UBS Global Oil & Gas Conference May 22, 2008
Forward Looking Statements This presentation includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company s control. All information, other than historical facts included in this presentation, regarding strategy, future operations, drilling plans, estimated reserves, future production, estimated capital expenditures, projected costs, the potential of drilling prospects and other plans and objectives of management is forward-looking information. All forward-looking statements speak only as of the date of this presentation. Although the Company believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Actual results may differ materially from those anticipated due to many factors, including oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production from enhanced recovery operations, availability of drilling rigs, pipe and other services and equipment, availability of oil and natural gas transportation capacity, availability of capital resources and other factors listed in reports we have filed or may file with the Securities and Exchange Commission. This presentation also includes information on reserves potentially recoverable through additional drilling or enhanced recovery operations. Non-proven estimates are generally not permitted to be disclosed in SEC filings and are subject to a substantial risk of not being realized. 1
Company Overview Completed IPO on May 14, 2007 at $15 (CLR on NYSE) $8 billion market capitalization currently Founded 1967 by Harold Hamm, Chairman & CEO Organic growth strategy focused on unconventional resource plays L3 years reserves adds drilling 66 MMboe vs. acquisitions 0.6 MMboe 2007 daily production 29,099 boe > 2X 2004 level of 14,121 boe 82% of proved reserves / 78% of production from unconventional resources 800,000 net undeveloped acres concentrated in unconventional resource plays Strong financial results 2007 EBITDAX $470MM > 4X 2004 EBITDAX $116MM 1Q 2008 EBITDAX $184MM 102% > 1Q 2007 $212MM of bank debt outstanding as of 3/31/08 100% of oil and gas production unhedged 2
Investment in Asset Base EBITDAX ($mm) Cash used in investing activities ($mm) 59% CAGR $285 $372 $470 $325 88% CAGR $483 $116 $184 $73 $134 $177 2004 2005 2006 2007 1Q 2008 2004 2005 2006 2007 1Q 2008 Production (boepd) 2008 Capex by Region - $783MM 27% CAGR 29,099 30,237 24,707 19,751 14,121 2004 2005 2006 2007 1Q 2008 $107 $21 $53 $130 $30 $13 $184 $245 Red River Units Bakken Other Rockies Woodford Other Mid-Con Gulf Coast Land & Seismic Other 3
Financial and Operating Summary Years ended December 31, 2004 2005 2006 2007 1Q 2008 Realized oil price ($/bbl) 1 $38.85 $52.45 $55.30 $63.55 $90.55 Realized natural gas price ($/Mcf) $5.06 $6.93 $6.08 $5.87 $7.55 Oil production (boepd) 10,104 15,638 20,493 23,832 24,043 Natural gas production (Mcfd) 24,093 24,674 25,274 31,599 37,160 Total production (boepd) 14,121 19,751 24,707 29,099 30,237 EBITDAX ($ thousands) 2 $116,498 $285,344 $372,115 $469,885 $183,968 Key Operational Statistics ($/boe) 3 Average oil equivalent price 1 $36.45 $50.19 $52.09 $58.32 $81.35 Production expense $8.49 $7.32 $6.99 $7.35 $8.33 Production tax 2.39 2.22 2.48 3.13 4.61 G&A (ex non-cash equity compensation) 2.02 2.43 2.24 1.92 2.22 Total cash costs $12.90 $11.97 $11.71 $12.40 $15.16 Cash margin $23.55 $38.22 $40.38 $45.92 $66.19 1 Excludes impact of price commodity derivative contracts covering period from August 2007 through April 2009. 2 See page 30 of first quarter Form 10Q and earnings release for a reconciliation of net income to EBITDAX. 3 Operating statistics per boe sold. Oil sales volumes are 19 Mbbls more than oil production volumes for 1Q 2008 and 21 Mbbls and 221 Mbbls less than oil production volumes for 2006 and 2007, respectively. 4
Operational Overview 1,306 net producing wells with >1,000 net drilling locations Proved Reserves by Geography Rockies Proved reserves: 110.0 MMboe Mid-Continent 11% Gulf Coast <1% Unconventional 82% Other Rockies - 7% Woodford - 7% Bakken Field 25% Red River Units 50% Total proved reserves (12/31/07) = 134.6 MMboe 74% PDP / 77% oil / 12.7 R/P / Operate 93% of PV-10% Production by Geography Headquarters Regional office Counties with acreage holdings are highlighted Mid-Continent Proved reserves: 24.3 MMboe Gulf Coast Proved reserves: 0.3 MMboe Gulf Coast Mid-Continent 2% 13% Other Rockies - 7% Woodford - 6% Bakken Field 27% Red River Units 45% Unconventional 78% Avg. daily production (Q1 2008) = 30.2 Mboepd 5
Key Drilling Projects Development (36% 2008 capex) Red River Units 50% proved reserves / 45% production Montana Bakken Shale 20% proved reserves / 22% production High impact plays (47% 2008 capex) North Dakota Bakken Shale 350,000 net acres Oklahoma Woodford Shale 45,000 net acres MT Bakken ND Bakken Red River Units Woodford Estimated exit rate 43,000 boepd (42% increase over 1Q 2008) 13 operated drilling rigs at 1/1/08 Now, 23 operated drillings with 30 planned Headquarters Regional office Counties with acreage holdings are highlighted Development Emerging Plays 6
CLR Unconventional Resource Plays > 800,000 net acres in unconventional plays and growing Bakken 490,000 Red River 70,000 Lewis 31,000 Anadarko Woodford 37,000 Atoka 29,000 Arkoma Woodford 45,000 New Albany 46,000 Marcellus Huron 34,000 Marfa Woodford/ Barnett 67,000 Haynesville 4,000 Shale Basin CLR owns acreage position CLR building acreage position Overthrust Belt 7
Red River Enhanced Recovery Units 67.9 MMboe proved reserves 13,620 net boepd in 1Q 2008 Cedar Hills developed in 1995 with hz 13 th largest onshore lower 48 oilfield Began enhanced recovery operations in 2003 2008 Plans $184MM capex / 5 to 6 drilling rigs Infield horizontal drilling and re-entry drilling program to accelerate production and enhance sweep efficiency Develop Cedar Hills on 320 acre / producer $17MM for increased water handling Forecast 2009 peak at ~21 net Mboepd Haley Prospect 70,000 net acres Extension of Red River B 8 well drilling program planned in 2008 Medicine Pole Hills West Unit Medicine Pole Hills South Unit Cedar Hills West Unit Cedar Hills North Unit Buffalo Units Medicine Pole Hills Unit Haley 25 Miles 8
Bakken Shale Outline of potential Bakken production Williston Basin Montana North Dakota Significant unconventional oil resource play Largest single oil assessment in L48 with 4B boe technologically recoverable - USGS Largest leaseholder - 490,000 net acres 8,210 net boepd in 1Q 2008 Developed through hz drilling and advanced fracture stimulation 70+ rigs operating ConocoPhillips EOG Resources Hess Marathon 2008 Plans $245MM capex 28 net wells 10 to 13 operated drilling rigs CLR acreage Horizontal Bakken producer 9
Richland County, Montana Bakken 2 Sinclair Bakken Discoveries 300 bopd IPs 207 boepd Newhouse 1-26H 95% WI 609 boepd Lea Joe 1-1H 63% WI 348 boepd Pennie 1-4H 93% WI 129 boepd Rachel 1-12H 86% WI 310 boepd Audrey 3-31H 72% WI 250 boepd Linnea 3-12H 95% WI YTD 2008 Completions and Remaining 2008 Scheduled Locations 320 acre Bakken location 640 acre Tri-Lateral Bakken location 640 acre Single Lateral Bakken location CLR acreage 10
Bakken Shale Geologic Cross-Section A Lodgepole B 20 Upper Bakken Shale Dolomite/Silty Dolomite Shaley Limestone/Limey Shale Sand Sanish 60 40 Middle Bakken Lower Bakken Three Forks 120 Sanish Over-pressured, oil bearing rock Both source and reservoir for the oil Three members (Upper, Middle, Lower) Upper Shale Highly organic (up to 20% TOC) Brittle due to high silica content Max 28 thick Middle Member Varies from dolomite, sand, shaley lime and shale across the basin Porosity is low, averaging 5% Max 87 thick Lower Shale Similar to Upper Shale Max 55 thick Micro fractured due to oil generation Macro fractured locally due to tectonics Depths 8500-11,000 A Bakken Pinchout MT ND ND Bakken Wells drilled since 12/2003 B Approx. Limit of Thermally Mature Bakken 11
North Dakota Bakken In 2007, CLR completed 27 wells with average gross EUR of 335 Mboe in Norse, Rocket, Galaxy, Pontiac and Valhalla prospects. Imsland 1-31H 7-day IP 299 bopd EOG Parshall Area Pletan 1-18H 7-day IP 760 boepd Cleo 1-12H IP 716 boepd CRI OPERATED CRI NON-OPERATED NO CRI INTEREST Bice 1-29H Three Forks/Sanish test 12
Arkoma Woodford Shale 4-well Simul-frac Scheduled Q3 08 2-well Simul-frac Scheduled Q3 08 Significant Unconventional gas resource play 40+ industry-operated rigs Newfield Antero Devon Salt Creek exploratory 2-well Simul-frac Scheduled Q3 08 4-well Simul-frac Avg 3,480 mcfd/well 45,000 net acres Significant reserve and production growth potential Caney Shale upside E. McAlester exploratory 2008 Plans $130MM capex 23 net wells Ashland development 5 to 6 drilling rigs 12 miles CLR Operated WOC CLR Operated Producer CLR 2008 Wells to be drilled Woodford Producer CLR Acreage Inset: CLR 2008 Completed Wells Inset: CLR 2008 Wells to be drilled 13
ND Bakken & Arkoma Woodford ND Bakken Net potential unbooked locations * Net reserves/well Reserve potential 517 256,000 bbls 132 MMboe Arkoma Woodford 527 2,400 MMcf 1.26 Tcf Total 1,043 342 MMboe * Assumed 640-acre spacing for ND Bakken and 80-acre for Woodford Shale Estimated average D&C Net boe/well $80/bbl & $7/Mcf Pre-tax IRR $100/bbl & $10/Mcf Pre-tax IRR ND Bakken $5,200,000 256,000 38% 69% Arkoma Woodford $5,000,000 400,000 50% 122% 14
Trenton/Black River Hillsdale Co., MI Albion-Scipio Field Discovered in 1956 Single largest field in Michigan Hydrothermal dolomitized reservoir Together with Stoney Point Field (discovered in 1983), produced ~190 MMboe Albion-Scipio Field Stoney Point CLR project 4 successful wells confirm ability to identify reservoir rock on 3D seismic McArthur 1-36 824 gross Mboe ~4,000 depth / $700M D&C Boardman 1-1 drilling 1 st of 4 wells to be drilled back to back 4 additional wells planned and 3D seismic being acquired 35,000 net acres Chicago/Norad 3-D 3-D 20 mi. (pending) Dog Leg 3-D 3-D 4.5 mi. Young #11-34 (planning hz) Pridgeon 3-3 (testing) McArthur 200 BOPD Anspaugh 250 BOPD Wessel 200 BOPD Boardman 1-1 (drilling) Kittyhawk 3-D Fred Bear 3-D (proposed) 5 Miles Hog Heaven 3-D 6.5 mi. 15
Summary High quality, proved reserve base Crude oil-concentrated, long-lived, high operated % Track record of drill bit growth at low cost L3 years cash flow from operations $1,075MM vs. $942MM cash invested Low risk production growth in Red River Units ~7,000 boepd expected production growth over next 1+ years Significant future production and reserve growth opportunities in several emerging plays 342 MMboe unbooked potential reserves in ND Bakken & Arkoma Woodford Low cash costs with one of the highest net operating margins Significant valuation and competitive advantage 16