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Continental Resources Reports Third Quarter 2007 Results, 2008 Capital Budget and 2008 Financial and Operating Guidance

Posted on: Tuesday, 6 November 2007, 06:00 CST

ENID, Okla., Nov. 6 /PRNewswire-FirstCall/ -- Continental Resources 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.

(LOGO: http://www.newscom.com/cgi-bin/prnh/20070501/DATU029LOGO )

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 Nine months ended September 30, 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 were 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 were 96 MBbls less than oil production for the nine months ended September 30, 2007 and 10 Mbbls less 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 on oil plays 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 be 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 areas for the three months ended September 30, 2007 compared to the three months ended September 30, 2006 and June 30, 2007.

Q3 2007 Q3 2006 Q2 2007 (boe per day) (boe per day) (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 approval by the State oil and gas regulatory department. Over the 68 day 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, November 6, 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 http://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 http://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 Nine months ended September 30, 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 September 30, December 31, (in thousands) 2007 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 (in thousands) September 30, 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 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 Nine months ended September 30, 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

Photo: NewsCom: http://www.newscom.com/cgi-bin/prnh/20070501/DATU029LOGOAP Archive: http://photoarchive.ap.org/PRN Photo Desk, photodesk@prnewswire.com

Continental Resources

CONTACT: Don Fischbach of Continental Resources, Inc., +1-580-548-5137,donfischbach@contres.com

Web site: http://www.contres.com/

Source: PRNewswire-FirstCall

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