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Continental Resources Reports 87 Percent Increase in Net Income for Third Quarter of 2008

November 6, 2008

ENID, Okla., Nov. 6 /PRNewswire-FirstCall/ — Continental Resources, Inc. reported strong growth in cash flow, net income and production for the quarter ended September 30, 2008, compared with the third quarter last year.

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“For the third quarter of 2008, Continental Resources again delivered strong operating and financial results,” said Harold Hamm, Chairman and Chief Executive Officer. “We increased profits, with strong cash flow margins on total revenues. Initial production results again improved in the North Dakota Bakken and Arkoma Woodford plays, and we have now completed nine Three Forks/Sanish wells in North Dakota, with strong initial production results.

“Looking to the remainder of this year and into 2009, the Company is positioned to capitalize on its strategy of strong organic growth in production and reserves and delivering industry-leading operating margins. Our balance sheet is strong, with low debt compared to cash flows. Finally, we have a large drilling inventory, including the largest acreage position in the nation’s largest onshore oil play, the Bakken shale of Montana and North Dakota,” he said.

With the rapid decline in commodity prices, Continental has begun to decrease its operated drilling rig count. Continental plans to reduce capital expenditures in line with the level of expected cash flows to minimize the need for external financing. Continental has set its 2009 capital expenditure budget at $609 million, with $541 million allocated primarily for drilling and completion operations. This compares with a 2008 capex budget of $883 million, with $663 million allocated primarily for drilling and completion operations.

For the third quarter ended September 30, 2008, the Company reported net income of $105.3 million, or $0.62 per diluted share, an increase of 87 percent over net income of $56.4 million, or $0.33 per diluted share, for the third quarter of 2007.

Oil and natural gas sales were $286.2 million for the third quarter of 2008, an increase of 72 percent over oil and gas sales for the third quarter last year. The Company’s average sales price per barrel of crude oil equivalent was $93.21 for the most recent quarter, compared with $62.61 for the third quarter last year.

EBITDAX for the third quarter of 2008 was $238.3 million, an increase of 79 percent over EBITDAX of $132.8 million for the third quarter of 2007. For the Company’s definition and reconciliation of EBITDAX to Generally Accepted Accounting Principles, see “Non-GAAP Financial Measures” at the end of this press release.

   At September 30, 2008, the Company's long-term debt was $229.4 million.    Operations Update  

The following table contains financial and operational highlights for the three and nine months ended September 30, 2008 compared to the same periods in 2007.

                                   Three months ended      Nine Months ended                                      September 30,          September 30,                                   -------------------    ------------------                                    2008         2007      2008        2007                                   -------     -------    -------     ------   Average daily production:     Oil (Bopd)                    24,937       24,224    24,368      23,672     Natural gas (Mcfd)            50,156       31,499    44,139      29,994     Oil equivalents (Boepd)       33,297       29,474    31,725      28,671   Average prices: (1)     Oil ($/Bbl)                  $108.37       $69.44   $105.78      $58.92     Natural gas ($/Mcf)             7.97         5.29      8.14        5.82     Oil equivalents ($/Boe)        93.21        62.61     92.64       54.68   Production expense ($/Boe) (1)    8.22         7.72      8.62        7.53   EBITDAX (in thousands)         238,289      132,817   665,027     332,472   Net income (in thousands) (2)  105,256       56,372   320,534     130,831   Diluted net income    per share (2)                    0.62         0.33      1.89        0.80    

(1) Average prices and per-unit production expense are calculated based on sales volumes. Crude oil sales volumes exceeded production in the third quarter and first nine months of 2008 by 7 MBbls and 42 MBbls, respectively. Crude oil production volumes exceeded oil sales in the third quarter and first nine months of 2007 by 49 MBbls and 96 MBbls, respectively.

(2) Net income and diluted net income per share for the nine months ended September 30, 2007 are after pro forma adjustments (i) to provide for income taxes as if the Company had been a subchapter C corporation prior to the completion of its initial public offering, and (ii) to eliminate the $198.4 million charge recorded to recognize deferred taxes upon its conversion from a nontaxable subchapter S corporation to a taxable subchapter C corporation in conjunction with the Company’s May 2007 initial public offering.

The following table presents average daily production for the Company’s principal operating areas for the three months ended September 30, 2008 compared to the three months ended June 30, 2008 and September 30, 2007.

   (boe per day)                Q3 2008     Q2 2008     Q3 2007                                -------     -------     -------   Red River Units               13,375      13,551      13,531   Montana Bakken                 6,187       6,363       7,637   North Dakota Bakken            3,444       2,082       1,119   Other Rockies                  2,275       2,484       1,834   Arkoma Woodford                2,627       2,125         953   Other Mid-Continent            4,895       4,419       3,945   Gulf Coast                       494         599         455                                -------     -------     -------   Total                         33,297      31,623      29,474     

Total production averaged 33,297 boepd for the third quarter of 2008, an increase of five percent over the second quarter of 2008 and 13 percent over the third quarter of 2007. The Company exited the quarter with production averaging 34,889 boepd for September 2008.

Red River Units

The Red River Units accounted for 40 percent of Continental’s production in the third quarter of 2008. As the Company anticipated, production in the Units declined slightly from the second quarter as the Company converted producer wells to injectors and continued to expand its secondary recovery program. During the third quarter, Continental also drilled two additional water source wells to increase its water injection capacity.

Continental has allocated $101 million in operational capital expenditures to the Units in 2009. The Company plans to drill 22 producer and 12 injector wells in the Units, convert 20 producer wells to injectors, convert 26 air injector wells to water injectors, drill two water disposal wells, and complete a sixth water supply well.

Continental formerly expected production to peak in the Units at 21,000 boepd in late 2009. The Company has begun to reduce capital expenditures, decreasing its operated rig count in the Units from five to two, and consequently the production peak is now expected to be lower, but with a more gradual production decline from the peak. Overall reserves and ultimate recovery are not expected to be affected by the timing of the peak. As a result of these initiatives, the Company expects to exit 2009 with production of approximately 19,000 boepd in the Red River Units.

Bakken Shale

Third quarter production in the North Dakota Bakken increased to 3,444 boepd, an increase of 65 percent over the second quarter of 2008, primarily reflecting improved well completion techniques and superior results from Continental’s Three Forks/Sanish (TFS) completions.

During the third quarter, Continental participated in the completion of 16 gross (5.3 net) Middle Bakken and TFS wells in North Dakota. These wells had an average rate of 602 boepd during their seven-day production period tests, representing a 22% increase in performance over the Bakken completions reported by the Company for the first half of 2008.

Of particular significance were the higher initial rates that the Company observed from its Three Forks/Sanish completions, compared to those targeting the Middle Bakken formation. In 2008, of the 23 gross (9 net) completions in the North Dakota Bakken that are Company-operated, Continental has completed nine gross (3.7 net) wells in the TFS formation. These TFS wells have had an average rate of 852 boepd during their seven-day production period tests, which represents a 49% increase over the average rate of 573 boepd for Company-operated Middle Bakken completions so far in 2008.

It is also significant to note that these TFS completions were strategically distributed throughout Continental’s acreage on the Nesson anticline and achieved comparable results spanning a distance of 100 miles north-to-south.

Recent completions of Company-operated wells targeting the Three Forks/Sanish formation of the North Dakota Bakken are shown below with average seven-day production period test results in gross barrels:

   -- Maryann 1-15H (38% WI) in McKenzie Co. - 1,216 boepd;   -- Morris 1-23H (29% WI) in Dunn Co. - 1,027 boepd;   -- Kirkland 1-33H (46% WI) in McKenzie Co. - 733 boepd;   -- Arvid 1-34H (42% WI) in Divide Co. - 340 boepd.    

The Company also recently completed the Veigel 1-9H (46% WI) in Dunn Co. and the Malcolm 1-29H (45% WI) in Williams Co., which produced at average rates of 863 boepd and 658 boepd, respectively, during their production period tests. These two wells were completed in the Middle Bakken formation.

In Richland County, MT, the Company saw improved production results during the third quarter in its 320-acre infield and field-extension program. Third quarter 2008 infield wells averaged 391 boepd in their seven-day production period tests, 33 percent higher than wells completed in the second quarter in the infield program. Continental attributed the production increase to the use of single-leg laterals with liners and multi-staged fracture-stimulation techniques that were developed in its North Dakota Bakken operations.

Recent notable completions in Richland County are shown below with average seven-day production period test results in gross barrels:

   -- Ardelle 3-10H (95% WI) - 531 boepd;   -- Melvin 3-3H (83% WI) - 405 boepd;   -- Staci 3-11H (95% WI) - 346 boepd;   -- Martin 1-27H (95% WI) - 228 boepd.    

The Company recently began drilling the Joann 1-32H (89% WI) in the northern tier of its Montana Bakken acreage. It is Continental’s first Three Forks/Sanish test well in Montana.

Continental also announced that it has joined several companies to form the Montana Bakken EOR Consortium, in order to initiate a CO2 injection pilot project in Richland County to determine the effectiveness of using CO2 for enhanced oil recovery in the play. The consortium intends to start injecting CO2 before year-end 2008, to inject CO2 for one month, and then shut in the well for one month. The well will then be produced back and data analyzed to determine its enhanced oil recovery potential.

Continental currently has the largest acreage position in the Bakken Shale resource play with approximately 604,000 net acres, of which approximately 75 percent is in North Dakota. The Company has allocated $281 million in 2009 operational capex in the North Dakota and Montana Bakken, or 52 percent of its operational capex budget, to drill 131 gross (44.1 net) wells in the play.

“We have a tremendous opportunity to add reserves in North Dakota,” Mr. Hamm said. “At year-end 2007, we had 300,000 net acres in the North Dakota Bakken, and proved reserves in the play represented only five percent of our total proved reserves. We’ve expanded that acreage position to 449,000 net acres since January 1. We have completed our first nine wells in the Three Forks/Sanish formation, with seven showing very strong results, and our Middle Bakken completions have been increasingly productive. Our opportunity over the next several years to grow reserves in this play is clearly a game-changer.”

Arkoma Woodford

In the Arkoma Woodford play, Continental increased production in the third quarter by 24 percent, compared with the second quarter of 2008. The Company completed 34 gross (5.2 net) wells during the quarter.

The Company completed its strongest well to date, the Blevins 1-1H (41% WI) in Hughes Co. during the third quarter. The Blevins well averaged 8.1 MMcf per day during its seven-day production period test, but actually increased production afterward, achieving a maximum seven-day rate of 10.4 MMcf. The Blevins was drilled east of the Salt Creek area and north of where the majority of the Company’s Arkoma Woodford wells have been drilled.

Continental also continued to develop its simul-fracture technology in the Arkoma Woodford. In the third quarter, the Company completed the six-well Luna-Pratt simul-frac project. It fracture-stimulated the horizontal laterals of the six wells one pair at a time. The six wells individually averaged 3.8 gross MMcf per day during their seven-day production test periods, with little variation between the most and least productive wells.

The next planned simul-frac will involve seven Pasquali wells in the Ashland development section of the play. Five of the wells have been drilled; drilling the final two and the simul-frac completion process are scheduled for completion by year-end.

Continental has allocated $99 million in 2009 operational capital expenditures to the Arkoma Woodford and plans to drill 76 gross (14.8 net) wells in the play during the year.

Anadarko Woodford Shale and Atoka Shale

In the Anadarko Woodford shale of western Oklahoma, Continental is currently drilling two test wells, the Brown 1-2H (100% WI) in Dewey Co. and the McCalla 1-11H (90% WI) in Grady Co. The Company has approximately 111,000 net acres in the play.

In Ellis County, Oklahoma, the Company has just begun completion of its initial test well in the Atoka shale play, the Shrewder 1-22H (100% WI). Continental is also drilling the Jones-Trust 1-168H (100% WI) in Lipscomb Co., TX in the western part of the play. Continental has leased 34,000 net acres in the Atoka shale play.

Capital Budget and Guidance

Continental expects strong growth in production and reserves in the fourth quarter of 2008 and in 2009. However, the Company no longer plans to achieve its year-end exit rate target of 43,000 boepd as a result of reductions in rig count and capital expenditures.

Continental began reducing its operated rig count in October with the intention of having 17 operated rigs as of December 31, 2008, compared with the previous target of 35 operated rigs. The Company’s 2009 capital budget envisions an average of 15.5 operated rigs for the year, with eight operating in the North Dakota Bakken.

Continental expects to achieve its 2008 total production volume target of at least 12,000 Mboe. Current trends indicate that the Company may slightly exceed its guidance for production expense, which had been expected to be $7.75-to-$8.00 per boe, and its guidance for depreciation, depletion and amortization expense, which had been expected to be $9.75-to-$10.50 per boe.

Continental’s regional allocations of capital expenditures in 2009 are listed below. Operational capex includes drilling, work-over and facilities capital expenditures.

                                                2009 Capex                                                    Budget                                              (in millions)       Net Wells                                              ------------     ------------   North Dakota Bakken                                $257             38.2   Red River Units                                     101             23.0   Arkoma Woodford                                      99             14.8   Montana Bakken                                       24              5.9   Anadarko Woodford                                    14              4.1   Atoka                                                12              4.5   Other                                                34             10.3                                              ------------     ------------       Operational capex                               541            100.8    Land and seismic                                     63   Other capital expenditures                            5                                              ------------       Total capex                                     609     

“Based on how commodity prices trend next year, we will adjust to maintain our capital budget generally in line with expected cash flows,” Mr. Hamm said. “We have a lean, productive team of approximately 400 employees. We are not planning layoffs or a reduction in force. In fact, our efficiency and productivity are significant competitive advantages in just this kind of challenging environment.”

Continental announced the following operating and financial guidance for 2009. As forward-looking information, this guidance is subject to a variety of risks and uncertainties, including adjustments related to fluctuations in commodity prices. Risk factors are discussed further at the end of this press release and in the Company’s filings with the Securities and Exchange Commission.

                                                               Year Ended                                                           December 31, 2009                                                        ---------------------   Production volumes:     Oil (MMbls)                                              10.2 - 11     Gas (MMcf)                                               22.4 - 24     Oil equivalent (MMboe)                                     14 - 15    Price differentials(1) :     Oil (Bbl)                                               $8.00 - $10.00     Gas (Mcf)                                               $1.50 - $2.00    Operating expenses:     Production expense (per boe)                            $7.75 - $8.50     Production tax (per $ of sales)                         6.25% - 6.75%     Depreciation, depletion, amortization and      accretion (per boe)                                   $13.00 - $14.00     General and administrative expense (per boe)(2)         $1.75 - $2.25     Non-cash stock-based compensation (per boe)             $0.70 - $0.90    Income tax rate (percent of pre-tax income)                    38%   Percent of income tax deferred                                 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  

Continental Resources will host a conference call on Thursday, Nov. 6, 2008, at 10:00 a.m. ET (9 a.m. CT) to discuss its third quarter 2008 results. Interested parties may listen to the conference call via the Company’s website at http://www.contres.com/ or by phone:

   Dial in:           (888) 713-4217   Intl. dial in:     (617) 213-4869   Pass code:         67361430    Replay number:     (888) 286-8010   Intl. replay:      (617) 801-6888   Pass code:         55052650     Conference Presentations  

Continental management is currently scheduled to present at the Bank of America Energy Conference in Key Biscayne, Florida on November 13, 2008; at the NYSE Euronext and WJB Capital Group Boston Growth Conference on December 4, 2008; and at the Raymond James Small and Mid-Cap Equity Conference in Boston on December 11, 2008. Presentations and audio links will be posted on the Company’s web site.

Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. The Company focuses its operations in large new and developing resource 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.

This press release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control. All information, other than historical facts included in this press release, regarding strategy, future operations, drilling plans, estimated reserves, future production, estimated capital expenditures, projected costs, the potential of drilling prospects and other plans and objectives of management are forward-looking information. All forward-looking statements speak only as of the date of this press release. Although the Company believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Actual results may differ materially from those anticipated due to many factors, including oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production from enhanced recovery operations, availability of drilling rigs and other services, availability of crude oil and natural gas transportation capacity, availability of capital resources and other factors listed in reports we have filed or may file with the Securities and Exchange Commission.

    CONTACT:   Continental Resources, Inc.          J. Warren Henry              Brian Engel         Investors                    Media         (580) 548-5127               (580) 249-4731      Condensed Consolidated Statements of Operations     (in thousands, except per       Three months ended      Nine Months ended     share amounts)                    September 30,          September 30,                                   -------------------    -------------------                                       2008      2007        2008     2007                                     -------   -------     -------   --------                                                  (unaudited)    Revenues:   Oil and natural gas sales        $286,194   $166,704  $809,238  $422,734   Loss on mark-to-market    derivatives                            -    (14,393)   (7,966)  (14,393)   Oil and natural gas service    operations                         7,415      4,461    23,422    14,880                                  ------------------------------------------   Total revenues                    293,609    156,772   824,694   423,221    Operating costs and expenses:   Production expense                 25,247     20,561    75,273    58,201   Production tax                     17,941      8,711    48,411    22,311   Exploration expense                15,285      2,758    26,278     6,664   Oil and gas service operations      5,099      2,414    15,797     8,767   Depreciation, depletion,    amortization and accretion        39,120     23,568    95,828    67,306   Property impairments                9,947      4,099    17,620    12,992   General and administrative (1)     10,005      6,231    27,812    27,654   (Gain) loss on sale of assets        (194)        62      (406)     (338)                                  ------------------------------------------   Total operating costs and    expenses                         122,450     68,404   306,613   203,557    Income from operations            171,159     88,368   518,081   219,664   Interest expense and other         (2,321)    (2,456)   (8,050)   (8,647)                                  ------------------------------------------   Net income before income tax    expense                          168,838     85,912   510,031   211,017   Income tax expense (2)             63,582     29,540   189,497   243,329                                  ------------------------------------------   Net income (loss)                $105,256    $56,372  $320,534  $(32,312)    Basic net income (loss) per    share                              $0.63      $0.34     $1.91    $(0.20)   Diluted net income (loss) per    share                               0.62       0.33      1.89     (0.20)    Basic weighted average shares     168,097    167,232   168,008   162,869    outstanding   Diluted weighted average    shares outstanding               169,526    169,043   169,477   162,869   

(1) Includes non-cash charges for stock-based compensation of $2.6 million and $1.2 million for the three months ended September 30, 2008 and 2007, respectively, and $6.5 million and $12.1 million for the nine months ended September 30, 2008 and 2007, respectively.

(2) Income tax expense for the nine months ended September 30, 2007 includes a charge of $198.4 million to recognize deferred taxes upon the conversion from a nontaxable subchapter S corporation to a taxable subchapter C corporation in conjunction with the Company’s May 2007 initial public offering of common stock.

   Condensed Consolidated Balance Sheets            September 30  December 31   (in thousands)                                   ------------  -----------                                                        2008         2007                                                    ------------  -----------                                                    (unaudited)    Assets:   Cash and cash equivalents                             $3,133      $8,761   Receivables                                          299,764     163,090   Inventories and other                                 36,636      33,713   Net property and equipment                         1,765,848   1,157,926   Other assets                                           1,296       1,683                                                 ----------------------------   Total assets                                      $2,106,677  $1,365,173                                                 ----------------------------    Liabilities and shareholders' equity:   Current liabilities                                 $467,473    $266,106   Long-term debt                                       229,400     165,000   Other noncurrent liabilities                         458,600     310,935   Shareholders' equity                                 951,204     623,132                                                 ----------------------------    Total liabilities and shareholders' equity       $2,106,677  $1,365,173                                                 ----------------------------                                                            Nine months ended   Condensed Consolidated Statements of Cash Flows          September 30,   (in thousands)                                    -----------  -----------                                                         2008        2007                                                     -----------  -----------                                                             (unaudited)    Net income (loss)                                   $320,534    $(32,312)   Adjustments to reconcile net income (loss)    to net cash provided by operating activities:   Non-cash expenses                                    251,374     351,526   Changes in assets and liabilities                     18,024     (40,858)                                                     ------------------------   Net cash provided by operating activities            589,932     278,356    Net cash used in investing activities               (660,116)   (367,933)    Net cash provided by financing activities    activities                                           64,556      87,882    Effect of exchange rate on change in cash and cash    equivalents                                               -         160                                                     ------------------------    Net change in cash and cash equivalents               (5,628)     (1,535)   Cash and cash equivalents at beginning of period       8,761       7,018                                                     ------------------------   Cash and cash equivalents at end of period            $3,133      $5,483      Non-GAAP Financial Measures  

EBITDAX represents earnings before interest expense, income taxes, 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      Nine Months ended                                      September 30,          September 30,                                   -------------------    -------------------   (in thousands)                    2008       2007       2008        2007                                   -------     -------    -------     -------                                                  (unaudited)    Net income (loss)              $105,256    $56,372  $320,534    $(32,312)   Unrealized loss on    mark-to-market derivatives           -     12,542         -      12,542   Income tax expense               63,582     29,540   189,497     243,329   Interest expense                  2,506      2,774     8,782       9,854   Depreciation, depletion,    amortization and accretion      39,120     23,568    95,828      67,306   Property impairments              9,947      4,099    17,620      12,992   Exploration expense              15,285      2,758    26,278       6,664   Equity compensation               2,593      1,164     6,488      12,097                                  -------------------------------------------   EBITDAX                        $238,289   $132,817  $665,027    $332,472  

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Continental Resources

CONTACT: Investors, J. Warren Henry, +1-580-548-5127, or Media, BrianEngel, +1-580-249-4731, both of Continental Resources

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




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