 Lehman Brothers – CEO Energy/Power September 6, 2007 Exhibit 99.1 |
 1 Forward Looking Statements This presentation includes forward-looking information that are subject to a number of risks and uncertainties, many of which are beyond our control. All information, other than historical facts included in this presentation, regarding our 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 are 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 and other services, 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. |
 2 Company Overview Completed IPO on May 14 at $15 (CLR on NYSE) – $2.5 billion market capitalization Founded 1967 by Harold Hamm, Chairman & CEO – Harold Hamm, family and management own 82% Organic growth strategy focused on unconventional resource plays – 99% of proved reserve adds through drill bit over last 3 years – >500 hz wells drilled targeting unconventional formations – 17 operated rigs, all drilling horizontal – >700,000 net undeveloped acres concentrated in emerging plays Strong financial position – $150 million of bank debt outstanding – 1H 2007 cash operating margin of $38.34/Boe ($6.39/Mcfe) |
 3 $94 $145 $327 $482 2004 2005 2006 2007E Investment in Asset Base Capex ($mm) 14,121 19,751 24,707 28,610 2004 2005 2006 Q2 '07 Production (Boe/d) $116 $285 2004 2005 2006 2007E EBITDAX 1 ($mm) 1 See second quarter 2007 earnings release for a reconciliation of net income to EBITDAX. 2 Average of DB, JPM, ML and RJ equity analyst reports. $372 Total = $482mm $131 $91 $71 $17 $79 $19 $11 $26 $37 Red River Units MT Bakken ND Bakken Other Rockies Woodford Other Mid-Con Facilities Land Other 2007 Capex by Region ($mm) $420 ² |
 4 Operational Overview Mid-Continent Proved reserves: 16.9 MMBoe 762 drilling locations Gulf Coast Proved reserves: 0.2 MMBoe 7 drilling locations Red River Units 56% Bakken Field 22% Other Rockies 8% Mid-Continent 14% Gulf Coast <1% Total proved reserves (12/31/06) = 118.3 MMBoe 74% PDP / 83% oil / 13.1 R/P / Operate 95% of PV-10% Unconventional 78% Red River Units 44% Bakken Field 31% Other Rockies 6% Mid-Continent 17% Gulf Coast 2% Avg. daily production (Q2 2007) = 28.6 MBoe/d Unconventional 77% 1,589 gross wells / 1,772 drilling locations Rockies Proved reserves: 101.2 MMBoe 1,003 drilling locations Counties with acreage holdings are highlighted Regional office Headquarters Proved Reserves by Geography Production by Geography |
 5 Key 2007 Drilling Projects Development (54% drilling capex) – Red River Units • 56% proved reserves / 44% production – Montana Bakken Shale • 20% proved reserves / 28% production Emerging Plays (37% drilling capex) – North Dakota Bakken • 288,000 net undeveloped acres – Oklahoma Woodford Shale • 45,000 net undeveloped acres Red River Units MT Bakken ND Bakken Woodford Counties with acreage holdings are highlighted Regional office Headquarters Development Emerging Plays |
 6 Red River Enhanced Recovery Units 66.5 MMBoe proved reserves 12,680 Boe/d net production in 2nd quarter 2007 Cedar Hills discovered in 1995, developed with hz drilling, 2003 enhanced recovery operations 2007 Plans – $131MM 2007E drilling capex – Infield horizontal drilling and re-entry drilling program to accelerate production and enhance sweep efficiency – Developing CHNU/CHWU on 320 acre spacing per producer – Badlands Plant began in August Forecast peak production in late 2008 at ~ 20,000 net Boe/d Cedar Hills North Unit Cedar Hills West Unit Buffalo Units Medicine Pole Hills West Unit Medicine Pole Hills South Unit Medicine Pole Hills Unit 25 Miles CLR operated units Others units |
 7 Montana Bakken Shale Significant unconventional oil resource play – Represents ½ of Montana’s oil production – CLR is largest producer (7,890 boepd) – Developed through horizontal drilling and advanced fracture stimulation 2007 Plans – $91 million 2007E drilling capex – Continue 640-acre development – Test un-booked upside • 320-acre infill drilling • Expansion of field with tri-lateral 640-acre wells • Enhanced recovery – Three drilling rigs CLR acreage 35 miles Bakken producer Williston Basin MT Bakken 47 wells $91 mm Outline of potential Bakken Production |
 8 Richland County, Montana Infills CLR acreage Sonja 1-23H Tri-Lateral (93% WI) Avg 228 bopd first 66 days Bidegaray 1-10H Tri-Lateral (83% WI) Avg 271 bopd first 17 days Edgar 1-34H Tri-Lateral WOC (75% WI) Tri-Lateral Scheduled (95%WI) Patricia 1-28H Tri-Lateral Testing 200+ bopd (95%WI) Hazel 1-18H Tri-Lateral WOC (95% WI) Georgia 1-25 Tri-Lateral Drilling (17% WI) Dorothy #3H 320 test WOC (77% WI) Third 320 Scheduled (95% WI) Margaret 3-15H First 320 acre well |
 9 MT Bakken economic models 17% 23% $60 / $6.00 Pre-tax IRR 22% 183 225 243 185 29% 203 250 270 205 $65 / $6.50 Pre-tax IRR Net boe (Mboe) Gross boe (Mboe) Gross gas (MMcf) Gross oil (Mbls) $3.6 million D&C 640-acre tri-lateral wells 20% 15% 163 200 216 153 47% $60 / $6.00 Pre-tax IRR 58% 244 300 324 246 $65 / $6.50 Pre-tax IRR Net boe (Mboe) Gross boe (Mboe) Gross gas (MMcf) Gross oil (Mbls) $3.3 million D&C 320-acre infield wells |
 10 North Dakota Bakken Shale CLR acreage Bakken producer 35 miles Filkowski 1-11H (63% WI) 246 bopd Williston Basin State Weydahl 44-36H (33% WI) 560 bopd Nelson Farms (13% WI) 350 bopd State Veeder 44-36H (38% WI) 344 bopd Lovdahl 1-16H (36% WI) 250 bopd Brown 44-1H (35% WI) 519 bopd Candee 11-9H (48% WI) 386 bopd Emerging unconventional oil resource play – 526,000 gross (288,000 net) undeveloped acres strategically located on Nesson Anticline – Significant reserve and production growth potential – ND oil prod. highest in 20 years – 20+ industry-operated rigs • Amerada Hess • Conoco Phillips • EOG Resources • Marathon 2007 Plans – $71 million 2007E drilling capex – 41 wells on 1280-acre locations – Six drilling rigs (three operated and three Conoco Phillips JV) Outline of potential Bakken production Josephine 1-8H (35% WI) testing Jean Nelson (42% WI) WOC Carus 28-28H (33% WI) 516 bopd |
 11 ND Bakken economic model 19% 26% $60 / $6.00 Pre-tax IRR 23% 228 280 300 230 32% 256 315 336 259 $65 / $6.50 Pre-tax IRR Net boe (Mboe) Gross boe (Mboe) Gross gas (MMcf) Gross oil (Mbls) $4.20 million D&C – dual leg lateral 33% 27% 228 280 300 230 36% $60 / $6.00 Pre-tax IRR 44% 256 315 336 259 $65 / $6.50 Pre-tax IRR Net boe (Mboe) Gross boe (Mboe) Gross gas (MMcf) Gross oil (Mbls) $3.66 million D&C – single leg lateral |
 12 New unconventional gas resource play – 40+ industry-operated rigs • Newfield • Antero • Devon – 45,000 net undeveloped acres – Significant reserve and production growth potential – Caney Shale upside 2007 Plans – $79 million 2007E drilling capex – ~100 gross (14 net) wells – Five drilling rigs Oklahoma Woodford Shale Project 6 miles Outline of potential Woodford production 07 CLR Locations 07 Woodford hz Spud CLR Producer Woodford Producer CLR Acreage 7-day average IP rates Meyer Trust 1-13H (34% WI) 1,655 Mcfd Arlan 1-15H (20% WI) 4,645 Mcfd Harden 1-20H (32% WI) 2,125 Mcfd Holder 1-5H (52% WI) 1,204 Mcfd Pasquali 1-30H (48% WI) 1,360 Mcfd Foster 1-6H (17% WI) 2,685 Mcfd Silva 20-1H (1% WI) 4,865 Mcfd Pratt 1-17H (23% WI) 3,752 Mcfd Wolohon 1-19H (30% WI) 3,240 Mcfd |
 13 OK Woodford economic model 68% 47% 2,400 3,000 43% $7.00 Pre-tax IRR 30% $6.00 Pre-tax IRR 2,000 2,500 Net gas (MMcf) Gross gas (MMcf) $4.40 million D&C -- operated 50% 34% 2,400 3,000 21% $6.00 Pre-tax IRR 32% 2,000 2,500 $7.00 Pre-tax IRR Net gas (MMcf) Gross gas (MMcf) $5.00 million D&C -- non-operated |
 14 Other ongoing and emerging plays Counties with acreage holdings are highlighted Regional office Headquarters Rockies: 66 scheduled locations 213,500 net undeveloped acres Red River, Winnipegosis, Fryburg, Phosphoria, Lewis Shale Midcontinent: 52 scheduled locations 146,000 undeveloped acres Morrow-Springer, Atoka, Mississipian, Hunton, New Albany Shale, Barnett Shale, Trenton/Black River Gulf Coast: 7 scheduled locations 6,400 net undeveloped acres 365,900 net undeveloped acres (50% of total undeveloped acreage) |
 14 2007 Plans Grow production to 30,000+ boepd – 24,707 boepd in 2006 – 28,610 boepd for second quarter 2007 Drill ~300 gross (160 net) wells – Expect good year in reserve additions Maintain high cash operating margin – $40.38 / Boe ($6.73 / Mcfe) net margin for 2006 – $38.34 / Boe ($6.39 / Mcfe) net margin for 1H 2007 Hedged 10,000 bopd for Aug 2007 – Apr 2008 at $72.90 – $100,000+ per day increase in EBITDAX over analyst crude price decks Continue to build acreage in emerging resource plays – Increase scheduled drilling locations – Add future unconventional resource plays |
 16 Financial and Operating Summary 1 See page 9 of the prospectus and second quarter 2007 earnings release for a reconciliation of net income to EBITDAX. 2 Operating statistics per Boe sold. Oil sales volumes are 21 MBbls and 47 MBbls less than oil production volumes for 2006 and 2007, respectively. Year ended December 31, 2004 2005 2006 1H 2007 Realized oil price ($/Bbl) $37.12 $52.45 $55.30 $53.44 Realized natural gas price ($/Mcf) $5.06 $6.93 $6.08 $6.11 Oil production ( boepd) 10,104 15,638 20,493 23,39 1 Natural gas production (Mcf d) 24,093 24,674 25,274 29,229 Total production (boed) 14,121 19,751 24,707 28,262 EBITDAX ($ thousands) 1 $116,498 $285,344 $372,115 $199,655 Key Operational Statistics ($/ Boe) 2 Oil and gas revenue $35.20 $50.1 9 $52.09 $50.52 Production expense 8.49 7.32 6.99 7.43 Production tax 2.39 2.22 2.48 2.68 G&A (excluding non-cash equity compensation) 2.02 2.43 2.24 2.07 Total cash costs $12.90 $11.97 $11.71 $12.18 Net operating margin $22.30 $38.22 $40.38 $38.34 |
 17 Summary High quality, proved reserve base – Crude oil-concentrated, long-lived, high operated % Track record of drill bit growth at low cost – Annual EBITDAX > Capex over past 3 years Low risk production growth in Red River Units – 7,000+ Boe/d expected production growth over next 2 years (~30% of 2006 average daily production for entire company) Significant future production and reserve growth opportunities in two large emerging plays – ND Bakken and OK Woodford Shales – Over 1,500 unbooked locations Low cash costs with one of highest net operating margins – Significant valuation and competitive advantage |