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Continental Resources Increases Production in Second Quarter

Company Reports Record Wells in Middle Bakken and Three Forks/Sanish Zones in North Dakota 2009 Capital Expenditure Budget Raised 42 Percent to $390 Million

ENID, Okla., Aug. 6 /PRNewswire-FirstCall/ -- Continental Resources, Inc. (NYSE: CLR) today announced that its total production grew 18 percent in the second quarter of 2009, compared with the second quarter last year. In addition, the Company reported the successful completion of the Mathistad 2-35H, a "companion well" designed to test its theory that the Middle Bakken and Three Forks/Sanish zones act as separate reservoirs in portions of the North Dakota Bakken shale play.

"Technical data from the Mathistad 2-35H supports our belief that the Middle Bakken and Three Forks/Sanish reservoirs are separate in this area of the play," said Harold Hamm, Chairman and Chief Executive Officer. "The Mathistad 2-35H tested at a seven-day initial production rate of 995 Boepd. This is the highest initial rate that we've recorded from our Middle Bakken completions in North Dakota, and this high initial productivity indicates that we tapped into new, undrained reservoir rock with the companion well."

For the second quarter of 2009, Continental reported net income of $13.5 million, or $0.08 per diluted share, compared with net income of $127.3 million, or $0.75 per diluted share, for the second quarter of 2008.

Net income for the second quarter of 2009 included a pre-tax property impairment charge of $23.3 million and mark-to-market gains on natural gas fixed price and basis swaps of $890,000. Apart from these non-cash items, Continental's net income was $27.1 million, or $0.16 per diluted share, for the second quarter of 2009. The impairment charge included $13.2 million for impairment of non-producing properties and $10.1 million for impairment of developed oil and gas properties. In the second quarter of 2008, the Company recorded a $3.2 million pre-tax property impairment charge.

Average daily production was 37,347 Boepd (barrels of oil equivalent per day) for the second quarter of 2009, 18 percent higher than production of 31,623 Boepd in the second quarter of 2008.

Continental's second quarter 2009 results reflected a significant year-over-year decline in crude oil and natural gas prices. The Company's average realized sales price per barrel of oil equivalent was $43.52 for the second quarter of 2009, a decline of 58 percent from the average sales price of $102.86 per Boe for the second quarter of 2008. The average realized price for crude oil was $53.44 per barrel in the second quarter of 2009, while the average natural gas price was $2.60 per Mcf. Average prices were $118.28 per barrel and $8.82 per Mcf in the second quarter last year. Crude oil accounted for 74 percent of Continental's second quarter 2009 total production.

Crude oil price differentials averaged $6.02 per barrel for the second quarter of 2009, compared with $8.32 in the first quarter of 2009 and $5.75 for the second quarter of 2008.

Total oil and natural gas sales were $146.4 million for the second quarter of 2009, compared with $297.6 million for the second quarter of 2008. Production exceeded sales in the second quarter due to the Company placing an additional 35 MBbls of crude oil in storage. As of June 30, 2009, the Company had 669 MBbls of crude oil in storage and pipeline-required line fill.

EBITDAX was $106.3 million for the second quarter of 2009, compared with $245.0 million for the second quarter last year. For the Company's definition and reconciliation of EBITDAX to net income, the most comparable figure calculated pursuant to generally accepted accounting principles, see "Non-GAAP Financial Measures" at the end of this press release.

At June 30, 2009, the Company's balance sheet included $5.1 million in cash and $592.0 million in long-term debt. As of August 6, 2009, $572 million was drawn against its revolving credit facility, leaving available borrowing capacity at $178 million, based on commitments of $750 million.

"We are pleased with our production growth year-over-year and the continued reduction in drilling and completion costs in the second quarter of 2009," Mr. Hamm said. "Production expense also declined to $7.14 per Boe in the quarter, compared with $9.32 in the second quarter last year. General and administrative expense per Boe also declined, to $2.78 from $3.55 in the second quarter last year.

"We're also drilling much more efficiently in North Dakota, with spud-to-rig-release down 40 percent from an average of 45 days in 2008 to an average of 28 days in the first half of 2009. We drilled our latest well to total depth of 20,904 feet in 16 days," he said.

Mathistad 2-35H Test

"We are proud of our operating and financial achievements, but clearly the most significant milestone in the quarter was our successful Mathistad 2-35H test," Mr. Hamm said. Continental issued a separate press release today with additional detail on the Mathistad 2-35H. The companion well was drilled horizontally in the Middle Bakken (MB) zone approximately 50 feet above the horizontal of the Mathistad 1-35H.

The Mathistad 1-35H was completed as a producing Three Forks/Sanish (TFS) well in June 2008. By the time Continental started drilling the Mathistad 2-35H, the Mathistad 1-35H had produced 103,000 Boe and was pumping 187 Boepd. In contrast, the Mathistad 2-35H flowed at 995 Boepd during its initial test period, more than four times the rate at which the first well had been performing on pump.

"This significant production difference is the strongest evidence that we stimulated new rock with the second well completion," Mr. Hamm said. "From a technical point of view, that is the only plausible explanation for this level of initial productivity."

He noted that additional drilling will be required to establish the extent to which the reservoirs are separate across the play. "We are very encouraged by these early steps in delineating the Bakken shale play, especially with regard to developing the Middle Bakken and the Three Forks/Sanish reservoirs separately. Based on the results of the Mathistad 2-35H, we believe the reserve potential of the Bakken play just went up."

The Company estimates that approximately half of its 439,000 net acres in North Dakota have the potential for the Middle Bakken and Three Forks/Sanish to produce independently. Continental controls a total of 605,000 net acres in the Bakken play in North Dakota and Montana.

Operations Update

The following table contains financial and operating highlights for the second quarter of 2009 compared to the second quarter of 2008.



                                          Three months ended  Six months ended
                                                June 30,          June 30,
                                          ------------------------------------
                                             2009     2008     2009     2008
                                          ------------------------------------
    Average daily production:
      Oil (Bbl)                             27,654   24,117   27,119   24,080
      Natural gas (Mcf)                     58,156   45,035   59,760   41,098
      Oil equivalents (Boe)                 37,347   31,623   37,079   30,930
    Average prices: (1)
      Oil ($/Bbl)                           $53.44  $118.28   $44.82  $104.43
      Natural gas ($/Mcf)                     2.60     8.82     2.79     8.25
      Oil equivalents ($/Boe)                43.52   102.86    36.99    92.34
    Production expense ($/Boe) (1)            7.14     9.32     7.19     8.83
    General and administrative expense
     ($/Boe) (1)                              2.78     3.55     3.04     3.14
    EBITDAX (in thousands)                 106,250  244,950  163,923  426,738
    Net income (loss) (in thousands)        13,508  127,307  (13,105) 215,278
    Diluted net income (loss) per share       0.08     0.75    (0.08)    1.27

      (1) Average prices and per-unit production expense are calculated based
          on sales volumes. Oil sales volumes were 35 MBbls less than oil
          production for the three months ended June 30, 2009 and 16 MBbls
          more than oil production for the three months ended June 30, 2008.
          For the six months ended June 30, 2009 oil sales volumes were 251
          MBbls less than oil production and 35 MBbls more than oil production
          for the six months ended June 30, 2008.


    The following table presents average daily production for the Company's
principal operating areas for the quarters ended June 30, 2009, March 31,
2009, and June 30, 2008.



    (Boe per day)               Q2 2009  Q1 2009  Q2 2008
                                -------  -------  -------
    Red River Units              14,092   14,162   13,551
    Montana Bakken                6,105    6,144    6,363
    North Dakota Bakken           6,286    4,807    2,082
    Other Rockies                 1,928    2,011    2,484
    Arkoma Woodford               4,235    4,799    2,125
    Other Mid-Continent           4,179    4,252    4,419
    Gulf Coast                      522      633      599
                                -------  -------  -------
      Total                      37,347   36,808   31,623

Continental is currently operating four drilling rigs - three in North Dakota and one in Oklahoma - compared with 32 operated rigs in October 2008 and 13 at the beginning of 2009.

Red River Units

Production in the Red River Units was 14,092 Boepd in the second quarter of 2009, accounting for 38 percent of Continental's production. The Company continues to convert producing wells to injector wells as part of its secondary recovery program in the Units.

North Dakota Bakken

North Dakota Bakken production accounted for 17 percent of the total for the second quarter 2009, for the first time surpassing production in its Montana Bakken properties.

Continental participated in completing 28 gross wells (8.1 net) in North Dakota during the quarter. Initial production averaged 737 Boepd, a significant increase over the first quarter of 2009 and the average for 2008. All initial well results discussed in this press release are seven consecutive day averages.

In terms of Company-operated wells, Continental completed nine gross wells (4.8 net) targeting the TFS zone in the play in the second quarter of 2009, including the Kukla 1-21H in Dunn Co., which was the Company's strongest TFS well to date, based on initial test production. As a group, the nine wells' initial test period results averaged 876 Boepd.

-- Kukla 1-21H (65% WI) in Dunn Co. - 1,429 Boepd;
-- McGregor 1-15H (54% WI) in Williams Co. - 1,101 Boepd;
-- Merton 1-3H (45% WI) in McKenzie Co. - 911 Boepd;
-- Lokken 1-2H (54% WI) in Williams Co. - 854 Boepd;
-- George 1-18H (48% WI) in McKenzie Co. - 872 Boepd;
-- Wiley 1-25H (48% WI) in McKenzie Co. - 816 Boepd;
-- Olson 1-8H (81% WI) in McKenzie Co. - 735 Boepd;
-- Thorvald 1-6H (43% WI) in Dunn Co. - 603 Boepd;
-- Lila 1-36RH (50% WI) in Divide Co. - 563 Boepd.

Since the end of the second quarter, Continental has completed three additional TFS wells.
-- Bohmbach 1-35H (76% WI) in McKenzie Co. - 1,367 Boepd;
-- Tangsrud 1-1H (91% WI) in Divide Co. - 834 Boepd;
-- Leonard 1-1H (49% WI) in Williams Co. - 166 Boepd.

The Company also completed a second Middle Bakken well during the second quarter of 2009, the Armstrong 1-24H (74% WI) in Billings Co., which generated initial production results of 356 Boepd.

Montana Bakken

Montana Bakken production was 6,105 Boepd in the second quarter of 2009, essentially flat with the first quarter of 2009 and four percent below production in the second quarter of 2008. Montana production accounted for 16 percent of the Company's second quarter 2009 production. The Company did not drill any wells in the second quarter of 2009 in the Montana part of the play.

Arkoma Woodford

Production in the Arkoma Woodford shale play was 4,235 Boepd in the second quarter of 2009, which was almost double that in the second quarter last year and which accounted for 11 percent of Continental's total production in the most recent quarter. Arkoma production declined slightly in the second quarter compared with the first quarter of 2009, reflecting reduced drilling activity since the beginning of the year in response to low commodity prices.

The Company participated in 14 gross wells (2.0 net) during the second quarter of 2009 and currently has one operated rig drilling in the play in southeastern Oklahoma.

In June, the Company announced that it had entered into natural gas fixed price and basis swaps for 600,000 MMBtu at an average price of $5.27 for December 2009 and for 600,000 MMBtu per month at an average price of $5.68 for calendar 2010. The hedges are indexed to Centerpoint East pricing and are net of differential. They were put in place to underpin the Company's current and expected level of operations in the Arkoma Woodford play.

Company Increases 2009 Capital Expenditure Budget

Continental has increased its 2009 capital expenditures budget by 42 percent to $390 million, citing the strengthening of crude oil prices and resulting increased cash flow in the second quarter of the year. Along with funding increased drilling operations, the Company plans to continue reducing the level of borrowings under its credit facility in the second half of the year.

Capital expenditures were $73 million for the second quarter of 2009 and $227 million for the first half of 2009. Looking to the second half, the Company plans to apply almost all of its additional capex spending to drilling operations in the North Dakota Bakken.

Under its original $275 million capex budget for 2009, the Company would have had only one operated rig active in the final four months of 2009. Now, the Company plans to keep the current total of four operated drilling rigs active through September, with a fifth added in October and a sixth in November. All additional rigs will be added in the North Dakota Bakken, and the single rig in the Arkoma will remain.

"The revised budget will enable us to build production momentum as we enter 2010," Mr. Hamm said. "We have only one drilling rig on long-term contract, so if crude oil prices change significantly, we will be able to adjust."

Conference Call Information

Continental Resources will host a conference call on Thursday, August 6, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its second quarter 2009 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) 679-8034
Intl. dial in: (617) 213-4847
Pass code: 89808872

Replay number: (888) 286-8010
Intl. replay: (617) 801-6888
Pass code: 53136120

Conference Presentations

Continental management is currently scheduled to present at the following research conferences:

  • August 10, 2009 EnerCom Oil & Gas Conference VII, Denver
  • September 2 The Hodges Capital 11th Annual Investment Forum, Dallas
  • September 17 The C.K. Cooper West Coast Energy Conference, Newport Beach, CA
  • September 21 The Bank of America/Merrill Lynch 2009 Smid Cap Conference, Boston

Presentation materials will be available on the Company's web site on the day of each presentation.

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 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.

Forward-Looking Statements

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: Investor Relations Media
  Warren Henry, VP Investor Relations Brian Engel, VP Public Affairs
  (580) 548-5127 (580) 249-4731
  warrenhenry@contres.com brianengel@contres.com


    Condensed Consolidated Statements of Operations
    (in thousands, except per share amounts)

                                      --------------------------------------
                                      Three months ended    Six months ended
                                           June 30,            June 30,
                                      --------------------------------------
                                        2009      2008      2009      2008
                                      --------------------------------------

    Revenues:
    Oil and natural gas sales         $146,439  $297,619  $239,007  $523,044
    Gain (loss) on mark-to-market
     derivative instruments                890    (3,358)      890    (7,966)

    Oil and natural gas service
     operations                          4,432     9,173     8,472    16,007
                                      --------------------------------------
    Total revenues                     151,761   303,434   248,369   531,085

    Operating costs and expenses:
    Production expenses                 24,038    26,953    46,464    50,026

    Production tax                      11,629    17,695    18,451    30,470
    Exploration expense                  1,530     5,731     8,649    10,993
    Oil and natural gas service
     operations                          2,694     6,468     5,097    10,698
    Depreciation, depletion,
     amortization and accretion         53,148    28,062   103,845    56,708
    Property impairments                23,275     3,153    58,700     7,673
    General and administrative(1)        9,351    10,276    19,635    17,807
    Gain on sale of assets                 (85)     (133)     (221)     (212)
                                      --------------------------------------
    Total operating costs and
     expenses                          125,580    98,205   260,620   184,163
                                      --------------------------------------
    Income from operations              26,181   205,229   (12,251)  346,922
    Other income (expense):
    Interest expense                    (4,723)   (2,865)   (9,310)   (6,276)
    Other                                  301       248       448       547
                                      --------------------------------------
                                        (4,422)   (2,617)   (8,862)   (5,729)
                                      --------------------------------------
    Income (loss) before income
     taxes                              21,759   202,612   (21,113)  341,193
    Provision (benefit) for income
     taxes                               8,251    75,305    (8,008)  125,915
                                      --------------------------------------
    Net income (loss)                  $13,508  $127,307  $(13,105) $215,278
                                      --------------------------------------
    Basic net income (loss) per share    $0.08     $0.76    $(0.08)    $1.28
    Diluted net income (loss) per
     share                                0.08      0.75     (0.08)     1.27
    Basic weighted average shares
     outstanding                       168,492   168,055   168,479   167,973
    Diluted weighted average
     shares outstanding                169,498   169,552   168,479   169,418

    (1) Includes non-cash charges for stock-based compensation of $2.7 million
        and $2.5 million for the three months ended June 30, 2009 and 2008,
        respectively and $5.4 million and $3.9 million for the six months
        ended June 30, 2009 and 2008, respectively.


    Condensed Consolidated Balance Sheets
    (in thousands)
                                                       June 30,  December 31,
                                                         2009        2008
                                                      ----------------------
                                                     (unaudited)
    Assets:
    Cash and cash equivalents                            $5,071       $5,229
    Receivables                                         177,046      229,079
    Inventories and other                                47,909       43,387
    Net property and equipment, based on successful
     efforts method of accounting                     1,990,046    1,935,143
    Other assets                                          4,049        3,041
                                                      ----------------------
    Total assets                                     $2,224,121   $2,215,879
                                                      ----------------------

    Liabilities and shareholders' equity
    Current liabilities                                $207,219     $403,594
    Long-term debt                                      592,000      376,400
    Other noncurrent liabilities                        484,230      487,177
    Shareholders' equity                                940,672      948,708
                                                      ----------------------
    Total liabilities and shareholders' equity       $2,224,121   $2,215,879
                                                      ----------------------


    Condensed Consolidated Statements of Cash Flows
    (in thousands)
                                                    Six months ended June 30,
                                                         2009        2008
                                                      ----------------------
                                                          (unaudited)
    Net income (loss)                                 $(13,105)   $215,278
    Adjustments to reconcile net income to net cash
     provided by operating activities:
    Non-cash expenses                                  168,995     140,900
    Changes in assets and liabilities                  (73,397)    (58,208)
                                                      ----------------------
    Net cash provided by operating activities           82,493     297,970

    Net cash used in investing activities             (295,773)   (348,729)
                                                      ----------------------

    Net cash provided by financing activities          213,122      55,188
                                                      ----------------------

    Net change in cash and cash equivalents               (158)      4,429
    Cash and cash equivalents at beginning of period     5,229       8,761
                                                      ----------------------
    Cash and cash equivalents at end of period          $5,071     $13,190

Non-GAAP Financial Measures

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains and 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). Management believes EBITDAX is useful because it allows them to more effectively evaluate the Company's operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at EBITDAX because as these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. 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    Six months ended
                                           June 30,             June 30,
                                     ---------------------------------------
                                        2009     2008        2009      2008
                                     ---------------------------------------
     (in thousands)                                  (unaudited)
    Net income (loss)                 $13,508  $127,307   $(13,105) $215,278
    Unrealized derivative gain           (890)        -       (890)        -
    Interest expense                    4,723     2,865      9,310     6,276
    Provision (benefit) for income
     taxes                              8,251    75,305     (8,008)  125,915
    Depreciation, depletion,
     amortization and accretion        53,148    28,062    103,845    56,708
    Property impairments               23,275     3,153     58,700     7,673
    Exploration expense                 1,530     5,731      8,649    10,993
    Equity compensation                 2,705     2,527      5,422     3,895
                                     ---------------------------------------
    EBITDAX                          $106,250  $244,950   $163,923  $426,738



SOURCE Continental Resources

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