Continental Resources Reports Fourth Quarter and Year-End 2007 Results
ENID, Okla., Feb. 26 /PRNewswire-FirstCall/ — Continental Resources, Inc. (“Continental” or the “Company”) today reported unaudited fourth quarter and year-end 2007 results.
(Logo: http://www.newscom.com/cgi-bin/prnh/20070501/DATU029LOGO) 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
Continental reported net income for the year ended December 31, 2007, of $28.6 million, or $0.17 per diluted share, on revenues of $582.2 million. Reported net income includes a one-time charge of $198.4 million for the initial establishment of deferred taxes that were recognized in conjunction with the Company’s conversion from a subchapter S corporation to a subchapter C corporation as of the Company’s initial public offering in May 2007. Additionally, reported net income includes an unrealized loss of $26.7 million ($16.6 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 2007 was $243.6 million, or $1.47 per diluted share, excluding the effect of these items.
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. Management Comments
Harold Hamm, Chairman and Chief Executive Officer stated, “2007 was an exciting year for Continental as we completed our initial public offering, celebrated our fortieth anniversary and posted record financial and operating results. Our decision to store some crude oil production in late 2007 rather than sell at a significant discount has been rewarded with much narrower differentials in early 2008. We are very pleased with the two recent successful confirmation tests in the Michigan Trenton/Black River project. As a result, we have confidence in our 3D seismic interpretations and have five additional wells planned early this year. In the North Dakota Bakken play, drilling results have exceeded our expectations and, with continued strong crude oil prices, we will likely expand the 2008 drilling budget in this region as well.”
Operations Update
The following table presents unaudited average daily production for each of the Company’s principal areas 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 (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 Presentation
Continental plans to participate in the Raymond James 29th Annual Institutional Investors Conference to be held in Orlando, Florida from March 2 through March 5, 2008. President Mark E. Monroe is scheduled to present at the conference on Monday, March 3, 2008 at 1:05 p.m. Eastern Time. Mr. Monroe’s presentation will be webcast live on the Company’s website at http://www.contres.com/.
Conference Call Information
The Company will host a conference call on Tuesday, February 26, 2008, at 9:00 a.m. Eastern 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 (888) 679-8037. The passcode is 21999378. Participants may pre-register for this conference call. Pre-registration is not mandatory. Callers who pre-register will be given a unique PIN to gain immediate access to the call and bypass the live operator. Callers may pre-register at any time, including up to and after the call start time, by going to the following URL: https://www.theconferencingservice.com/prereg/key.process?key=PNUVWEYCJ A replay of the conference call will be available for 30 days on the Company’s website or by dialing (888) 286-8010. The replay passcode is 99066154.
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.
Forward-Looking Information
This press release 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 press release, 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 are forward-looking information. All forward-looking statements speak only as of the date of this press release. 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. J. Warren Henry, 580-548-5127 ir@contres.com Condensed Consolidated Statements of Income (in thousands, except per share amounts) Three months ended Year ended December 31, December 31, 2007 2006 2007 2006 (unaudited) (unaudited) Revenues: Oil and natural gas sales $183,780 $110,598 $606,514 $468,602 Loss on mark-to-market derivatives (30,476) – (44,869) – Oil and natural gas service operations 5,690 3,315 20,570 15,050 Total revenues $158,994 $113,913 $582,215 $483,652 Operating costs and expenses: Production expense $18,288 $16,705 $76,489 $62,865 Production tax 10,251 5,721 32,562 22,331 Exploration expense 2,499 10,653 9,163 19,738 Oil and natural gas service operations 3,942 1,587 12,709 8,231 Depreciation, depletion, amortization and accretion 26,326 19,052 93,632 65,428 Property impairments 4,887 2,671 17,879 11,751 General and administrative 5,148 6,503 32,802 31,074 (Gain) loss on sale of assets (650) 2 (988) (290) Total operating costs and expenses 70,691 62,894 274,248 221,128 Income from operations 88,303 51,019 307,967 262,524 Interest expense and other (2,543) (2,276) (11,190) (9,568) Net income before income tax expense 85,760 48,743 296,777 252,956 Income tax expense (benefit) 24,868 268,197 (132) Net income $60,892 $48,743 $28,580 $253,088 Basic net income per share $0.36 $0.31 $0.17 $1.60 Diluted net income per share $0.36 $0.31 $0.17 $1.59 Basic weighted average shares outstanding 167,590 158,279 164,059 158,114 Diluted weighted average shares outstanding 169,255 159,247 165,422 159,665 Condensed Consolidated Balance Sheets (in thousands) December 31, 2007 2006 (unaudited) Assets: Cash and cash equivalents $8,761 $7,018 Receivables 163,090 89,086 Inventories and other 33,713 8,877 Net property and equipment 1,157,926 751,747 Other assets 15,163 2,201 Total assets $1,378,653 $858,929 Liabilities and shareholders’ equity: Current liabilities $266,106 $188,637 Long-term debt 165,000 140,000 Other noncurrent liabilities 39,511 39,831 Deferred income taxes 284,904 – Shareholders’ equity 623,132 490,461 Total liabilities and shareholders’ equity $1,378,653 $858,929 Condensed Consolidated Statements of Cash Flows (in thousands) Year ended December 31, 2007 2006 (unaudited) Net income $28,580 $253,088 Adjustments to reconcile net income to net cash provided by operating activities: Non-cash expenses 424,392 102,177 Changes in assets and liabilities (60,694) 61,776 Net cash provided by operating activities 392,278 417,041 Net cash used in investing activities (483,498) (324,523) Net cash provided by (used in) financing activities 92,938 (91,451) Effect of exchange rate on change in cash and cash equivalents 25 (63) Net change in cash and cash equivalents 1,743 1,004 Cash and cash equivalents at beginning of period 7,018 6,014 Cash and cash equivalents at end of period $8,761 $7,018 Non-GAAP Financial Measures
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 (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 to EBITDAX.
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
Photo: NewsCom: http://www.newscom.com/cgi-bin/prnh/20070501/DATU029LOGOAP Archive: http://photoarchive.ap.org/PRN Photo Desk, photodesk@prnewswire.com
Continental Resources, Inc.
CONTACT: J. Warren Henry of Continental Resources, Inc.,+1-580-548-5127, ir@contres.com
Web site: http://www.contres.com/