ENID, Okla., Feb. 23, 2011 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) reported strong growth in crude oil and natural gas production for 2010. Total production of 15.8 million barrels of oil equivalent (MMBoe) for the year represented a 16 percent gain over production of 13.6 MMBoe for 2009.
"We achieved our 2010 production target and again reported strong growth in oil-concentrated proved reserves," said Harold Hamm, Chairman and Chief Executive Officer. "We're on track today for 30 percent production growth in 2011."
Fourth Quarter 2010 Results
The Company reported production of 48,034 barrels of oil equivalent per day (Boepd) for the fourth quarter of 2010, a 27 percent increase over production of 37,747 Boepd for the fourth quarter of 2009 and an increase of seven percent over production in the third quarter of 2010.
Crude oil accounted for 73 percent of Continental's fourth quarter 2010 production.
Continental's proved reserves grew to 364.7 MMBoe as of December 31, 2010, 42 percent higher than proved reserves of 257.3 MMBoe at year-end 2009.
The bulk of the increase reflected its drilling program in the Bakken play, which is expected to continue leading Continental's growth.
For the fourth quarter of 2010, the Company reported a net loss of $45.0 million, or $0.27 per diluted share, compared with net income for the fourth quarter of 2009 of $49.5 million, or $0.29 per diluted share.
The net loss for the fourth quarter of 2010 included a $188.4 million loss on mark-to-market derivative instruments, a $15.6 million pre-tax property impairment charge, and a $2.2 million loss on sale of an asset. The loss on derivative instruments was comprised of a $194.4 million unrealized loss, offset partially by a $6.0 million realized gain.
In the fourth quarter, the combined impairment charge, loss on sale of asset and $194.4 million unrealized loss on derivatives reduced net income by $0.78 cents per share on an after-tax basis.
"Throughout 2010 we put in place a series of price swaps and collars to reduce the uncertainty of future cash flow in order to underpin our capital expenditures and drilling plan for the next three years," Mr. Hamm said.
Net income for 2010 as a whole was $168.3 million, or $0.99 per diluted share, compared with net income of $71.3 million, or $0.42 per diluted share for 2009. For 2010, the combined effect of unrealized derivative losses, total property impairment charges, and gain on sale of assets reduced net income by $0.74 cents per share.
Crude oil and natural gas sales were $273.1 million for the fourth quarter of 2010, compared with $203.3 million for the same period of 2009.
Continental reported EBITDAX of $220.9 million for the fourth quarter of 2010, a 40 percent increase over EBITDAX of $158.1 million for the fourth quarter of 2009 and a 12 percent increase over EBITDAX for the third quarter of 2010.
Full-year 2010 EBITDAX was $810.9 million, an increase of 80 percent over 2009 EBITDAX of $450.6 million. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.
Continental's average realized crude oil price was $75.41 per barrel in the fourth quarter of 2010, while the average realized natural gas price was $4.15 per Mcf, yielding a blended realized price of $61.98 per Boe. In the fourth quarter of 2009, the Company realized a blended price of $56.69 per Boe.
The Company's crude oil price differential for the fourth quarter of 2010 was $9.92 per barrel, and its natural gas price differential was a premium of $0.35 per Mcf.
Production expense was $5.31 per Boe for the fourth quarter of 2010, compared with $6.71 per Boe for the fourth quarter of 2009. The Company attributed the reduced production expense in 2010 primarily to renegotiated equipment leases and reduced injectant costs in the Red River Units, as well as new production growth.
General and administrative expense was $3.09 per Boe for the fourth quarter of 2010, compared with $3.18 per Boe for the comparable period in 2009.
As of December 31, 2010, the Company's balance sheet included $7.9 million in cash and $926.0 million in long-term debt. The Company's long-term debt at year-end 2010 included $30.0 million in borrowings under its $750 million revolving credit facility.
2010 Proved Reserves Grow 42 Percent
Continental increased its proved reserves to 364.7 MMBoe for the year ended December 31, 2010. The additions primarily reflected the Company's accelerated drilling in the North Dakota Bakken. During 2010, Continental completed or participated in completing 76.5 net wells in the Bakken.
Total reserve additions were 95.2 MMBoe, which equated to 602 percent of the year's production of 15.8 MMBoe. Essentially all of Continental's 2010 reserve additions were the result of the Company's exploration and production efforts; only 0.4 MMBoe of proved reserves were acquired by purchase. The proved reserve additions and acquisitions were at an average finding and development (F&D) cost of $12.42 per Boe, excluding revisions. The Company also reported 27.6 MMBoe in positive revisions, yielding a total F&D cost of $9.63, including revisions.
Of the total 2010 proved reserves, 38 percent were proved developed producing (PDP).
The Company's 2010 proved reserves included 1,282 gross (546.7 net) proved undeveloped locations (PUDs). Of these, 393.7 net PUDs, or 72 percent of the total, are located in the Bakken Shale play.
"We have a tremendous, multi-decade growth platform," Mr. Hamm said.
Continental's 2010 proved reserves are primarily located in three plays: The Bakken and the Red River Units in Montana, North Dakota and South Dakota; and in the Oklahoma Woodford play. The Bakken accounted for 54 percent of proved reserves, followed by the Oklahoma Woodford with 26 percent and the Red River Units with 15 percent.
Continental's 2010 proved reserves represented $12.0 billion in undiscounted future net cash flows, before income taxes, with a net present value discounted at 10 percent (PV-10) of $4.6 billion. Continental's standardized measure of discounted future net cash flows, which differs from PV-10 by including the effects of income taxes on future net cash flows, was $3.8 billion at December 31, 2010, representing an $0.8 million difference from PV-10, because of the tax effect.
Ryder Scott Company, L.P. evaluated properties representing 100 percent of the Company's PUDs and 94 percent of Continental's PV-10 at year-end 2010, with Continental reserve engineers evaluating the remaining properties.
Three months ended
Average daily production:
Crude oil (Bopd)
Natural gas (Mcfpd)
Crude oil equivalents (Boepd)
Average sales prices: (1)
Crude oil ($/Bbl)
Natural gas ($/Mcf)
Crude oil equivalents ($/Boe)
Production expense ($/Boe) (1)
EBITDAX (in thousands)
Net income (loss) (in thousands)
Diluted net income (loss) per share
(1) Average sales prices and per-unit expenses are calculated based on sales volumes, and
exclude any effect of derivatives. Crude oil production exceeded sales volumes in the fourth
quarter of 2010 by 12 thousand barrels (MBbls); crude oil sales exceeded production volumes
in the fourth quarter of 2009 by 114 MBbls. Crude oil sales exceeded production volumes for
fiscal 2010 by 78 MBbls; crude oil production exceeded sales volumes in fiscal 2009 by 82 MBbls.
The following table presents the Company's average daily production by region for the periods presented.
Boe per day
North Dakota Bakken
Red River Units
Bakken Shale Play (North Dakota and Montana)
For the fourth quarter of 2010, Bakken production climbed to 22,520 Boepd, or 47 percent of Continental's total production, compared with 36 percent of production in the fourth quarter of 2009. On a year-over-year basis, Continental's Bakken production increased 64 percent over the fourth quarter of 2009.
In the North Dakota portion of the Bakken, Continental's fourth quarter 2010 production was 17,834 Boepd, an increase of 113 percent over the total for the fourth quarter of 2009.
The Company participated in completing 77 gross (26.4 net) wells in the North Dakota Bakken in the fourth quarter of 2010, with initial production rates averaging 1,002 Boepd during single-day test periods. During 2010 as a whole, the Company completed or participated in completing 222 gross (71.1 net) wells in the North Dakota Bakken, bringing its total wells drilled in this part of the play to 475 gross (150.2 net) wells at December 31, 2010.
Continental has restricted initial production rates on a significant number of its Bakken wells to minimize natural gas flaring and in response to constraints in transportation capacity primarily related to periodic severe winter weather conditions.
Notable Company-operated wells completed in North Dakota during the fourth quarter of 2010 (with initial test period gross production results) included:
- Rolfsrud 1-11H (43% WI) in McKenzie Co. – 1,713 Boepd;
- Jerol 1-27H (28% WI) in Williams Co. – 1,663 Boepd;
- Brandvik 2-25H (45% WI) in Dunn Co. – 1,630 Boepd;
- Olson 2-8H (33% WI) in McKenzie Co. – 1,613 Boepd;
- Evenson 1-19H (69% WI) in Divide Co. – 1,426 Boepd;
- Hendrickson 2-36H (83% WI) in McKenzie Co. – 1,323 Boepd; and
- Tangsrud 2-1H (92% WI) in Divide Co. – 1,023 Boepd.
In addition, Continental completed three ECO-Pad® projects in North Dakota during the fourth quarter of 2010. ECO-Pad technology allows four wells (two Middle Bakken, two Three Forks) to be drilled from a single pad on two adjoining 1,280-acre spacing units. Application of ECO-Pad technology is expected to increase recoveries per well and to reduce drilling costs, completion costs and environmental impact by centralizing operations on a single pad. The three ECO-pad projects are listed below with their gross initial production results.
The Miles-Kennedy ECO-Pad wells were drilled in McKenzie County. This project involved the Miles 1-6H and 2-6H (31% WI for each) and the Kennedy 1-31H (31% WI) and 2-31H (67% WI). Initial production averaged 1,377 Boepd, with the strongest well testing at 1,448 Boepd.
The Glasoe-Raymo ECO-Pad project was drilled in Divide County. This involved the Glasoe 2-19H (46% WI) and 3-19H (50% WI) and the Raymo 1-30H (71% WI) and 2-30H (76% WI). Initial production averaged 940 Boepd per well for the four wells, with the strongest well testing at 1,129 Boepd.
The Bridger-Bonneville ECO-Pad project was drilled in Dunn County. It involved the Bridger 2-14H and 3-14H (47% WI for each) and the Bonneville 2-23H and 3-23H (47% WI for each). Initial production (restricted) averaged 745 Boepd per well for the four wells, with the strongest well testing at a restricted 883 Boepd.
In Montana, Continental announced the completion of two notable wells in Richland County in the fourth quarter of 2010. The Tolksdorf 1-1H (95% WI) and the Baxter 1-5H (33% WI) were completed in the extension area north and northeast of the Elm Coulee Field fairway, and had initial production test rates of 642 gross Boepd and 412 gross Boepd, respectively. The two wells were fracture-stimulated with 24 stages each.
"We're pleased with the outcome on these two wells. This sets up the area for continued development, expanding the field with new technology," Mr. Hamm said. At year-end 2010, Continental had 165,316 net undeveloped acres leased in the Montana Bakken.
Continental completed or participated in 11 gross (5.5 net) wells in the Montana Bakken during 2010. As of year-end 2010, the Company had completed 171 gross (108.6 net) wells in the Montana portion of the play.
"Continental completed the first commercially viable well in the North Dakota Bakken that used both horizontal drilling and fracture stimulation – the Robert Heuer 1-17R in Divide County in March 2004," Mr. Hamm said. "We were an early pioneer in the play, and since then we've established Continental as the leading leaseholder. We expect the Bakken to drive our growth for many years."
At year-end 2010, Continental had a total of 855,936 net acres leased in the Bakken play, with 623,649 net acres leased in North Dakota and 232,287 net acres in Montana. The Company has 21 operated drilling rigs in North Dakota and two in Montana.
Red River Units (Montana, North Dakota and South Dakota)
The Company's production in the Red River Units averaged 13,896 Boepd in the fourth quarter of 2010. Continental currently has two operated rigs active in the Units, completing its increased density drilling pattern in the water-flood secondary recovery project.
Niobrara Shale Play (Colorado and Wyoming)
Continental began drilling the Newton 1-4H (87% WI) in early February 2011 in Weld County, Colorado. The Newton 1-4H is the first 1,280-acre spaced well in the Niobrara, which the Company expects will yield superior economics compared with 640-acre spaced wells.
The Company plans to drill five gross (3.3 net) wells in the Niobrara in 2011. It currently has 71,712 net acres leased in the DJ Basin - Niobrara.
Fort Union (Wyoming)
During 2010, the Company participated in completing two conventional Fort Union sand wells in Sweetwater County, Wyoming. The Barricade 24-36 (22% WI) was completed November 10 with an initial production test rate of 5.0 gross MMcfpd of natural gas and 198 gross Bopd.
The Barricade 11-7 (40% WI) was completed November 18 with an initial production test rate of 4.4 gross MMcfpd of natural gas and 100 gross Bopd.
Continental owns an average 22 percent working interest in the 12,970 gross acre Barricade Unit and a seven percent average working interest in the adjacent 8,640 gross acre Endurance Unit. Based on well control in the area, Continental believes its entire acreage position is prospective for development on 40-acre spacing. The two Barricade wells indicate an average estimated ultimate recovery (EUR) of 2.65 Bcf of natural gas and 58,000 Bo per well.
Woodford Shale Play (Oklahoma)
Production in the Anadarko Woodford Shale play in western Oklahoma was 1,705 Boepd in the fourth quarter of 2010, an increase of 130 percent over the fourth quarter of 2009 and an increase of 24 percent over the third quarter of 2010. Increased production reflects the Company's quickening pace of drilling in late 2010.
During 2010, the Company completed or participated in 16 gross (8.2 net) wells in the Anadarko Woodford, delineating the productive potential of the play from the Northwest Cana to the Southeast Cana, a distance of 90 miles.
In January 2011, Continental completed the Sprowls 1-14H (100% WI) in Grady County, 17 miles northwest of the Dana 1-29H, which the Company announced in October 2010. The Company previously established production in the Dana 1-29H, which is 41 miles southeast of the center of the Cana Play.
The Sprowls 1-14H was completed flowing at 2.8 gross MMcfpd and 96 gross Bopd in its initial test period. It is producing rich gas, 1313 Btu per Mcf , which is characteristic of the Southeast Cana. At a residue price of $3.95 per MMBtu, the Sprowls 1-14H had a wellhead price of $8.45 per Mcf for its January gas production.
"The Sprowls 1-14H gives us a pair of strong wells at the southeast end of the current extent of the Anadarko Woodford," Mr. Hamm said. "In the Northwest Cana, we completed the Brown 1-2H and the Doris 1-25H. In the Southeast Cana, we now have the Dana 1-29H confirmed by the Sprowls 1-14H.
"We are currently working to extend the Southeast Cana even farther, drilling a test well 24 miles southeast of the Dana 1-29H to determine how far the Southeast Cana's productivity extends."
In Northwest Cana, Continental's type curve on wells completed to date reflects an EUR of 6.6 Bcf of natural gas and 85,000 barrels of crude oil. BTU content of the gas is typically about 1200. In Southeast Cana, the Company's type curve for wells completed in the silica-rich section reflects an EUR of 4.6 Bcf of natural gas and 88,000 barrels of crude oil. The Southeast Cana typically produces gas with a BTU content in excess of 1300.
Continental has now completed four wells in the Southeast Cana: The McCalla 1-11H, Ballard 1-17H, Dana 1-29H and the Sprowls 1-14H. January 2011 natural gas sales prices for these wells were in a range of $7.00 to $8.45 on a wellhead Mcf basis.
"Given the rich gas and oil production, even at current low gas prices, we're seeing 40 percent-plus rates of return in the Northwest Cana and 30 percent-plus in the Southeast," Mr. Hamm said.
Continental plans to complete or participate in 99 gross (28.8 net) wells in the Anadarko Woodford in 2011. It currently has 10 operated rigs in the play, with nine in the Northwest Cana part of the play and one in the Southeast Cana.
In the Arkoma Woodford Shale play of Oklahoma, the Company's production was 4,403 Boepd in the fourth quarter of 2010, an increase of 23 percent over production in the fourth quarter of 2009. The increase reflected drilling activity in the East Krebs portion of the Arkoma Woodford in the past year. The Company currently has one operated rig active in the area.
At year-end 2010, the Company had 322,194 net acres leased in the Oklahoma Woodford, of which 267,542 net acres are in the Anadarko Woodford.
Paris Basin Opportunity
Continental initiated a process in the fourth quarter of 2010 to secure permits to develop four blocks covering approximately 67,000 net acres in the Paris Basin in France. The permits would be valid for five years. Continental is pursuing the Paris Basin opportunity in an 80/20 joint venture with Jordan Oil and Gas of Healdsburg, California. The two companies have worked together on several projects in North Dakota, and Jordan Oil and Gas has operating experience in France and other international oil and gas plays.
If awarded the permits, Continental and Jordan together would commit to invest a minimum of approximately $13.8 million over a four-year period. The French government is expected to rule on the permit applications by year-end 2011.
"We believe there is the potential for significant recoverable oil reserves, using technology that we've developed in the Bakken," Mr. Hamm said.
Conference Call Information
Continental Resources plans to host its fourth quarter 2010 earnings conference call on Thursday, Feb. 24, 2011 at 10 a.m. ET to discuss its results for the quarter. Those wishing to listen to the conference call may do so via the Company's web site at www.contres.com or by phone:
Time and date:
10 a.m. ET
Thursday, Feb. 24, 2011
888 680 0860
Intl. dial in:
617 213 4852
A replay of the call will be available later for 30 days on the Company's web site or by dialing:
888 286 8010
617 801 6888
Continental management is currently scheduled to present at the following research conferences. Presentation materials will be available on the Company's web site.
Raymond James 32nd Annual Institutional Investors Conference, Orlando
Howard Weil 39th Annual Energy Conference, New Orleans
Platt's Rockies Oil and Gas Conference, Denver
Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company. The Company focuses its operations in large new and 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.
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. Other than historical facts included in this press release, all information 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, changes in estimates of projected crude oil and natural gas recoveries from certain fields, 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, changes in regulatory constraints, and other factors listed in reports we have filed or may file with the Securities and Exchange Commission. The Company undertakes no obligation to publicly update any forward-looking statement to reflect events or circumstances that may arise after the date of this press release.
Warren Henry, VP Investor Relations
Brian Engel, VP Public Affairs
Consolidated Statements of Income
Ended December 31,
In thousands, except per share data
Crude oil and natural gas sales
Gain (loss) on mark-to-market derivative instruments
Crude oil and natural gas service operations
Operating costs and expenses:
Production taxes and other expenses
Crude oil and natural gas service operations
Depreciation, depletion, amortization and accretion
General and administrative expenses (1)
(Gain) loss on sale of assets
Total operating costs and expenses
Income (loss) from operations
Other income (expense):
Income (loss) before income taxes
Provision (benefit) for income taxes
Net income (loss)
Basic net income (loss) per share
Diluted net income (loss) per share
Basic weighted average shares outstanding
Diluted weighted average shares outstanding
(1) Includes non-cash charges for stock-based compensation of $3.1 million and $2.8 million for the three
months ended December 31, 2010 and 2009, respectively, and $11.7 million and $11.4 million for
the years ended December 31, 2010 and 2009, respectively.
Consolidated Balance Sheets
Cash and cash equivalents
Inventories and other current assets
Net property and equipment
Debt issuance costs, net
Liabilities and shareholders' equity:
Other noncurrent liabilities
Total liabilities and shareholders' equity
Consolidated Statements of Cash Flows
Adjustments to reconcile net income to net cash provided by operating activities:
Changes in assets and liabilities
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Non-GAAP Financial Measures
EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, unrealized derivative gains and losses, and non-cash equity compensation expense. EBITDAX is not a measure of net income or cash flows as determined by U.S. GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows as determined in accordance with U.S. 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. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our revolving credit facility requires that we maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1.0 on a rolling four-quarter basis. Our revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. The following table is a reconciliation of our net income to EBITDAX.
ended December 31,
Net income (loss)
Provision (benefit) for income taxes
Depreciation, depletion, amortization and accretion
Unrealized losses on derivatives
Non-cash equity compensation
SOURCE Continental Resources