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Continental Resources Reports Fourth Quarter and Year-End 2007 Results

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ENID, Okla., Feb. 26 /PRNewswire-FirstCall/ -- Continental Resources, Inc. (NYSE: CLR) ("Continental" or the "Company") today reported unaudited fourth quarter and year-end 2007 results.

Fourth Quarter 2007

Continental reported net income for the three months ended December 31, 2007, of $60.9 million, or $0.36 per diluted share, on revenues of $159.0 million. Reported net income includes an unrealized loss of $20.8 million ($13.0 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 was $73.9 million, or $0.44 per diluted share, excluding unrealized losses on crude oil derivative contracts.

Continental's crude oil sales price averaged $13.05 per barrel less than NYMEX WTI during the fourth quarter of 2007 due to seasonal demand factors. In order to mitigate the wider differentials, the Company stored production in off-lease tanks and moved some production to alternative markets by railcar. Sales volumes for the quarter were 125 MBbls less than production volumes during the quarter due to the increase in crude oil inventory in leased tankage and railcars in transit. During the first two months of 2008, Continental sold approximately 100 MBbls of the stored crude oil. The Company's cost basis in the stored crude oil was approximately $36 per barrel. The crude oil price differential has improved during the first quarter of 2008 and is expected to be less than the $9.88 per barrel differential realized for first quarter 2007.

Net income for the three months ended December 31, 2006, was $30.2 million, or $0.19 per diluted share, after pro forma adjustments to provide for income taxes as if the Company had been a subchapter C corporation during the fourth quarter of 2006 and was $48.7 million, or $0.31 per diluted share, excluding pro forma adjustments.

Full Year 2007

Continental reported net income for the year ended December 31, 2007, of $28.6 million, or $0.17 per diluted share, on revenues of $582.2 million. Reported net income includes a one-time charge of $198.4 million for the initial establishment of deferred taxes that were recognized in conjunction with the Company's conversion from a subchapter S corporation to a subchapter C corporation as of the Company's initial public offering in May 2007. Additionally, reported net income includes an unrealized loss of $26.7 million ($16.6 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 2007 was $243.6 million, or $1.47 per diluted share, excluding the effect of these items.

Net income for the year ended December 31, 2006 was $156.8 million, or $0.96 per diluted share, after pro forma adjustments to provide for income taxes as if Continental had been a subchapter C corporation during 2006 and was $253.1 million, or $1.59 per diluted share, excluding pro forma adjustments.

The following table contains unaudited financial and operational highlights for the three months and year ended December 31, 2007 compared to the corresponding periods in the prior year.



                                           Quarter Ended        Year Ended
                                            December 31,        December 31,
                                           2007     2006       2007     2006
    Average daily production:
       Crude oil (bopd)                   24,309   22,028    23,832   20,494
       Natural gas (Mcfd)                 36,362   26,847    31,599   25,274
       Crude oil equivalent (boepd)       30,369   26,503    29,099   24,706
    Average prices: (1)
       Crude oil ($ / Bbl)                $77.53   $47.89    $63.55   $55.30
       Natural gas ($ / Mcf)               $5.99    $5.71     $5.87    $6.08
       Crude oil equivalent ($ / boe)     $68.84   $45.57    $58.31   $52.09
    Production expense ($ / boe) (1)       $6.85    $6.88     $7.35    $6.99
    EBITDAX (in thousands) (2)          $144,074  $85,106  $469,885 $372,115
    Net income (in thousands)            $60,892  $48,743   $28,580 $253,088
    Diluted net income per share           $0.36    $0.31      $.17    $1.59
    Pro forma net income (in
     thousands) (3)                               $30,221  $184,002 $156,833
    Pro forma diluted net income per
     share                                          $0.19     $1.11    $0.96

    (1) Oil sales volumes were 125 MBbls less than oil production for the
        three months ended December 31, 2007 and 11 MBbls less than oil
        production for the three months ended December 31, 2006. Oil sales
        volumes were 221 MBbls less than oil production for the year ended
        December 31, 2007 and 21 Mbbls less than oil production for the year
        ended December 31, 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. A reconciliation of net income to
        EBITDAX is provided later in this press release.
    (3) In connection with the initial public offering, 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 initial public offering. Pro forma net
        income reflects adjustments to provide for income taxes as if the
        Company had been a subchapter C corporation for the periods presented.

Management Comments

Harold Hamm, Chairman and Chief Executive Officer stated, "2007 was an exciting year for Continental as we completed our initial public offering, celebrated our fortieth anniversary and posted record financial and operating results. Our decision to store some crude oil production in late 2007 rather than sell at a significant discount has been rewarded with much narrower differentials in early 2008. We are very pleased with the two recent successful confirmation tests in the Michigan Trenton/Black River project. As a result, we have confidence in our 3D seismic interpretations and have five additional wells planned early this year. In the North Dakota Bakken play, drilling results have exceeded our expectations and, with continued strong crude oil prices, we will likely expand the 2008 drilling budget in this region as well."

Operations Update

The following table presents unaudited average daily production for each of the Company's principal areas for the three months and year ended December 31, 2007 compared to the corresponding periods in the prior year.



                                        Quarter Ended         Year Ended
                                         December 31,         December 31,
                                       2007       2006      2007       2006
                                     (boe per   (boe per  (boe per   (boe per
                                       day)       day)      day)       day)
    Red River Units                   14,374     11,732    13,356     10,842
    Montana Bakken Field               7,244      7,591     7,613      7,041
    North Dakota Bakken Field          1,382        314       967        152
    Other Rockies                      1,600      1,717     1,678      1,579
    Oklahoma Woodford Field            1,338         57       832         32
    Other Mid-Continent                3,767      4,223     4,083      4,069
    Gulf Coast                           664        869       570        991
    Total                             30,369     26,503    29,099     24,706



According to the year-end proved reserve report for the Red River Units, peak daily production is projected to be approximately 19,000 barrels of oil equivalent in 2009. The Company currently has five rigs drilling increased density wells within the Red River Units. Conversions of producing wells to injectors continues on schedule and the expansion of existing facilities for increased water injection and disposal capacity is approximately 50% complete. On February 5, 2008, Hiland Partners took the Badlands plant out of service when it discovered that a primary piece of equipment had failed. Hiland Partners anticipates that the plant will start up at the beginning of March. The Company's net natural gas sales from the Red River units were 5 MMcfd during the fourth quarter of 2007.

In the Montana Bakken Field, the Company completed 2 gross (1.3 net) third wells within existing 1280-acre units during 2007 with an average gross estimated ultimate recovery (EUR) of 468 Mboe. Additionally, the Company completed 8 gross (6.2 net) 640-acre tri-lateral step-out wells during 2007 with an average gross EUR of 245 Mboe. The proved reserve estimates for the 2007 infield and step-out programs support continuation of both efforts and, with more than 60 additional infield locations and approximately 60,000 net undeveloped acres north of the field for 640-acre tri-lateral step-out locations, we expect to keep two to three drilling rigs in the Montana Bakken field during 2008.

In the North Dakota Bakken Field, the Company continues to be pleased with its drilling results in the central and northern portions of its acreage holdings. The Company completed 27 Bakken Shale wells in the central and northern areas during 2007 with an average gross EUR of 335 Mboe, exceeding our economic model of 315 gross Mboe. If crude oil prices remain strong, the Company plans to seek Board approval in the second quarter to increase the 2008 drilling budget in the North Dakota Bakken Field.

The McGinnity 1-15H (54% WI), located in the northern portion of the Company's acreage holdings in the North Dakota Bakken Field, was recently completed using an uncemented liner within a long single lateral for an initial 7-day average production rate of 589 boepd. The Company also had a significant completion recently in the southern portion of its acreage with the Basaraba 44X-27 (26% WI) flowing at an initial 7-day average production rate of 463 boepd from an unstimulated, 1,280-acre tri-lateral wellbore. Of additional significance for the North Dakota Bakken play is the reservoir potential of the Three Forks-Sanish formation (TFS) found immediately below the lower Bakken Shale. As the middle Bakken and lower Bakken Shale sections expand it is more likely that the TFS formation contains incremental reserves not being drained by fracture stimulating the upper portion of the middle Bakken. The Company expects to spud its first TFS test in the next 30 days to begin evaluating the TFS potential. The Company also plans to participate in two non-operated TFS tests scheduled to be drilled in the first and second quarters.

In the Oklahoma Woodford Shale field, the Company recently completed four strategic wells, the Wilson 2-14H (23% WI), Tucker 2-26H (30% WI), Kimberley 1-11H (48% WI) and Mary 1-6H (86% WI) with initial 7-day average production rates of 6,392 Mcfd, 2,091 Mcfd, 2,900 Mcfd and 1,765 Mcfd, respectively. The Wilson 2-14H, located in the Ashland prospect, is the Company's first 320-acre increased density test and demonstrates the potential for down spacing in the play. The Tucker 2-26H and Kimberly 1-11H are of particular significance because they provide justification for expanded development of the northern and western extents of the Ashland prospect. The Mary 1-6H is an exploratory test located in the center of the Company's East McAlester prospect in the 15E-16E areas and supports further development of this area. The Company currently has four operated rigs in the play and plans to add one additional rig in the first half and one more rig in the second half of 2008. Most of the Company's operated drilling activity in 2008 is expect to focus on development and step-out opportunities within the Ashland and Rushing prospects.

As part of its development plan, the Company is preparing to conduct a simul-frac of 4 gross (1.3 net) wells currently being drilled on 160-acre spacing within the Ashland prospect. The Ashland Simul-Frac is designed to simultaneously fracture stimulate these four wells, drilled approximately 1,320 feet apart to better contain the stimulation and more effectively fracture the reservoir rock.

The Company continues to monitor production in the Salt Creek area and is in the process of acquiring approximately 18 square miles of 3D seismic data to further evaluate the potential of the prospect. The Company plans also to participate in the acquisition of approximately 53 square miles of 3D seismic over its East McAlester acreage during the second half of 2008.

The Company's Trenton/Black River project in and around Hillsdale County, Michigan continues to produce excellent results. Guided by innovative 3D seismic techniques, the Company has experienced 100% success completing 3 gross (2.5 net) operated wells in the project. The Company's initial discovery well, the McArthur 1-36 (83% WI) is flowing 260 bopd and has been assigned gross proved reserves of 824,000 barrels of crude oil equivalent. The Company's second well, the Anspaugh 1-1 (83% WI) encountered similar type pay and is currently flow testing 200 bopd. The Company's third well, the Wessel 1-6 (83% WI) recently began testing flowing at rates up to 100 barrels of oil per hour during cleanup. Testing will continue on the Anspaugh 1-1 and Wessel 1-6 to establish reservoir characteristics and estimated reserves. The Company has also participated in 2 gross (0.6 net) non-operated Trenton/Black River tests. The Clark 1-36 (21% WI) is testing very low volumes of oil. The Young 10-34 (42% WI) encountered encouraging shows while drilling and is currently waiting on completion. The Company owns 35,200 gross (29,200 net) acres in the Trenton/Black River play and has shot, processed and interpreted 11 square miles of 3D seismic on the acreage so far. The Company is currently permitting and will begin acquisition of 20 square miles of new 3D data in March with plans to acquire additional data later this year. The Company plans to drill five additional wells in the second and third quarters of 2008.

Conference Presentation

Continental plans to participate in the Raymond James 29th Annual Institutional Investors Conference to be held in Orlando, Florida from March 2 through March 5, 2008. President Mark E. Monroe is scheduled to present at the conference on Monday, March 3, 2008 at 1:05 p.m. Eastern Time. Mr. Monroe's presentation will be webcast live on the Company's website at http://www.contres.com.

Conference Call Information

The Company will host a conference call on Tuesday, February 26, 2008, 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 (888) 679-8037. The passcode is 21999378. Participants may pre-register for this conference call. Pre-registration is not mandatory. Callers who pre-register will be given a unique PIN to gain immediate access to the call and bypass the live operator. Callers may pre-register at any time, including up to and after the call start time, by going to the following URL: https://www.theconferencingservice.com/prereg/key.process?key=PNUVWEYCJ A replay of the conference call will be available for 30 days on the Company's website or by dialing (888) 286-8010. The replay passcode is 99066154.

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 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, 580-548-5127
ir@contres.com

     Condensed Consolidated Statements of Income
     (in thousands, except per share amounts)
                            Three months ended           Year ended
                               December 31,              December 31,
                            2007          2006         2007         2006
                              (unaudited)                 (unaudited)

    Revenues:
    Oil and natural gas
     sales                $183,780     $110,598     $606,514     $468,602
    Loss on mark-to-market
     derivatives           (30,476)           -      (44,869)           -
    Oil and natural gas
     service operations      5,690        3,315       20,570       15,050
    Total revenues        $158,994     $113,913     $582,215     $483,652

    Operating costs and
     expenses:
    Production expense     $18,288      $16,705      $76,489      $62,865
    Production tax          10,251        5,721       32,562       22,331
    Exploration expense      2,499       10,653        9,163       19,738
    Oil and natural gas
     service operations      3,942        1,587       12,709        8,231
    Depreciation,
     depletion,
     amortization and
     accretion              26,326       19,052       93,632       65,428
    Property impairments     4,887        2,671       17,879       11,751
    General and
     administrative          5,148        6,503       32,802       31,074
    (Gain) loss on sale
     of assets                (650)           2         (988)        (290)
    Total operating costs
     and expenses           70,691       62,894      274,248      221,128

    Income from operations  88,303       51,019      307,967      262,524
    Interest expense and
     other                  (2,543)      (2,276)     (11,190)      (9,568)
    Net income before
     income tax expense     85,760       48,743      296,777      252,956

    Income tax expense
     (benefit)              24,868                   268,197         (132)

    Net income             $60,892      $48,743      $28,580     $253,088

    Basic net income
     per share               $0.36        $0.31        $0.17        $1.60
    Diluted net income
     per share               $0.36        $0.31        $0.17        $1.59

    Basic weighted
     average shares
     outstanding           167,590      158,279      164,059      158,114
    Diluted weighted
     average shares
     outstanding           169,255      159,247      165,422      159,665




    Condensed Consolidated Balance Sheets
    (in thousands)
                                                            December 31,
                                                       2007           2006
                                                            (unaudited)
    Assets:
    Cash and cash equivalents                         $8,761         $7,018
    Receivables                                      163,090         89,086
    Inventories and other                             33,713          8,877
    Net property and equipment                     1,157,926        751,747
    Other assets                                      15,163          2,201
    Total assets                                  $1,378,653       $858,929

    Liabilities and shareholders' equity:
    Current liabilities                             $266,106       $188,637
    Long-term debt                                   165,000        140,000
    Other noncurrent liabilities                      39,511         39,831
    Deferred income taxes                            284,904              -
    Shareholders' equity                             623,132        490,461
    Total liabilities and shareholders' equity    $1,378,653       $858,929



    Condensed Consolidated Statements of Cash Flows
    (in thousands)                                          Year ended
                                                            December 31,
                                                       2007           2006
                                                           (unaudited)

    Net income                                       $28,580       $253,088
    Adjustments to reconcile net income to net
     cash provided by operating activities:
    Non-cash expenses                                424,392        102,177
    Changes in assets and liabilities                (60,694)        61,776
    Net cash provided by operating activities        392,278        417,041

    Net cash used in investing activities           (483,498)      (324,523)

    Net cash provided by (used in) financing
     activities                                       92,938        (91,451)

    Effect of exchange rate on change in cash
     and cash equivalents                                 25            (63)

    Net change in cash and cash equivalents            1,743          1,004
    Cash and cash equivalents at beginning of period   7,018          6,014
    Cash and cash equivalents at end of period        $8,761         $7,018

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 to EBITDAX.



                                      Three months ended       Year  ended
                                         December 31,          December 31,
    (in thousands)                      2007      2006      2007        2006
                                         (unaudited)           (unaudited)

    Net income                       $60,892   $48,743    $28,580   $253,088
    Unrealized oil derivative loss    20,822         -     26,703          -
    Income tax expense (benefit)      24,868         -    268,197       (132)
    Interest expense                   3,085     2,787     12,939     11,310
    Depreciation, depletion,
    amortization and accretion        26,326    19,052     93,632     65,428
    Property impairments               4,887     2,671     17,879     11,751
    Exploration expense                2,499    10,653      9,163     19,738
    Equity compensation                  695     1,200     12,792     10,932
    EBITDAX                         $144,074   $85,106   $469,885   $372,115

SOURCE Continental Resources, Inc.

CONTACT: J. Warren Henry of Continental Resources, Inc.,
+1-580-548-5127, ir@contres.com

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