2009 Capital Expenditure Budget Reduced in Line with Cash Flow Outlook
ENID, Okla., Feb. 26 /PRNewswire-FirstCall/ -- Continental Resources, Inc. (NYSE: CLR) today reported continued strong growth in production in the fourth quarter ended December 31, 2008, compared with the third quarter of 2008 and the fourth quarter last year. In addition, the Company reported year-end 2008 proved reserves of 159.3 MMboe, an 18 percent increase over the 134.6 MMboe reported at year-end 2007. Combined drilling and proved undeveloped (PUDs) additions of 47.6 MMboe were almost 400 percent of Continental's total production of 12.0 MMboe for 2008.
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Despite challenging economics in the final quarter of 2008, Continental completed a record year for net income and cash flow growth. Net income increased 74 percent to $321.0 million and EBITDAX increased 61 percent to $757.7 million, compared with full-year 2007 results. For the Company's definition and reconciliation of EBITDAX to Generally Accepted Accounting Principles, see "Non-GAAP Financial Measures" at the end of this press release. Net income for 2007 is pro forma for income taxes as if the Company had been a subchapter C corporation prior to its initial public offering in May 2007.
For the fourth quarter ended December 31, 2008, the Company reported net income of $416,000, or $0.00 per diluted share, compared with net income of $60.9 million, or $0.36 per diluted share, for the fourth quarter of 2007. Falling commodity prices reduced fourth quarter revenue and earnings compared to the fourth quarter of 2007.
For the fourth quarter of 2008, Continental achieved total production of 36,018 boepd, an eight percent increase over the third quarter of 2008 and a 19 percent increase over the fourth quarter last year. The Company exited the fourth quarter with average production of 37,954 boepd for December 2008, an increase of 27 percent over December 2007. Production growth strengthened despite the Company significantly scaling back its drilling program as commodity prices declined in the fourth quarter of 2008. Continental has reduced its operated drilling rig count from 32 in early October to seven rigs currently and plans to drop additional rigs as drilling contracts expire later in 2009.
With energy prices remaining low, Continental plans to reduce capital expenditures to preserve capital and the value of its assets. "Our first priority is the integrity of our balance sheet," said Harold Hamm, Chairman and Chief Executive Officer. "We plan to restrain spending until we see commodity prices begin to recover. We remain committed to financing our growth with cash flow and will not use debt to fund a high level of drilling activity, especially in an environment of low energy prices."
"I'm proud that we achieved our operating goals for 2008, finishing the year with strong fourth quarter production growth and increased reserves," he said. "The Company's accomplishments are a strong indicator of the value of our assets and our ability to accelerate growth when the economy and industry conditions rebound."
The Company has revised its 2009 capital expenditures budget to $275 million, which includes $211 million for drilling and related activities and $58 million for land and seismic, and $6 million for other capital needs. Based on the new budget, 2009 production is expected to be in a range of 12.5 MMboe to 13.0 MMboe, which would constitute growth of up to eight percent over 2008. Under this revised capex budget, Continental expects to average approximately five operated drilling rigs during the year.
Oil and natural gas sales were $130.7 million for the fourth quarter of 2008, compared with oil and gas sales of $183.8 million for the fourth quarter of 2007. The Company's average sales price per barrel of crude oil equivalent was $38.80 for the fourth quarter of 2008, compared with $68.84 for the fourth quarter of 2007.
Crude oil price differentials averaged $14.45 per barrel for the fourth quarter of 2008 and $9.50 for 2008 as a whole. This compares with $13.05 per barrel in the fourth quarter of 2007 and $8.85 per barrel for the full year. Continental noted that the differential has been improving in the first quarter of 2009.
EBITDAX for the fourth quarter of 2008 was $92.7 million, compared with EBITDAX of $137.4 million for the fourth quarter of 2007.
At December 31, 2008, the Company's balance sheet included $5.2 million in cash and $376.4 million in long-term debt. Commitments under the Company's revolving credit facility were recently increased to $672.5 million, compared with $552.5 million at December 31, 2008 and $400.0 million at September 30, 2008. With debt outstanding currently of $474.4 million, the Company has $198.1 million in availability under its revolving credit facility.
Increased Reserves
Continental's 2008 reserves growth was primarily the result of increased drilling activity in the North Dakota Bakken and in Oklahoma's Arkoma Woodford in the first nine months of the year.
The Company increased its proved reserves by 24.6 MMboe to a total of 159.3 MMboe. Total proved reserve additions were comprised of 12.7 MMboe in drilling additions, 35.0 MMboe of PUD reserve additions, and 2.2 MMboe in acquisitions. Additions were offset by 13.3 MMboe in downward revisions, of which 64 percent were related to low energy prices at year-end 2008.
Future net cash flows from the year-end 2008 proved reserves, before income taxes, were $3.1 billion, with a present value discounted at 10 percent (PV10) of $1.5 billion. In terms of crude oil/natural gas mix, crude oil reserves were 106.2 million barrels, or 67 percent, of total proved reserves at year-end 2008. Proved developed reserves represented 67 percent of total reserves at year-end 2008.
Operations Update
The following table contains financial and operating highlights for the three months and year ended December 31, 2008 compared to the same periods in 2007.
Three months ended Year ended
------------------ ----------
December 31, December 31,
------------ ------------
2008 2007 2008 2007
------ ------ ------ ------
Average daily production:
Oil (Bopd) 26,857 24,309 24,993 23,832
Natural gas (Mcfd) 54,963 36,362 46,861 31,599
Oil equivalents (Boepd) 36,018 30,369 32,803 29,099
Average prices: (1)
Oil ($/Bbl) $43.89 $77.53 $88.87 $63.55
Natural gas ($/Mcf) 3.93 5.99 6.90 5.87
Oil equivalents ($/Boe) 38.80 68.84 77.66 58.31
Production expense ($/Boe) (1) 7.83 6.85 8.40 7.35
EBITDAX (in thousands) 92,680 137,412 757,708 469,885
Net income (in thousands) (2) 416 60,892 320,950 184,002
Diluted net income per share 0.00 0.36 1.89 1.11
(1) Average prices and per-unit production expense are calculated
based on sales volumes. Crude oil sales volumes exceeded production in
the fourth quarter and full-year 2008 by 54 MBbls and 97 MBbls,
respectively. Crude oil production volumes exceeded oil sales in the
fourth quarter and full year 2007 by 125 MBbls and 221 MBbls,
respectively.
(2) Net income and diluted net income per share for full-year 2007
are after pro forma adjustments (i) to provide for income taxes as if
the Company had been a subchapter C corporation prior to the completion
of its initial public offering, and (ii) to eliminate the $198.4 million
charge recorded to recognize deferred taxes upon its conversion from a
nontaxable subchapter S corporation to a taxable subchapter C
corporation in conjunction with the Company's May 2007 initial public
offering.
The following table presents average daily production for the Company's
principal operating areas for the quarters ended December 31, 2008,
September 30, 2008 and December 31, 2007.
(boe per day) Q4 2008 Q3 2008 Q4 2007
------- ------- -------
Red River Units 14,058 13,375 14,374
Montana Bakken 6,410 6,187 7,244
North Dakota Bakken 4,401 3,444 1,382
Other Rockies 2,507 2,275 1,600
Arkoma Woodford 3,276 2,627 1,338
Other Mid-Continent 4,751 4,895 3,767
Gulf Coast 615 494 664
------- ------- -------
Total 36,018 33,297 30,369
Production growth continued to accelerate in the North Dakota Bakken and the Arkoma Woodford plays in the fourth quarter of 2008. Based on capital expenditure re-allocations and its revised 2009 budget, production in the Red River Units is expected to be flat or to decline slightly through the first nine months of 2009, then resume growing in the fourth quarter. Continental expects to generate most of its 2009 production growth in the North Dakota Bakken and the Arkoma Woodford plays.
Red River Units
Production in the Red River Units was 14,058 boepd in the fourth quarter of 2008, accounting for 39 percent of Continental's production in the quarter. This was a five percent increase over the third quarter of 2008, but down slightly from the fourth quarter last year.
The Units accounted for 37 percent of year-end 2008 proved reserves, compared with 50 percent of reserves at the end of 2007.
During fourth quarter 2008, the Company continued to convert producer wells to injectors and to expand its secondary recovery program, but the pace of the secondary recovery program was considerably reduced in November and December.
The Company currently has one operated rig drilling in the Units. Under the revised 2009 capital expenditures budget, Continental has allocated $46 million to the Units, with plans to drill four producer wells, two disposal wells, a sixth water supply well, and converting producer and air injector wells to water injectors.
As noted above, production is expected to resume growing in the Red River Units in late 2009. The Company does not expect changes in the timing of capex funding to reduce total production or ultimate reserve recovery in the Units. The Company expects production to peak at just over 17,000 boepd in the Units in 2010.
Bakken Shale
Production in the Bakken Shale of North Dakota and Montana was 10,811 boepd in the fourth quarter of 2008, or 30 percent of Continental's production in the quarter. This was a 12 percent increase over the third quarter of 2008 and a 25 percent increase over production for the fourth quarter last year.
Total proved reserves in the Bakken were 45.7 MMboe at December 31, 2008, or 29 percent of the Company's year-end 2008 reserves. This constituted an increase of 38 percent over proved reserves of 33.2 MMboe in the Bakken Shale at December 31, 2007.
In the North Dakota part of the Bakken play, total proved reserves were 17.5 MMboe at December 31, 2008, or 11 percent of the Company's total year-end 2008 reserves. This represented growth of 187 percent over reserves of 6.1 MMboe in the North Dakota Bakken at December 31, 2007.
The Company currently has four operated rigs drilling in North Dakota and none in Montana, compared with 10 rigs in North Dakota and three in Montana at the beginning of the fourth quarter of 2008.
During the fourth quarter, Continental participated in the completion of 33 gross wells (8.9 net) in North Dakota. These wells had an average rate of 546 boepd during their seven-day production period tests. All initial production period test results in this press release are seven consecutive day averages.
Since the beginning of the fourth quarter of 2008, notable completions of Company-operated wells targeting the Three Forks/Sanish (TFS) formation in North Dakota are shown below with average production period test results in gross barrels:
-- Morris 1-23H (29% WI) in Dunn Co. - 1,185 boepd;
-- Blegen 1-13H (26% WI) in McKenzie Co. - 1,028 boepd;
-- Mittelstadt 1-20H (44% WI) in Dunn Co. - 998 boepd;
-- Skachenko 1-31H (34% WI) in Dunn Co. - 809 boepd;
-- Hamlet 1-11H (39% WI) in Williams Co. - 450 boepd;
-- Glasoe 1-18H (45% WI) in Divide Co. - 441 boepd;
-- Arvid 1-34H (42% WI) in Divide Co. - 340 boepd;
-- Elveida 1-33H (46% WI) in Divide Co. - 302 boepd.
Notable recent well completions in North Dakota targeting the Middle Bakken formation include:
-- Malcolm 1-29H (45% WI) in Williams Co. - 693 boepd;
-- Shonna 1-15H (44% WI) in Divide Co. - 436 boepd;
-- Marlene 1-10H (53% WI) in Williams Co. - 427 boepd;
-- Viola 1-7H (54% WI) in Divide Co. - 391 boepd.
In the Montana Bakken, the Company continued to implement its 320-acre infield and field-extension program in the fourth quarter of 2008.
Notable completions in Richland County, MT in the fourth quarter of 2008 included the Prevost 3-16H (83% WI), which had a production period test rate of 507 boepd, and the Rita 3-19H (79% WI), which had production period test rate of 412 boepd. Production results have continued to improve in Richland County as the Company implemented multi-stage fracture stimulation technology that it developed in North Dakota.
Continental recently completed its first Montana TFS test well, the Joann 1-32H (89% WI), in Richland County. The well exhibited poor oil shows and reservoir rock quality during drilling, and in its initial production test period yielded an average 60 boepd.
The Company has commenced a pilot carbon dioxide injection project to evaluate the potential for enhanced recovery of oil in the Elm Coulee field. Utilizing the huff-and-puff technique, carbon dioxide was injected in January and will continue to be injected through March. After letting the carbon dioxide soak in for approximately 30 days, the carbon dioxide and associated fluids will be flowed back and analyzed for performance and economics.
Under its revised 2009 capital expenditures budget, Continental has allocated $72 million to drilling-related activity in North Dakota and $7 million to Montana. Another $36 million in land and seismic capex was allocated for the Bakken play in the two states, primarily to extend leases in the play.
Continental plans to participate in 86 gross wells (20.2 net) in North Dakota and no new wells in Montana in 2009. Drilling activity in North Dakota will focus on the Three Forks/Sanish formation.
Arkoma Woodford
Production in the Arkoma Woodford shale play in southeast Oklahoma was 3,276 boepd in the fourth quarter of 2008, accounting for 9 percent of Continental's production in the period. This was a 25 percent increase over the third quarter of 2008, and was more than double production for the fourth quarter last year.
Total proved reserves in the Arkoma Woodford were 30.7 MMboe at December 31, 2008, or 19 percent of the Company's year-end 2008 reserves. This represented growth of 245 percent over reserves of 8.9 MMboe in the Arkoma Woodford at December 31, 2007.
During the fourth quarter of 2008, Continental continued to develop its simultaneous fracture stimulation technology in the Arkoma Woodford, most notably with the Pasquali, Luna-Pratt and Wilson simul-fracs in the Ashland development section of the play.
After the simul-frac, the seven Pasquali wells flowed at an average 2,440 Mcfpd during their production period test, with the most prolific well flowing at 3,599 Mcfpd. The six Luna-Pratt wells flowed at an average 3,761 Mcfpd, with the most prolific flowing at 4,576 Mcfpd. The two wells in the Wilson simul-frac flowed at 8,569 Mcfpd and 5,982 Mcfpd, for an average rate of 7,276 Mcfpd.
The Company currently has one operated rig drilling in the Arkoma Woodford, compared to six rigs at the beginning of the fourth quarter of 2008. Under its revised 2009 capital expenditures budget, Continental has allocated $56 million to drilling-related activity in the play, as well as $7 million in land and seismic capex. In 2009, the Company plans to participate in 63 gross wells (8.0 net) in the Arkoma Woodford.
Emerging Plays
In the Anadarko Woodford shale of western Oklahoma, Continental is currently completing two test wells, the Brown 1-2H (100% WI) in Dewey Co. and the McCalla 1-11H (90% WI) in Grady Co.
In Ellis County, OK, the Company completed its initial test well in the Atoka shale play, the Shrewder 1-22H (100% WI), which flowed at 1.3 MMcfpd from a short, 1,300-foot lateral. The Jones-Trust 1-168H (100% WI), completed in Lipscomb Co., TX in the western part of the play, flowed at 700 Mcf per day in its initial production period test.
The Company currently has no operated rig drillings in the Anadarko Woodford or the Atoka, compared to one in each play at the beginning of the fourth quarter of 2008. Under its revised 2009 capital expenditures budget, Continental has allocated $12 million to drilling-related activity in its emerging plays, as well as $6 million in land and seismic. In 2009, the Company plans to participate in six gross wells (1.8 net) in its emerging plays.
Capital Budget and Guidance
Continental's regional allocations of capital expenditures in 2009 are listed below. Operational capex includes drilling, work-over and facilities capital expenditures.
2009 Capex Budget
-----------------
(in millions) Net Wells
----------------- ---------
North Dakota Bakken $72 20.2
Arkoma Woodford 56 8.0
Red River Units 46 3.8
Emerging plays 12 1.8
Montana Bakken 7 0.0
Other 18 3.9
----------------- ---------
Operational capex 211 37.7
Land and seismic 58
Other capital expenditures 6
----------------- ---------
Total capex $275
Continental announced its previously issued operating and financial guidance for 2009 has been revised and is as follows. As forward-looking information, this guidance is subject to a variety of risks and uncertainties, including adjustments related to fluctuations in commodity prices. Risk factors are discussed further at the end of this press release and in the Company's filings with the Securities and Exchange Commission.
Year Ended
December 31, 2009
-----------------
Production volumes:
Oil (MMbls) 8.8 - 9.1
Gas (MMcf) 22.5 - 23.4
Oil equivalent (MMboe) 12.5 - 13.0
Price differentials(1) :
Oil (Bbl) $8.00 - $10.00
Gas (Mcf) $1.50 - $2.25
Operating expenses:
Production expense (per boe) $7.75 - $8.50
Production tax (percent of sales) 6.25% - 6.75%
Depreciation, depletion, amortization and
accretion (per boe) $15.00 - $18.00
General and administrative expense (per boe)(2) $1.75 - $2.25
Non-cash stock-based compensation (per boe) $0.70 - $1.00
Income tax rate (percent of pre-tax income) 38%
Percent of income tax deferred 90%
(1) Differential to calendar month average NYMEX futures price for oil
and to average of last three trading days of prompt NYMEX futures
contract for gas.
(2) Excludes non-cash stock-based compensation.
Conference Call Information
Continental Resources will host a conference call on Thursday, Feb. 26, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its fourth quarter 2008 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) 713-4217
Intl. dial in: (617) 213-4869
Pass code: 65130417
Replay number: (888) 286-8010
Intl. replay: (617) 801-6888
Pass code: 18971146
Conference Presentations
Continental management is currently scheduled to present at the Raymond James & Associates 30th Annual Institutional Investors Conference in Orlando (March 8-11, 2009) and at the Howard Weil 37th Annual Energy Conference in New Orleans (March 22-26, 2009).
Continental Resources is a crude-oil concentrated, 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 and developing resource 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. 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 Brian Engel
Investors Media
(580) 548-5127 (580) 249-4731
Condensed Consolidated Statements of Income
(in thousands, except Three months ended Year ended
share data) ------------------ -----------
December 31, December 31,
------------ ------------
2008 2007 2008 2007
---- ---- ---- ----
Revenues:
Oil and natural gas sales $130,668 $183,780 $939,906 $606,514
Loss on mark-to-market
derivatives - (30,476) (7,966) (44,869)
Oil and natural gas
service operations 5,128 5,690 28,550 20,570
----------------------------------------
Total revenues 135,796 158,994 960,490 582,215
Operating costs and expenses:
Production expense 26,362 18,288 101,635 76,489
Production tax 10,199 10,251 58,610 32,562
Exploration expense 13,882 2,499 40,160 9,163
Oil and gas service operations 2,391 3,942 18,188 12,709
Depreciation, depletion,
amortization and accretion 53,074 26,326 148,902 93,632
Property impairments 11,227 4,887 28,847 17,879
General and administrative (1) 7,907 5,148 35,719 32,802
Gain on sale of assets (488) (650) (894) (988)
----------------------------------------
Total operating costs and
expenses 124,554 70,691 431,167 274,248
Income from operations 11,242 88,303 529,323 307,967
Interest expense and other (2,743) (2,543) (10,793) (11,190)
----------------------------------------
Net income before income
tax expense 8,499 85,760 518,530 296,777
Income tax expense 8,083 24,868 197,580 268,197
----------------------------------------
Net income $416 $60,892 $320,950 $28,580
Basic net income per share $0.00 $0.36 $1.91 $0.17
Diluted net income per share 0.00 0.36 1.89 0.17
Basic weighted average
shares outstanding 168,335 167,590 168,087 164,059
Diluted weighted average
shares outstanding 169,231 169,255 169,392 165,422
(1) Includes non-cash charges for stock-based compensation of
$2.6 million and $0.7 million for the three months ended December 31,
2008 and 2007, respectively, and $9.1 million and $12.8 million for
the years ended December 31, 2008 and 2007, respectively.
Condensed Consolidated Balance Sheets December 31, December 31,
(in thousands) ----------- -----------
2008 2007
---- ----
Assets:
Cash and cash equivalents $5,229 $8,761
Receivables 229,079 163,090
Inventories and other 43,387 33,713
Net property and equipment 1,935,143 1,157,926
Other assets 3,041 1,683
----------------------
Total assets $2,215,879 $1,365,173
----------------------
Liabilities and shareholders' equity:
Current liabilities $403,594 $266,106
Long-term debt 376,400 165,000
Other noncurrent liabilities 487,177 310,935
Shareholders' equity 948,708 623,132
----------------------
Total liabilities and shareholders' equity $2,215,879 $1,365,173
----------------------
Year ended
Condensed Consolidated Statements of Cash Flows ----------
(in thousands) December 31,
------------
2008 2007
---- ----
Net income $320,950 $28,580
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash expenses 363,801 416,977
Changes in assets and liabilities 35,164 (54,909)
-------------------
Net cash provided by operating activities 719,915 390,648
Net cash used in investing activities (927,617) (483,498)
Net cash provided by financing activities 204,170 94,568
Effect of exchange rate on change in cash and cash
equivalents - 25
-------------------
Net change in cash and cash equivalents (3,532) 1,743
Cash and cash equivalents at beginning of period 8,761 7,018
-------------------
Cash and cash equivalents at end of period $5,229 $8,761
Non-GAAP Financial Measures
EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains and 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 funded debt to EBITDAX ratio, as defined therein, 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
(in thousands) December 31, December 31,
-------------- ---------------
2008 2007 2008 2007
---- ---- ---- ----
(unaudited)
Net income $416 $60,892 $320,950 $28,580
Loss on mark-to-market
derivatives - 14,160 - 26,703
Income tax expense 8,083 24,868 197,580 268,197
Interest expense 3,406 3,085 12,188 12,939
Depreciation, depletion,
amortization and accretion 53,074 26,326 148,902 93,632
Property impairments 11,227 4,887 28,847 17,879
Exploration expense 13,882 2,499 40,160 9,163
Equity compensation 2,592 695 9,081 12,792
-----------------------------------------
EBITDAX $92,680 $137,412 $757,708 $469,885
