Exhibit 99.1
CONTINENTAL RESOURCES INCREASES PRODUCTION IN SECOND QUARTER
Company Reports Record Wells in Middle Bakken and Three Forks/Sanish Zones in North Dakota
2009 Capital Expenditure Budget Raised 42 Percent to $390 Million
ENID, Oklahoma, August 6, 2009 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) today announced that its total production grew 18 percent in the second quarter of 2009, compared with the second quarter last year. In addition, the Company reported the successful completion of the Mathistad 2-35H, a “companion well” designed to test its theory that the Middle Bakken and Three Forks/Sanish zones act as separate reservoirs in portions of the North Dakota Bakken shale play.
“Technical data from the Mathistad 2-35H supports our belief that the Middle Bakken and Three Forks/Sanish reservoirs are separate in this area of the play,” said Harold Hamm, Chairman and Chief Executive Officer. “The Mathistad 2-35H tested at a seven-day initial production rate of 995 Boepd. This is the highest initial rate that we’ve recorded from our Middle Bakken completions in North Dakota, and this high initial productivity indicates that we tapped into new, undrained reservoir rock with the companion well.”
For the second quarter of 2009, Continental reported net income of $13.5 million, or $0.08 per diluted share, compared with net income of $127.3 million, or $0.75 per diluted share, for the second quarter of 2008.
Net income for the second quarter of 2009 included a pre-tax property impairment charge of $23.3 million and mark-to-market gains on natural gas fixed price and basis swaps of $890,000. Apart from these non-cash items, Continental’s net income was $27.1 million, or $0.16 per diluted share, for the second quarter of 2009. The impairment charge included $13.2 million for impairment of non-producing properties and $10.1 million for impairment of developed oil and gas properties. In the second quarter of 2008, the Company recorded a $3.2 million pre-tax property impairment charge.
Average daily production was 37,347 Boepd (barrels of oil equivalent per day) for the second quarter of 2009, 18 percent higher than production of 31,623 Boepd in the second quarter of 2008.
Continental’s second quarter 2009 results reflected a significant year-over-year decline in crude oil and natural gas prices. The Company’s average realized sales price per barrel of oil equivalent was $43.52 for the second quarter of 2009, a decline of 58 percent from the average sales price of $102.86 per Boe for the second quarter of 2008. The average realized price for crude oil was $53.44 per barrel in the second quarter of 2009, while the average natural gas price was $2.60 per Mcf. Average prices were $118.28 per barrel and $8.82 per Mcf in the second quarter last year. Crude oil accounted for 74 percent of Continental’s second quarter 2009 total production.
Crude oil price differentials averaged $6.02 per barrel for the second quarter of 2009, compared with $8.32 in the first quarter of 2009 and $5.75 for the second quarter of 2008.
Total oil and natural gas sales were $146.4 million for the second quarter of 2009, compared with $297.6 million for the second quarter of 2008. Production exceeded sales in the second quarter due to the Company placing an additional 35 MBbls of crude oil in storage. As of June 30, 2009, the Company had 669 MBbls of crude oil in storage and pipeline-required line fill.
EBITDAX was $106.3 million for the second quarter of 2009, compared with $245.0 million for the second quarter last year. For the Company’s definition and reconciliation of EBITDAX to net income, the most comparable figure calculated pursuant to generally accepted accounting principles, see “Non-GAAP Financial Measures” at the end of this press release.
At June 30, 2009, the Company’s balance sheet included $5.1 million in cash and $592.0 million in long-term debt. As of August 6, 2009, $572 million was drawn against its revolving credit facility, leaving available borrowing capacity at $178 million, based on commitments of $750 million.
“We are pleased with our production growth year-over-year and the continued reduction in drilling and completion costs in the second quarter of 2009,” Mr. Hamm said. “Production expense also declined to $7.14 per Boe in the quarter, compared with $9.32 in the second quarter last year. General and administrative expense per Boe also declined, to $2.78 from $3.55 in the second quarter last year.
“We’re also drilling much more efficiently in North Dakota, with spud-to-rig-release down 40 percent from an average of 45 days in 2008 to an average of 28 days in the first half of 2009. We drilled our latest well to total depth of 20,904 feet in 16 days,” he said.
Mathistad 2-35H Test
“We are proud of our operating and financial achievements, but clearly the most significant milestone in the quarter was our successful Mathistad 2-35H test,” Mr. Hamm said. Continental issued a separate press release today with additional detail on the Mathistad 2-35H. The companion well was drilled horizontally in the Middle Bakken (MB) zone approximately 50 feet above the horizontal of the Mathistad 1-35H.
The Mathistad 1-35H was completed as a producing Three Forks/Sanish (TFS) well in June 2008. By the time Continental started drilling the Mathistad 2-35H, the Mathistad 1-35H had produced 103,000 Boe and was pumping 187 Boepd. In contrast, the Mathistad 2-35H flowed at 995 Boepd during its initial test period, more than four times the rate at which the first well had been performing on pump.
“This significant production difference is the strongest evidence that we stimulated new rock with the second well completion,” Mr. Hamm said. “From a technical point of view, that is the only plausible explanation for this level of initial productivity.”
He noted that additional drilling will be required to establish the extent to which the reservoirs are separate across the play. “We are very encouraged by these early steps in delineating the Bakken shale play, especially with regard to developing the Middle Bakken and the Three Forks/Sanish reservoirs separately. Based on the results of the Mathistad 2-35H, we believe the reserve potential of the Bakken play just went up.”
The Company estimates that approximately half of its 439,000 net acres in North Dakota have the potential for the Middle Bakken and Three Forks/Sanish to produce independently. Continental controls a total of 605,000 net acres in the Bakken play in North Dakota and Montana.
Operations Update
The following table contains financial and operating highlights for the second quarter of 2009 compared to the second quarter of 2008.
| | | | | | | | | | | | | |
| | | Three months ended
June 30, | | Six months ended
June 30, |
| | | 2009 | | 2008 | | 2009 | | | 2008 |
Average daily production: | | | | | | | | | | | | | |
Oil (Bbl) | | | 27,654 | | | 24,117 | | | 27,119 | | | | 24,080 |
Natural gas (Mcf) | | | 58,156 | | | 45,035 | | | 59,760 | | | | 41,098 |
Oil equivalents (Boe) | | | 37,347 | | | 31,623 | | | 37,079 | | | | 30,930 |
Average prices:(1) | | | | | | | | | | | | | |
Oil ($/Bbl) | | $ | 53.44 | | $ | 118.28 | | $ | 44.82 | | | $ | 104.43 |
Natural gas ($/Mcf) | | | 2.60 | | | 8.82 | | | 2.79 | | | | 8.25 |
Oil equivalents ($/Boe) | | | 43.52 | | | 102.86 | | | 36.99 | | | | 92.34 |
Production expense ($/Boe)(1) | | | 7.14 | | | 9.32 | | | 7.19 | | | | 8.83 |
General and administrative expense ($/Boe)(1) | | | 2.78 | | | 3.55 | | | 3.04 | | | | 3.14 |
EBITDAX (in thousands) | | | 106,250 | | | 244,950 | | | 163,923 | | | | 426,738 |
Net income (loss) (in thousands) | | | 13,508 | | | 127,307 | | | (13,105 | ) | | | 215,278 |
Diluted net income (loss) per share | | | 0.08 | | | 0.75 | | | (0.08 | ) | | | 1.27 |
| (1) | Average prices and per-unit production expense are calculated based on sales volumes. Oil sales volumes were 35 MBbls less than oil production for the three months ended June 30, 2009 and 16 MBbls more than oil production for the three months ended June 30, 2008. For the six months ended June 30, 2009 oil sales volumes were 251 MBbls less than oil production and 35 MBbls more than oil production for the six months ended June 30, 2008. |
The following table presents average daily production for the Company’s principal operating areas for the quarters ended June 30, 2009, March 31, 2009, and June 30, 2008.
| | | | | | |
| (Boe per day) | | Q2 2009 | | Q1 2009 | | Q2 2008 |
Red River Units | | 14,092 | | 14,162 | | 13,551 |
Montana Bakken | | 6,105 | | 6,144 | | 6,363 |
North Dakota Bakken | | 6,286 | | 4,807 | | 2,082 |
Other Rockies | | 1,928 | | 2,011 | | 2,484 |
Arkoma Woodford | | 4,235 | | 4,799 | | 2,125 |
Other Mid-Continent | | 4,179 | | 4,252 | | 4,419 |
Gulf Coast | | 522 | | 633 | | 599 |
| | | | | | |
Total | | 37,347 | | 36,808 | | 31,623 |
Continental is currently operating four drilling rigs – three in North Dakota and one in Oklahoma – compared with 32 operated rigs in October 2008 and 13 at the beginning of 2009.
Red River Units
Production in the Red River Units was 14,092 Boepd in the second quarter of 2009, accounting for 38 percent of Continental’s production. The Company continues to convert producing wells to injector wells as part of its secondary recovery program in the Units.
North Dakota Bakken
North Dakota Bakken production accounted for 17 percent of the total for the second quarter 2009, for the first time surpassing production in its Montana Bakken properties.
Continental participated in completing 28 gross wells (8.1 net) in North Dakota during the quarter. Initial production averaged 737 Boepd, a significant increase over the first quarter of 2009 and the average for 2008.All initial well results discussed in this press release are seven consecutive day averages.
In terms of Company-operated wells, Continental completed nine gross wells (4.8 net) targeting the TFS zone in the play in the second quarter of 2009, including the Kukla 1-21H in Dunn Co., which was the Company’s strongest TFS well to date, based on initial test production. As a group, the nine wells’ initial test period results averaged 876 Boepd.
| | • | | Kukla 1-21H (65% WI) in Dunn Co. – 1,429 Boepd; |
| | • | | McGregor 1-15H (54% WI) in Williams Co. – 1,101 Boepd; |
| | • | | Merton 1-3H (45% WI) in McKenzie Co. – 911 Boepd; |
| | • | | Lokken 1-2H (54% WI) in Williams Co. – 854 Boepd; |
| | • | | George 1-18H (48% WI) in McKenzie Co. – 872 Boepd; |
| | • | | Wiley 1-25H (48% WI) in McKenzie Co. – 816 Boepd; |
| | • | | Olson 1-8H (81% WI) in McKenzie Co. – 735 Boepd; |
| | • | | Thorvald 1-6H (43% WI) in Dunn Co. – 603 Boepd; |
| | • | | Lila 1-36RH (50% WI) in Divide Co. – 563 Boepd. |
Since the end of the second quarter, Continental has completed three additional TFS wells.
| | • | | Bohmbach 1-35H (76% WI) in McKenzie Co. – 1,367 Boepd; |
| | • | | Tangsrud 1-1H (91% WI) in Divide Co. – 834 Boepd; |
| | • | | Leonard 1-1H (49% WI) in Williams Co. – 166 Boepd. |
The Company also completed a second Middle Bakken well during the second quarter of 2009, the Armstrong 1-24H (74% WI) in Billings Co., which generated initial production results of 356 Boepd.
Montana Bakken
Montana Bakken production was 6,105 Boepd in the second quarter of 2009, essentially flat with the first quarter of 2009 and four percent below production in the second quarter of 2008. Montana production accounted for 16 percent of the Company’s second quarter 2009 production. The Company did not drill any wells in the second quarter of 2009 in the Montana part of the play.
Arkoma Woodford
Production in the Arkoma Woodford shale play was 4,235 Boepd in the second quarter of 2009, which was almost double that in the second quarter last year and which accounted for 11 percent of Continental’s total production in the most recent quarter. Arkoma production declined slightly in the second quarter compared with the first quarter of 2009, reflecting reduced drilling activity since the beginning of the year in response to low commodity prices.
The Company participated in 14 gross wells (2.0 net) during the second quarter of 2009 and currently has one operated rig drilling in the play in southeastern Oklahoma.
In June, the Company announced that it had entered into natural gas fixed price and basis swaps for 600,000 MMBtu at an average price of $5.27 for December 2009 and for 600,000 MMBtu per month at an average price of $5.68 for calendar 2010. The hedges are indexed to Centerpoint East pricing and are net of differential. They were put in place to underpin the Company’s current and expected level of operations in the Arkoma Woodford play.
Company Increases 2009 Capital Expenditure Budget
Continental has increased its 2009 capital expenditures budget by 42 percent to $390 million, citing the strengthening of crude oil prices and resulting increased cash flow in the second quarter of the year. Along with funding increased drilling operations, the Company plans to continue reducing the level of borrowings under its credit facility in the second half of the year.
Capital expenditures were $73 million for the second quarter of 2009 and $227 million for the first half of 2009. Looking to the second half, the Company plans to apply almost all of its additional capex spending to drilling operations in the North Dakota Bakken.
Under its original $275 million capex budget for 2009, the Company would have had only one operated rig active in the final four months of 2009. Now, the Company plans to keep the current total of four operated drilling rigs active through September, with a fifth added in October and a sixth in November. All additional rigs will be added in the North Dakota Bakken, and the single rig in the Arkoma will remain.
“The revised budget will enable us to build production momentum as we enter 2010,” Mr. Hamm said. “We have only one drilling rig on long-term contract, so if crude oil prices change significantly, we will be able to adjust.”
Conference Call Information
Continental Resources will host a conference call on Thursday, August 6, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its second 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) 679-8034 |
| Intl. dial in: | | (617) 213-4847 |
| Pass code: | | 89808872 |
| |
| Replay number: | | (888) 286-8010 |
| Intl. replay: | | (617) 801-6888 |
| Pass code: | | 53136120 |
Conference Presentations
Continental management is currently scheduled to present at the following research conferences:
| | |
| August 10, 2009 | | EnerCom Oil & Gas Conference VII, Denver |
| September 2 | | The Hodges Capital 11th Annual Investment Forum, Dallas |
| September 17 | | The C.K. Cooper West Coast Energy Conference, Newport Beach, CA |
| September 21 | | The Bank of America/Merrill Lynch 2009 Smid Cap Conference, Boston |
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 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 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.
CONTACT: Continental Resources, Inc.
| | |
| J. Warren Henry | | Brian Engel |
| Investors | | Media |
| (580) 548-5127 | | (580) 249-4731 |
Condensed Consolidated Statements of Operations
(in thousands, except per share amounts)
| | | | | | | | | | | | | | | | |
| | | Three months ended
June 30, | | | Six months ended
June 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Revenues: | | | | | | | | | | | | | | | | |
Oil and natural gas sales | | $ | 146,439 | | | $ | 297,619 | | | $ | 239,007 | | | $ | 523,044 | |
Gain (loss) on mark-to-market derivative instruments | | | 890 | | | | (3,358 | ) | | | 890 | | | | (7,966 | ) |
Oil and natural gas service operations | | | 4,432 | | | | 9,173 | | | | 8,472 | | | | 16,007 | |
| | | | | | | | | | | | | | | | |
Total revenues | | | 151,761 | | | | 303,434 | | | | 248,369 | | | | 531,085 | |
| | | | |
Operating costs and expenses: | | | | | | | | | | | | | | | | |
Production expenses | | | 24,038 | | | | 26,953 | | | | 46,464 | | | | 50,026 | |
Production tax | | | 11,629 | | | | 17,695 | | | | 18,451 | | | | 30,470 | |
Exploration expense | | | 1,530 | | | | 5,731 | | | | 8,649 | | | | 10,993 | |
Oil and natural gas service operations | | | 2,694 | | | | 6,468 | | | | 5,097 | | | | 10,698 | |
Depreciation, depletion, amortization and accretion | | | 53,148 | | | | 28,062 | | | | 103,845 | | | | 56,708 | |
Property impairments | | | 23,275 | | | | 3,153 | | | | 58,700 | | | | 7,673 | |
General and administrative1 | | | 9,351 | | | | 10,276 | | | | 19,635 | | | | 17,807 | |
Gain on sale of assets | | | (85 | ) | | | (133 | ) | | | (221 | ) | | | (212 | ) |
| | | | | | | | | | | | | | | | |
Total operating costs and expenses | | | 125,580 | | | | 98,205 | | | | 260,620 | | | | 184,163 | |
| | | | | | | | | | | | | | | | |
Income from operations | | | 26,181 | | | | 205,229 | | | | (12,251 | ) | | | 346,922 | |
Other income (expense): | | | | | | | | | | | | | | | | |
Interest expense | | | (4,723 | ) | | | (2,865 | ) | | | (9,310 | ) | | | (6,276 | ) |
Other | | | 301 | | | | 248 | | | | 448 | | | | 547 | |
| | | | | | | | | | | | | | | | |
| | | (4,422 | ) | | | (2,617 | ) | | | (8,862 | ) | | | (5,729 | ) |
| | | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | 21,759 | | | | 202,612 | | | | (21,113 | ) | | | 341,193 | |
Provision (benefit) for income taxes | | | 8,251 | | | | 75,305 | | | | (8,008 | ) | | | 125,915 | |
| | | | | | | | | | | | | | | | |
Net income (loss) | | $ | 13,508 | | | $ | 127,307 | | | $ | (13,105 | ) | | $ | 215,278 | |
| | | | | | | | | | | | | | | | |
Basic net income (loss) per share | | $ | 0.08 | | | $ | 0.76 | | | $ | (0.08 | ) | | $ | 1.28 | |
Diluted net income (loss) per share | | | 0.08 | | | | 0.75 | | | | (0.08 | ) | | | 1.27 | |
Basic weighted average shares outstanding | | | 168,492 | | | | 168,055 | | | | 168,479 | | | | 167,973 | |
Diluted weighted average shares outstanding | | | 169,498 | | | | 169,552 | | | | 168,479 | | | | 169,418 | |
| (1) | Includes non-cash charges for stock-based compensation of $2.7 million and $2.5 million for the three months ended June 30, 2009 and 2008, respectively and $5.4 million and $3.9 million for the six months ended June 30, 2009 and 2008, respectively. |
Condensed Consolidated Balance Sheets
(in thousands)
| | | | | | |
| | | June 30,
2009 | | December 31,
2008 |
| | | (unaudited) | | |
Assets: | | | | | | |
Cash and cash equivalents | | $ | 5,071 | | $ | 5,229 |
Receivables | | | 177,046 | | | 229,079 |
Inventories and other | | | 47,909 | | | 43,387 |
Net property and equipment, based on successful efforts method of accounting | | | 1,990,046 | | | 1,935,143 |
Other assets | | | 4,049 | | | 3,041 |
| | | | | | |
Total assets | | $ | 2,224,121 | | $ | 2,215,879 |
| | | | | | |
| | |
Liabilities and shareholders’ equity | | | | | | |
Current liabilities | | $ | 207,219 | | $ | 403,594 |
Long-term debt | | | 592,000 | | | 376,400 |
Other noncurrent liabilities | | | 484,230 | | | 487,177 |
Shareholders’ equity | | | 940,672 | | | 948,708 |
| | | | | | |
Total liabilities and shareholders’ equity | | $ | 2,224,121 | | $ | 2,215,879 |
| | | | | | |
Condensed Consolidated Statements of Cash Flows
(in thousands)
| | | | | | | | |
| | | Six months ended June 30, | |
| | | 2009 | | | 2008 | |
| | | (unaudited) | |
Net income (loss) | | $ | (13,105 | ) | | $ | 215,278 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Non-cash expenses | | | 168,995 | | | | 140,900 | |
Changes in assets and liabilities | | | (73,397 | ) | | | (58,208 | ) |
| | | | | | | | |
Net cash provided by operating activities | | | 82,493 | | | | 297,970 | |
| | |
Net cash used in investing activities | | | (295,773 | ) | | | (348,729 | ) |
| | | | | | | | |
| | |
Net cash provided by financing activities | | | 213,122 | | | | 55,188 | |
| | | | | | | | |
| | |
Net change in cash and cash equivalents | | | (158 | ) | | | 4,429 | |
Cash and cash equivalents at beginning of period | | | 5,229 | | | | 8,761 | |
| | | | | | | | |
Cash and cash equivalents at end of period | | $ | 5,071 | | | $ | 13,190 | |
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). Management believes EBITDAX is useful because it allows them 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 as 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 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 June 30, | | Six months ended June 30, |
| | | 2009 | | | 2008 | | 2009 | | | 2008 |
| (in thousands) | | (unaudited) |
Net income (loss) | | $ | 13,508 | | | $ | 127,307 | | $ | (13,105 | ) | | $ | 215,278 |
Unrealized derivative gain | | | (890 | ) | | | — | | | (890 | ) | | | — |
Interest expense | | | 4,723 | | | | 2,865 | | | 9,310 | | | | 6,276 |
Provision (benefit) for income taxes | | | 8,251 | | | | 75,305 | | | (8,008 | ) | | | 125,915 |
Depreciation, depletion, amortization and accretion | | | 53,148 | | | | 28,062 | | | 103,845 | | | | 56,708 |
Property impairments | | | 23,275 | | | | 3,153 | | | 58,700 | | | | 7,673 |
Exploration expense | | | 1,530 | | | | 5,731 | | | 8,649 | | | | 10,993 |
Equity compensation | | | 2,705 | | | | 2,527 | | | 5,422 | | | | 3,895 |
| | | | | | | | | | | | | | |
EBITDAX | | $ | 106,250 | | | $ | 244,950 | | $ | 163,923 | | | $ | 426,738 |
