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|Continental Resources Reports Fourth Quarter and Year-End 2007 Results|
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Fourth Quarter 2007
Continental reported net income for the three months ended December 31, 2007, of $60.9 million, or $0.36 per diluted share, on revenues of $159.0 million. Reported net income includes an unrealized loss of $20.8 million ($13.0 million net of taxes) recognized for the change in the fair market value of open crude oil derivative contracts not designated for hedge accounting. Net income for the quarter was $73.9 million, or $0.44 per diluted share, excluding unrealized losses on crude oil derivative contracts.
Continental's crude oil sales price averaged $13.05 per barrel less than NYMEX WTI during the fourth quarter of 2007 due to seasonal demand factors. In order to mitigate the wider differentials, the Company stored production in off-lease tanks and moved some production to alternative markets by railcar. Sales volumes for the quarter were 125 MBbls less than production volumes during the quarter due to the increase in crude oil inventory in leased tankage and railcars in transit. During the first two months of 2008, Continental sold approximately 100 MBbls of the stored crude oil. The Company's cost basis in the stored crude oil was approximately $36 per barrel. The crude oil price differential has improved during the first quarter of 2008 and is expected to be less than the $9.88 per barrel differential realized for first quarter 2007.
Net income for the three months ended December 31, 2006, was $30.2 million, or $0.19 per diluted share, after pro forma adjustments to provide for income taxes as if the Company had been a subchapter C corporation during the fourth quarter of 2006 and was $48.7 million, or $0.31 per diluted share, excluding pro forma adjustments.
Full Year 2007
Net income for the year ended December 31, 2006 was $156.8 million, or $0.96 per diluted share, after pro forma adjustments to provide for income taxes as if Continental had been a subchapter C corporation during 2006 and was $253.1 million, or $1.59 per diluted share, excluding pro forma adjustments.
The following table contains unaudited financial and operational highlights for the three months and year ended December 31, 2007 compared to the corresponding periods in the prior year.
Quarter Ended Year Ended December 31, December 31, 2007 2006 2007 2006 Average daily production: Crude oil (bopd) 24,309 22,028 23,832 20,494 Natural gas (Mcfd) 36,362 26,847 31,599 25,274 Crude oil equivalent (boepd) 30,369 26,503 29,099 24,706 Average prices: (1) Crude oil ($ / Bbl) $77.53 $47.89 $63.55 $55.30 Natural gas ($ / Mcf) $5.99 $5.71 $5.87 $6.08 Crude oil equivalent ($ / boe) $68.84 $45.57 $58.31 $52.09 Production expense ($ / boe) (1) $6.85 $6.88 $7.35 $6.99 EBITDAX (in thousands) (2) $144,074 $85,106 $469,885 $372,115 Net income (in thousands) $60,892 $48,743 $28,580 $253,088 Diluted net income per share $0.36 $0.31 $.17 $1.59 Pro forma net income (in thousands) (3) $30,221 $184,002 $156,833 Pro forma diluted net income per share $0.19 $1.11 $0.96 (1) Oil sales volumes were 125 MBbls less than oil production for the three months ended December 31, 2007 and 11 MBbls less than oil production for the three months ended December 31, 2006. Oil sales volumes were 221 MBbls less than oil production for the year ended December 31, 2007 and 21 Mbbls less than oil production for the year ended December 31, 2006. Average prices and per unit production expense have been calculated using sales volumes. (2) EBITDAX represents earnings before interest expense, income taxes (when applicable), depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains or losses and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles. A reconciliation of net income to EBITDAX is provided later in this press release. (3) In connection with the initial public offering, the Company recorded a charge of $198.4 million to recognize deferred taxes upon its conversion from a non-taxable subchapter S corporation to a taxable subchapter C corporation. The Company provides income taxes on net income for periods after the initial public offering. Pro forma net income reflects adjustments to provide for income taxes as if the Company had been a subchapter C corporation for the periods presented.
Quarter Ended Year Ended December 31, December 31, 2007 2006 2007 2006 (boe per (boe per (boe per (boe per day) day) day) day) Red River Units 14,374 11,732 13,356 10,842 Montana Bakken Field 7,244 7,591 7,613 7,041 North Dakota Bakken Field 1,382 314 967 152 Other Rockies 1,600 1,717 1,678 1,579 Oklahoma Woodford Field 1,338 57 832 32 Other Mid-Continent 3,767 4,223 4,083 4,069 Gulf Coast 664 869 570 991 Total 30,369 26,503 29,099 24,706
According to the year-end proved reserve report for the Red River Units, peak daily production is projected to be approximately 19,000 barrels of oil equivalent in 2009. The Company currently has five rigs drilling increased density wells within the Red River Units. Conversions of producing wells to injectors continues on schedule and the expansion of existing facilities for increased water injection and disposal capacity is approximately 50% complete. On February 5, 2008, Hiland Partners took the Badlands plant out of service when it discovered that a primary piece of equipment had failed. Hiland Partners anticipates that the plant will start up at the beginning of March. The Company's net natural gas sales from the Red River units were 5 MMcfd during the fourth quarter of 2007.
In the Montana Bakken Field, the Company completed 2 gross (1.3 net) third wells within existing 1280-acre units during 2007 with an average gross estimated ultimate recovery (EUR) of 468 Mboe. Additionally, the Company completed 8 gross (6.2 net) 640-acre tri-lateral step-out wells during 2007 with an average gross EUR of 245 Mboe. The proved reserve estimates for the 2007 infield and step-out programs support continuation of both efforts and, with more than 60 additional infield locations and approximately 60,000 net undeveloped acres north of the field for 640-acre tri-lateral step-out locations, we expect to keep two to three drilling rigs in the Montana Bakken field during 2008.
In the North Dakota Bakken Field, the Company continues to be pleased with its drilling results in the central and northern portions of its acreage holdings. The Company completed 27 Bakken Shale wells in the central and northern areas during 2007 with an average gross EUR of 335 Mboe, exceeding our economic model of 315 gross Mboe. If crude oil prices remain strong, the Company plans to seek Board approval in the second quarter to increase the 2008 drilling budget in the North Dakota Bakken Field.
The McGinnity 1-15H (54% WI), located in the northern portion of the Company's acreage holdings in the North Dakota Bakken Field, was recently completed using an uncemented liner within a long single lateral for an initial 7-day average production rate of 589 boepd. The Company also had a significant completion recently in the southern portion of its acreage with the Basaraba 44X-27 (26% WI) flowing at an initial 7-day average production rate of 463 boepd from an unstimulated, 1,280-acre tri-lateral wellbore. Of additional significance for the North Dakota Bakken play is the reservoir potential of the Three Forks-Sanish formation (TFS) found immediately below the lower Bakken Shale. As the middle Bakken and lower Bakken Shale sections expand it is more likely that the TFS formation contains incremental reserves not being drained by fracture stimulating the upper portion of the middle Bakken. The Company expects to spud its first TFS test in the next 30 days to begin evaluating the TFS potential. The Company also plans to participate in two non-operated TFS tests scheduled to be drilled in the first and second quarters.
In the Oklahoma Woodford Shale field, the Company recently completed four strategic wells, the Wilson 2-14H (23% WI), Tucker 2-26H (30% WI), Kimberley 1-11H (48% WI) and Mary 1-6H (86% WI) with initial 7-day average production rates of 6,392 Mcfd, 2,091 Mcfd, 2,900 Mcfd and 1,765 Mcfd, respectively. The Wilson 2-14H, located in the Ashland prospect, is the Company's first 320-acre increased density test and demonstrates the potential for down spacing in the play. The Tucker 2-26H and Kimberly 1-11H are of particular significance because they provide justification for expanded development of the northern and western extents of the Ashland prospect. The Mary 1-6H is an exploratory test located in the center of the Company's East McAlester prospect in the 15E-16E areas and supports further development of this area. The Company currently has four operated rigs in the play and plans to add one additional rig in the first half and one more rig in the second half of 2008. Most of the Company's operated drilling activity in 2008 is expect to focus on development and step-out opportunities within the Ashland and Rushing prospects.
As part of its development plan, the Company is preparing to conduct a simul-frac of 4 gross (1.3 net) wells currently being drilled on 160-acre spacing within the Ashland prospect. The Ashland Simul-Frac is designed to simultaneously fracture stimulate these four wells, drilled approximately 1,320 feet apart to better contain the stimulation and more effectively fracture the reservoir rock.
The Company continues to monitor production in the Salt Creek area and is in the process of acquiring approximately 18 square miles of 3D seismic data to further evaluate the potential of the prospect. The Company plans also to participate in the acquisition of approximately 53 square miles of 3D seismic over its East McAlester acreage during the second half of 2008.
The Company's Trenton/Black River project in and around Hillsdale County, Michigan continues to produce excellent results. Guided by innovative 3D seismic techniques, the Company has experienced 100% success completing 3 gross (2.5 net) operated wells in the project. The Company's initial discovery well, the McArthur 1-36 (83% WI) is flowing 260 bopd and has been assigned gross proved reserves of 824,000 barrels of crude oil equivalent. The Company's second well, the Anspaugh 1-1 (83% WI) encountered similar type pay and is currently flow testing 200 bopd. The Company's third well, the Wessel 1-6 (83% WI) recently began testing flowing at rates up to 100 barrels of oil per hour during cleanup. Testing will continue on the Anspaugh 1-1 and Wessel 1-6 to establish reservoir characteristics and estimated reserves. The Company has also participated in 2 gross (0.6 net) non-operated Trenton/Black River tests. The Clark 1-36 (21% WI) is testing very low volumes of oil. The Young 10-34 (42% WI) encountered encouraging shows while drilling and is currently waiting on completion. The Company owns 35,200 gross (29,200 net) acres in the Trenton/Black River play and has shot, processed and interpreted 11 square miles of 3D seismic on the acreage so far. The Company is currently permitting and will begin acquisition of 20 square miles of new 3D data in March with plans to acquire additional data later this year. The Company plans to drill five additional wells in the second and third quarters of 2008.
Conference Call Information
About Continental Resources
CONTACT: Continental Resources, Inc.
Non-GAAP Financial Measures
Three months ended Year ended December 31, December 31, (in thousands) 2007 2006 2007 2006 (unaudited) (unaudited) Net income $60,892 $48,743 $28,580 $253,088 Unrealized oil derivative loss 20,822 - 26,703 - Income tax expense (benefit) 24,868 - 268,197 (132) Interest expense 3,085 2,787 12,939 11,310 Depreciation, depletion, amortization and accretion 26,326 19,052 93,632 65,428 Property impairments 4,887 2,671 17,879 11,751 Exploration expense 2,499 10,653 9,163 19,738 Equity compensation 695 1,200 12,792 10,932 EBITDAX $144,074 $85,106 $469,885 $372,115
SOURCE Continental Resources, Inc.