Denver August 23-25, 2010 ENERCOM Energy Conference 2010 Exhibit 99.1 |
2 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. |
3 #3 oil producer in the Rocky Mountains Accelerating growth with oil-rich drilling inventory Excellent 1H10 results • $392MM EBITDAX • 20%> in EUR model to 518,000 Boe per well (ND Bakken) • #1 Land position in Bakken Shale play with 816,852 net acres • 9% production growth in 2Q10 vs. 1Q10 • 2Q10: 41,913 Boepd • 1Q10: 38,428 Boepd • 2Q09: 37,347 Boepd Continental Resources, Inc. |
Organic growth • Inventory to 3X production and reserves over the next five years Crude-oil focused • 75% of 2Q10 production Advanced technology applied to unconventional resource plays Conservative fiscal discipline 4 Growth Strategy |
5 Operating Areas Headquarters: Enid, Oklahoma Field offices Counties with acreage holdings are highlighted |
6 Strong Production Growth 2005-2009 7,209 9,018 10,621 12,006 13,623 79% oil 83% 82% 76% 75% MBoe Est. 15,800 74% * CLR 2Q10 production 75% crude oil. 2010 production guidance is for 15% to 17% growth. |
7 116,665 118,349 134,615 159,262 257,293 85% oil 83% 77% 67% 67% Growth in Reserves 2005-2009 MBoe |
8 The Bakken #1 crude oil play in lower 48 (USGS) 4.3B barrels of recoverable oil CLR: +171,505 net acres since January 1, 2010 ~ |
9 Growth Driver: North Dakota Bakken Hz producer 2Q10: 13,046 Boepd • +93% over 2Q09 • +30% over 1Q10 41% of ‘09 proved reserves • 616 gross (261.9 net) PUD locations at YE09 589,937 net acres 2010: $588MM capex (67% of total drilling capex) |
CLR firsts • Drilled the Three Forks in May 2008 • Dual zone development with Mathistad 2-35H in 2009 • ECO-Pad drilling in 2010 75% of acreage could be prospective for dual zone development 10 MB/TF Dual Reservoir Development ® CLR TF producer CLR Q2 MB completion CLR Q2 TF completion CLR MB producer 2Q10 TF Completions Meldahl 1-23H – 2,489 Boe Ole 1-29H – 1,864 Boe Bang 2-33H – 1,860 Boe Roger 1-18H – 1,486 Boe 2Q10 MB Completions Franklin 1-20H – 1,288 Boe Bohmbach 2-35H – 1,271 Boe Brockmeier 1-1H – 1,217 Boe Anseth 1-29H – 1,088 Boe |
North Dakota Industrial Commission reduced property line set-back requirement • At least 5% longer lateral Expect results from first ECO- Pad projects in near future 10% less D&C cost • 4 wells per ECO-Pad, versus 4 separate drilling pads 11 ECO-Pad Development Spacing unit #2 1,280-acre spacing unit #1 50’ set-back 500’ set-back 500’ set-back ® |
12 Improving ND Bakken Well Results Boepd Current standard is 24 stages; testing 30 210 333 323 329 376 539 567 507 432 815 722 1,123 954 122 155 184 179 185 267 306 260 201 402 335 546 576 895 Completions: 7 7 7 5 5 10 6 15 11 9 9 9 14 Avg. CLR stages: 1 1 4 9 8 10 11 13 11 12 15 18 20 23 24 NA |
13 Expanding Montana Bakken +63,416 net acres added in 2010 2Q10: 5,196 Boepd 11% of 2009 proved reserves • 65 gross (44.7 net) PUD locations $55MM in 2010 capex • Added second rig to play |
14 Good Plays Keep Getting Better 50 Miles The Bakken keeps growing |
15 Production Base: Red River Units Cedar Hills Units Buffalo Units Medicine Pole Hills Units Cedar Hills Units: 7 largest onshore oil field in Lower 48 2Q10: 15,080 Boepd 21% of 2009 proved reserves $82MM in 2010 capex • 5 new producers drilled 2Q10 th |
16 Williston Takeaway Capacity |
17 Arkoma Woodford: Working East CLR Acreage Woodford Producer SALT CREEK RUSHING ASHLAND AMI Foster Development 6 wells: avg. 2.4 MMcfpd EAST KREBS Ennis 7H-12 (non-op) 8.4 MMcfpd Marilyn 1-29H 4.2 MMcfpd Delphia 1-34H 2.1 MMcfpd 2Q10: 3,721 Boepd 17% of 2009 proved reserves • 401 gross (100 net) PUD locations • 46,074 net acre position; 47% HBP $41MM in 2010 capex |
18 Anadarko Woodford: Coming on Strong 12 miles Wichita Uplift Nemaha Uplift Cana Gas/Condensate Oil Gas Brown 1-2H 4.2 MMcfpd, 102 Bopd Doris 1-25H 4.5 MMcfpd, 72 Bopd McCalla 1-11H Ballard 1-17H 750 Mcfpd, 200 Bopd NW Cana SE Cana Young 2-22H 7.5 MMcfpd Very encouraged by early well results Liquids content enhances economics 251,626 net acres $75MM in 2010 capex • 3 operated rigs • Adding 4 by year end |
19 Operating and Fiscal Discipline 1 See Non-GAAP Financial Measures in Form 10-K, Form 10-Q and earnings release for a reconciliation of net income to EBITDAX. 2 Average costs per Boe have been computed using sales volumes. Realized oil price ($/bbl) Realized natural gas price ($/Mcf) Oil production (bopd) Natural gas production (Mcfd) Total production (boepd) EBITDAX ($000’s) Key Operational Statistics Average oil equivalent price Production expense Production tax G&A Interest Total cash costs Cash margin Cash margin % Years ended December 31, 2009 $54.44 $3.22 27,459 59,194 37,324 $450,648 $45.10 6.89 3.37 3.03 1.72 $15.01 $30.09 66.7% 2008 $88.87 $6.90 24,993 46,861 32,803 $757,708 $77.66 8.40 4.84 2.95 1.01 $17.20 $60.46 77.9% 1H10 $69.87 $4.84 30,373 58,844 40,180 $391,578 $59.92 6.17 4.70 3.20 2.78 $16.85 $43.07 71.9% 1 2 |
20 Plenty of Running Room * CLR internal economic model, based on EUR of 518K Boe and 640-acre spacing for the ND Bakken; 430K Boe and 320-acre spacing for the MT Bakken; 300K and 320-acre spacing for the Niobrara; 3 Bcf 80-acre spacing for the Arkoma Woodford; and 6 Bcf and 160-acre spacing for the Anadarko Woodford. ND Bakken MB zone 600 253 1,932 MMBoe additional reserves potential in the Bakken, Niobrara and Woodford; 7.5X 2009 reserves of 257.3 MMBoe. In addition to our 62% increase in 2009 proved reserves... Potential unbooked locations (net) Additional MMBoe reserve potential ND Bakken TF zone 400 168 Arkoma Woodford 425 174 (1.0 Tcf) Anadarko Woodford 1,500 1,218 (7.3 Tcf) MT Bakken 200 70 Niobrara 200 49 |
21 Positioned for Value Creation Low-cost, high-margin operator • Operate 93% of our PV-10 Strong balance sheet Hedged for operational stability Huge drilling inventory Goal: 3X in 5 years – production and reserves |
Continental Resources, Inc. |
23 Appendix |
Year ended December 31, 2010 Production growth Price differentials (1) Oil (Bbl) Gas (Mcf) Operating expenses per Boe: Production expense Production tax (percent of sales) Depreciation, depletion, amortization and accretion General and administrative expense (2) Non-cash stock-based compensation Income tax rate, percent of pre-tax income Percent of income tax deferred 24 2010 Guidance 15% to 17% $8 to $10 +/- $0.25 $6.50 to $7.00 7.0% to 7.5% $15 to $18 $2.00 to $2.40 $0.75 to $1.00 38% 95% (1) Differential to calendar month average NYMEX futures price for oil and to average of last three trading days of prompt NYMEX futures contract for gas. (2) Excludes non-cash stock-based compensation. |
25 Crude Oil Hedge Positions 2010 Jul. to Sep. Swaps Collars Oct. to Dec. Swaps Collars 2011 Jan. to Mar. Swaps Collars Apr. to Dec. Collars 2012 Jan. to Dec. Collars Volume in Barrels 687,000 1,380,000 1,089,000 1,380,000 225,000 2,565,000 7,837,500 2,745,000 Weighted Avg. of Swaps $84.58 $83.99 $84.55 Range $75-78 $75-78 $75-80 $75-80 $80 Weighted Average $76.00 $76.00 $78.95 $79.39 $80 Range $88.75-96.75 $88.75-96.75 $88.65-97.25 $89.00-97.25 $93.25-93.65 Weighted Average $93.43 $93.43 $91.70 $91.27 $93.54 Collars: Floors Collars: Ceilings |
26 Natgas Swaps 2010 Jul. to Sep. Oct. to Dec. 2011 Jan. to Dec. Natgas Basis Swaps, Centerpoint East 2010 Jul. to Dec. Natural Gas Swaps MMBtus 3,778,000 3,778,000 11,862,500 3,600,000 Swaps Weighted Avg. $6.09 $6.09 $6.36 ($0.62) |