Continental Resources Increases Production 20 Percent in Third Quarter of 2010, Compared With Third Quarter 2009
ENID, Okla., Nov. 3, 2010 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) reported strong growth in crude oil and natural gas production and strong year-over-year EBITDAX growth for the three months ended September 30, 2010.
(Logo: http://photos.prnewswire.com/prnh/20080505/LAM014LOGO)
(Logo: http://www.newscom.com/cgi-bin/prnh/20080505/LAM014LOGO)
Production was 44,775 barrels of oil equivalent per day (Boepd) for the third quarter of 2010, a 20 percent increase over production of 37,384 Boepd for the third quarter of 2009 and seven percent higher than daily production for the second quarter of 2010. Crude oil accounted for 75 percent of third quarter 2010 production.
Continental’s production increased to 47,336 Boepd in September 2010, the final month in the third quarter.
Continental reported net income of $39.1 million, or $0.23 per diluted share, for the third quarter of 2010. Net income included a pre-tax property impairment charge of $14.7 million and a $24.2 million loss on mark-to-market derivative instruments. The loss on derivative instruments was comprised of a $36.6 million unrealized loss, offset partially by a $12.4 million realized gain. The third quarter 2010 impairment charge and $36.6 million unrealized loss together reduced net income per share by $0.19.
Net income for the third quarter of 2009 was $34.9 million, or $0.21 per diluted share. Net income for the third quarter of 2009 included an impairments charge of $11.8 million and a $2.1 million unrealized loss on mark-to-market derivative instruments.
Oil and natural gas sales were $238.8 million for the third quarter of 2010, compared with $168.4 million for the same period last year.
Continental reported EBITDAX of $196.9 million for the third quarter of 2010, a 53 percent increase over EBITDAX of $128.7 million for the third quarter of 2009. For the Company’s definition and reconciliation of EBITDAX to net income, see “Non-GAAP Financial Measures” at the end of this press release.
“Strong production growth has us firmly on track for a solid 2010 and an even stronger year in 2011,” said Harold Hamm, Chairman and Chief Executive Officer. “Our teams continue to operate at a very high level, and we have the liquids-rich inventory in hand to support years of continued growth.”
Continental’s average realized crude oil price was $67.26 per barrel in the third quarter of 2010, while the average realized natural gas price was $4.28 per Mcf, yielding a blended realized price of $56.92 per Boe. In the third quarter of 2009, the Company reported a blended price of $48.19 per Boe.
The Company’s crude oil price differential for the third quarter of 2010 averaged $8.93 per barrel. The Company’s natural gas differential was $0.08 per Mcf for the third quarter of 2010.
Production expense was $5.92 per Boe for the third quarter of 2010, compared with $6.50 per Boe for the third quarter of 2009.
General and administrative expense was $2.90 per Boe, compared with $2.88 per Boe for the third quarter of 2009. These included non-cash equity compensation of $0.63 per Boe for the third quarter of 2010 and $0.92 per Boe for the third quarter of 2009.
At September 30, 2010, the Company’s balance sheet included $149.5 million in cash and $895.9 million in long-term debt. At the end of the third quarter of 2010, the Company had no borrowings under its revolving credit facility.
Operating Highlights
Three months ended
Sept. 30,
------------------
2010 2009
Average daily production:
Crude oil (Bopd) 33,432 27,552
Natural gas (Mcfd) 68,057 58,995
Crude oil equivalents
(Boepd) 44,775 37,384
Average prices: (1)
Crude oil ($/Bbl) $67.26 $58.78
Natural gas ($/Mcf) 4.28 2.98
Crude oil equivalents
($/Boe) 56.92 48.19
Production expense ($/Boe)
(1) 5.92 6.50
General and admin. exp.
($/Boe) (1) 2.90 2.88
EBITDAX (in thousands) 196,917 128,655
Net income (in thousands) 39,077 34,929
Diluted net income per
share 0.23 0.21
Nine months ended
Sept. 30,
-----------------
2010 2009
Average daily production:
Crude oil (Bopd) 31,404 27,265
Natural gas (Mcfd) 61,948 59,503
Crude oil equivalents
(Boepd) 41,728 37,182
Average prices: (1)
Crude oil ($/Bbl) $68.92 $49.81
Natural gas ($/Mcf) 4.63 2.86
Crude oil equivalents
($/Boe) 58.82 40.92
Production expense ($/Boe)
(1) 6.08 6.95
General and admin. exp.
($/Boe) (1) 3.09 2.98
EBITDAX (in thousands) 589,962 292,578
Net income (in thousands) 213,283 21,824
Diluted net income per
share 1.26 0.13
1) Average prices and per-unit expenses are calculated based on
sales volumes. Crude oil sales exceeded production volumes in the
third quarter of 2010 by 78 MBbls. Crude oil sales exceeded
production volumes in the third quarter of 2009 by 55 MBbls. Crude
oil sales exceeded production volumes in the first nine months of
2010 by 90 MBbls. Crude oil production exceeded sales volumes in the
first nine months of 2009 by 196 MBbls.
Production by Region
3Q 2Q 3Q
Boe per day 2010 2010 2009
----------- ---- ---- ----
North Region:
Red River Units 14,953 15,080 14,917
Montana Bakken 5,098 5,196 5,986
North Dakota Bakken 15,062 13,046 7,436
South Region:
Arkoma Woodford 4,413 3,721 4,260
Anadarko Woodford 1,377 1,079 294
Other 2,640 2,617 3,012
East Region 1,232 1,174 1,479
----- ----- -----
Total 44,775 41,913 37,384
Bakken Shale Play (North Dakota and Montana)
Continental’s Bakken Shale production of 20,160 Boepd represented 45 percent of the Company’s total production for the third quarter of 2010, compared with 36 percent in the third quarter last year. Bakken production for the third quarter of 2010 was 50 percent higher than that for the third quarter of 2009.
In the North Dakota Bakken, Continental reported a 103 percent increase in production, compared to the third quarter of 2009. The Company participated in completing 53 gross wells (19.3 net) in the North Dakota Bakken during the quarter. Initial production rates averaged 1,017 Boepd during single-day test periods. All initial well results in this press release are 24-hour tests.
In terms of Company-operated wells, Continental completed 26 gross operated wells (16.4 net) during the quarter, with an average 1,011 Boepd.
Continental’s operated wells included its first ECO-Pad® project completion. The ECO-Pad design involves drilling, from a single pad, four wells on two adjoining 1,280-acre spacing units. Expected benefits from the innovative approach include higher production from longer horizontal bores, more efficient drilling and completion, and reduced environmental impact due to the smaller surface footprint, compared with four individual drilling sites.
The Company’s first ECO-Pad project involved the Hegler 1-13H and 2-13H wells (both 83% WI) and the Arthur 1-12H and 2-12H wells (both 94% WI). Of the two wells that targeted the Three Forks zone, the Hegler 1-13H produced 1,195 Boe at 1,400 psi on a 22 choke, and the Arthur 1-12H produced 849 Boe at 1,150 psi on a 22 choke. In terms of the Middle Bakken wells, the Hegler 2-13H produced 1,203 Boe at 2,200 psi on an 18 choke, and the Arthur 2-12H produced 1,103 Boe at 2,350 psi on an 18 choke.
“The different flowing pressures clearly demonstrate that the Middle Bakken and Three Forks reservoirs are separate and not communicating in this part of western Dunn County,” Mr. Hamm said.
The Company has 20 operated rigs in the North Dakota Bakken and two rigs in the Montana Bakken.
The Company has 864,559 net acres leased in the Bakken Shale play, with 620,620 net acres in North Dakota and 243,939 net acres in Montana portion.
Red River Units (Montana, North Dakota and South Dakota)
Red River Units’ production was 14,953 Boepd in the third quarter, or 33 percent of total production. Continental has two operated drilling rigs in the Units and is drilling wells to complete its increased density sweep pattern in the secondary recovery program. The Company also continues to convert producer wells to injection wells.
Woodford Shale Play (Oklahoma)
Production in the Anadarko Woodford shale play in western Oklahoma was 1,377 Boepd in the third quarter of 2010, reflecting a significant increase in drilling activity this year.
During the quarter, Continental completed a key confirmation well in the southeastern part of the play, the Dana 1-29H (78% WI) in Grady County. The Dana flowed at 2.5 MMcfd of liquids-rich natural gas and 88 Bopd in its initial one-day test period, by far the most productive well completed in the southeast extension of the play.
“The Southeast Cana clearly has an even higher liquids component than the core and the northwest,” Mr. Hamm said. “We are very bullish on the southeastern part of the play, especially as we continue to improve the productivity of wells in the area.” The Company expects to have additional data in early 2011 on another confirmation well in the Southeast Cana.
The Company has leased 258,816 net acres in the Anadarko Woodford. Continental currently has six operated rigs in the Anadarko Woodford play and plans to add two more by year end.
Continental’s production in the eastern part of the Woodford Shale play, the Arkoma Woodford, was 4,413 Boepd in the third quarter of 2010. The Company currently has one operated rig in the Arkoma Woodford, where its acreage position totals 47,201 net acres.
Niobrara Shale Play (Colorado and Wyoming)
Continental today announced plans to spud its first long-lateral Niobrara shale well – the Newton 1-9H (87% WI) – in early December 2010 in northern Weld County, Colorado. The Newton 1-9H is the first Niobrara well permitted for 1,280-acre spacing in the Colorado portion of the play. The Company is planning to drill a 9,200-foot lateral section in the well, similar to the well design approach it is using in the North Dakota Bakken Shale play.
The Company is in the process of permitting additional Niobrara wells in northern Colorado and southern Wyoming. “If the results of the Newton 1-9H go as planned, we expect to spud additional Niobrara wells early in the second quarter next year,” Mr. Hamm said.
Continental has 73,009 net acres leased in the Niobrara Shale play, with acreage in Weld County, Colorado and Platte, Laramie and Goshen counties, Wyoming.
Conference Call Information
Continental Resources will host a conference call on Thursday, November 4, 2010, at 10:00 a.m. ET (9 a.m. CT) to discuss its third quarter 2010 results. Interested parties may listen to the conference call via the Company’s website at http://www.contres.com or by phone:
Dial in: (888) 713-4216
Intl. dial-in: (617) 213-4868
Pass code: 60117799
Replay number: (888) 286-8010
Intl. replay: (617) 801-6888
Pass code: 59215224
Conference Presentations
Continental management is currently scheduled to present at the following research conferences:
Nov. 12 Bank of America Energy Conference, Miami
Nov. 17-18 Bank of America High Yield Conference, New York
Nov. 30 JP Morgan Oil & Gas Conference, Boston
Dec. 1 Jefferies &. Co. Energy Summit, Houston
Dec. 7 Raymond James Fall Investor Conference, Boston
Dec. 8 Wells Fargo Energy Symposium, New York
Capital One Southcoast 5th Annual Energy
Dec. 8 Conference, New Orleans
Presentation materials will be available on the Company’s web site on the day of each presentation.
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.
Forward-Looking Statements
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. 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.
Contact: Investor Relations Media
Warren Henry, VP Investor Brian Engel, VP Public
Relations Affairs
(580) 548-5127 (580) 249-4731
Unaudited Condensed Consolidated Statements of Income
Three Months
------------
Ended September
30,
----------------
In thousands, except
per share data 2010 2009
---- ----
Revenues:
Oil and natural gas
sales $238,826 $168,372
Gain (loss) on mark-
to-market derivative
instruments (24,183) (2,105)
Oil and natural gas
service operations 4,807 3,937
----- -----
Total revenues 219,450 170,204
Operating costs and
expenses:
Production expenses 24,857 22,719
Production taxes and
other expenses 19,517 12,378
Exploration expenses 3,530 1,077
Oil and natural gas
service operations 4,935 2,326
Depreciation,
depletion,
amortization and
accretion 62,918 51,030
Property impairments 14,698 11,791
General and
administrative
expenses (1) 12,148 10,049
(Gain) loss on sale of
assets 491 (452)
--- ----
Total operating costs
and expenses 143,094 110,918
------- -------
Income from operations 76,356 59,286
Other income
(expense):
Interest expense (12,612) (4,763)
Other 237 194
--- ---
(12,375) (4,569)
------- ------
Income before income
taxes 63,981 54,717
Provision for income
taxes 24,904 19,788
------ ------
Net income $39,077 $34,929
------- -------
Basic net income per
share $0.23 $0.21
Diluted net income per
share $0.23 $0.21
Basic weighted average
shares outstanding 168,925 168,516
Diluted weighted
average shares
outstanding 169,949 169,706
Nine Months
-----------
Ended September
30,
----------------
In thousands, except
per share data 2010 2009
---- ----
Revenues:
Oil and natural gas
sales $675,376 $407,379
Gain (loss) on mark-
to-market derivative
instruments 57,626 (1,215)
Oil and natural gas
service operations 14,684 12,409
------ ------
Total revenues 747,686 418,573
Operating costs and
expenses:
Production expenses 69,806 69,183
Production taxes and
other expenses 53,755 30,829
Exploration expenses 7,585 9,726
Oil and natural gas
service operations 12,982 7,423
Depreciation,
depletion,
amortization and
accretion 174,327 154,875
Property impairments 49,387 70,491
General and
administrative
expenses (1) 35,491 29,684
(Gain) loss on sale of
assets (32,855) (673)
------- ----
Total operating costs
and expenses 370,478 371,538
------- -------
Income from operations 377,208 47,035
Other income
(expense):
Interest expense (32,875) (14,073)
Other 1,021 642
----- ---
(31,854) (13,431)
------- -------
Income before income
taxes 345,354 33,604
Provision for income
taxes 132,071 11,780
------- ------
Net income $213,283 $21,824
-------- -------
Basic net income per
share $1.26 $0.13
Diluted net income per
share $1.26 $0.13
Basic weighted average
shares outstanding 168,889 168,492
Diluted weighted
average shares
outstanding 169,904 169,399
(1) Includes non-cash charges for stock-based compensation of $2.6
million and $3.2 million for the three months ended September 30,
2010 and 2009, respectively, and $8.6 million for both the nine
months ended September 30, 2010 and 2009.
Condensed Consolidated September
Balance Sheets 30 December 31
---------- -----------
(in thousands) 2010 2009
---- ----
(unaudited)
Assets:
Cash and cash equivalents $149,477 $14,222
Receivables 376,328 183,358
Derivative assets 39,511 2,218
Inventories, prepaid
expenses and other 37,366 36,230
Net property and equipment 2,703,867 2,068,055
Debt issuance costs, net 28,076 10,844
------ ------
Total assets $3,334,625 $2,314,927
---------- ----------
Liabilities and
shareholders' equity:
Current liabilities $527,306 $219,710
Long-term debt 895,917 523,524
Other noncurrent liabilities 662,651 541,414
Shareholders' equity 1,248,751 1,030,279
--------- ---------
Total liabilities and
shareholders' equity $3,334,625 $2,314,927
---------- ----------
Unaudited Condensed Consolidated Nine months
Statements of Cash Flows ended
-----------
September 30,
-------------
(in thousands) 2010 2009
---- ----
Net income $213,283 $21,824
Adjustments to reconcile net income to
net cash provided by operating
activities:
Non-cash expenses 292,026 255,831
Changes in assets and liabilities (9,969) (61,660)
------ -------
Net cash provided by operating
activities 495,340 215,995
Net cash used in investing activities (708,953) (375,421)
Net cash provided by financing
activities 348,868 159,492
------- -------
Net change in cash and cash
equivalents 135,255 66
Cash and cash equivalents at beginning
of period 14,222 5,229
------ -----
Cash and cash equivalents at end of
period $149,477 $5,295
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 the Company’s operating performance and compare the results of the Company’s operations from period to period without regard to the Company’s 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 the 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. The Company’s 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. The revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table is a reconciliation of our net income to EBITDAX.
Three
months
ended
September
30,
----------
in thousands 2010 2009
------------ ---- ----
Net income $39,077 $34,929
Interest expense 12,612 4,763
Provision for
income taxes 24,904 19,788
Depreciation,
depletion,
amortization and
accretion 62,918 51,030
Property
impairments 14,698 11,791
Exploration
expenses 3,530 1,077
Unrealized
derivative
(gain) loss 36,552 2,105
Non-cash equity
compensation 2,626 3,172
----- -----
EBITDAX $196,917 $128,655
Nine months
ended
September
30,
----------
in thousands 2010 2009
------------ ---- ----
Net income $213,283 $21,824
Interest expense 32,875 14,073
Provision for
income taxes 132,071 11,780
Depreciation,
depletion,
amortization and
accretion 174,327 154,875
Property
impairments 49,387 70,491
Exploration
expenses 7,585 9,726
Unrealized
derivative
(gain) loss (28,162) 1,215
Non-cash equity
compensation 8,596 8,594
----- -----
EBITDAX $589,962 $292,578
SOURCE Continental Resources