Continental Resources Completes 2009 with Strong Growth in Production and Cash Flow
2009 Proved Reserves Increase 62 percent, Replacing 811 Percent of 2009 Production Capital Expenditure Budget Increased 31 Percent to $850 Million to Accelerate Drilling Successful Anadarko Woodford Drilling Extends Cana Play Potential 40 Miles Northwest
Continental Resources, Inc.
Harold Hamm, Chairman and Chief Executive Officer, said the strong fourth quarter 2009 results position Continental for increased growth.
"We have an excellent opportunity to accelerate growth in production, cash flow and value for our shareholders," Mr. Hamm said. "With our inventory of high-value crude oil assets in the Bakken, Continental is positioned for a higher rate of growth as crude oil prices remain favorable.
"In addition, we're building a strong presence in the Anadarko Woodford, which has a strong oil component. We believe the Anadarko Woodford is of the quality to be Continental's next major building block," he said. "We expect that our increased growth rate will maximize long-term value for our shareholders."
Recent milestones provide visibility into Continental's long-term strategic growth plans:
-- Continental increased proved reserves in 2009 by 62 percent to 257.3 MMBoe, compared to year-end 2008 proved reserves. Sixty-seven percent of 2009 proved reserves were crude oil. -- 2009 total production was 13.6 MMBoe, a 13 percent increase over 2008 production. Production growth in the North Dakota Bakken was the primary growth driver, totaling 2.4 MMBoe, which was double the Company's North Dakota production in 2008. -- The Company has increased its 2010 capital expenditure budget by 31 percent to $850 million to accelerate further its drilling program in the Bakken and Anadarko Woodford plays. -- Continental announced a successful well, the Brown 1-2H (100% WI) in Dewey County, Oklahoma, which extends the Cana Field's potential 40 miles northwest. The Company has increased its Anadarko Woodford leasehold position to 200,000 net acres. -- The Company has ramped up its drilling rig activity to 15 operated rigs and plans to have 24 operated rigs by mid-2010. Six of these will be ECO-Pad(TM) drilling rigs; one is currently drilling in the North Dakota Bakken play. Year-End 2009 Proved Reserves
Continental reported 2009 proved reserves of 257.3 MMboe (million barrels of oil equivalent), a 62 percent increase over 2008 proved reserves. The additional reserves reflected changes in SEC rules to allow producers in continuous accumulation plays to report additional undrilled locations beyond one offset on each side of a horizontal producing well. The additions also reflected the Company's successful drilling results in the North Dakota Bakken Shale play last year.
Of Continental's 2009 proved reserves, 44 percent were proved developed producing (PDP).
Continental's 2009 proved reserves included 1,118 gross (436 net) proved undeveloped locations (PUDs), with 616 gross (262 net) PUDs in the North Dakota Bakken play and 401 gross (100 net) PUDs in the Arkoma Woodford play in Oklahoma.
The Company holds extensive undeveloped acreage beyond the properties that were evaluated in its 2009 proved reserves report. The PUDs in the 2009 proved reserves included only 9 percent of Continental's undeveloped acreage in the North Dakota Bakken, 2 percent of its undeveloped acreage in the Montana Bakken, and 2 percent of its undeveloped acreage in the Anadarko Woodford Shale play of Oklahoma.
"The remainder of our undeveloped acreage represents a tremendous opportunity to continue growing reserves over the next 10-year period," Mr. Hamm said.
North Dakota Bakken accounted for the largest portion the Company's 2009 proved reserves, at 41 percent of the total. The Red River Units accounted for 21 percent, followed by the Arkoma Woodford shale play with 17 percent and the Montana Bakken with 11 percent of the total.
Total 2009 reserve additions were 110.5 MMBoe, which equated to 811 percent of the year's production of 13.6 MMBoe. The Company also reported 1.2 MMBoe in positive revisions.
New SEC reserve rules require crude oil and natural gas producers to calculate future net cash flows based on the average of prices as of the first day of each month of the year. On this basis, Continental's 2009 proved reserves represented $5.8 billion in undiscounted future net cash flows, before income taxes, with a net present value discounted at 10 percent (PV-10) of $2.2 billion.
Prior to 2009, these calculations were made using commodity prices as of December 31 of the year. Based on year-end 2009 oil and gas prices, Continental's proved reserves equated to $9.1 billion in undiscounted future net cash flows, before income taxes, with a PV-10 of $3.7 billion.
Ryder Scott Company, L.P. evaluated properties representing 90 percent of Continental's PV-10 at year-end 2009. Company reserve engineers evaluated the remaining properties.
Full-Year and Fourth Quarter 2009 Results
Continental's total production of 13.6 MMBoe in 2009 exceeded its original guidance range of 12.5-to-13.0 MMBoe and its updated guidance of 13.3 MMBoe.
Crude oil represented 74 percent of 2009 production, but increased to 77 percent of the Company's fourth quarter 2009 total production.
Average daily production was 37,747 Boepd (barrels of oil equivalent per day) for the fourth quarter of 2009, compared with production of 36,018 Boepd for the fourth quarter of 2008.
Total oil and natural gas sales were $203.3 million for the fourth quarter of 2009, compared with $130.7 million for the fourth quarter of 2008.
Continental's average realized crude oil price was $66.91 per barrel in the fourth quarter of 2009, while the average realized natural gas price was $4.31 per Mcf, yielding a blended price per Boe of $56.69. These compare with average realized prices of $43.89 per barrel of crude oil, $3.93 per Mcf of natural gas, and $38.80 per Boe for the fourth quarter of 2008.
Crude oil price differentials averaged $9.30 per barrel for the fourth quarter of 2009, in line with the third quarter of 2009 and down from $14.45 for the fourth quarter of 2008. For 2009 as a whole, the Company's crude oil price differential averaged $8.29, at the low end of its guidance range of $8 to $10. The 2009 average natural gas differential was $0.78 per Mcf, significantly below the Company's guidance range of $1.50 to $2.25.
Continental reduced production expenses per Boe on a year-over-year basis. Production expense was $6.71 per Boe for the fourth quarter of 2009, compared with $7.83 for the fourth quarter of 2008. Production expense of $6.89 for full-year 2009 was below the Company's guidance range of $7.75 to $8.50 per Boe.
Income from operations was $85.3 million for the fourth quarter of 2009, compared with $11.2 million for the fourth quarter of 2008.
EBITDAX was $158.1 million for the fourth quarter of 2009, an increase of 70 percent over $92.7 million for the fourth quarter of 2008. For the Company's definition and reconciliation of EBITDAX to net income, see "Non-GAAP Financial Measures" at the end of this press release.
At December 31, 2009, the Company's balance sheet included $14 million in cash and $524 million in long-term debt. As of February 25, 2010, long-term debt was $496 million, including $198 million drawn against the Company's $750 million revolving credit facility, leaving $552 million in available borrowing capacity.
Operating Highlights Three mos. ended Year ended December 31, December 31, --------------- -------------- 2009 2008 2009 2008 ---- ---- ---- ---- Average daily production: Oil (Bopd) 28,034 26,857 27,459 24,993 Natural gas (Mcfd) 58,277 54,963 59,194 46,861 Oil equivalents (Boepd) 37,747 36,018 37,324 32,803 Average prices: (1) Oil ($/Bbl) $66.91 $43.89 $54.44 $88.87 Natural gas ($/Mcf) 4.31 3.93 3.22 6.90 Oil equivalents ($/Boe) 56.69 38.80 45.10 77.66 Production exp. ($/Boe)(1) 6.71 7.83 6.89 8.40 EBITDAX (in thousands) 158,070 92,680 450,648 757,708 Net income (in thousands) 49,514 416 71,338 320,950 Diluted net income per share 0.29 0.04 0.42 1.89 Production by Region (Boe per day) Q4 2009 Q3 2009 Q4 2008 ------- ------- ------- Red River Units 14,249 13,942 14,058 Montana Bakken 5,047 5,581 6,410 North Dakota Bakken 7,843 6,943 4,401 Other Rockies 1,993 1,874 2,507 Arkoma Woodford 3,573 4,260 3,276 Other Mid-Continent 4,568 4,338 4,751 Gulf Coast 474 446 615 --- --- --- Total 37,747 37,384 36,018 (1) Average prices and per-unit production expense are calculated based on sales volumes. Crude oil sales exceeded production volumes in the fourth quarter of 2009 by 114 MBbls. Crude oil sales volumes exceeded oil production in the fourth quarter of 2008 by 55 MBbls.
Fourth quarter 2009 production increased in the North Dakota Bakken and Arkoma Woodford shale plays, compared with the fourth quarter of 2008. In North Dakota, fourth quarter 2009 production of 7,843 Boepd was 78 percent higher than that for the fourth quarter last year, while Arkoma Woodford production of 3,573 Boepd was nine percent higher than the fourth quarter of 2008. Montana Bakken production declined, reflecting the lack of drilling activity in the play until late 2009.
The Red River Units accounted for 38 percent of the Company's total production of 37,747 Boepd in the fourth quarter of 2009. The North Dakota Bakken accounted for 21 percent, followed by the Montana Bakken at 13 percent and the Arkoma Woodford at nine percent of total production for the fourth quarter of 2009.
North Dakota Bakken
Continental set a new initial production record for a Company-operated North Dakota Bakken well in the fourth quarter with the Hendrickson 1-36H (95% WI) in McKenzie Co. The well produced 1,990 Boepd in its seven-day production period test, and the well's best single-day production was 2,105 Boe, with a flowing tubing pressure of approximately 3,000 psi.
In the first quarter of 2010, Continental plans to begin reporting single-day initial production tests for new wells in the Bakken field. Initial seven-day production rates on some wells in the Bakken field are being restricted because of natural gas pipeline capacity limitations. The limitations generally only affect production during the first few weeks.
The Company participated in completing 22 gross wells (6.7 net) in North Dakota during the fourth quarter of 2009. Initial production rates averaged 1,070 Boepd during their seven-day test periods, a 41 percent increase over the average initial well production rate of 761 Boepd in the third quarter of 2009 and a 96 percent increase over the average of 546 Boepd for wells completed in the fourth quarter of 2008.
The totals for the fourth quarter of 2009 exclude the Company's Traxel 1-31H (74% WI) in Mercer County, North Dakota, which was completed in the Scallion formation, and a separate non-operated dry hole in which Continental had a small working interest.
The Company completed eight gross operated wells (4.3 net) in North Dakota during the quarter, with six gross wells targeting the Three Forks/Sanish (TFS) zone. The six TFS wells averaged 1,242 Boepd in their initial seven-day production tests. These completions involved 18 fracture stimulation stages and approximately 100,000 pounds of proppant injected per stage.
The Company's strong production results continued in the first quarter of 2010 with the Hawkinson 1-22H (48% WI) in Dunn County, North Dakota, which produced 1,667 Boepd in its initial seven-day test period. The Hawkinson's strongest single-day production total was 2,338 Boe.
Continental currently has 11 operated drilling rigs in the North Dakota Bakken and plans to increase to 15 by mid-year 2010.
At year-end 2009, the Company had 481,850 net acres in the North Dakota Bakken, of which 81 percent were undeveloped. The Company had increased its total acreage position in the North Dakota Bakken to 488,500 net acres as of February 25, 2010.
Continental resumed drilling activity in the Montana Bakken in late 2009 and in January 2010 completed the Rognas 2-22H (95% WI). Located on the northern edge of the fairway of the Elm Coulee Field, the Rognas 2-22H was one of the Company's strongest Montana wells to date, averaging 841 Boepd during its initial seven-day test period. Its best single-day production rate was 1,014 Boe. Continental completed the Rognas with a 14-stage frac and higher proppant load design developed in the North Dakota Bakken.
The Company plans to keep at least one operated drilling rig active in Richland County in 2010, alternating between drilling 320-acre in-field locations in the fairway of the play and additional wells in the Company's undeveloped acreage. The Company has 163,500 net acres in the Montana Bakken, of which 60 percent are undeveloped.
Red River Units
Continental currently has one operated drilling rig in the Red River Units. The Company is drilling 12 wells to complete its increased density sweep pattern in the secondary recovery program, and currently has 25 producing and air-injector wells remaining to convert to water-injector wells.
Continental has added 51,500 net acres to its Anadarko Woodford leasehold in early 2010, increasing its total position to 200,000 net acres.
Industry activity in the play has primarily focused on the Cana Field in Canadian and southern Blaine counties. Continental's fourth quarter 2009 discovery, the Brown 1-2H (100% WI) in Dewey County, indicates that the Cana Field may extend another 40 miles to the northwest, an area Continental refers to as the Northwest Cana.
"Based on our assessment, we believe the true productive area of the Anadarko Woodford goes well beyond the core Cana Field," Mr. Hamm said. "We are now one of the largest acreage holders in the extended play, and we continue to add acreage.
"We think the Anadarko Woodford Shale play will be capable of competing with the economics of any shale play in the United States," he said.
The Brown 1-2H produced 4.2 MMcf of natural gas and 102 barrels of crude oil per day in its initial seven-day test period. It remains a very strong well, producing 382 MMcf of natural gas and 6,862 barrels of crude oil in its first five months of production.
Its production compares favorably with Continental's Young 2-22H (55% WI) in Blaine County, in the western Cana Field. The Young 2-22H initially flowed at 6.8 MMcf per day on a restricted basis and has flowed 683 MMcf during its first six months of production.
Continental is currently drilling a step-out confirmation well five miles south of the Brown 1-2H. The Company has leased 124,000 net acres in the Cana and Northwest Cana portions of the Anadarko Woodford.
The Company is currently completing its second test well, the Ballard 1-17H (99% WI), in Grady County. Continental has leased 76,000 net acres in the Southeast Cana, which includes portions of Caddo, Grady and McClain counties.
Of Continental's total net acreage in the Anadarko Woodford, approximately 15 percent is developed and held by production from formations other than the Woodford. The Company currently has one operated drilling rig in the Anadarko Woodford and plans to add two by mid-year.
Continental is continuing to develop its acreage in the Arkoma Woodford Shale play in southeastern Oklahoma. The Company had 44,800 net acres in the Arkoma Woodford at year-end 2009, but has since increased its position to a total of 47,500 net acres. Of this position, 47 percent is held by production. Continental plans to maintain one operated drilling rig in the Arkoma in 2010.
Capital Expenditure Budget
Continental announced that it had increased its 2010 capital expenditure budget to $850 million, primarily to fund additional drilling in the North Dakota Bakken and Anadarko Woodford plays. The additional $200 million in capex is planned to be spent almost entirely in the second half of 2010, enabling the Company to maintain a high level of drilling momentum as it enters 2011. The Company plans to spud an additional 28 gross wells (21.2 net) in the second half of 2010, mostly in the North Dakota Bakken.
Production growth in 2010 is expected to be approximately 13 percent, versus the Company's earlier guidance of approximately 10 percent production growth.
"This gives us significantly stronger momentum entering 2011," Mr. Hamm said. "We have sufficient capacity in our revolving credit facility to fund the increase."
Conference Call Information
Continental Resources will host a conference call on Thursday, February 25, 2010, at 10:00 a.m. ET (9 a.m. CT) to discuss its fourth quarter 2009 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) 679-8040 Intl. dial-in: (617) 213-4851 Pass code: 34691584 Replay number: (888) 286-8010 Intl. replay: (617) 801-6888 Pass code: 10828166 Conference Presentations
Continental management is currently scheduled to present at the following research conferences:
March 8, Raymond James 31st Annual Institutional Investors' Conference, Orlando, FL March 24, Howard Weil 38th Annual Energy Conference, New Orleans, LA
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.
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 Brian Engel, VP Investor Relations Public Affairs (580) 548-5127 (580) 249-4731 Consolidated Statements of Three months ended Twelve months ended Income December 31, December 31, ---------------- ----------------- (in thousands, except per share amounts) 2009 2008 2009 2008 ------------------------- ---- ---- ---- ---- Revenues: Oil and natural gas sales $203,319 $130,668 $610,698 $939,906 Loss on mark-to-market derivatives (305) - (1,520) (7,966) Oil and natural gas service operations 4,624 5,128 17,033 28,550 ----- ----- ------ ------ Total revenues 207,638 135,796 626,211 960,490 Operating costs and expenses: Production expense 24,059 26,362 93,242 101,635 Production tax, and other expenses 14,816 10,199 45,645 58,610 Exploration expense 2,889 13,882 12,615 40,160 Oil and natural gas service operations 3,317 2,391 10,740 18,188 Depreciation, depletion, amortization and accretion 52,727 53,074 207,602 148,902 Property impairments 13,203 11,227 83,694 28,847 General and administrative (1) 11,410 7,907 41,094 35,719 Gain on sale of assets (36) (488) (709) (894) --- ---- ---- ---- Total operating costs and expenses 122,385 124,554 493,923 431,167 Income from operations 85,253 11,242 132,288 529,323 Interest expense and other (8,849) (2,743) (22,280) (10,793) ------ ------ ------- ------- Net income before income tax expense 76,404 8,499 110,008 518,530 Income tax expense 26,890 8,083 38,670 197,580 ------ ----- ------ ---- Net income $49,514 $416 $71,338 $320,950 Basic net income per share 0.29 0.00 0.42 1.91 Diluted net income per share $0.29 $0.00 $0.42 $1.89 Basic weighted average shares outstanding 168,758 168,335 168,559 168,087 Diluted weighted average shares outstanding 169,784 169,231 169,529 169,392 (1) Includes non-cash charges for stock-based compensation of $2.8 million and $2.6 million for the three months ended December 31, 2009 and 2008, respectively, and $11.4 million and $9.1 million for the years ended December 31, 2009 and 2008, respectively. Consolidated Balance Sheets December 31, December 31, --------------------------- (in thousands) 2009 2008 ----------- ------------ Assets: Cash and cash equivalents $14,222 $5,229 Receivables 185,576 229,079 Inventories and other 36,230 43,387 Net property and equipment 2,068,055 1,935,143 Other assets 10,844 3,041 ------ ----- Total assets $2,314,927 $2,215,879 ---------- ---------- Liabilities and shareholders' equity: Current liabilities $219,710 $403,594 Long-term debt 523,524 376,400 Other noncurrent liabilities 541,414 487,177 Shareholders' equity 1,030,279 948,708 --------- ------- Total liabilities and shareholders' equity $2,314,927 $2,215,879 ---------- ---------- Consolidated Statements of Cash Flows Year ended December 31, ----------------- (in thousands) 2009 2008 -------------- ---- ---- Net income $71,338 $320,950 Adjustments to reconcile net income to net cash provided by operating activities: Non-cash expenses 350,570 363,801 Changes in assets and liabilities (46,050) 35,164 ------- ------ Net cash provided by operating activities 375,858 719,915 Net cash used in investing activities (499,822) (927,617) Net cash provided by financing activities 132,957 204,170 ------- ------- Net change in cash and cash equivalents 8,993 (3,532) Cash and cash equivalents at beginning of period 5,229 8,761 ----- ----- Cash and cash equivalents at end of period $14,222 $5,229 Non-GAAP Financial Measures
EBITDAX represents earnings before interest expense, income taxes (when applicable), depreciation, depletion, amortization and accretion, property impairments, exploration expense and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a Company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. The Company's computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet future debt service requirements, if any. The Company's credit facility requires that it maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1 on a rolling four-quarter basis. The credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table represents a reconciliation of the Company's net income to EBITDAX.
Three months ended Year ended December 31, December 31, -------------- -------------- (in thousands) 2009 2008 2009 2008 ----------- ---- ---- ---- ---- (unaudited) Net income $49,514 $416 $71,338 $320,950 Unrealized derivative loss 874 - 2,089 - Interest expense 9,159 3,406 23,232 12,188 Provision for income taxes 26,890 8,083 38,670 197,580 Depreciation, depletion, amortization and accretion 52,727 53,074 207,602 148,902 Property impairments 13,203 11,227 83,694 28,847 Exploration expense 2,889 13,882 12,615 40,160 Equity compensation 2,814 2,592 11,408 9,081 ----- ----- ------ ----- EBITDAX $158,070 $92,680 $450,648 $757,708
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SOURCE: Continental Resources
CONTACT: investors, Warren Henry, VP Investor Relations,
Web Site: http://www.contres.com/