Continental Resources Reports Second Quarter 2007 Results and Updates Guidance
Net income after pro forma adjustments to provide for income taxes as if Continental had been a subchapter C corporation during the entirety of both quarters is $44.2 million, or $.27 per diluted share, for the three months ended June 30, 2007 and $41.0 million, or $.26 per diluted share, for the three months ended June 30, 2006.
The following table contains unaudited financial and operational highlights for the three and six months ended June 30, 2007 compared to the corresponding periods in the prior year.
Three months ended Six months ended June 30, June 30, 2007 2006 2007 2006 Average daily production: Crude oil (bopd) 23,674 19,921 23,391 19,278 Natural gas (Mcfd) 29,618 23,159 29,229 24,274 Crude oil equivalent (boepd) 28,610 23,781 28,262 23,323 Average prices: (1) Crude oil ($ / Bbl) $58.25 $58.60 $53.44 $55.93 Natural gas ($ / Mcf) $6.07 $5.74 $6.11 $6.46 Crude oil equivalent ($ / boe) $54.44 $54.75 $50.52 $52.92 Production expense ($ / boe) (1) $8.42 $6.67 $7.43 $7.27 EBITDAX (in thousands) (2) $108,659 $96,889 $199,655 $174,506 Net income (loss) (in thousands) (3) $(142,498) $66,061 $(88,684) $116,354 Diluted net income (loss) per share $(0.87) $0.41 $(0.55) $0.73 (1) Oil sales volumes are 31 MBbls less than oil production for the three months ended June 30, 2007 and 45 MBbls greater than oil production for the three months ended June 30, 2006. Oil sales volumes are 47 MBbls and 51 MBbls less than oil production for the six months ended June 30, 2007 and 2006, respectively. 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 and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). A reconciliation of net income to EBITDAX is provided later in this press release. (3) In connection with the IPO, 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 IPO. Management Comments
"The 20% increase in daily equivalent production was the principal driver for the higher revenues and EBITDAX during the second quarter of 2007 compared to the second quarter of 2006", said Harold Hamm, Chairman and Chief Executive Officer. "Additionally, our financial results benefited from a $3.92 per barrel improvement in our crude oil basis differential from first quarter 2007 to second quarter 2007."
"With higher expected revenues as a result of current crude oil prices and our recent $72.90 crude oil hedges, I will be recommending to the Board an increase in our 2007 capital expenditure budget to $482 million, an increase of $45 million", said Mr. Hamm. "The Company has continued a four drilling rig schedule in the Montana Bakken area longer than originally planned in order to take advantage of this favorable crude oil drilling economic environment and expects to drill 11 additional net wells in the Montana Bakken this year. I think it makes a lot of sense to target increasing crude oil production during this time. The proposed budget increase also includes $5 million for acreage acquisitions, bringing the new land budget amount to $37 million."
Delays in completion of the new Hiland Partners Badlands Plant limited natural gas sales in the Red River Units to less than 200 net Mcf per day during the second quarter. The plant is now expected to be operational in August with the Company's share of natural gas volumes growing to approximately 10,000 MMBtus per day by the end of this year. Due to the delays in commencement of gas sales at the Badlands Plant and delays in completions and pipeline connections in the Woodford Shale area, full year natural gas production is expected to be near or below the low end of the guidance range of 13,800 to 15,000 MMcf. However, crude oil production is expected to be near the high end of the guidance range of 8,400 to 8,800 Mbbls. As a result, the Company is maintaining its equivalent production guidance range of 10,700 to 11,300 Mboe.
Greater workover activity and higher labor and service costs led to a production cost per boe of $8.42, outside the guidance range for the second quarter 2007. In the first quarter 2007, production costs were $6.40 per boe, outside the guidance range on the low side. Some of the workover and other production operations conducted during the second quarter would have been incurred during the first quarter were it not for cold weather conditions in the Rocky Mountain region. The Company believes full year production cost per boe will be within the guidance range of $6.50 to $7.20 per boe, though likely at the high end of the range.
The guidance for depreciation, depletion, amortization and accretion is being increased to between $9.00 and $9.50 per boe. The relative contribution of production from higher cost basis properties is greater that originally estimated.
The following table presents average daily production for each of the Company's principal regions for the three months ended June 30, 2007 compared to the three months ended June 30, 2006 and March 31, 2007.
Q2 2007 Q2 2006 Q1 2007 (boe per day) (boe per day) (boe per day) Red River Units 12,680 10,806 12,599 Montana Bakken Field 7,890 6,406 7,685 North Dakota Bakken Field 924 79 429 Other Rockies 1,774 1,556 1,724 Oklahoma Woodford Field 586 20 440 Other Mid-Continent 4,320 3,949 4,307 Gulf Coast 436 965 727 Total 28,610 23,781 27,911
In the Red River Units, average daily production was up 17% from the second quarter 2006 average. During the second quarter, the Company completed 7 gross (6.8 net) horizontal wells and 3 gross (2.9 net) horizontal re-entries within the Red River Units. The Company currently has five drilling rigs working in the Red River Units.
In the Montana Bakken field, average daily production was up 23% from the second quarter 2006 average due to results from the infield drilling program. During the second quarter, the Company participated in 10 gross (6.7 net) completed wells in the Bakken field with 100% success. The Company is finishing development of its acreage on 640-acre spacing and is currently evaluating the potential to develop the Montana Bakken on 320 acre spacing. The Company's initial 320-acre well, the Margaret 3-15H, completed in April is currently producing about 180 boepd and appears to meet or exceed our economic model of 300 MBoe of ultimate per well reserves for increased density wells. The Company's second 320-acre well, the Dorothy 3-33H, is currently drilling. The Company's second 640-acre tri-lateral in the northern part of the field, the Sonja 1-34H, has been producing 35 days at an average rate of 245 bopd and appears to exceed our economic model of 250 MBoe of ultimate per well reserves for the field extension wells.
In the North Dakota Bakken field, average daily production was up 845 boepd from the second quarter 2006 average. During the second quarter, the Company participated in 9 gross (4.6 net) completed wells in the North Dakota Bakken field with 100% success. The Company currently has two operated drilling rigs working in the field and three drilling rigs operated under a joint venture agreement with ConocoPhillips. The Company expects to add an additional operated drilling rig in the North Dakota field in September. Recent completions in the North Dakota field include the Brown 44-1H (35% WI) for 519 gross bopd and the State Veeder 41-36H (46% WI) completed for 344 bopd. The 2007 exit rate for North Dakota Bakken Shale production is forecasted to be 2,000 net boepd.
In the Oklahoma Woodford Shale field in the Mid-Continent region, the Company currently has four operated drilling rigs working and plans to add a fifth drilling rig in August. During the second quarter, the Company completed 4 gross (1.5 net) Woodford Shale wells and participated in another 15 gross (1.0 net) non-operated Woodford Shale completions. The Company-operated completions, the Arlan 1-15H (20% WI), Pasquali 1-30H (48% WI), Harden 1-20H (32% WI) and Holder 1-5H (53% WI) had 7-day average initial production rates of 4,645 Mcfd, 1,360 Mcfd, 2,125 Mcfd and 1,204 Mcfd of natural gas, respectively. Recently, the Company completed the Pratt 1-17H (23% WI) for a 7-day average initial production rate of 3,752 Mcfd. The 2007 exit rate for Oklahoma Woodford Shale production is forecasted to be 15,000 net Mcfd.
Conference Call Information
The Company will host a conference call on Monday, August 6, 2007, at 10:00 a.m. Central Time to discuss this press release. Interested parties may listen to the conference call via the Company's website at http://www.contres.com/ or by dialing (866) 271-6130. The passcode is 44488326. A replay of the conference call will be available for 30 days on the Company's website or by dialing (888) 286-8010. The passcode is 23421529.
The Company also announced its participation in The Oil & Gas Conference to be held in Denver, Colorado on August 19 - 23, 2007. President Mark E. Monroe will present at the conference on Wednesday, August 22, 2007, at 4:00 p.m. Mountain Time. Mr. Monroe's presentation will be webcast live on the Company's website at http://www.contres.com/ and at http://www.theoilandgasconference.com/index.html.
About Continental Resources
Continental Resources is an independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. The Company focuses its operations in large new or developing plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves from unconventional formations. The Company completed its initial public offering in May 2007.
This press release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control. All information, other than historical facts included in this press release, 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 crude 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.
CONTACT: Continental Resources, Inc. Don Fischbach, 580-548-5137
EBITDAX represents earnings before interest expense, income taxes (when applicable), depreciation, depletion, amortization and accretion, property impairments, exploration expense and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a Company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. The Company's computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet future debt service requirements, if any. The Company's credit facility requires that it maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1 on a rolling four-quarter basis. The credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table represents a reconciliation of the Company's net income loss to EBITDAX.
Three months ended Six months ended June 30, June 30, (in thousands) 2007 2006 2007 2006 (unaudited) (unaudited) Net income (loss) $(142,498) $66,061 $(88,684) $116,354 Provision for income taxes 213,789 - 213,789 - Interest expense 3,427 2,936 7,080 5,421 Depreciation, depletion, amortization and accretion 23,330 14,689 43,738 27,981 Property impairments 5,923 6,318 8,893 7,733 Exploration expense 1,602 2,985 3,906 5,067 Equity compensation 3,086 3,900 10,933 11,950 EBITDAX $108,659 $96,889 $199,655 $174,506
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SOURCE: Continental Resources, Inc.
CONTACT: Don Fischbach of Continental Resources, Inc., +1-580-548-5137,
Web site: http://www.contres.com/