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

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

SOURCE Continental Resources

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

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