in-place tons, $195 million, of which 287 million tons now classified as non-reserve coal deposits, of which 272 million tons are at 8% royalty rate 9,200 Btu, low sulfur, and lower sodium than Spring Creek Mine Complementary to existing reserves of 293 million tons* at Spring Creek Multiple development options, production rates, timing and capex Permitted at 6 million tons in 2015, increasing to 14 million tons by 2019 Potential synergies with facilities, equipment, and reserves expansion * As of 12/31/2012

Youngs Creek – Land Assets Acquired 20 38,800 acres of surface land, $105 million Key location connecting Spring Creek, Youngs Creek, and potential Crow Exploration Area Will support access for Multiple development options of Youngs Creek Existing Spring Creek operations Future Spring Creek LBAs Air permits Rail corridors and access

Crow Tribal Legislature Agreements 21 Overview and process Exploration Agreement and Option Agreement to lease up to 1.4 billion tons of in-place Northern PRB coal. Approved by the Legislature and signed by the Crow Tribe and Cloud Peak Energy in January 2013. Cloud Peak Energy paid the Crow Tribe $2.25 million upon the signing. The executed agreements have been submitted to the U.S. Department of the Interior for up to 180 days for review and requested approval by the Bureau of Indian Affairs. On approval, further $1.5 million payment to the Crow Tribe.

Crow Tribal Legislature Agreements 22 Exploration Agreement To complete delineation of the potentially economic coal tonnages subject to the options. Option Agreement Three exclusive options to lease three separate coal deposits. Initial five-year term, with potential extensions through 2035 if certain conditions are met. Total option payments of up to $10 million over the initial term, with additional annual option payments through any extension periods. Option exercise payments equal to $0.08 to $0.15 per ton, variable by deposit.

23 Cloud Peak Energy Port Position Westshore Terminal Capesize vessels – deep-water port 2012 expanded to 33 million tonnes total throughput Cloud Peak Energy has throughput agreement to 2023 for a portion of our anticipated exports Cloud Peak Energy expects to ship 4.1 million tonnes (4.5 million tons) in 2013 Gateway Pacific Terminal (multi-commodity) Capesize vessels – deep-water port 48 million tonnes of coal at planned full development Cloud Peak Energy secured option for up to 16 million tonnes throughput, depending on ultimate terminal size Scoping concluded January 2013 – EIS process continues Initial opening expected ~2018 Millennium Bulk Terminal Panamax vessels 44 million tonnes of coal at planned full development Cloud Peak Energy potential option for up to 5 million tonnes at full development; anticipated upon closing sale of 50% interest in Decker mine to Ambre Energy EIS process continues Initial opening expected ~2017/2018 Export Potential (tonnes) Westshore – 2013+ 4.1 Gateway ~2018 16.0 Millennium ~2017/2018(1) 5.0 25.1 (1) Assuming completion of sale of Decker mine to Ambre

24 Growing “Pro-Coal” Efforts 24 24 Cloud Peak Energy is working with others to counter opposition of export development and to further expansion of ports, construction of new ports, and alternative shipping options

25 Executing on our Export Strategy Strong International Demand Cloud Peak Energy Logistics Established as the Primary Exporter of PRB Coal Youngs Creek Asset Acquisition Crow Exploration and Option Agreements Secured Port Throughput China and India expected to continue to drive significant demand growth 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 Geographic advantage of Spring Creek complex, closer to ports Quality advantage compares well with seaborne competitive coal 450 million tons in-place, of which 287 million tons non-reserve coal deposits 38,800 acres strategic land Multiple development options with Spring Creek complex 1.4 billion in-place tons Exploration agreement Option to lease agreement Multiple development options with Spring Creek complex Subject to BIA regulatory approval Westshore 2022 Gateway Pacific option for up to 16 million tonnes Millennium potential option for up to 5 million tonnes Other opportunities

26 Looking Forward - 2013 Large, resilient domestic business Growing logistics business supplying to export customers Strong, low-sulfur reserve holdings in best positioned U.S. basin Addition of export focused coal and land increases development options 88.8 million tons committed for 2013 Strong balance sheet provides financial flexibility Actively working on terminal expansion and new terminal projects in Pacific Northwest

Appendices (Cloud Peak Energy Inc.)

28 2013 Guidance – Estimates and 2012 Actuals 2013 (estimated) 2012 (actual) Inclusive of intersegment sales Non-GAAP financial measure Excluding impact of Tax Receivable Agreement. (4) Excluding capitalized interest and federal coal lease payments. Coal shipments for our three operated mines (1) 87 – 93 million tons 90.6 million tons Committed sales with fixed prices Approximately 81 million tons n/a Anticipated realized price of produced coal with fixed prices Approximately $13.40 per ton $13.19 per ton Adjusted EBITDA (2) $230 – $300 million $338.8 million Net interest expense Approximately $40 million $36.3 million Depreciation, depletion and accretion $110 – $120 million $107.8 million Effective income tax rate (3) Approximately 36% 26.7% Capital expenditures (4) $80 – $110 million $53.6 million Committed federal coal lease payments $79 million $129.2 million

29 Average Cost of Produced Coal * Represents average cost of product sold for produced coal for our three owned and operated mines. Owned and Operated Mines* $9.57/ton Owned and Operated Mines* $9.12/ton 2011 2012

Operating Segments 30 Owned and Operated Mines - mine site sales from our three owned and operated mines Key metrics: Tons sold Realized price per ton Cost of product sold per ton Logistics and Related Activities – delivered sales from our logistics and transportation services to international and domestic customers Key profitability drivers: Tons delivered Cost of transportation services contracted Benchmark price of Newcastle for international deliveries Corporate and Other Broker activity Results from 50% interest in Decker mine Unallocated corporate costs

Owned and Operated Mines 31 Our Owned and Operated Mines segment comprises the results of mine site sales from our three owned and operated mines primarily to our domestic utility customers and also to our Logistics and Related Activities segment. (in millions, except per ton amounts) Q4 2012 Q4 2011 Full Year 2012 Full Year 2011 Tons sold 23.6 25.2 90.6 95.6 Realized price per ton sold $13.07 $13.06 $13.19 $12.92 Average cost of product sold per ton $ 9.38 $ 9.15 $ 9.57 $ 9.12 Adjusted EBITDA (1) $ 75.4 $ 88.2 $283.3 $318.8 We reduced production in 2012 by 5 million tons in response to weaker market demand Managed costs well Reduced use of contractors Matching labor demands to market needs Conditionally monitoring and maintenance program for equipment (1) Reconciliation tables for Adjusted EBITDA are included in the Appendix

Logistics and Related Activities 32 Our Logistics and Related Activities segment comprises the results of our logistics and transportation services to our domestic and international customers. Profitability improvements Higher Newcastle prices resulting in higher settlement to international customers Curtailed international deliveries through Ridley Terminal $11.2 million realized gain in derivative financial instruments (1) Reconciliation tables for Adjusted EBITDA are included in the Appendix (in millions) Q4 2012 Q4 2011 Full Year 2012 Full Year 2011 Tons delivered 1.3 1.3 5.8 5.9 Revenue $ 65.1 $ 72.3 $ 338.8 $ 327.4 Cost of product sold (delivered tons) $ 57.5 $ 66.2 $ 280.2 $ 294.2 Adjusted EBITDA (1) $ 15.4 $ 2.6 $ 57.1 $ 24.7

33 Statement of Operations Data (in millions, except per share amounts) Three Months Ended December 31, Year Ended December 31, 2012 2011 2012 2011 Revenue $ 374.8 $ 402.5 $ 1,516.8 $ 1,553.7 Operating income 54.5 64.0 241.9 252.7 Net income 28.2 43.8 173.7 189.8 Earnings per common share – basic Net income $ 0.47 $ 0.73 $ 2.89 $ 3.16 Earnings per share – diluted Net income $ 0.46 $ 0.72 $ 2.85 $ 3.13

34 Statement of Operations Data (in millions, except per share amounts) Revenue $ 1,516.8 $ 1,553.7 $ 1,370.8 $1,398.2 $1,239.7 Operating income 241.9 250.5 211.9 255.0 124.9 Income from continuing operations 173.7 189.8 117.2 182.5 88.3 Income (loss) from discontinued operations — — — 211.1 (25.2) Net income 173.7 189.8 117.2 393.6 63.1 Amounts attributable to controlling interest: Income from continuing operations 173.7 189.8 33.7 170.6 88.3 Income (loss) from discontinued operations — — — 211.1 (25.2) Net income attributable to controlling interest $ 173.7 $ 189.8 $ 33.7 $ 381.7 $ 63.1 Earnings per share – basic Income from continuing operations $ 2.89 $ 3.16 $ 1.06 $ 3.01 $ 1.47 Income (loss) from discontinued operations — — — 3.73 (0.42) Net income $ 2.89 $ 3.16 $ 1.06 $ 6.74 $ 1.05 Earnings per share attributed to controlling interest – diluted Income from continuing operations $ 2.85 $ 3.13 $ 1.06 $ 2.97 $ 1.47 Income (loss) from discontinued operations — — — 3.52 (0.42) Net income $ 2.85 $ 3.13 $ 1.06 $ 6.49 $ 1.05 Year Ended December 31, 2012 2011 2010 2009 2008

35 Balance Sheet Data (in millions) Cash, cash equivalents and investments $ 278.0 $ 479.5 $ 340.1 $ 268.3 $ 15.9 Restricted cash — — 71.2 182.1 80.2 Property, plant and equipment, net 1,678.3 1,350.1 1,008.3 987.1 927.9 Total assets 2,351.3 2,319.3 1,915.1 1,677.6 1,785.2 Senior notes, net of unamortized discount 596.5 596.1 595.7 595.3 — Federal coal lease obligations 186.1 288.3 118.3 169.1 206.3 Asset retirement obligations, net of current portion 239.0 192.7 182.2 175.9 164.2 Total liabilities 1,420.3 1,568.9 1,383.9 1,232.1 800.0 Controlling interest equity 931.0 750.4 531.2 252.9 985.2 Noncontrolling interest equity — — — — 192.6 — December 31, 2012 2011 2010 2009 2008

36 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in millions) (1) Changes to related deferred taxes are included in income tax expense. (2) Mark-to-market and realized gains on derivative financial instruments consisted of the following (in millions): Net income $ 28.2 $ 43.8 $ 173.7 $ 189.8 Interest income (0.1) (0.1) (1.1) (0.6) Interest expense 10.9 6.3 36.3 33.9 Income tax expense 15.1 13.5 62.6 11.4 Depreciation and depletion 24.2 28.6 94.6 87.1 Accretion 3.9 3.0 13.2 12.5 EBITDA $ 82.1 $ 95.1 $ 379.3 $ 334.1 Tax agreement expense (1) — — (29.0) 19.9 Derivative financial instruments (2) 6.9 (2.3) (11.5) (2.3) Expired significant broker contract — — — — Adjusted EBITDA $ 89.0 $ 92.9 $ 338.8 $ 351.7 Three Months Ended December 31, Year Ended December 31, 2012 2011 2012 2011 Three Months Ended Year Ended December 31, December 31, 2012 2011 2012 2011 Mark-to-market (gains) losses $ (3.3) $ (2.3) $ (22.8) $ (2.3) Realized gains (3) 10.2 — 11.2 — Net derivative financial instrument activity $ 6.9 $ (2.3) $ (11.5) $ (2.3) (3) Derivative cash settlement gains and losses reflected within operating cash flows.

 Year Ended December 31, 2012 2011 Mark-to-market (gains) losses $ (22.8) $ (2.3) Realized gains (3) 11.2 — Net derivative financial instrument activity $ (11.5) $ (2.3) 37 Reconciliation of Non-GAAP Measures – Adjusted EBITDA (in millions) Year Ended December 31, 2012 2011 2010 2009 2008 Net income $ 173.7 $ 189.8 $ 117.2 $ * $ * Net income from continuing operations * * * 182.5 88.3 Interest income (1.1) (0.6) (0.6) (0.3) (2.9) Interest expense 36.3 33.9 46.9 6.0 20.4 Income tax expense (benefit) 62.6 11.4 32.0 68.2 25.3 Depreciation and depletion 94.6 87.1 100.0 97.9 89.0 Amortization — — 3.2 28.7 46.0 Accretion 13.2 12.5 12.5 12.6 12.7 EBITDA $ 379.3 $ 334.1 $ 311.3 $ 395.6 $ 278.9 Tax agreement expense (1) (29.0) 19.9 19.7 — — Derivative financial instruments (2) (11.5) (2.3) — — — Expired significant broker contract — — (8.2) (75.0) (71.6) Adjusted EBITDA $ 338.8 $ 351.7 $ 322.7 $ 320.6 $ 207.2 * 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. (1) Changes to related deferred taxes are included in income tax expense. (2) Mark-to-market and realized gains on derivative financial instruments consisted of the following (in millions): (3) Derivative cash settlement gains and losses reflected within operating cash flows.

38 Reconciliation of Non-GAAP Measures – Adjusted EPS Three Months Ended December 31, Year Ended December 31, 2012 2011 2012 2011 Diluted earnings per common share $ 0.46 $ 0.72 $ 2.85 $ 3.13 Tax agreement expense (benefit) including tax impacts of IPO and Secondary Offering — — (0.58) (0.63) Derivative financial instruments 0.08 (0.02) (0.12) (0.02) Expired significant broker contract — — — — Adjusted EPS $ 0.54 $ 0.70 $ 2.15 $ 2.47 Weighted-average dilutive shares outstanding (in millions) 61.3 60.7 60.9 60.6

39 Diluted earnings per common share attributable to controlling interest $ 2.85 $ 3.13 $ 1.06 $ * $ * Diluted earnings per common share attributable to controlling interest from continuing operations * * * 2.97 1.47 Tax agreement expense including tax impacts of IPO and Secondary Offering (0.58) (0.63) 0.78 — — Derivative financial instruments (0.12) (0.02) — — — Expired significant broker contract — — (0.10) (0.49) (0.41) Adjusted EPS $ 2.15 $ 2.47 $ 1.74 $ 2.48 $ 1.06 Weighted-average shares outstanding (in millions) 60.9 60.6 31.9 60.0 60.0 Reconciliation of Non-GAAP Measures – Adjusted EPS Year Ended December 31, 2012 2011 2010 2009 2008 * 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.

Adjusted EBITDA by Segment 40 Three Months Ended December 31, Year Ended December 31, 2012 2011 2012 2011 Owned and Operated Mines Adjusted EBITDA $ 75.4 $ 88.2 $ 283.3 $ 318.8 Depreciation and depletion (23.4) (24.3) (89.2) (80.4) Accretion (2.8) (1.9) (9.5) (8.0) Derivative financial instruments (0.2) — 0.1 — Other 0.5 0.1 0.9 0.3 Operating income 49.6 62.1 185.6 230.6 Logistics and Related Activities Adjusted EBITDA 15.4 2.6 57.1 24.7 Derivative financial instruments (6.7) 2.3 11.4 2.3 Operating income 8.6 4.9 68.4 27.0 Corporate and Other Adjusted EBITDA (1.4) 1.7 — 8.1 Depreciation and depletion (0.9) (4.2) (5.3) (6.7) Accretion (1.1) (1.2) (3.7) (4.5) Earnings from unconsolidated affiliates, net of tax — 0.3 (1.6) (1.8) Operating income (3.3) (3.3) (10.5) (5.0) Eliminations Adjusted EBITDA (0.4) 0.3 (1.6) 0.1 Operating income (0.4) 0.3 (1.6) 0.1 Consolidated operating income 54.5 64.0 241.9 252.7 Interest income 0.1 0.1 1.1 0.6 Interest expense (10.9) (6.3) (36.3) (33.9) Tax agreement expense — — 29.0 (19.9) Other, net (0.5) (0.1) (0.8) (0.2) Income tax expense (15.1) (13.5) (62.6) (11.4) Earnings from unconsolidated affiliates, net of tax — (0.3) 1.6 1.8 Net income $ 28.2 $ 43.8 $ 173.7 $ 189.8

41 Other Data (1) Represents only the three company-operated mines. Three Months Ended December 31, Year Ended December 31, 2012 2011 2012 2011 Total tons sold (in millions) (1) 23.6 25.2 90.6 95.6 Average realized price per ton sold (in millions) (1) $ 13.07 $ 13.06 $ 13.19 $ 12.92 Average cost of product sold per ton(1) $ 9.38 $ 9.15 $ 9.57 $ 9.12

42 Other Data (in millions) Tons sold – company owned and operated mines 90.6 95.6 93.7 90.9 93.7 Total tons sold– Decker Mine (50% share) 1.4 1.5 1.5 2.3 3.3 Tons sold from all production * 92.1 97.2 95.1 93.2 97.0 Tons purchased and resold 0.9 1.6 1.7 10.1 8.1 Year Ended December 31, 2012 2011 2010 2009 2008 * Total reflects rounding

43 43 43 Sulfur Content by Basin 43 Source: SNL U.S. Coal Consumption by Region Region/ Avg Btu Average lbs SO2 PRB/ 8,600 0.5 – 1.0/mmBtu Rocky Mountain 11,500 0.9 – 1.4/mmBtu Illinois Basin 11,500 2.5 – 6.0/mmBtu Appalachia 12,000 1.2 – 7.0/mmBtu Lignite 6,000 1.4 – 4.0/mmBtu Cloud Peak Energy Mines Antelope 8,875 0.52/mmBtu Cordero Rojo 8,425 0.69/mmBtu Spring Creek 9,350 0.73/mmBtu Source: Public record

44 Lease Acquisition Strategy Building Reserves 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. Cordero Rojo Mine (8425 Btu) Maysdorf II North Tract Maysdorf II LBA is expected to be bid 2013. Tonnages below are as estimated by the BLM. Maysdorf II North Tract – 149 million minable tons (1) Maysdorf II South Tract - 234 million minable tons (1) (1) In October 2012, an environmental group filed a notice of appeal with the Interior Board of Land Appeals, challenging the Bureau of Land Management’s record of decision authorizing the sale and issuance of the Maysdorf II North and South tracts. Subsequently, the environmental group requested to dismiss the appeal, which was granted by the Board of Land Appeals. Additional legal challenges may be made in the future. WAII North and South Tracts – 383 million proven and probable reserves(1) Ridgerunner lease previously acquired – 81 million proven and probable reserves Extends mine life by approximately 12 years at current production rates (1) Environmental organizations challenged certain actions of the BLM and Secretary of the Interior relating to the North and South tract leases. On July 30, 2012, the U.S. District Court for D.C. rejected these challenges. In September 2012, the environmental organizations appealed the District Court’s decision to the D.C. Court of Appeals. Any adverse outcome of the appeal could adversely impact or delay our ability to mine the coal subject to the leases. Antelope Mine (8875 Btu) Ridgerunner Lease South Tract Acquired 2011 North Tract Acquired 2011 AWARDED LBA Mined Area (2009/1010) Leased Coal Maysdorf II South Tract