Exhibit 99.1
CONTINENTAL RESOURCES ANNOUNCES FIRST QUARTER 2009 RESULTS
ENID, Oklahoma, May 7, 2009 /PRNewswire-FirstCall/ — Continental Resources, Inc. (NYSE: CLR) today reported a net loss of $26.6 million, or $0.16 per diluted share, for the first quarter ended March 31, 2009, compared with net income of $88.0 million, or $0.52 per share, for the first quarter of 2008.
Net income included a pre-tax property impairment charge of $35.4 million for the first quarter of 2009, compared with a $4.5 million pre-tax property impairment charge for the first quarter of 2008. Excluding the $35.4 million charge, Continental’s net loss was $4.6 million, or $0.03 per diluted share, for the first quarter of 2009.
The 2009 impairment charge included $9.4 million for impairment of non-producing properties and $26.0 million for impairment of developed oil and gas properties. Of the latter amount, $14.1 million related to uneconomic drilling results in two exploratory wells completed in the first quarter of 2009 in western Oklahoma and the Texas panhandle. The remainder of the $26.0 million charge primarily related to uneconomic wells in Texas and non-Bakken Montana properties.
Continental continued to increase crude oil and natural gas production in the first quarter of 2009. Average daily production was 36,808 Boepd (barrels of oil equivalent per day) for the quarter, a 22 percent increase over the first quarter of 2008 and a two percent increase over the fourth quarter of 2008. Total production for the first quarter of 2009 was 3.3 MMBoe, compared with 2.8 MMBoe for the first quarter of 2008. Production grew despite the continued reduction in drilling activity. Continental is currently operating four drilling rigs, compared with 32 operated rigs in October 2008 and 13 at the beginning of the first quarter of 2009.
“We are conserving cash and preserving the strength of our balance sheet,” said Harold Hamm, Chairman and Chief Executive Officer. “We are also focused on reducing operating costs. Industry service costs have declined due to the drastic cuts in U.S. drilling activity in the past six months. In the first quarter, we reduced production expense by 13 percent to $7.24 per Boe, compared with $8.33 in the first quarter of 2008. In addition, we expect further reductions in drilling and completion costs.”
The Company’s average sales price per barrel of oil equivalent was $29.90 for the first quarter of 2009, 63 percent lower than the average sales price of $81.35 per Boe for the first quarter of 2008. The average price for the Company’s crude oil fell to $34.99 per barrel in the first quarter of 2009, compared with $90.55 for the first quarter last year. The Company’s average natural gas price was $2.98 per Mcf for the first quarter of 2009, compared with $7.55 in the first quarter of 2008.
Crude oil price differentials averaged $8.32 per barrel for the first quarter of 2009, compared with $14.45 per barrel for the fourth quarter of 2008 and $7.41 in the first quarter last year. The Company’s average crude oil price differential for March 2009 was $4.43.
Despite increased production, total oil and natural gas sales fell to $92.6 million for the first quarter of 2009, a reduction of 59 percent from oil and gas sales of $225.4 million for the first quarter of 2008. Anticipating stronger crude oil prices, Continental stored 216 MBbls of crude oil in the first quarter of 2009. In the first quarter of 2008, the Company sold 19 MBbls of crude oil more than it produced, selling oil out of storage.
EBITDAX was $57.7 million for the first quarter of 2009, compared with $184.0 million for the first 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.
Capital expenditures were $153.1 million for the first quarter of 2009. The Company plans to manage its drilling and completion activity through the remainder of 2009 to keep full-year capital expenditures in line with its $275 million budget. The Company has only one operated drilling rig with a contract term beyond August 2009.
At March 31, 2009, the Company’s balance sheet included $5.3 million in cash and $544.0 million in long-term debt. Commitments under the Company’s revolving credit facility are currently $672.5 million, resulting in available borrowing capacity of $128.5 million as of March 31, 2009.
Operations Update
The following table contains financial and operating highlights for the first quarter of 2009 compared to the first quarter of 2008.
| | | | | | | |
| | | Three months ended
March 31, |
| | | 2009 | | | 2008 |
Average daily production: | | | | | | | |
Oil (Bopd) | | | 26,578 | | | | 24,043 |
Natural gas (Mcfd) | | | 61,382 | | | | 37,160 |
Oil equivalents (Boepd) | | | 36,808 | | | | 30,237 |
Average prices:(1) | | | | | | | |
Oil ($/Bbl) | | $ | 34.99 | | | $ | 90.55 |
Natural gas ($/ Mcf) | | | 2.98 | | | | 7.55 |
Oil equivalents ($/ Boe) | | | 29.90 | | | | 81.35 |
Production expense ($/ Boe)(1) | | | 7.24 | | | | 8.33 |
EBITDAX (in thousands) | | | 57,673 | | | | 183,968 |
Net income (loss) (in thousands) | | | (26,613 | ) | | | 87,971 |
Diluted net income (loss) per share | | | (0.16 | ) | | | 0.52 |
(1) | Average prices and per-unit production expense are calculated based on sales volumes. Crude oil production exceeded sales volumes in the first quarter of 2009 by 216 MBbls. Crude oil sales volumes exceeded oil production in the first quarter of 2008 by 19 MBbls. |
The following table presents average daily production for the Company’s principal operating areas for the quarters ended March 31, 2009, December 31, 2008, and March 31, 2008.
| | | | | | |
| (Boe per day) | | Q1 2009 | | Q4 2008 | | Q1 2008 |
Red River Units | | 14,162 | | 14,058 | | 13,620 |
Montana Bakken | | 6,144 | | 6,410 | | 6,678 |
North Dakota Bakken | | 4,807 | | 4,401 | | 1,532 |
Other Rockies | | 2,011 | | 2,507 | | 2,060 |
Arkoma Woodford | | 4,799 | | 3,276 | | 1,900 |
Other Mid-Continent | | 4,252 | | 4,751 | | 3,831 |
Gulf Coast | | 633 | | 615 | | 616 |
| | | | | | |
Total | | 36,808 | | 36,018 | | 30,237 |
Continental generated its strongest production growth in the North Dakota Bakken and the Arkoma Woodford plays in the first quarter of 2009. North Dakota Bakken production was three times higher than production in the first quarter of 2008, while production in the Arkoma Woodford of Southeast Oklahoma was 2.5 times higher than the first quarter last year.
Red River Units
Production in the Red River Units was 14,162 Boepd in the first quarter of 2009, accounting for 39 percent of Continental’s production. During the quarter, the Company continued to convert producing wells to injector wells as part of its secondary recovery program. Under this program, the Company expects production in the Units to peak in 2010.
Bakken Shale
Production in the Bakken Shale of North Dakota and Montana was 10,951 Boepd in the first quarter of 2009, a 33 percent increase over the first quarter last year. Bakken production in the first quarter of 2009 accounted for 30 percent of the Company’s total production.
Increased Bakken production was concentrated in North Dakota, where production grew nine percent from the fourth quarter of 2008 to the first quarter of 2009. On the same sequential basis, Montana Bakken production declined four percent, primarily as a result of reduced drilling activity in Montana in the last 12 months and normal well production declines. The Company currently has two operated rigs in North Dakota and none in Montana, compared with the October 2008 peak of 10 rigs in North Dakota and three rigs in Montana.
North Dakota Bakken
Continental participated in completing 26 gross wells (7.4 net) in North Dakota during the first three months of 2009. These wells produced at an average rate of 489 Boepd during their seven-day production period tests. Well test period results in this press release are seven consecutive day averages.
In terms of Company-operated wells, Continental completed 12 gross wells (5.3 net) in the North Dakota Bakken in the first quarter of 2009, with all but one targeting the Three Forks/Sanish (TFS) zone in the play. Initial production for the TFS wells averaged 503 Boepd in seven-day test periods.
Among these wells, notable completions are shown below with production period test results in gross barrels:
| | • | | Parrish 1-31H (46% WI) in McKenzie Co. – 795 Boepd; |
| | • | | Jerome 1-15H (25%WI) in McKenzie Co. – 783 Boepd; |
| | • | | Landblom 1-35H (30% WI) in Divide Co. – 648 Boepd; |
| | • | | Lawrence 1-24H (53% WI) in Williams Co. – 645 Boepd; |
| | • | | Mack 1-2H (77% WI) in McKenzie Co. – 644 Boepd; |
| | • | | Myrtle 1-7H (57% WI) in Williams Co. – 603 Boepd; and |
| | • | | Rhonda 1-28H (48% WI) in Dunn Co. – 508 Boepd. |
The Company’s Middle Bakken (MB) zone well in the first quarter of 2009 was the Rossow 1-10H (52% WI) in Divide County, which produced 329 Boepd during its initial seven-day test period.
Since the beginning of the second quarter of 2009, Continental has participated in completing five notable wells in McKenzie County. Two were Company-operated wells that targeted the TFS zone:
| | • | | Merton 1-3H (45% WI) – 912 Boepd; |
| | • | | George 1-18H (44% WI) — 896 Boepd. |
Three other wells were drilled by ConocoPhillips and targeted the MB zone. The following indicate Continental’s working interests and seven-day production test periods:
| | • | | Iron Horse 31-2H (25% WI) — 1,085 Boepd; |
| | • | | Sunline 31-12H (25% WI) — 927 Boepd; |
| | • | | Waterton 34-32H (20% WI) — 886 Boepd. |
Significant Reservoir Test
Continental is currently drilling a Middle Bakken “companion well” to a TFS producing well. The companion well, the Mathistad 2-35H, is being drilled with a lateral well bore in the MB zone approximately 60 feet above and 200 feet to the side of the existing Mathistad 1-35H well bore. The Mathistad 1-35H was completed in mid-2008, producing 1,260 Boepd from the TFS zone during its initial seven-day test period.
The Company will monitor pressures and performance of both wells during and after completion of the new well to determine whether the MB and TFS zones act as separate producing reservoirs in that part of the play. The Company believes the two zones are not in communication over most of the play, based on reservoir simulation and fracture modeling.
Montana Bakken
In the Montana Bakken, the Company continued to implement its 320-acre infield and field-extension program in the first quarter of 2009. Notable completions included the Mondalin 3-10H (71% WI) and the Stoney Butte Farms 3-17H (83% WI), which produced at 625 and 474 Boepd, respectively, in their initial seven-day test periods.
The Company also re-entered an existing open-hole producer well, Constance 2-18H, cleaned it out to total depth, installed a liner with swell packers, and then fracture-stimulated it using the plug-perforation technique. After almost three months of production, the well is still producing an incremental 150 Boepd. Other wells in Richland County are being reviewed for possible re-completion.
As previously announced, Continental also commenced a pilot carbon dioxide injection project during the first quarter of 2009 to evaluate the potential for enhanced recovery of oil in Richland County, Montana. Utilizing the huff-and-puff technique, carbon dioxide was injected, and the carbon dioxide and associated fluids are currently flowing back and being analyzed for performance and economics.
Arkoma Woodford
Production in the Arkoma Woodford shale play was 4,799 Boepd in the first quarter of 2009, accounting for 13 percent of Continental’s total production. The Arkoma production volume was 153 percent higher than that for the first quarter of 2008 and 47 percent higher than fourth quarter 2008 production. The Company participated in 27 gross wells (4.4 net) during the first quarter of 2009. Continental currently has one operated rig in the Arkoma and one operated rig drilling in the Anadarko Woodford.
Conference Call Information
Continental Resources will host a conference call on Thursday, May 7, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its first 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) 680-0879 | | |
| Intl. dial in: | | (617) 213-4856 | | |
| Pass code: | | 80506866 | | |
| | |
| Replay number: | | (888) 286-8010 | | |
| Intl. replay: | | (617) 801-6888 | | |
| Pass code: | | 81245474 | | |
Conference Presentations
Continental management is currently scheduled to present May 18, 2009 at the UBS Global Oil and Gas Conference in Austin and on June 1 at the RBC Capital Markets Global Energy and Power Conference in New York. Presentation materials for the conferences 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
March 31, | |
| | | 2009 | | | 2008 | |
| | | (unaudited) | |
Revenues: | | | | | | | | |
Oil and natural gas sales | | $ | 92,568 | | | $ | 225,425 | |
Loss on mark-to-market derivatives | | | — | | | | (4,608 | ) |
Oil and natural gas service operations | | | 4,040 | | | | 6,834 | |
| | | | | | | | |
Total revenues | | | 96,608 | | | | 227,651 | |
| | | | | | | | |
| | |
Operating costs and expenses: | | | | | | | | |
Production expense | | | 22,426 | | | | 23,073 | |
Production tax | | | 6,822 | | | | 12,775 | |
Exploration expense | | | 7,119 | | | | 5,262 | |
Oil and gas service operations | | | 2,403 | | | | 4,230 | |
Depreciation, depletion, amortization and accretion | | | 50,697 | | | | 28,646 | |
Property impairments | | | 35,425 | | | | 4,520 | |
General and administrative (1) | | | 10,284 | | | | 7,531 | |
Gain on sale of assets | | | (136 | ) | | | (79 | ) |
| | | | | | | | |
Total operating costs and expenses | | | 135,040 | | | | 85,958 | |
| | |
Income (loss) from operations | | | (38,432 | ) | | | 141,693 | |
Interest expense and other | | | 4,440 | | | | 3,112 | |
| | | | | | | | |
Net income (loss) before income tax expense | | | (42,872 | ) | | | 138,581 | |
Income tax (benefit) expense | | | (16,259 | ) | | | 50,610 | |
| | | | | | | | |
Net income (loss) | | $ | (26,613 | ) | | $ | 87,971 | |
| | |
Basic net income (loss) per share | | $ | (0.16 | ) | | $ | 0.52 | |
Diluted net income (loss) per share | | | (0.16 | ) | | | 0.52 | |
| | |
Basic weighted average shares outstanding | | | 168,467 | | | | 167,890 | |
Diluted weighted average shares outstanding | | | 168,467 | | | | 169,138 | |
| | | | | | | | |
| (1) | Includes non-cash charges for stock-based compensation of $2.7 million and $1.4 million for the three months ended March 31, 2009 and 2008, respectively. |
Condensed Consolidated Balance Sheets
(in thousands)
| | | | | | |
| | | March 31,
2009 | | December 31,
2008 |
| | | (unaudited) | | |
Assets: | | | | | | |
Cash and cash equivalents | | $ | 5,315 | | $ | 5,229 |
Receivables | | | 174,939 | | | 229,079 |
Inventories and other | | | 58,147 | | | 43,387 |
Net property and equipment | | | 1,993,291 | | | 1,935,143 |
Other assets | | | 3,635 | | | 3,041 |
| | | | | | |
Total assets | | $ | 2,235,327 | | $ | 2,215,879 |
| | | | | | |
| | |
Liabilities and shareholders’ equity: | | | | | | |
Current liabilities | | $ | 291,236 | | $ | 403,594 |
Long-term debt | | | 544,000 | | | 376,400 |
Other noncurrent liabilities | | | 475,339 | | | 487,177 |
Shareholders’ equity | | | 924,752 | | | 948,708 |
| | | | | | |
Total liabilities and shareholders’ equity | | $ | 2,235,327 | | $ | 2,215,879 |
| | | | | | |
Condensed Consolidated Statements of Cash Flows
(in thousands)
| | | | | | | | |
| | | Three months ended
March 31, | |
| | | 2009 | | | 2008 | |
| | | (unaudited) | |
Net income (loss) | | $ | (26,613 | ) | | $ | 87,971 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Non-cash expenses | | | 82,639 | | | | 56,949 | |
Changes in assets and liabilities | | | (15,923 | ) | | | (20,114 | ) |
| | | | | | | | |
Net cash provided by operating activities | | | 40,103 | | | | 124,806 | |
| | | | | | | | |
| | |
Net cash used in investing activities | | | (206,333 | ) | | | (176,726 | ) |
| | | | | | | | |
| | |
Net cash provided by financing activities | | | 166,316 | | | | 46,822 | |
| | | | | | | | |
| | |
Net change in cash and cash equivalents | | | 86 | | | | (5,098 | ) |
Cash and cash equivalents at beginning of period | | | 5,229 | | | | 8,761 | |
| | | | | | | | |
Cash and cash equivalents at end of period | | $ | 5,315 | | | $ | 3,663 | |
| | | | | | | | |
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
March 31, |
| (in thousands) | | 2009 | | | 2008 |
| | | (unaudited) |
Net income (loss) | | $ | (26,613 | ) | | $ | 87,971 |
Unrealized oil derivative loss | | | 0 | | | | 2,180 |
Income tax expense (benefit) | | | (16,259 | ) | | | 50,610 |
Interest expense | | | 4,587 | | | | 3,411 |
Depreciation, depletion, amortization and accretion | | | 50,697 | | | | 28,646 |
Property impairments | | | 35,425 | | | | 4,520 |
Exploration expense | | | 7,119 | | | | 5,262 |
Equity compensation | | | 2,717 | | | | 1,368 |
| | | | | | | |
EBITDAX | | $ | 57,673 | | | $ | 183,968 |
| | | | | | | |
