Exhibit 99.1
Continental Resources Posts Strong Quarterly Growth in Production and Earnings
2Q 2010 Production Increases Nine Percent Over 1Q 2010
EBITDAX Grows 99 Percent to $211.6 Million
$101.7 Million in Net Income, or $0.60 Per Share
Significant Confirmation Well Announced in Anadarko Woodford Play
ENID, Okla., August 4, 2010 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) reported strong growth in crude oil and natural gas production for the three months ended June 30, 2010 compared with the same period of 2009 and for first quarter of 2010.
Production was 41,913 barrels of oil equivalent per day (Boepd) for the second quarter of 2010, a 12 percent increase over production of 37,347 Boepd for the second quarter of 2009 and nine percent higher than production for the first quarter of 2010. Crude oil accounted for 75 percent of second quarter 2010 production.
Continental reported net income of $101.7 million, or $0.60 per diluted share, for the second quarter ended June 30, 2010. This compared with net income of $13.5 million, or $0.08 per diluted share, for the second quarter of 2009. Net income for the second quarter of 2010 included a pre-tax property impairments charge of $19.5 million, compared with an impairments charge of $23.3 million for the second quarter of 2009. Net income for the second quarter of 2010 also included a $33.1 million pre-tax gain on sale of assets.
Total revenue was $280.0 million for the second quarter of 2010, which included oil and natural gas sales of $219.4 million and a $55.5 million gain on mark-to-market derivative instruments. In the second quarter last year, total revenue was $151.8 million, which included oil and natural gas sales of $146.4 million and an $890,000 gain on mark-to-market derivative instruments.
EBITDAX was $211.6 million for the second quarter of 2010, almost double EBITDAX of $106.3 million for the second 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.
“Our second quarter performance was very solid, highlighted by strong, organic production growth and excellent financial results,” said Harold Hamm, Chairman and Chief Executive Officer.
“With our premium lease positions in oil-rich and liquids-rich plays, we’ve launched what we believe will be a multi-year period of exceptional increases in production, proved reserves and earnings,” he said. “We will continue to monetize non-strategic assets and maintain operating and capital discipline as we accelerate production growth.”
In early July, the Company increased its 2010 capital expenditure budget by 53 percent to $1.3 billion, which included $400 million allocated for lease acquisition and retention. Continental currently has 27 operated drilling rigs, more than double the total at the beginning of the year. The Company plans to exit 2010 with 32 operated drilling rigs.
Continental’s average realized crude oil price was $68.44 per barrel in the second quarter of 2010, while the average realized natural gas price was $4.33 per Mcf, yielding a blended realized price of $57.94 per Boe. In the second quarter of 2009, the Company reported a blended price of $43.52 per Boe.
Second quarter crude oil price differential averaged $9.59 per barrel, which included a spike in the month of May to $13.08. Differentials were $6.73 and $9.04 in April and June, respectively. The Company’s natural gas differential was a $0.24 per Mcf premium for the second quarter of 2010.
Increased production and continued operating efficiencies resulted in production expense of $5.90 per Boe for the second quarter of 2010. This was a reduction of 17 percent from the second quarter of 2009, when production expense was $7.14 per Boe.
General and administrative expense was $3.03 per Boe, compared with $2.78 for the second quarter of 2009. These included non-cash equity compensation of $0.82 per Boe in both periods.
Income from operations was $176.3 million for the second quarter of 2010, compared with operating income of $26.2 million for the second quarter of 2009.
At June 30, 2010, the Company’s balance sheet included $15.2 million in cash and $609.8 million in long-term debt, which included $114.0 million borrowed under the Company’s revolving credit facility.
Operating Highlights
| Three months ended June 30, | Six months ended June 30, | ||||||||||||
| 2010 | 2009 | 2010 | 2009 | ||||||||||
Average daily production: | |||||||||||||
Crude oil (Bopd) | 31,611 | 27,654 | 30,373 | 27,119 | |||||||||
Natural gas (Mcfd) | 61,815 | 58,156 | 58,844 | 59,760 | |||||||||
Crude oil equivalents (Boepd) | 41,913 | 37,347 | 40,180 | 37,079 | |||||||||
Average prices:(1) | |||||||||||||
Crude oil ($/Bbl) | $ | 68.44 | $ | 53.44 | $ | 69.87 | $ | 44.82 | |||||
Natural gas ($/Mcf) | 4.33 | 2.60 | 4.84 | 2.79 | |||||||||
Crude oil equivalents ($/Boe) | 57.94 | 43.52 | 59.92 | 36.99 | |||||||||
Production expense ($/Boe)(1) | 5.90 | 7.14 | 6.17 | 7.19 | |||||||||
General and admin. exp. ($/Boe)(1) | 3.03 | 2.78 | 3.20 | 3.04 | |||||||||
EBITDAX (in thousands) | 211,611 | 106,250 | 391,578 | 163,923 | |||||||||
Net income (loss) (in thousands) | 101,741 | 13,508 | 174,206 | (13,105 | ) | ||||||||
Diluted net income (loss) per share | 0.60 | 0.08 | 1.03 | (0.08 | ) | ||||||||
| 1) | Average prices and per-unit expenses are calculated based on sales volumes. Crude oil production exceeded sales volumes in the second quarter of 2010 by 28 MBbls. Crude oil production exceeded sales volumes in the second quarter of 2009 by 35 MBbls. Crude oil sales exceeded production volumes in the first half of 2010 by 13 MBbls. Crude oil production exceeded sales volumes in the first half of 2009 by 251 MBbls. |
Production by Region
Boe per day | 2Q 2010 | 1Q 2010 | 2Q 2009 | |||
North Region: | ||||||
Red River Units | 15,080 | 14,467 | 15,095 | |||
Montana Bakken | 5,196 | 5,584 | 6,541 | |||
North Dakota Bakken | 13,046 | 10,023 | 6,774 | |||
South Region: | ||||||
Arkoma Woodford | 3,721 | 3,481 | 4,235 | |||
Anadarko Woodford | 1,079 | 925 | 61 | |||
Other | 2,617 | 2,570 | 3,172 | |||
East Region | 1,174 | 1,378 | 1,469 | |||
Total | 41,913 | 38,428 | 37,347 |
Bakken Shale Play (North Dakota and Montana)
Production growth in the Bakken continued to trend higher in the second quarter of 2010, accounting for 43 percent of the Company’s total production. Bakken production was 18,242 Boepd in the second quarter of 2010, an increase of 37 percent over the second quarter of 2009.
Continental reported a 93 percent increase in its North Dakota production, compared to the second quarter of 2009. The Company participated in completing 49 gross wells (13.0 net) in North Dakota in the second quarter of 2010. Initial production rates averaged 1,265 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 22 gross operated wells during the quarter, including 14 wells that targeted the Three Forks formation and eight wells targeting the Middle Bakken zone.
Notable Company-operated wells that targeted the Three Forks zone, with initial test results, included:
| • | Meldahl 1-23H (35% WI) in McKenzie Co. – 2,489 Boe; |
| • | Ole 1-29H (36% WI) in McKenzie Co. – 1,864 Boe; |
| • | Bang 2-33H (45% WI) in Dunn Co. – 1,860 Boe; |
| • | Roger 1-18H (22% WI) in Dunn Co. – 1,486 Boe; |
| • | Stortroen 1-13H (49% WI) in McKenzie Co. – 1,461 Boe; |
| • | Lundberg 1-8H (39% WI) in Dunn Co. – 1,238 Boe; |
| • | Strid 1-26H (35% WI) in Williams Co. – 1,092 Boe. |
Notable Company-operated wells that targeted the Middle Bakken zone, with initial test results, included:
| • | Franklin 1-20H (34% WI) in Divide Co. – 1,288 Boe; |
| • | Bohmbach 2-35H (68% WI) in McKenzie Co. – 1,271 Boe; |
| • | Brockmeier 1-1H (59% WI) in McKenzie Co. – 1,217 Boe; |
| • | Anseth 1-29H (69% WI) in Williams Co. – 1,088 Boe. |
Continental is currently completing the first of three ECO-Pad® projects that it began drilling in the second quarter of 2010. 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, reduced drilling and completion cost, and reduced environmental impact due to the smaller surface footprint, compared with four individual drilling sites.
Continental is currently completing Bakken wells with 24-stage fracture stimulation, but in some cases is testing 30-stage completions. The Company has 18 operated rigs in the North Dakota Bakken and one rig in Montana Bakken, and plans to add one more rig each in each state by year end.
The Company has 816,852 net acres leased in the Bakken Shale play, with 589,937 net acres in North Dakota and 226,915 net acres in Montana portion.
Red River Units (Montana, North Dakota and South Dakota)
Red River Units’ production was 15,080 Boepd in the second quarter, or 36 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 1,079 Boepd in the second quarter of 2010, reflecting a significant increase in drilling activity this year.
In late May, Continental completed a key confirmation well, the Doris 1-25H (98% WI), in its Northwest Cana project. The Doris 1-25H was completed flowing at an initial production test rate of 4.5 MMcfpd and 72 Bopd of condensate from the Woodford shale zone.
The Doris 1-25H is located in Dewey County, four miles south of the Company’s discovery well, the Brown 1-2H. The Brown 1-2H was completed flowing 4.2 MMcfpd and 102 Bopd, and has produced a cumulative 920 MMcf and 13,400 barrels of condensate since it began production in September 2009.
“The Doris 1-25H is another strong producer, confirming that the performance of the Brown well is repeatable,” Mr. Hamm said. “This goes a long way toward demonstrating the potential of our Northwest Cana acreage position.”
The Company has leased 251,626 net acres in the Anadarko Woodford, with approximately 70 percent of its acreage in the Northwest Cana, primarily in Blaine, Canadian, Custer and Dewey counties. The remainder is in the Southeast Cana, primarily Grady County. Continental currently has three operated rigs in the Anadarko Woodford play and plans to add four more by year end.
“The level of competitive interest in the Anadarko Woodford continues to rise,” he said. “With a total of 21 industry rigs active in the play and successes like the Doris 1-25H, the play is being rapidly de-risked.”
Continental’s production in the eastern part of the Woodford Shale play, the Arkoma Woodford, was 3,721 Boepd in the second quarter of 2010.
The Company completed its two initial wells in the East Krebs portion of the Arkoma Woodford in the second quarter of 2010, utilizing information from a recently completed 3-D seismic project that covered 50 square miles. The Marilyn 1-29H (79% WI) flowed 4.2 MMcf in its initial one-day test period. Seven miles to the east of the Marilyn 1-29H, the Delphia 1-34H flowed 2.1 MMcf in its initial test period. Continental is currently drilling its third well in the East Krebs prospect. Both the Marilyn 1-29H and the Delphia 1-34H are located in Pittsburg County.
The Company currently has one operated rig in the Arkoma Woodford, where its acreage position totals 46,074 net acres.
Niobrara Shale Play (Colorado and Wyoming)
Continental announced July 9 that it has established a strategic position in the Niobrara Shale play, and has now leased 59,071 net acres in Weld County, Colorado and Platte, Laramie and Goshen counties, Wyoming. The Company was active drilling horizontal wells in the Silo Field portion of the play in the early 1990s, prior to the development of multi-stage fracture stimulation techniques. Continental sees excellent potential for development in the play using current well completion technology.
Continental plans to initiate drilling in the Niobrara in the fourth quarter of this year.
2010 Guidance Update
Continental also announced today that reductions in operating costs have resulted in two positive changes in its 2010 guidance and an upward revision to expected taxes.
The Company expects that production expense will average between $6.50 and $7.00 per Boe for the year, versus its original guidance of a range of $7.75 to $8.25 per Boe. In addition, the Company expects that its 2010 natural gas price differential will be in a range from a $0.25 per Mcf differential cost to a $0.25 per Mcf premium, versus its earlier estimate of a differential cost of $1.25 to $1.75 per Mcf. The Company expects production taxes will average between 7.0% and 7.5% of oil and gas revenue for the year, versus its original guidance of a range of 6.5% to 7.0% of oil and gas revenue.
Conference Call Information
Continental Resources will host a conference call on Thursday, August 5, 2010, at 10:00 a.m. ET (9 a.m. CT) to discuss its second 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) 680-0890 | |
| Intl. dial-in: | (617) 213-4857 | |
| Pass code: | 42960135 | |
| Replay number: | (888) 286-8010 | |
| Intl. replay: | (617) 801-6888 | |
| Pass code: | 76654675 | |
Conference Presentations
Continental management is currently scheduled to present at the following research conferences:
August 23-24, ENERCOM Energy Conference, Denver
September 2, Hodges Capital Management 12th Annual Investment Forum, Dallas
September 29, DeutscheBank Energy Conference, Boston
October 28, Osage Oil and Gas Summit, Tulsa
The Company also plans to host an investors’ day on Tuesday, October 12 in Oklahoma City.
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 Relations | Brian Engel, VP Public Affairs | |||
| (580) 548-5127 | (580) 249-4731 |
Unaudited Condensed Consolidated Statements of Operations
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
| In thousands, except per share data | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas sales | $ | 219,426 | $ | 146,439 | $ | 436,550 | $ | 239,007 | ||||||||
Gain on mark-to-market derivative instruments | 55,465 | 890 | 81,809 | 890 | ||||||||||||
Oil and natural gas service operations | 5,077 | 4,432 | 9,877 | 8,472 | ||||||||||||
Total revenues | 279,968 | 151,761 | 528,236 | 248,369 | ||||||||||||
Operating costs and expenses: | ||||||||||||||||
Production expenses | 22,348 | 24,038 | 44,949 | 46,464 | ||||||||||||
Production taxes and other expenses | 18,231 | 11,629 | 34,238 | 18,451 | ||||||||||||
Exploration expenses | 2,269 | 1,530 | 4,055 | 8,649 | ||||||||||||
Oil and natural gas service operations | 4,091 | 2,694 | 8,047 | 5,097 | ||||||||||||
Depreciation, depletion, amortization and accretion | 58,822 | 53,148 | 111,409 | 103,845 | ||||||||||||
Property impairments | 19,514 | 23,275 | 34,689 | 58,700 | ||||||||||||
General and administrative expenses(1) | 11,494 | 9,351 | 23,343 | 19,635 | ||||||||||||
Gain on sale of assets | (33,124 | ) | (85 | ) | (33,346 | ) | (221 | ) | ||||||||
Total operating costs and expenses | 103,645 | 125,580 | 227,384 | 260,620 | ||||||||||||
Income (loss) from operations | 176,323 | 26,181 | 300,852 | (12,251 | ) | |||||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (11,903 | ) | (4,723 | ) | (20,263 | ) | (9,310 | ) | ||||||||
Other | 78 | 301 | 784 | 448 | ||||||||||||
| (11,825 | ) | (4,422 | ) | (19,479 | ) | (8,862 | ) | |||||||||
Income (loss) before income taxes | 164,498 | 21,759 | 281,373 | (21,113 | ) | |||||||||||
Provision (benefit) for income taxes | 62,757 | 8,251 | 107,167 | (8,008 | ) | |||||||||||
Net income (loss) | $ | 101,741 | $ | 13,508 | $ | 174,206 | $ | (13,105 | ) | |||||||
Basic net income (loss) per share | $ | 0.60 | $ | 0.08 | $ | 1.03 | $ | (0.08 | ) | |||||||
Diluted net income (loss) per share | $ | 0.60 | $ | 0.08 | $ | 1.03 | $ | (0.08 | ) | |||||||
Basic weighted average shares outstanding | 168,887 | 168,492 | 168,872 | 168,479 | ||||||||||||
Diluted weighted average shares outstanding | �� | 169,932 | 169,498 | 169,878 | 168,479 | |||||||||||
| (1) | Includes non-cash charges for stock-based compensation of $3.1 million and $2.7 million for the three months ended June 30, 2010 and 2009, respectively, and $6.0 million and $5.4 million for the six months ended June 30, 2010 and 2009, respectively. |
| Condensed Consolidated Balance Sheets | June 30 | December 31 | ||||||
| (In thousands) | 2010 | 2009 | ||||||
| (unaudited) | ||||||||
Assets: | ||||||||
Cash and cash equivalents | $ | 15,232 | $ | 14,222 | ||||
Receivables | 305,923 | 183,358 | ||||||
Derivative assets | 62,625 | 2,218 | ||||||
Inventories and other | 44,862 | 36,230 | ||||||
Net property and equipment | 2,442,252 | 2,068,055 | ||||||
Other assets | 20,725 | 10,844 | ||||||
Total assets | $ | 2,891,619 | $ | 2,314,927 | ||||
Liabilities and shareholders’ equity: | ||||||||
Current liabilities | $ | 451,373 | $ | 219,710 | ||||
Long-term debt | 609,844 | 523,524 | ||||||
Other noncurrent liabilities | 620,929 | 541,414 | ||||||
Shareholders’ equity | 1,209,473 | 1,030,279 | ||||||
Total liabilities and shareholders’ equity | $ | 2,891,619 | $ | 2,314,927 | ||||
| Unaudited Condensed Consolidated Statements of Cash Flows | Six months ended June 30, | |||||||
| (In thousands) | 2010 | 2009 | ||||||
Net income (loss) | $ | 174,206 | $ | (13,105 | ) | |||
Adjustments to reconcile net inc. (loss) to net cash provided by operating activities: | ||||||||
Non-cash expenses | 152,671 | 168,995 | ||||||
Changes in assets and liabilities | 63,348 | (73,397 | ) | |||||
Net cash provided by operating activities | 390,225 | 82,493 | ||||||
Net cash used in investing activities | (462,564 | ) | (295,773 | ) | ||||
Net cash provided by financing activities | 73,349 | 213,122 | ||||||
Net change in cash and cash equivalents | 1,010 | (158 | ) | |||||
Cash and cash equivalents at beginning of period | 14,222 | 5,229 | ||||||
Cash and cash equivalents at end of period | $ | 15,232 | $ | 5,071 | ||||
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. The Company’s management believes EBITDAX is useful because it allows one to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within its 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 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 revolving credit facility requires that it maintain a total debt to EBITDAX ratio of no greater than 3.75 to 1.0 on a rolling four-quarter basis. The Company was in compliance with this covenant at June 30, 2010. A violation of this covenant in the future could result in a default under our revolving credit facility. In the event of such default, the lenders under the Company’s revolving credit facility could elect to terminate their commitments thereunder, cease making further loans, and could declare all outstanding amounts, together with accrued interest, to be due and payable. If the indebtedness under the Company’s revolving credit facility were to be accelerated, its assets may not be sufficient to repay in full such indebtedness. The Company’s revolving credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by Continental. The following table is a reconciliation of our net income to EBITDAX.
| Three months ended June 30, | Six months ended June 30, | |||||||||||||||
In thousands | 2010 | 2009 | 2010 | 2009 | ||||||||||||
Net income (loss) | $ | 101,741 | $ | 13,508 | $ | 174,206 | $ | (13,105 | ) | |||||||
Interest expense | 11,903 | 4,723 | 20,263 | 9,310 | ||||||||||||
Provision (benefit) for income taxes | 62,757 | 8,251 | 107,167 | (8,008 | ) | |||||||||||
Depreciation, depletion, amortization and accretion | 58,822 | 53,148 | 111,409 | 103,845 | ||||||||||||
Property impairments | 19,514 | 23,275 | 34,689 | 58,700 | ||||||||||||
Exploration expenses | 2,269 | 1,530 | 4,055 | 8,649 | ||||||||||||
Unrealized derivative gain | (48,513 | ) | (890 | ) | (66,181 | ) | (890 | ) | ||||||||
Non-cash equity compensation | 3,118 | 2,705 | 5,970 | 5,422 | ||||||||||||
EBITDAX | $ | 211,611 | $ | 106,250 | $ | 391,578 | $ | 163,923 | ||||||||