Exhibit 99.1
Continental Resources Reports Third Quarter 2007 Results, 2008 Capital Budget and 2008 Financial and Operating Guidance
Enid, Oklahoma – November 6, 2007 – Continental Resources (NYSE:CLR) today reported unaudited third quarter 2007 results, the 2008 capital budget approved by the Company’s Board of Directors and 2008 financial and operating guidance. The Company reported net income for the three months ended September 30, 2007, of $56.4 million, or $0.33 per diluted share, on revenues of $156.8 million. The reported net income includes an unrealized loss of $12.5 million (7.8 million net of taxes) recognized for the change in the fair market value of open crude oil derivative contracts not designated for hedge accounting. Net income for the quarter would have been $64.2 million, or $.38 per diluted share without the effect of the unrealized derivative loss.
Net income for the three months ended September 30, 2006, was $54.5 million, or $0.34 per diluted share, after pro forma adjustments to provide for income taxes as if the Company had been a subchapter C corporation during the 2006 third quarter.
The following table contains unaudited financial and operational highlights for the three and nine months ended September 30, 2007 compared to the corresponding periods in the prior year.
| | | | | | | | | | | | | |
| | | Three months ended
September 30, | | Nine months ended
September 30, |
| | | 2007 | | 2006 | | 2007 | | | 2006 |
Average daily production: | | | | | | | | | | | | | |
Crude oil (bopd) | | | 24,224 | | | 21,352 | | | 23,672 | | | | 19,977 |
Natural gas (Mcfd) | | | 31,499 | | | 25,668 | | | 29,994 | | | | 24,744 |
Crude oil equivalent (boepd) | | | 29,474 | | | 25,630 | | | 28,671 | | | | 24,101 |
Average prices: (1) | | | | | | | | | | | | | |
Crude oil ($ / Bbl) | | $ | 69.44 | | $ | 61.67 | | $ | 58.92 | | | $ | 58.05 |
Natural gas ($ / Mcf) | | $ | 5.29 | | $ | 5.77 | | $ | 5.82 | | | $ | 6.22 |
Crude oil equivalent ($ / boe) | | $ | 62.61 | | $ | 57.24 | | $ | 54.68 | | | $ | 54.50 |
Production expense ($ / boe) (1) | | $ | 7.72 | | $ | 6.61 | | $ | 7.53 | | | $ | 7.03 |
EBITDAX (in thousands) (2) | | $ | 132,817 | | $ | 112,503 | | $ | 332,472 | | | $ | 287,009 |
Net income (loss) (in thousands) (3) | | $ | 56,372 | | $ | 87,991 | | $ | (32,312 | ) | | $ | 204,345 |
Diluted net income (loss) per share | | $ | 0.33 | | $ | 0.55 | | $ | (0.20 | ) | | $ | 1.28 |
| (1) | Oil sales volumes are 49 MBbls less than oil production for the three months ended September 30, 2007 and 41 MBbls greater than oil production for the three months ended September 30, 2006. Oil sales volumes are 96 MBbls less than oil production for the nine months ended September 30, 2007 and 10 Mbbls greater than oil production for the nine months ended September 30, 2006. Average prices and per unit production expense have been calculated using sales volumes. |
| (2) | EBITDAX represents earnings before interest expense, income taxes (when applicable), depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains or 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). A reconciliation of net income to EBITDAX is provided later in this press release. |
| (3) | In connection with the IPO, the Company recorded a charge of $198.4 million to recognize deferred taxes upon its conversion from a non-taxable subchapter S corporation to a taxable subchapter C corporation. The Company provides income taxes on net income for periods after the IPO. |
Management Comments
“As a result of record high production and revenues, the Company’s EBITDAX of $133 million was $24 million higher than last quarter”, said Harold Hamm, Chairman and Chief Executive Officer. “Our cash operating margin was $49 per equivalent barrel in the third quarter when NYMEX oil prices averaged $75 per barrel. With higher NYMEX oil prices in the fourth quarter, our cash operating margin should continue to grow.”
“We are excited about our 2008 drilling program”, said Mr. Hamm. “The capital budget of $616 million represents a 28% increase over the 2007 budget and will be focused in the Williston Basin and the Oklahoma Woodford Shale. We estimate that the drilling program will increase average daily production to approximately 34,000 boepd for 2008, about 16 percent above the 2007 third quarter rate. This estimated daily production rate would also represent about a 20,000 boepd increase over the 2004 average daily rate of 14,121 boepd with essentially all of the production growth during that period coming from drilling operations.”
2007 Guidance Update
As noted in the second quarter earnings press release, delays in completion of the new gas plant at the Red River Units and in pipeline connections in the Woodford Shale area reduced natural gas sales below the low end of the guidance range. Natural gas production for 2007 is now projected to be approximately 12,000 MMcf. In part due to the lower natural gas production, production expense guidance is being increased to an estimated $7.50 per boe for 2007. In connection with the initial public offering, the Company converted to a subchapter C- Corporation from a subchapter S- Corporation. During the third quarter, the Company determined that earnings would be allocated between the subchapter S and C-Corporation periods on a pro-rata basis. As a result, the 2007 effective tax rate is estimated to be approximately 35%.
Operations Update
The following table presents average daily production for each of the Company’s principal regions for the three months ended September 30, 2007 compared to the three months ended September 30, 2006 and June 30, 2007.
| | | | | | |
| | | Q3 2007
(boe per day) | | Q3 2006
(boe per day) | | Q2 2007
(boe per day) |
Red River Units | | 13,524 | | 11,162 | | 12,680 |
Montana Bakken Field | | 7,637 | | 7,651 | | 7,890 |
North Dakota Bakken Field | | 1,119 | | 149 | | 924 |
Other Rockies | | 1,841 | | 1,620 | | 1,774 |
Oklahoma Woodford Field | | 953 | | 46 | | 586 |
Other Mid-Continent | | 3,945 | | 4,190 | | 4,320 |
Gulf Coast | | 455 | | 812 | | 436 |
| | | | | | |
Total | | 29,474 | | 25,630 | | 28,610 |
In the Red River Units, average daily production was up 21% from the third quarter 2006 average. During the three months ended September 30, 2007, the Company completed 9 gross (8.6 net) horizontal wells and 10 gross (9.6 net) horizontal re-entries within the Red River Units. Production grew as a result of increased density drilling, response from enhanced oil recovery operations and the August commencement of the new gas processing plant. The Company currently has five drilling rigs working in the Red River Units.
In the Montana Bakken field, average daily production was flat with the prior year as production from new wells offset declines from older wells. During the third quarter, the Company completed 7 gross (6.2 net) wells in the Montana Bakken field. The Company is finishing development of its acreage on 640-acre spacing, drilling tri-lateral wells on the boundaries of the field and evaluating the potential to develop the Montana Bakken on 320 acre spacing. The Company’s initial two 320-acre wells appear to meet or exceed the economic model of 300 MBoe of ultimate per well reserves for increased density wells. The Company’s third 320-acre well, the Linnea 3-12H, is currently drilling. Potential exists for up to 60 additional 320-acre spaced wells to be drilled on the Company’s acreage. The Company currently has three drilling rigs operating in this field.
In the North Dakota Bakken field, average daily production was up 970 boepd from the third quarter 2006 average. During the third quarter, the Company participated in 11 gross (3.7 net) completed wells in the North Dakota Bakken field. Notable completions during the quarter include the Carus 24-28H (33% WI), Dvirnak 14-6H (41% WI), Jean Nelson 1-35H (43% WI), Josephine 1-8H (38% WI), Ryden 21-24H (38% WI) and State Dodge 11-21H (14% WI) which had 7-day average initial production rates of 602 boepd, 449 boepd, 276 boepd, 448 boepd, 378 boepd and 435 boped, respectively. Both the Jean Nelson 1-35H and Josephine 1-8H were completed using uncemented liners and
mechanically-diverted fracture stimulation. Early time production rates from the Jean Nelson 1-35H and Josesphine 1-8H have been higher than offset producers in their respective areas which were completed using open hole, single-stage fracture stimulation completion techniques. The Company currently has three operated drilling rigs working in the field and three drilling rigs operated under a joint venture agreement with ConocoPhillips.
In the Oklahoma Woodford Shale field in the Mid-Continent region, average daily net production for the third quarter was 5,718 Mcfd, up 62 percent over second quarter 2007. During the third quarter, the Company completed 6 gross (2.7 net) operated horizontal Woodford Shale wells and participated in another 25 gross (1.1 net) non-operated Woodford Shale completions. Notable completions during the third quarter include the Boyce 1-34H (83% WI), Brown 1-33H (83% WI), Linda 1-24H (29% WI), Pratt 1-17H (23% WI) and Wolohon 1-19H (30% WI) which had initial 7-day average production rates of 1,637 Mcfd, 975 Mcfd, 1,700 Mcfd, 3,807 Mcfd and 3,091 Mcfd, respectively. Recently, the Company completed the Luna 1-18H (17% WI) for an average rate of 5,086 Mcfd during the well’s first four days of production. Near the end of the quarter, the Company began selling natural gas from 3 gross (2.3 net) wells in its Salt Creek prospect in the 6N 10E area of the Woodford Shale field. Production rates are fluctuating as the wells clean up and currently range from 500 Mcfd to 1,700 Mcfd per well. The Company owns approximately 9,000 net acres in the Salt Creek prospect which is located 6 to 12 miles north of the Company’s Ashland prospect where most of the drilling has occurred to date. The Woodford shale formation in the Salt Creek area is similar in thickness to the Ashland area but approximately 2,000 feet shallower. The Company currently has five operated drilling rigs working in the Woodford Shale field.
Production testing has concluded on the Company’s Trenton/Black River discovery well in Hillsdale County, Michigan. The purpose of the test was to establish the optimum producing rate for the well. The future daily production rate for the well will be determined after analysis of the test results by the Company and the state oil and gas regulatory department. Over the 68 test period, the McArthur 1-36 (83% WI) produced approximately 12,000 gross barrels of oil, flowing at increasing rates from 110 bopd to 260 bopd with minimal drop in flowing and bottom hole pressure. Production is through 10 feet of perforations in approximately 182 feet of potential pay which was encountered in the well between 3,400 to 4,020 feet. The current reserve estimate for the well is approximately 700 gross Mboe. The Company has over 23,000 acres under lease in this play and plans to drill two additional wells before year end.
2008 Capital Budget
The Board of Directors approved a capital budget for 2008 of $616 million on November 5, 2007. The allocation of the budget and estimated number of net wells to be drilled by area are included in the following table (dollars in millions):
| | | | | |
| | | Capital Budget | | Net Wells |
Red River Units | | $ | 168 | | 36 |
Montana Bakken Field | | | 55 | | 13 |
North Dakota Bakken Field | | | 125 | | 20 |
Other Rockies | | | 29 | | 13 |
Oklahoma Woodford Field | | | 103 | | 20 |
Other Mid-Continent | | | 46 | | 40 |
Gulf Coast | | | 21 | | 5 |
| | | | | |
Total | | | 547 | | 147 |
| | |
Land and Seismic | | | 56 | | |
Other | | | 13 | | |
| | | | | |
Total | | $ | 616 | | |
2008 Financial and Operating Guidance
The 2008 financial and operating guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control, as further described later in this press release.
| | |
| | | Year Ended December 31, 2008 |
Production volumes: | | |
Oil (Mbbls) | | 9,000 – 9,600 |
Gas (MMcf) | | 18,000 – 19,800 |
Oil equivalent (Mboe) | | 12,000 – 12,900 |
| |
Price differentials (1): | | |
Oil (per bbl) | | $5.00 – $8.00 |
Gas (per Mcf) | | $1.00 – $1.50 |
| |
Operating costs and expenses: | | |
Production expense (per boe) | | $7.75 – $8.00 |
Production tax (percent of sales) | | 5.6% – 6.1% |
Depreciation, depletion, amortization and accretion (per boe) | | $9.75 – $10.50 |
General and administrative (per boe) (2) | | $2.10 – $2.25 |
Non-cash stock-based compensation (per boe) | | $0.75 – $1.00 |
Net oil and natural gas services income (in thousands) | | $5,000 – $7,000 |
| |
Income tax rate (percent of pre-tax net income) | | 38% |
Percent deferred | | 85% – 90% |
| (1) | Differential to calendar month average NYMEX futures price for oil and to average of last three trading days of prompt NYMEX futures contract for gas. |
| (2) | Excludes non-cash stock-based compensation. |
Conference Call Information
The Company will host a conference call on Tuesday, September 5, 2007, at 9:00 a.m. Eastern Time to discuss this press release. Interested parties may listen to the conference call via the Company’s website at www.contres.com or by dialing (800) 322-2803. The passcode is 60260824. A replay of the conference call will be available for 30 days on the Company’s website or by dialing (888) 286-8010. The passcode is 20318426.
Conference Presentation
The Company also announced its participation in Merrill Lynch Global Energy Conference to be held in New York City on November 7 and 8, 2007. President Mark E. Monroe will present at the conference on Wednesday, November 7, 2007, at 3:10 p.m. Eastern Time. Mr. Monroe’s presentation will be webcast live on the Company’s website at www.contres.com.
About Continental Resources
Continental Resources is an 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 or 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. The Company completed its initial public offering in May 2007.
Forward-Looking Information
This press release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond our control. All information, other than historical facts included in this press release, regarding our 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.
Don Fischbach, 580-548-5137
donfischbach@contres.com
Condensed Consolidated Statements of Operations
| | | | | | | | | | | | | | | | |
| | | Three months ended
September 30, | | | Nine months ended
September 30, | |
| (in thousands, except per share amounts) | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | (unaudited) | | | (unaudited) | |
Revenues: | | | | | | | | | | | | | | | | |
Oil and natural gas sales | | $ | 166,704 | | | $ | 137,281 | | | $ | 422,734 | | | $ | 358,004 | |
Loss on mark-to-market derivatives | | | (14,393 | ) | | | — | | | | (14,393 | ) | | | — | |
Oil and natural gas service operations | | | 4,461 | | | | 3,592 | | | | 14,880 | | | | 11,735 | |
| | | | | | | | | | | | | | | | |
Total revenues | | $ | 156,772 | | | $ | 140,873 | | | $ | 423,221 | | | $ | 369,739 | |
| | | | |
Operating costs and expenses: | | | | | | | | | | | | | | | | |
Production expense | | $ | 20,561 | | | $ | 15,854 | | | $ | 58,201 | | | $ | 46,160 | |
Production tax | | | 8,711 | | | | 6,618 | | | | 22,311 | | | | 16,610 | |
Exploration expense | | | 2,758 | | | | 4,018 | | | | 6,664 | | | | 9,085 | |
Oil and gas service operations | | | 2,414 | | | | 1,863 | | | | 8,767 | | | | 6,644 | |
Depreciation, depletion, amortization and accretion | | | 23,568 | | | | 18,395 | | | | 67,306 | | | | 46,376 | |
Property impairments | | | 4,099 | | | | 1,347 | | | | 12,992 | | | | 9,080 | |
General and administrative (1) | | | 6,231 | | | | 2,420 | | | | 27,654 | | | | 24,571 | |
(Gain) loss on sale of assets | | | 62 | | | | (85 | ) | | | (338 | ) | | | (292 | ) |
| | | | | | | | | | | | | | | | |
Total operating costs and expenses | | | 68,404 | | | | 50,430 | | | | 203,557 | | | | 158,234 | |
| | | | |
Income from operations | | | 88,368 | | | | 90,443 | | | | 219,664 | | | | 211,505 | |
Interest expense and other | | | (2,456 | ) | | | (2,584 | ) | | | (8,647 | ) | | | (7,292 | ) |
| | | | | | | | | | | | | | | | |
Net income before income tax expense | | | 85,912 | | | | 87,859 | | | | 211,017 | | | | 204,213 | |
Income tax expense (benefit) | | | 29,540 | | | | (132 | ) | | | 243,329 | | | | (132 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Net income (loss) | | $ | 56,372 | | | $ | 87,991 | | | $ | (32,312 | ) | | $ | 204,345 | |
| | | | | | | | | | | | | | | | |
Basic net income (loss) per share | | $ | 0.34 | | | $ | 0.56 | | | $ | (0.20 | ) | | $ | 1.29 | |
Diluted net income (loss) per share | | $ | 0.33 | | | $ | 0.55 | | | $ | (0.20 | ) | | $ | 1.28 | |
| | | | |
Basic weighted average shares outstanding | | | 167,232 | | | | 158,106 | | | | 162,869 | | | | 158,058 | |
Diluted weighted average shares outstanding | | | 169,043 | | | | 159,919 | | | | 164,546 | | | | 159,680 | |
| (1) | Includes non-cash charges for stock-based compensation of $1.2 million and $(2.2) million for the three months ended September 30, 2007 and 2006, respectively, and $12.1 million and $9.7 million for the nine months ended September 30, 2007 and 2006, respectively. |
Condensed Consolidated Balance Sheets
| | | | | | |
| (in thousands) | | September 30,
2007 | | December 31,
2006 |
| | | (unaudited) | | |
Assets: | | | | | | |
Cash and cash equivalents | | $ | 5,483 | | $ | 7,018 |
Receivables | | | 144,892 | | | 89,086 |
Inventories and other | | | 31,365 | | | 8,877 |
Net property and equipment | | | 1,072,245 | | | 751,747 |
Other assets | | | 1,808 | | | 2,201 |
| | | | | | |
Total assets | | $ | 1,255,793 | | $ | 858,929 |
| | | | | | |
| | |
Liabilities and shareholders’ equity: | | | | | | |
Current liabilities | | $ | 238,739 | | $ | 188,637 |
Long-term debt | | | 156,500 | | | 140,000 |
Other noncurrent liabilities | | | 44,786 | | | 39,831 |
Deferred income taxes | | | 253,869 | | | — |
Shareholders’ equity | | | 561,899 | | | 490,461 |
| | | | | | |
Total liabilities and shareholders’ equity | | $ | 1,255,793 | | $ | 858,929 |
Condensed Consolidated Statements of Cash Flows
| | | | | | | | |
| | | Nine months ended
September 30, | |
| (in thousands) | | 2007 | | | 2006 | |
| | | (unaudited) | |
Net income (loss) | | $ | (32,312 | ) | | $ | 204,345 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
Non-cash expenses | | | 351,526 | | | | 70,827 | |
Changes in assets and liabilities | | | (40,858 | ) | | | 13,827 | |
| | | | | | | | |
Net cash provided by operating activities | | | 278,356 | | | | 288,999 | |
| | |
Net cash used in investing activities | | | (367,933 | ) | | | (219,436 | ) |
| | |
Net cash provided by (used in) financing activities | | | 87,882 | | | | (71,162 | ) |
| | |
Effect of exchange rate on change in cash and cash equivalents | | | 160 | | | | 41 | |
| | | | | | | | |
Net change in cash and cash equivalents | | | (1,535 | ) | | | (1,558 | ) |
Cash and cash equivalents at beginning of period | | | 7,018 | | | | 6,014 | |
| | | | | | | | |
Cash and cash equivalents at end of period | | $ | 5,483 | | | $ | 4,456 | |
Non-GAAP Financial Measures
EBITDAX represents earnings before unrealized derivative gains or losses, interest expense, income taxes (when applicable), depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains or losses and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a Company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. The Company’s computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet future debt service requirements, if any. The Company’s credit facility requires that it maintain a total 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 (loss) to EBITDAX.
| | | | | | | | | | | | | | | |
| | | Three months ended
September 30, | | | Nine months ended
September 30, | |
| (in thousands) | | 2007 | | 2006 | | | 2007 | | | 2006 | |
| | | (unaudited) | | | (unaudited) | |
Net income (loss) | | $ | 56,372 | | $ | 87,991 | | | $ | (32,312 | ) | | $ | 204,345 | |
Unrealized oil derivative loss | | | 12,542 | | | — | | | | 12,542 | | | | — | |
Income tax expense (benefit) | | | 29,540 | | | (132 | ) | | | 243,329 | | | | (132 | ) |
Interest expense | | | 2,774 | | | 3,101 | | | | 9,854 | | | | 8,522 | |
Depreciation, depletion, amortization and accretion | | | 23,568 | | | 18,395 | | | | 67,306 | | | | 46,376 | |
Property impairments | | | 4,099 | | | 1,347 | | | | 12,992 | | | | 9,080 | |
Exploration expense | | | 2,758 | | | 4,018 | | | | 6,664 | | | | 9,085 | |
Equity compensation | | | 1,164 | | | (2,217 | ) | | | 12,097 | | | | 9,733 | |
| | | | | | | | | | | | | | | |
EBITDAX | | $ | 132,817 | | $ | 112,503 | | | $ | 332,472 | | | $ | 287,009 | |
