================================================================================

                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C.  20549

                                    FORM 10-Q


              [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                For the quarterly period ended September 30, 2004

                                       OR

              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

             For the transition period from __________ to __________

                        Commission File Number: 000-22433

                           BRIGHAM EXPLORATION COMPANY
             (Exact name of registrant as specified in its charter)

<TABLE>
<CAPTION>
<S>                                <C>                             <C>
          DELAWARE                             1311                     75-2692967
  (State of other jurisdiction     (Primary Standard Industrial      (I.R.S. Employer
of incorporation or organization)   Classification Code Number)    Identification Number)
</TABLE>

      6300 BRIDGE POINT PARKWAY, BUILDING 2, SUITE 500, AUSTIN, TEXAS 78730
                    (Address of principal executive offices)

                                 (512) 427-3300
              (Registrant's telephone number, including area code)


Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding twelve months (or for such shorter period that the registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days.
                            Yes [X]           No [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12 b-2 of the Act).
                            Yes [X]           No [ ]

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

              CLASS                                     OUTSTANDING
              -----                                     -----------
Common Stock, par value $.01 per share                   42,313,625
as of November 5, 2004

================================================================================


<PAGE>
<TABLE>
<CAPTION>
                                           BRIGHAM EXPLORATION COMPANY

                                       THIRD QUARTER 2004 FORM 10-Q REPORT

                                                TABLE OF CONTENTS
                                                -----------------

                                                                                                          PAGE
                                                                                                          ----
<S>      <C>                                                                                              <C>
                                          PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

         Consolidated Balance Sheets - September 30, 2004 and December 31, 2003 . . . . . . . . . . . . .  1
         Consolidated Statements of Operations - Three and nine months ended September 30, 2004 and 2003.  2
         Consolidated Statement of Stockholders' Equity - Nine months ended September 30, 2004. . . . . .  3
         Consolidated Statements of Cash Flows - Nine months ended September 30, 2004 and 2003. . . . . .  4
         Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . .  5

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   15

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . . . . . . . . . . . . . .   32

ITEM 4.  CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   33


                                           PART II  - OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   34

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. . . . . . . . . . . . . . . . . .   34

ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   34

SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   35
</TABLE>


<PAGE>
<TABLE>
<CAPTION>
                                                   BRIGHAM EXPLORATION COMPANY
                                                   CONSOLIDATED BALANCE SHEETS
                                                (IN THOUSANDS, EXCEPT SHARE DATA)
                                                           (UNAUDITED)


                                                                                                  SEPTEMBER 30,    DECEMBER 31,
                                                                                                      2004             2003
                                                                                                 ---------------  --------------
<S>                                                                                              <C>              <C>
                                                            ASSETS
                                                                                                   (Unaudited)
Current assets:
  Cash and cash equivalents                                                                      $        8,951   $       5,779
  Accounts receivable                                                                                    11,191          11,143
  Deferred income taxes                                                                                   1,188             307
  Other current assets                                                                                    1,179           3,606
                                                                                                 ---------------  --------------
      Total current assets                                                                               22,509          20,835
                                                                                                 ---------------  --------------

Oil and natural gas properties, net (full cost method)                                                  245,312         197,311
Other property and equipment, net                                                                         1,114           1,219
Deferred income taxes                                                                                         -           1,890
Deferred loan fees                                                                                        1,937           2,501
Other noncurrent assets                                                                                     597             460
                                                                                                 ---------------  --------------
      Total assets                                                                               $      271,469   $     224,216
                                                                                                 ===============  ==============
                                              LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable                                                                               $       16,557   $      19,806
  Royalties payable                                                                                       5,894           5,280
  Accrued drilling costs                                                                                  6,519           3,916
  Participant advances received                                                                             551           1,179
  Other current liabilities                                                                               4,512           5,398
                                                                                                 ---------------  --------------
    Total current liabilities                                                                            34,033          35,579
                                                                                                 ---------------  --------------

Senior credit facility                                                                                   23,500          19,000
Senior subordinated notes                                                                                20,000          20,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption
  value, 2,250,000 shares authorized, 466,599 and 439,722 shares issued and outstanding at
  September 30, 2004 and December 31, 2003, respectively                                                  9,332           8,794
Deferred income taxes                                                                                     5,871               -
Other noncurrent liabilities                                                                              3,269           2,498

Commitments and contingencies

Stockholders' equity:
  Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000 shares are
    designated as Series A and zero and 1,000,000 shares are designated as Series B, at
    September 30, 2004 and December 31, 2003, respectively                                                    -               -
  Common stock, $.01 par value, 50 million shares authorized, 43,152,893 and 40,246,729 shares
    issued and 41,971,535 and 39,086,096 shares outstanding at September 30, 2004 and
    December 31, 2003, respectively                                                                         432             402
  Additional paid-in capital                                                                            174,432         151,263
  Treasury stock, at cost; 1,181,358 and 1,160,633 shares at September 30, 2004 and December
    31, 2003, respectively                                                                               (4,562)         (4,402)
  Unearned stock compensation                                                                            (1,722)         (1,816)
  Accumulated other comprehensive income (loss)                                                          (1,698)         (1,040)
  Retained earnings (Accumulated deficit)                                                                 8,582          (6,062)
                                                                                                 ---------------  --------------
    Total stockholders' equity                                                                          175,464         138,345
                                                                                                 ---------------  --------------
      Total liabilities and stockholders' equity                                                 $      271,469   $     224,216
                                                                                                 ===============  ==============
<FN>
                     The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                        1
<PAGE>
<TABLE>
<CAPTION>
                                          BRIGHAM EXPLORATION COMPANY
                                     CONSOLIDATED STATEMENTS OF OPERATIONS
                                     (IN THOUSANDS, EXCEPT PER SHARE DATA)
                                                  (UNAUDITED)


                                                                 THREE MONTHS ENDED       NINE MONTHS ENDED
                                                                    SEPTEMBER 30,           SEPTEMBER 30,
                                                              ------------------------  -----------------------
                                                                 2004         2003         2004         2003
                                                              -----------  -----------  -----------  ----------
<S>                                                           <C>          <C>          <C>          <C>
Revenues:
  Oil and natural gas sales                                   $   17,240   $   13,181   $   51,975   $  39,947
  Other revenue                                                       27           32           69         113
                                                              -----------  -----------  -----------  ----------
                                                                  17,267       13,213       52,044      40,060
                                                              -----------  -----------  -----------  ----------
Costs and expenses:
  Lease operating                                                  1,648        1,793        4,362       4,037
  Production taxes                                                   675          553        2,434       2,297
  General and administrative                                       1,304        1,094        3,723       3,420
  Depletion of oil and natural gas properties                      5,871        3,952       16,374      11,853
  Depreciation and amortization                                      179          192          544         449
  Accretion of discount on asset retirement obligations               40           39          117         110
                                                              -----------  -----------  -----------  ----------
                                                                   9,717        7,623       27,554      22,166
                                                              -----------  -----------  -----------  ----------
      Operating income                                             7,550        5,590       24,490      17,894
                                                              -----------  -----------  -----------  ----------

Other income (expense):
  Interest income                                                     26            8           55          36
  Interest expense                                                  (872)      (1,271)      (2,508)     (3,777)
  Other income (expense)                                            (168)         (80)        (159)       (250)
                                                              -----------  -----------  -----------  ----------
                                                                  (1,014)      (1,343)      (2,612)     (3,991)
                                                              -----------  -----------  -----------  ----------
Income before income taxes and cumulative effect of
  change in accounting principle                                   6,536        4,247       21,878      13,903
                                                              -----------  -----------  -----------  ----------
Income tax expense:
  Current                                                              -            -            -           -
  Deferred                                                        (2,051)           -       (7,234)          -
                                                              -----------  -----------  -----------  ----------
                                                                  (2,051)           -       (7,234)          -
                                                              -----------  -----------  -----------  ----------
Income before cumulative effect of change in accounting
  principle                                                        4,485        4,247       14,644      13,903
Cumulative effect of change in accounting principle                    -            -            -         268
                                                              -----------  -----------  -----------  ----------
Net income                                                         4,485        4,247       14,644      14,171
Less accretion and dividends on redeemable preferred stock             -          904            -       2,927
                                                              -----------  -----------  -----------  ----------
Net income available to common stockholders                   $    4,485   $    3,343   $   14,644   $  11,244
                                                              ===========  ===========  ===========  ==========

Net income per share available to common stockholders:
  Basic
    Income before cumulative effect of change in accounting
      principle                                               $     0.11   $     0.16   $     0.37   $    0.54
    Cumulative effect of change in accounting principle                -            -            -        0.01
                                                              -----------  -----------  -----------  ----------
                                                              $     0.11   $     0.16   $     0.37   $    0.55
                                                              ===========  ===========  ===========  ==========

  Diluted
    Income before cumulative effect of change in accounting
      principle                                               $     0.11   $     0.13   $     0.36   $    0.42
    Cumulative effect of change in accounting principle                -            -            -        0.01
                                                              -----------  -----------  -----------  ----------
                                                              $     0.11   $     0.13   $     0.36   $    0.43
                                                              ===========  ===========  ===========  ==========

Weighted average shares outstanding:
  Basic                                                           41,227       21,210       39,921      20,340
                                                              ===========  ===========  ===========  ==========
  Diluted                                                         42,340       30,751       41,078      32,406
                                                              ===========  ===========  ===========  ==========
<FN>
            The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                        2
<PAGE>
<TABLE>
<CAPTION>
                                                 BRIGHAM EXPLORATION COMPANY
                                       CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
                                                       (IN THOUSANDS)
                                                         (UNAUDITED)

                                                                                               ACCUMULATED       RETAINED
                                   COMMON STOCK     ADDITIONAL                  UNEARNED          OTHER          EARNINGS
                                 ----------------    PAID IN      TREASURY       STOCK        COMPREHENSIVE    (ACCUMULATED
                                 SHARES  AMOUNTS     CAPITAL       STOCK      COMPENSATION    INCOME (LOSS)      DEFICIT)
                                 ------  --------  ------------  ----------  --------------  ---------------  --------------
<S>                              <C>     <C>       <C>           <C>         <C>             <C>              <C>
Balance, December 31, 2003       40,247  $    402  $   151,263   $  (4,402)  $      (1,816)  $       (1,040)  $      (6,062)
Comprehensive income:
  Net income                          -         -            -           -               -                -          14,644
  Unrealized gain (losses) on
    cash flow hedges                  -         -            -           -               -           (1,217)              -
  Tax provisions related to
    cash flow hedges                  -         -            -           -               -              354               -
  Net losses realized and
    included in net income            -         -            -           -               -              205               -

    Comprehensive income
Issuance of common stock          2,599        26       22,106           -               -                -               -
Exercises of incentive stock
  options                           235         3          681           -               -                -               -
Issuance of restricted stock          -         -          514           -            (514)               -               -
Vesting of restricted stock          72         1           (1)          -               -                -               -
Forfeitures of restricted stock       -         -         (131)         (4)            131                -               -
Repurchases of common
  stock                               -         -            -        (156)              -                -               -
Amortization of unearned
  stock compensation                  -         -            -           -             477                -               -
                                 ------  --------  ------------  ----------  --------------  ---------------  --------------
Balance, September 30, 2004      43,153  $    432  $   174,432   $  (4,562)  $      (1,722)  $       (1,698)  $       8,582
                                 ======  ========  ============  ==========  ==============  ===============  ==============



                                      TOTAL
                                  STOCKHOLDERS'
                                     EQUITY
                                 ---------------
<S>                              <C>
Balance, December 31, 2003       $      138,345
Comprehensive income:
  Net income                             14,644
  Unrealized gain (losses) on
    cash flow hedges                     (1,217)
  Tax provisions related to
    cash flow hedges                        354
  Net losses realized and
    included in net income                  205
                                 ---------------
    Comprehensive income                 13,986
Issuance of common stock                 22,132
Exercises of incentive stock
  options                                   684
Issuance of restricted stock                  -
Vesting of restricted stock                   -
Forfeitures of restricted stock              (4)
Repurchases of common
  stock                                    (156)
Amortization of unearned
  stock compensation                        477
                                 ---------------
Balance, September 30, 2004      $      175,464
                                 ===============
<FN>
                   The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                        3
<PAGE>
<TABLE>
<CAPTION>
                                          BRIGHAM EXPLORATION COMPANY
                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                (IN THOUSANDS)
                                                  (UNAUDITED)

                                                                                              NINE MONTHS ENDED
                                                                                                 SEPTEMBER 30,
                                                                                           -----------------------
                                                                                              2004         2003
                                                                                           -----------  ----------
<S>                                                                                        <C>          <C>
Cash flows from operating activities:
  Net income                                                                               $   14,644   $  14,171
  Adjustments to reconcile net income to cash provided by operating
  activities:
      Depletion of oil and natural gas properties                                              16,374      11,853
      Depreciation and amortization                                                               544         449
      Interest paid through issuance of additional senior subordinated notes                        -         888
      Interest paid through issuance of additional mandatorily redeemable preferred stock         538         161
      Amortization of deferred loan fees  and debt issuance costs                                 574         809
      Market value adjustment for derivative instruments                                          227         250
      Accretion of discount on asset retirement obligations                                       117         110
      Cumulative effect of change in accounting principle                                           -        (268)
      Deferred income taxes                                                                     7,234           -
      Changes in operating assets and liabilities:
        Accounts receivable                                                                       (48)      1,565
        Gas imbalance receivable                                                                2,435      (5,537)
        Other current assets                                                                       (8)      1,344
        Accounts payable                                                                       (3,249)       (777)
        Royalties payable                                                                         614         934
        Participant advances received                                                            (628)     (1,355)
        Gas imbalance liability                                                                (2,064)      7,275
        Other current liabilities                                                                 327         588
        Other noncurrent assets and liabilities                                                  (126)        (35)
                                                                                           -----------  ----------
          Net cash provided by operating activities                                            37,505      32,425
                                                                                           -----------  ----------
Cash flows from investing activities:
    Additions to oil and natural gas properties                                               (61,160)    (30,356)
    Proceeds from sale of oil and natural gas properties                                            -       1,183
    Additions to other property and equipment                                                    (186)       (247)
    Decrease (Increase) in drilling advances paid                                                (137)         18
                                                                                           -----------  ----------
          Net cash used by investing activities                                               (61,483)    (29,402)
                                                                                           -----------  ----------
Cash flows from financing activities:
    Proceeds from the issuance of common stock, net of issuance costs                          22,132      40,000
    Increase in senior credit facility                                                         28,000           -
    Repayment of senior credit facility                                                       (23,500)    (47,000)
    Deferred loan fees paid                                                                       (10)       (985)
    Proceeds from exercise of incentive stock options                                             684         660
    Repurchases of common stock                                                                  (156)          -
                                                                                           -----------  ----------
          Net cash provided (used) by financing activities                                     27,150      (7,325)
                                                                                           -----------  ----------
Net increase (decrease) in cash and cash equivalents                                            3,172      (4,302)
Cash and cash equivalents, beginning of year                                                    5,779      15,318
                                                                                           -----------  ----------
Cash and cash equivalents, end of period                                                   $    8,951   $  11,016
                                                                                           ===========  ==========
<FN>
              The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>


                                        4
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


1.   ORGANIZATION AND NATURE OF OPERATIONS

     Brigham Exploration Company ("Brigham"), a Delaware corporation formed on
February 25, 1997, explores and develops onshore domestic oil and natural gas
properties using 3-D seismic imaging and other advanced technologies. Brigham
focuses its exploration and development of onshore oil and natural gas
properties primarily in the onshore Gulf Coast, the Anadarko Basin, and West
Texas.

2.   BASIS OF PRESENTATION

     The accompanying consolidated financial statements include the accounts of
Brigham and its wholly-owned subsidiaries, and its proportionate share of
assets, liabilities and income and expenses of the joint operations in which
Brigham, or any of its subsidiaries, has a participating interest. All
significant intercompany accounts and transactions have been eliminated.

     The accompanying consolidated financial statements are unaudited, and in
the opinion of management, reflect all adjustments that are necessary for a fair
presentation of the financial position and results of operations for the periods
presented. All such adjustments are of a normal and recurring nature. The
results of operations for the periods presented are not necessarily indicative
of the results to be expected for the entire year. The unaudited consolidated
financial statements should be read in conjunction with Brigham's 2003 Annual
Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.

     STOCK BASED COMPENSATION

     Brigham accounts for employee incentive stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the
disclosure-only provisions of Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation" ("SFAS 123") as amended by SFAS
148.

     Had compensation cost for Brigham's stock options been determined based on
the fair market value at the grant dates of the awards consistent with the
methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income
and net income per share for the three and nine month periods ended September
30, 2004 and 2003 would have been the pro forma amounts indicated below:

<TABLE>
<CAPTION>
                                                 THREE MONTHS ENDED         NINE MONTHS ENDED
                                                    SEPTEMBER 30,             SEPTEMBER 30,
                                            -------------------------  --------------------------
                                                2004         2003          2004          2003
                                            ------------  -----------  -------------  -----------
<S>                                         <C>           <C>          <C>            <C>
                                                  (in thousands, except per share amounts)
Net income available to common
stockholders - basic:
  As reported                               $     4,485   $    3,343   $     14,644   $   11,244
  Add back: Stock compensation expense
    previously included in net income               103            5            340           10
  Effect of total incentive stock-based
    compensation expense, determined
    under fair value method for all awards         (916)         (98)        (1,908)        (279)
                                            ------------  -----------  -------------  -----------
  Pro forma                                 $     3,672   $    3,250   $     13,076   $   10,975
                                            ============  ===========  =============  ===========
</TABLE>


                                        5
<PAGE>
<TABLE>
<CAPTION>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


                                                 THREE MONTHS ENDED          NINE MONTHS ENDED
                                                    SEPTEMBER 30,              SEPTEMBER 30,
                                            -------------------------  --------------------------
                                                2004         2003          2004          2003
                                            ------------  -----------  -------------  -----------
                                                  (in thousands, except per share amounts)
<S>                                         <C>           <C>          <C>            <C>
Net income available to common
stockholders - diluted:
  As reported                               $     4,485   $    4,032   $     14,644   $   13,959
  Add back: Stock compensation expense
    previously included in net income               103            5            340           10
  Effect of total incentive stock-based
    compensation expense, determined
    under fair value method for all awards         (916)         (98)        (1,908)        (279)
                                            ------------  -----------  -------------  -----------
  Pro forma                                 $     3,672   $    3,939   $     13,076   $   13,690
                                            ============  ===========  =============  ===========

Net income per share:
  Basic:
    As reported                             $      0.11   $     0.16   $       0.37   $     0.55
    Pro forma                                      0.09         0.15           0.33         0.54
  Diluted:
    As reported                             $      0.11   $     0.13   $       0.36   $     0.43
    Pro forma                                      0.09         0.13           0.32         0.42
</TABLE>

3.   COMMITMENTS AND CONTINGENCIES

     Brigham is, from time to time, party to certain lawsuits and claims arising
in the ordinary course of business.  While the outcome of lawsuits and claims
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial condition, results of
operations or cash flows of Brigham.

     On November 20, 2001, Brigham filed a lawsuit in the District Court of
Travis County, Texas, against Steve Massey Company, Inc. ("Massey"). The
Petition claims Massey furnished defective casing to Brigham, which ultimately
led to the casing failure of the Palmer 347 #5 well and the loss of the Palmer
#5 as a producing well. In 2004, the parties settled the case on terms favorable
to Brigham. Brigham received approximately $440,000 as a result of this
settlement, which reduced capitalized well costs. In addition, Massey dropped
its $445,819 counterclaim.

     On July 11, 2002, an employee of a contractor on Brigham's Burkhart #1-R
location, Matagorda County, Texas, was involved in a fatal accident. The United
States Department of Labor Occupational Safety & Health Administration conducted
an inspection and, in October 2003, Brigham settled all issues resulting from
that inspection for $70,000.

     On October 8, 2002, relatives of the contractor's employee filed a wrongful
death action in the district court for Matagorda County, Texas, against Brigham
and three of Brigham's contractors in connection with his accidental death.
Plaintiffs were seeking unspecified actual and punitive damages. On March 23,
2004, a jury determined that Brigham had no liability in the accidental death of
the contractor's employee.  The plaintiffs filed a motion for a new trial. In
late October 2004, the judge granted plaintiffs a new trial. Brigham has not
recorded a contingent liability for this suit.

     In September 2002, Brigham filed suit in the district court of Matagorda
County, Texas, against one of its contractors in connection with the drilling of
the Burkhart #1-R well. The suit claims that the contractor breached its
contract with Brigham and negligently performed services on the well, resulting
in damages of approximately $650,000. The contractor filed a counterclaim for
the recovery of approximately $315,000. The parties settled the case in April
2004 resulting in a payment by the contractor to Brigham and its
co-participants. In addition, the contractor dropped its counterclaim. Based on
the amount of the settlement, the


                                        6
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


additional costs that were covered by insurance, and the insurer being
subrogated to Brigham's claim, Brigham's incremental recovery as a result of the
settlement was diminimus.

     The operator of the Stonehocker #1 disputed Brigham's ownership interest in
the well. In January 2004, the Oklahoma Corporation Commission ruled in favor of
Brigham. The operator of the Stonehocker #1 appealed the ruling and the Oklahoma
Corporation Commission affirmed its original ruling in March 2004. The operator
has appealed the ruling to the Oklahoma Supreme Court.

     A working interest owner that relinquished its ownership interest in the
Nold #1S well as a result of a non-consent election in the re-completion of the
well asserted that it did not relinquish its entire interest, but rather became
subject only to a 400 percent payout provision. In November 2003, the working
interest owner filed a lawsuit against Brigham for breach of contract. In April
2004, the parties negotiated a settlement that resulted in Brigham making a
payment of approximately $390,000 to the working interest owner in exchange for
an assignment of any interest owned by the working interest owner in this well.

     In December 2003, Brigham filed a lawsuit in the United States District
Court for the Western District of Texas against another company and a former
employee concerning the defendants' misappropriation of Brigham's trade secrets
and breach of confidentiality obligations. Defendants denied any wrongdoing and
asserted a counterclaim against Brigham for alleged tortuous interference with
an existing business relationship between the company and its employee.  The
parties settled the lawsuit in April 2004 on terms favorable to Brigham. The
settlement resulted in a $50,000 payment to Brigham, a small overriding royalty
interest assignment to Brigham in three tracts and an agreement to not compete
in specific areas covered by the confidential information. In addition, the
other company has dropped its counterclaim against Brigham.

4.   NET INCOME PER SHARE

     Basic earnings per share are computed by dividing net income available to
common stockholders by the weighted average number of common shares outstanding
for the period. The computation of diluted net income per share reflects the
potential dilution that could occur if securities or other contracts to issue
common stock were exercised or converted into common stock or resulted in the
issuance of common stock that would then share in the earnings of Brigham.

     The following table reconciles the numerators and denominators of the basic
and  diluted  earnings per common share computations for net income available to
common  stockholders  for the three and nine months ended September 30, 2004 and
2003:

<TABLE>
<CAPTION>
                                                   THREE MONTHS ENDED        NINE MONTHS ENDED
                                                      SEPTEMBER 30,             SEPTEMBER 30,
                                                -----------------------  -------------------------
                                                   2004         2003         2004         2003
                                                -----------  ----------  ------------  -----------
<S>                                             <C>          <C>         <C>           <C>
                                                    (in thousands, except per share amounts)
Basic EPS:
    Income (loss) available to common
      stockholders before cumulative change
      in accounting principle                   $     4,485  $    3,343  $     14,644  $    10,976
    Cumulative change in accounting principle             -           -             -          268
                                                -----------  ----------  ------------  -----------
      Income (loss) available to common
        stockholders                            $     4,485  $    3,343  $     14,644  $    11,244
                                                ===========  ==========  ============  ===========
      Common shares outstanding                      41,227      21,210        39,921       20,340
                                                ===========  ==========  ============  ===========

   Basic EPS
    Income (loss) available to common
      stockholders before change in
      accounting principle                      $      0.11  $     0.16  $       0.37  $      0.54
    Cumulative change in accounting principle             -           -             -         0.01
                                                -----------  ----------  ------------  -----------
                                                $      0.11  $     0.16  $       0.37  $      0.55
                                                ===========  ==========  ============  ===========


                                        7
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


                                                   THREE MONTHS ENDED        NINE MONTHS ENDED
                                                      SEPTEMBER 30,             SEPTEMBER 30,
                                                -----------------------  -------------------------
                                                   2004         2003         2004         2003
                                                -----------  ----------  ------------  -----------
                                                    (in thousands, except per share amounts)

Diluted EPS:
    Income (loss) available to common
      stockholders before cumulative change
      in accounting principle                   $     4,485  $    3,343  $     14,644  $    10,976
    Cumulative change in accounting principle             -           -             -          268
                                                -----------  ----------  ------------  -----------
      Income (loss) available to common
        stockholders                                  4,485       3,343        14,644       11,244
    Adjustments for assumed conversions:
      Dividends and accretion on mandatorily
        redeemable preferred stock (1)                    -         689             -        2,715
                                                -----------  ----------  ------------  -----------
  Income (loss) available to common
    stockholders before change in
    accounting principle-diluted                      4,485       4,032        14,644       13,691
    Cumulative change in accounting principle             -           -             -          268
                                                -----------  ----------  ------------  -----------
      Income (loss) available to common
        stockholders-diluted                    $     4,485  $    4,032  $     14,644  $    13,959
                                                ===========  ==========  ============  ===========


  Common shares outstanding                          41,227      21,210        39,921       20,340
  Effect of dilutive securities:
    Warrants                                              -           -             -          402
    Mandatorily redeemable preferred stock                -       8,966             -       11,071
    Stock options                                     1,113         575         1,157          593
                                                -----------  ----------  ------------  -----------
  Potentially dilutive common shares                  1,113       9,541         1,157       12,066
                                                -----------  ----------  ------------  -----------
    Adjusted common shares outstanding
      diluted                                        42,340      30,751        41,078       32,406
                                                ===========  ==========  ============  ===========

  Diluted EPS
    Income (loss) available to common
      stockholders before change in
      accounting principle                      $      0.11  $     0.13  $       0.36  $      0.42
    Change in accounting principle                        -           -             -         0.01
                                                -----------  ----------  ------------  -----------
                                                $      0.11  $     0.13  $       0.36  $      0.43
                                                ===========  ==========  ============  ===========
</TABLE>

(1)  The amount of dividends included in dividends and accretion on mandatorily
     redeemable preferred stock includes only the dividends paid in kind on the
     $40 million of mandatorily redeemable preferred stock (2.0 million shares)
     that were issued with warrants whose exercise price is payable in either
     cash or in shares of mandatorily redeemable preferred stock.

     Options and warrants to purchase 656,000 shares and 2.1 million shares of
common stock were outstanding but not included in the calculation of diluted
earnings (loss) per share for the three months ended September 30, 2004 and
2003, respectively, and options and warrants to purchase 676,000 shares and
12,000 shares of common stock were outstanding but not included in the
calculation of diluted earnings (loss) per share for the nine months ended
September 30, 2004 and 2003, respectively, because the effects would have been
antidilutive.


                                        8
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


5.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

     Brigham utilizes various commodity swap and option contracts to (i) reduce
the effects of volatility in price changes on the oil and natural gas
commodities it produces and sells, (ii) reduce commodity price risk and (iii)
provide a base level of cash flow in order to assure it can execute at least a
portion of its capital spending plans.

     Brigham reports average oil and natural gas prices and revenues including
the net results of hedging activities. The following table sets forth Brigham's
oil and natural gas prices including and excluding the hedging gains and losses
and the increase or decrease in oil and natural gas revenues as a result of the
hedging activities for the three and nine month periods ended September 30, 2004
and 2003:

<TABLE>
<CAPTION>
                                                                   THREE MONTHS ENDED         NINE MONTHS ENDED
                                                                       SEPTEMBER 30,             SEPTEMBER 30,
                                                                 ------------------------  -----------------------
                                                                    2004         2003         2004         2003
                                                                 -----------  -----------  -----------  ----------
<S>                                                              <C>          <C>          <C>          <C>
NATURAL GAS
  Average price per Mcf as reported (including hedging results)  $     5.44   $     5.27   $     5.68   $    5.17
  Average price per Mcf realized (excluding hedging results)     $     5.62   $     5.72   $     5.87   $    6.16
  Decrease in revenue (in thousands)                             $     (390)  $     (738)  $   (1,250)  $  (4,584)
OIL
  Average price per Bbl as reported (including hedging results)  $    36.82   $    28.08   $    33.51   $   28.31
  Average price per Bbl realized (excluding hedging results)     $    42.50   $    30.30   $    38.01   $   31.08
  Decrease in revenue (in thousands)                             $     (843)  $     (356)  $   (2,018)  $  (1,554)
</TABLE>

     For the three months ended September 30, 2004 and 2003, ineffectiveness
associated with Brigham's derivative commodity instruments designated as cash
flow hedges decreased earnings by approximately $146,000 and $80,000,
respectively. For the nine months ended September 30, 2004 and 2003,
ineffectiveness associated with Brigham's derivative commodity instruments
designated as cash flow hedges decreased earnings by approximately $206,000 and
$250,000, respectively. These amounts are included in other income (expense).


                                        9
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS

CASH-FLOW HEDGES

     Brigham's cash-flow hedges consisted of fixed-price swaps and costless
collars (purchased put options and written call options). The fixed-price swap
agreements are used to fix the prices of anticipated future oil and natural gas
production. The costless collars are used to establish floor and ceiling prices
on anticipated future oil and natural gas production. There were no net premiums
received when Brigham entered into these option agreements. As of September 30,
2004, Brigham had entered into derivative contracts that qualify as cash flow
hedges with respect to future production as follows:

<TABLE>
<CAPTION>
                              2004                   2005
                            --------  --------------------------------------
                             FOURTH    FIRST     SECOND    THIRD     FOURTH
                            QUARTER   QUARTER   QUARTER   QUARTER   QUARTER
                            --------  --------  --------  --------  --------
<S>                         <C>       <C>       <C>       <C>       <C>
NATURAL GAS SWAPS:
Volumes (MMbtu). . . . . .    92,000         -         -         -         -
Average price ($per MMBtu)  $  4.360  $      -  $      -  $      -  $      -

NATURAL GAS COLLARS:
Volumes (MMbtu). . . . . .   726,100   727,500   455,000         -         -
Average price ($per MMBtu)
Floor. . . . . . . . . . .  $  5.065  $  5.164  $  4.725  $      -  $      -
Ceiling. . . . . . . . . .     6.873     7.256     6.712         -         -

CRUDE OIL SWAPS:
Volumes (Bbls) . . . . . .     9,200         -         -         -         -
Average price ($per Bbl) .  $  23.80  $      -  $      -  $      -  $      -

CRUDE OIL COLLARS:
Volumes (Bbls) . . . . . .    34,260    27,450    18,655         -         -
Average price ($per Bbl)
Floor. . . . . . . . . . .  $  26.38  $  25.56  $  26.80  $      -  $      -
Ceiling. . . . . . . . . .     31.71     30.18     32.51         -         -
</TABLE>

     As of September 30, 2004, Brigham's derivative positions included an option
contract that is not designated as a hedge. This contract was entered into to
offset the cost of other options that are designated as hedges.

<TABLE>
<CAPTION>
                              2004                   2005
                            --------  --------------------------------------
                             FOURTH    FIRST     SECOND    THIRD     FOURTH
                            QUARTER   QUARTER   QUARTER   QUARTER   QUARTER
                            --------  --------  --------  --------  --------
<S>                         <C>       <C>       <C>       <C>       <C>
NATURAL GAS WRITTEN PUTS:
Volumes (MMbtu). . . . . .   140,000   210,000         -         -         -
Average price ($per MMBtu)  $  5.500  $  5.500  $      -  $      -  $      -
</TABLE>

     Derivative instruments not qualifying as hedging contracts are recorded at
fair value on the balance sheet. At each balance sheet date, the value of
derivatives not qualifying as hedging contracts is adjusted to reflect current
fair value and any gains or losses are recognized as other income or expense. At
September 30, 2004 and 2003, the fair value of these derivatives included in
other current liabilities was approximately $22,000 and $0, respectively. For
the three and nine months ended September 30, 2004, and 2003, other income
(expense) included approximately $21,000 and $0, respectively, in non-cash
losses related to changes in the fair values of these derivative contracts.
There were no cash settlement payments made by Brigham to the counterparty for
the three and nine months ended September 30, 2004 and 2003.


                                       10
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


     INTEREST RATE SWAP

     Periodically, Brigham may use interest rate swap contracts to adjust the
proportion of its total debt that is subject to variable interest rates. Under
such an interest rate swap contract, Brigham agrees to pay an amount equal to a
specified fixed-rate of interest for a certain notional amount and receive in
return an amount equal to a variable-rate. The notional amounts of the contract
are not exchanged. No other cash payments are made unless the contract is
terminated prior to maturity. Although no collateral is held or exchanged for
the contract, the interest rate swap contract is entered into with a major
financial institution in order to minimize Brigham's counterparty credit risk.
The interest rate swap contract is designated as a cash flow hedge against
changes in the amount of future cash flows associated with Brigham's interest
payments on variable-rate debt. The effect of this accounting on operating
results is that interest expense on a portion of variable-rate debt being hedged
is recorded based on fixed interest rates.

     At September 30, 2004, Brigham had an interest rate swap contract to pay a
fixed-rate of interest of 8.76% on $20.0 million notional amount of senior
subordinated notes. The $20.0 million notional amount of the outstanding
contract matures in March 2009. As of September 30, 2004, approximately $79,000
of unrealized losses are included in accumulated other comprehensive income
(loss) on the balance sheet and the fair value of the interest rate swap
agreement represents approximately $191,000 of other noncurrent liabilities. The
fair value of the interest rate swap contract is based on quoted market prices
and third-party provided calculations, which reflect the present values of the
difference between estimated future variable-rate receipts and future fixed-rate
payments.

     FAIR VALUES

     The fair value of commodity hedging and interest rate swap contracts is
reflected on the consolidated balance sheets as detailed in the following table.
The current asset and liability amounts represent the fair values expected to be
included in the results of operations for the next twelve months.

<TABLE>
<CAPTION>
                                  SEPTEMBER 30,
                              --------------------
                                2004       2003
                              ---------  ---------
<S>                           <C>        <C>
                                 (in thousands)

Other current liabilities     $ (2,970)  $ (1,134)
Other noncurrent liabilities      (428)      (136)
Other current assets                 -         91
Other noncurrent assets              3         12
                              ---------  ---------
                              $ (3,395)  $ (1,167)
                              =========  =========
</TABLE>

6.   ASSET RETIREMENT OBLIGATIONS

     On January 1, 2003, Brigham adopted the provisions of Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143").  SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. The liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized.  Brigham has asset retirement obligations
associated with the future plugging and abandonment of proved properties and
related facilities.  Prior to the adoption of SFAS 143, Brigham assumed salvage
value approximated plugging and abandonment costs.  As such, estimated salvage
value was not excluded from depletion and plugging and abandonment costs were
not accrued for over the life of the oil and gas properties.

     The estimated liability is based on historical experience in plugging and
abandoning wells, estimated remaining lives of those wells, estimates as to the
cost to plug and abandon the wells in the future, and federal and state
regulatory requirements.  The liability is discounted using an assumed
credit-adjusted risk-free interest


                                       11
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


rate of 7.5%. Revisions to the liability could occur due to changes in estimates
of plugging and abandonment costs, changes in the risk-free interest rate or
remaining lives of the wells, or if federal or state regulators enact new
plugging and abandonment requirements.

     The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $1.4 million increase in the carrying values of
proved properties, (ii) a $0.8 million decrease in accumulated depletion of oil
and natural gas properties and (iii) a $1.9 million increase in noncurrent
abandonment liabilities. The net impact of items (i) through (iii) was to record
a gain of $0.3 million as a cumulative effect adjustment of a change in
accounting principle in Brigham's consolidated statements of operations upon
adoption on January 1, 2003.

     Brigham has no assets that are legally restricted for purposes of settling
asset retirement obligations. The following table summarizes Brigham's asset
retirement obligation transactions recorded in accordance with the provisions of
SFAS 143 during the three and nine months ended September 30, 2004:

<TABLE>
<CAPTION>
                                                 THREE MONTHS ENDED       NINE MONTHS ENDED
                                                     SEPTEMBER 30,           SEPTEMBER 30,
                                              -----------------------  ----------------------
                                                 2004         2003        2004        2003
                                              -----------  ----------  -----------  ---------
<S>                                           <C>          <C>         <C>          <C>
                                                               (in thousands)

Beginning asset retirement obligations        $    2,665   $    2,062  $    2,320   $   1,931
Liabilities incurred for new wells placed on
   production                                         58           82         394         142
Liabilities settled                                  (24)           -         (92)          -
Accretion of discount on asset retirement
   obligations                                        40           39         117         110
                                              -----------  ----------  -----------  ---------
Ending asset retirement obligations           $    2,739   $    2,183  $    2,739   $   2,183
                                              ===========  ==========  ===========  =========
</TABLE>

7.   INCOME TAXES

     The provision for income taxes was computed in accordance with
Interpretation No. 18 of Accounting Principles Board Opinion (APB) No. 28 on
reporting taxes for interim periods and accordingly was based on the projection
of total 2004 pretax income.  Interpretation No. 18 of APB 28 provides that
interim income taxes should be computed using the projected effective tax rate
on the total projected pretax income for the year.

     At September 30, 2004, management believes that Brigham will (i) begin to
utilize net operating losses (NOLs) and (ii) have reversals of existing
temporary differences between book and taxable income sufficient to result in a
deferred tax liability at year-end 2004.  Management also believes that it is
more likely than not that capital loss carryforwards of approximately $1.8
million may expire unused and, accordingly, has established a valuation
allowance of $0.6 million.  The components of deferred income tax assets and
liabilities are as follows:

<TABLE>
<CAPTION>
                                       SEPTEMBER 30,    DECEMBER 31,
                                           2004            2003
                                      --------------  --------------
<S>                                   <C>             <C>
                                              (in thousands)
Deferred tax assets
  Current:
    Net operating loss carryforwards  $            -  $          451
    Unrealized hedging losses                    914               -
    Derivative assets                            274               -
                                      --------------  --------------
                                               1,188             451
                                      --------------  --------------
</TABLE>


                                       12
<PAGE>
<TABLE>
<CAPTION>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


                                                     SEPTEMBER 30,    DECEMBER 31,
                                                         2004             2003
                                                    ---------------  --------------
<S>                                                 <C>              <C>
                                                            (in thousands)
Non-current:
    Net operating loss carryforwards                        35,614          34,409
    Capital loss carryforwards                                 642             634
    Stock compensation                                         680             818
    Unrealized hedging losses                                    -             561
    Derivative assets                                            -             276
    Asset retirement obligations                               958             812
    Preferred stock dividends as interest expense              307             119
    Other                                                       27              27
                                                    ---------------  --------------
      Non-current                                           38,228          37,656
                                                    ---------------  --------------
                                                            39,416          38,107
                                                    ---------------  --------------

Deferred tax liabilities
  Current:
    Gas imbalances                                               -            (144)
  Non-current:
    Depreciable and depletable property                    (43,279)        (35,132)
    Other                                                     (186)              -
                                                    ---------------  --------------
      Non-current                                          (43,465)        (35,132)
                                                    ---------------  --------------
                                                           (43,465)        (35,276)
                                                    ---------------  --------------
  Net deferred tax assets (liabilities)                     (4,049)          2,831
  Valuation allowance                                         (634)           (634)
                                                    ---------------  --------------
                                                    $       (4,683)  $       2,197
                                                    ===============  ==============
</TABLE>

     At September 30, 2004, Brigham has regular tax NOLs of approximately $101.8
million. Additionally, Brigham has approximately $87.6 million of alternative
minimum tax ("AMT") NOLs available as a deduction against future taxable income.
The NOLs expire from 2012 through 2024. The value of these NOLs depends on the
ability of Brigham to generate taxable income.

     In addition, at September 30, 2004, Brigham has capital loss carryforwards
of approximately $1.8 million that expire in varying years through 2007.

     Brigham believes it has a $4.5 million annual limitation on the utilization
of certain of its NOLs under Internal Revenue Code Section 382 due to a
potential 50% change in ownership among its 5% stockholders over a three-year
period.

8.   ISSUANCE OF COMMON STOCK

     During July and August 2004, Brigham completed the sale of 2,598,500 shares
of its common stock under a universal shelf registration statement declared
effective by the Securities and Exchange Commission in June 2004.  Net proceeds
from the stock sale of approximately $22.1 million were used to repay
outstanding borrowings under the senior credit facility.  Brigham plans to
reborrow the repaid amounts under the senior credit facility as necessary to
fund future exploration and development activities and for general corporate
purposes.

9.   ACCOUNTING PRONOUNCEMENTS

     In September 2004, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin No. 106. This pronouncement will require companies
that use the full cost method for accounting for their oil and gas producing


                                       13
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


activities to include an estimate of future asset retirement costs to be
incurred as a result of future development activities on proved reserves in
their calculation of depreciation, depletion and amortization. This
pronouncement will also require these companies to exclude any future cash
outflows associated with settling asset retirement liabilities from their full
cost ceiling test calculation. This standard will also require these companies
to disclose the impact of their asset retirement obligations on their oil and
gas producing activities, ceiling test calculations and depreciation, depletion
and amortization calculations. Brigham will adopt the provisions of this
pronouncement in the fourth quarter of 2004 and is currently evaluating the
impact, if any, on our consolidated financial statements.


                                       14
<PAGE>
ITEM 2.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
            RESULTS OF OPERATIONS

     The following updates information as to our financial condition provided in
our 2003 Annual Report on Form 10-K, and analyzes the changes in the results of
operations between the three and nine month periods ended September 30, 2004,
and the comparable periods of 2003. For definitions of commonly used oil and gas
terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas
Terms" provided in our 2003 Annual Report on Form 10-K.

OVERVIEW OF FIRST NINE MONTHS OF 2004

     For the quarter and nine-month periods ended September 30, 2004, our net
capital expenditures for oil and natural gas activities were $24.4 million and
$64 million, respectively.  Our drilling capital expenditures alone for the
third quarter 2004 were up approximately 122% over the amount we spent in the
third quarter of last year.  For the nine months ended September 30, 2004, our
net capital expenditures for oil and natural gas activities are up approximately
126% when compared to the first nine months of last year.  Our operating
performance for the third quarter and first nine months of 2004 was highlighted
by production of 34 MMcfe/d and 34.1 MMcfe/d, respectively.  This represents a
17% growth in production over the amount we produced in the third quarter of
2003 and a 15% increase over the amount we produced in the first nine months of
2003.  The increase in our production is primarily the result of the increase in
drilling capital expenditures during the fourth quarter of last year and the
first nine months of 2004.

     Net income to common stockholders for the third quarter 2004 was $4.5
million, or $0.11 per diluted share, on total revenues of $17.3 million.  This
compares to reported net income of $3.3 million, or $0.13 per diluted share on
total revenues of $13.2 million in the third quarter last year.

     For the nine month period ended September 30, 2004, our reported net income
to common stockholders was $14.6 million, or $0.36 per diluted share, on total
revenues of $52 million.  This compares to reported net income of $11.2 million,
or $0.43 per diluted share, on revenue of $40.1 million for the first nine
months of last year.  Net cash provided by operating activities funded
approximately 61% of the cash used in our capital expenditure program during the
first nine months of 2004.  During the third quarter of 2004, we sold 2,598,500
shares of our common stock under a universal shelf registration statement
declared effective by the Securities and Exchange Commission in June 2004.  Net
proceeds from the stock sale were approximately $22.1 million and were used to
repay outstanding indebtedness under our senior credit facility. "Net proceeds"
is the amount we received after paying the underwriting discount and other
expenses related to offering.  We intend to reborrow the repaid amount to fund
future exploration and development activities, including taking advantage of
opportunities to retain larger working interests in wells and in 3-D seismic
programs and for general corporate purposes.

     At September 30, 2004, we had $9 million in cash, total assets of $271.5
million and a debt to total book capitalization ratio of 23%.


                                       15
<PAGE>
<TABLE>
<CAPTION>
OUTLOOK FOR THE REMAINDER OF 2004

                                                        ESTIMATED   ORIGINAL
                                                           2004       2004
                                                         SPENDING    BUDGET    % CHANGE
                                                        ----------  ---------  ---------
                                                                 (IN THOUSANDS)
<S>                                                     <C>         <C>        <C>
Drilling . . . . . . . . . . . . . . . . . . . . . . .  $   69,280  $  61,432        13%
Land and G&G . . . . . . . . . . . . . . . . . . . . .      16,589     11,973        39%
Capitalized interest and G&A . . . . . . . . . . . . .       6,085      5,535        10%
                                                        ---------------------
    Net capital expenditures on oil and gas activities  $   91,954  $  78,940        16%

Other property and equipment . . . . . . . . . . . . .         474        473         0%
                                                        ---------------------
    Net capital expenditures . . . . . . . . . . . . .  $   92,428  $  79,413        16%
                                                        =====================
</TABLE>


Current  Estimated  Capital  Expenditures  for  2004

     Approximately $40.2 million, or 58%, of our estimated drilling capital
expenditures for 2004 will be allocated to drill 23 wells in our onshore Texas
Gulf Coast region.  For 2004, our drilling activities in our onshore Gulf Coast
region will be focused on the Vicksburg and Frio Trends where we will drill 11
development wells with an average working interest of 61% and 12 exploratory
wells with an average working interest of 68%.  Of the wells we currently plan
to drill in 2004, 14 of the wells had reached total depth as of September 30,
2004.

     In the Vicksburg, we currently estimate that we will spend approximately
$19.4 million to drill four development wells with an average working interest
of 51% and three exploration wells with an average working interest of 71%.  As
of September 30, 2004, four of the wells budgeted for 2004 had reached total
depth and one well was drilling.  We currently plan to spud the remaining two
Vicksburg wells in our 2004 drilling program in the fourth quarter of this year.

     In the Frio, we currently estimate that we will spend approximately $20.7
million to drill seven development wells with an average working interest of 66%
and nine exploration wells with an average working interest of 67%.  As of
September 30, 2004, ten of the wells in budgeted for 2004 had reached total
depth and one was drilling. We currently plan to spud the remaining five Frio
wells in the fourth quarter of this year.

     Approximately $26.8 million, or 39%, of our currently estimated drilling
capital expenditures for 2004 will be allocated to drill 37 wells in our
Anadarko Basin region.  The majority of our drilling capital allocated to our
Anadarko Basin region will be focused on the Hunton/Arbuckle, Springer Channel
and Springer Bar Trends.  For 2004, we currently plan to drill 30 development
wells with an average working interest of 29% and seven exploratory wells with
an average working interest of 16% in our Anadarko Basin region.  Of the wells
currently plan to drill in 2004, 24 had reached total depth as of September 30,
2004.

     We currently estimate that we will spend approximately $13.1 million to
drill two Hunton/Arbuckle development wells with an average working interest of
96%.  As of September 30, 2004, one well had reached total depth and we expect
to spud the remaining well in the fourth quarter of this year.

     For the Springer Channel, we currently estimate that we will spend
approximately $4.7 million to drill seven development wells with an average
working interest of 41% and five exploratory wells with an average working
interest of 18%.  As of September 30, 2004, nine of these wells had reached
total depth of which three were completing and one well was drilling.  We
currently plan to spud the remaining two wells in the fourth quarter of this
year.

     For the Springer Bar, we currently estimate that we will spend
approximately $2.3 million to drill seven development wells with an average
working interest of 12%.  As of September 30, 2004, one well was drilling and
four wells, of which two were completing, had reached total depth.  We currently
plan to spud the remaining three wells in the fourth quarter of this year.


                                       16
<PAGE>
     Additional estimated capital expenditures for the Anadarko Basin region in
2004 includes $4 million to drill 13 development wells in the granite wash
formation with and average working interest of 22%.  As of September 30, 2004,
eight of these granite wash wells reached total depth and two were drilling.  We
currently plan to spud the remaining two wells in the fourth quarter.  We also
plan to spend $2.5 million to drill two Grady County Bromide tests with an
average working interest of 16%, a combined Hunton/Springer Channel test with a
17% working interest and for other various drilling activities.  As of September
30, 2004, one of the Bromide tests and the combined Hunton/Springer Channel test
had reached total depth.  The other Bromide test was drilling at September 30,
2004.

     We currently plan to spend approximately $2.3 million, or 3%, of our
estimated 2004 drilling capital expenditures, to drill two exploratory wells in
our West Texas region with an average working interest of 94%.  As of September
30, 2004, one well had reached total depth and was completing.  The other well
was drilling at the end of the third quarter.

     Approximately 18% of current estimated 2004 capital expenditures will be
used to fund land and seismic acquisitions in an effort to add to our inventory
of drilling projects in current focus plays. We believe that our cash on hand at
September 30, 2004, net cash provided by operating activities, net proceeds from
our sale of common stock in July and August 2004 and the remaining availability
under our senior credit facility will fund our spending for the remainder of the
year. Our estimated net capital expenditures for 2004 represent an increase of
approximately 96% over the amount that we spent in 2003.

     The final determination with respect to our 2004 budgeted expenditures will
depend on a number of factors, including:

     -    commodity prices;
     -    production from our existing producing wells;
     -    the results of our current exploration and development drilling
          efforts;
     -    economic and industry conditions at the time of drilling, including
          the availability of drilling equipment; and
     -    the availability of more economically attractive prospects.

     There can be no assurance that the budgeted wells will, if drilled,
encounter commercial quantities of natural gas or oil.


                                       17
<PAGE>
CAPITAL COMMITMENTS

     Net cash provided by operating activities, net proceeds from the sale of
common stock and additional borrowings from our senior credit facility were our
primary sources of cash during the first nine months of 2004. This cash was used
to fund the costs associated with drilling, land acquisition and 3-D seismic
acquisition, processing and interpretation. We believe our cash on hand at the
end of the third quarter 2004, net cash provided by operating activities, net
proceeds from our sale of common stock in July and August 2004 and the remaining
availability under our senior credit facility will be sufficient to fund our
budgeted capital expenditures for the remainder of 2004.

Capital  Expenditures

     The timing of most of our capital expenditures is discretionary because we
have no material long-term capital expenditure commitments. Consequently, we
have a significant degree of flexibility to adjust the level of our capital
expenditures as circumstances warrant.  The table below lists our capital
expenditures for the first nine months of 2004 and 2003.

<TABLE>
<CAPTION>
                                                             NINE MONTHS ENDED SEPTEMBER 30,
                                                        ----------------------------------------
                                                           2004            2003      % CHANGE
                                                        ----------  --------------  ------------
<S>                                                     <C>         <C>             <C>
                                                                        (IN THOUSANDS)

Drilling . . . . . . . . . . . . . . . . . . . . . . .  $   48,638  $      20,542           137%
Land and G&G . . . . . . . . . . . . . . . . . . . . .      10,749          3,135           243%
Capitalized interest and G&A . . . . . . . . . . . . .       4,595          4,622           (1%)
Proceeds from the sale of oil and gas properties . . .           -            (23)        (100%)
                                                        --------------------------
    Net capital expenditures on oil and gas activities  $   63,982  $      28,276           126%

Other property and equipment . . . . . . . . . . . . .         186            247          (25%)
                                                        --------------------------
    Net capital expenditures . . . . . . . . . . . . .  $   64,168  $      28,523           125%
                                                        ==========================
</TABLE>


LIQUIDITY AND CAPITAL RESOURCES

Cash flows from operating activities

     During the first nine months of 2004, net cash provided by operating
activities, net proceeds from the sale of common stock and additional borrowings
from our senior credit facility were our primary source of cash.  This cash was
used to fund the costs associated with drilling, land acquisition and 3-D
seismic acquisition, processing and interpretation.

<TABLE>
<CAPTION>
                                               NINE MONTHS ENDED SEPTEMBER 30,
                                           --------------------------------------
                                              2004          2003      % CHANGE
                                           ----------  -------------  -----------
                                                      (IN THOUSANDS)

<S>                                        <C>         <C>            <C>
Net cash provided by operating activities  $   37,505  $      32,425          16%
</TABLE>

     The 16% increase in net cash provided by operating activities is primarily
related to the following:

-    An increase in oil and natural gas sales resulted in a $9.1 million
     increase in net cash provided by operating activities.
-    An increase in revenue due to a decline in losses from the settlement of
     derivative contracts resulted in a $2.9 million increase in net cash
     provided by operating activities.

     These increases were partially offset by the following:

-    The repayment of accounts payable in excess of collections of accounts
     receivable reduced net cash provided by


                                       18
<PAGE>
     operating activities by $4.1 million.
-    The settlement of the gas imbalance with our industry participant in our
     Diablo project reduced net cash provided by operating activities by $1.4
     million.
-    An increase in production costs and general and administrative expenses
     reduced net cash provided by operating activities by $765,000.
-    A decrease in royalties payable of $320,000.

     Working capital is the amount by which current assets exceed current
liabilities. It is normal for us to report a working capital deficit at the end
of a period. These deficits are primarily the result of accounts payable related
to lease operating expenses, exploration and development costs, liabilities
related to derivative contracts and royalties payable.  Settlement of these
payables will be funded by cash flows from operations or, if necessary, by
additional borrowing under our senior credit facility.  At September 30, 2004,
we had a working capital deficit of $11.5 million compared to a working capital
deficit of $14.7 million at December 31, 2003.  Current liabilities at September
30, 2004, included a liability of $3 million related to the fair value of our
open derivative contracts.

Cash flows from financing activities

Common stock transactions
-------------------------

-    During the third quarter 2004, we sold 2,598,500 shares of our common stock
     under a universal shelf registration statement declared effective by the
     Securities and Exchange Commission in June 2004. We received net proceeds
     of approximately $22.1 million and used the net proceeds from the offering
     to repay outstanding indebtedness under our senior credit facility. "Net
     proceeds" is the amount we received after paying the underwriting discount
     and other expenses related to offering.
-    We issued 126,600 shares of common stock and received $310,000 in net
     proceeds related to the exercise of employee and director stock options in
     the first quarter of 2004, issued 81,481 shares of common stock and
     received $288,000 in net proceeds in the second quarter of 2004 and issued
     27,500 shares of common stock and received $86,000 in net proceeds in the
     third quarter 2004.
-    During January and June of 2004, we acquired 19,596 and 821 shares of our
     common stock, respectively, from certain employees to satisfy
     tax-withholding obligations associated with the vesting of stock grants.
     The transferred shares were valued at fair market value as of the date of
     surrender.
-    In September 2003, we sold 7,384,090 shares of common stock and received
     $40 million in net proceeds. The net proceeds from the sale were used to
     increase the amount of capital spent on our exploration and development
     activities. Pending such use, the net proceeds were used to repay $40
     million of the borrowings outstanding under our senior credit facility.
-    We issued 171,800 shares of common stock and received $432,000 in net
     proceeds related to the exercise of employee and director stock options in
     the first quarter of 2003, issued 52,793 and received net proceeds of
     $162,000 in the second quarter of 2003 and issued 25,042 shares of common
     stock and received net proceed of $66,000 in the third quarter of 2003.
-    In the first quarter of 2003, we issued 248,028 unregistered shares of our
     common stock to a group of institutional investors. The shares were issued
     to the group in connection with the cashless exercise of warrants that it
     owned and we received no proceeds from the exercise of the warrants.
-    In June 2003, we issued 408,928 and 206,982 unregistered shares of our
     common stock to the Bank of Montreal and Soci t G n rale, respectively. We
     received no proceeds from the exercise of these warrants as both parties
     elected to execute a cashless exercise of the warrants. Both parties sold
     the shares from this exercise in our common stock sale in September 2003.
     We received no proceeds from the sale.

Senior credit facility
----------------------

     Future outstanding balances under our senior credit facility are dependent
primarily on our level of capital expenditures, net cash provided by operating
activities and the proceeds from other financing activities.  Our committed
borrowing capacity under our senior credit facility at September 30, 2004, was
$23.5 million, with a $68.5 million borrowing base that is subject to adjustment
on the basis of the present value of estimated future net cash flows from proved
oil and gas reserves (as determined by the lender's petroleum engineer).  Our
unused committed borrowing base capacity under our senior credit facility was
$44.5 million at November 5, 2004.

     During the first nine months of 2004 we borrowed $28 million of additional
debt from our senior credit facility to fund our working capital obligations and
capital expenditures and repaid $23.5 million.  During the first nine


                                       19
<PAGE>
months of 2003, we repaid $47 million of the debt outstanding under our senior
credit facility and paid $985,000 in fees related to our new credit facility
that was put in place in March 2003.

     Our current ratio, as defined by the senior credit facility, at September
30, 2004 and interest coverage ratio for the twelve-month period ending
September 30, 2004, were 2 to 1 and 13.7 to 1, respectively.  As of September
30, 2004, we were in compliance with the covenants of our senior credit
facility.

Senior subordinated notes
-------------------------

     Our current ratio, as defined by the senior credit facility, at September
30, 2004 and interest coverage ratio for the twelve-month period ending
September 30, 2004, were 2 to 1 and 13.7 to 1, respectively.    Our ratio of
risked net present value (as defined) discounted at 9% to total debt at June 30,
2004, was 2.3 to 1, and was in compliance with the subordinated notes covenant
that requires us to maintain a ratio of 1.5 to 1.  As of September 30, 2004, we
were in compliance with the covenants of our senior subordinated notes.



RESULTS OF OPERATIONS

Comparison of the three and nine month periods ended September 30, 2004 and 2003

     Production.

<TABLE>
<CAPTION>
                                          THREE MONTHS ENDED SEPTEMBER 30,           NINE MONTHS ENDED SEPTEMBER 30,
                                      -----------------------------------------  -----------------------------------------
                                         2004           2003        % CHANGE        2004          2003         % CHANGE
                                      ----------  -------------  --------------  ----------  -------------  --------------
<S>                                   <C>         <C>            <C>             <C>         <C>            <C>
Oil (MBbls). . . . . . . . . . . . .        148            160             (7%)        449            562            (20%)
Natural gas (MMcf) . . . . . . . . .      2,167          1,648              31%      6,506          4,648              40%
  Natural gas equivalent (MMcfe) . .      3,057          2,608              17%      9,199          8,019              15%

  Average daily production (MMcfe/d)       34.0           29.0              17%       34.1           29.7              15%
  % Natural gas. . . . . . . . . . .         71%            63%                         71%            58%
</TABLE>

     The increase in our production volumes was due to organic production growth
from wells that we drilled and completed in the fourth quarter of 2003 and the
first nine months of 2004.  New production related to these recently completed
wells was partially offset by the natural decline of existing production.

     Revenues from the sale of oil and natural gas.  Reported revenues from the
sale of oil and natural gas are based on the market price we receive for our
commodities, adjusted for marketing charges and the results from the settlement
of our derivative commodity contracts that have been designated as cash flow
hedges under SFAS 133.

     We utilize fixed price swaps, costless collars, three way costless collars
and floor contracts to (i) reduce the effect of price volatility on the
commodities that we produce and sell, (ii) reduce commodity price risk and (iii)
provide a base level of cash flow in order to assure we can execute at least a
portion of our capital spending plans.  See "Item 3.  Quantitative and
Qualitative Disclosures About Market Risk" for a list of our open derivative
commodity contracts at September 30, 2004."

     The effective portions of changes in the fair values of our derivative
commodity contracts that are designated as cash flow hedges is recorded as
increases or decreases to stockholders' equity until the underlying contract is
settled.  Consequentially, these changes could add volatility to our reported
stockholders' equity until the contract is settled or is terminated.

     Derivative commodity contracts that do not meet the hedge criteria of SFAS
133 are not designated as hedges.  Gains or losses related to the settlement,
the ineffective portion of changes in the fair market value and the changes in
the fair values of our derivative commodity contracts that are not designated as
cash flow hedges are recognized in other income (expense).


                                       20
<PAGE>
     The following table presents revenues that we realized from the sale of oil
and natural gas during the third quarter and first nine months of 2004 and 2003.

<TABLE>
<CAPTION>
                                                         THREE MONTHS ENDED SEPTEMBER 30,      NINE MONTHS ENDED SEPTEMBER 30,
                                                       -----------------------------------  --------------------------------------
                                                         2004        2003       % CHANGE       2004         2003        % CHANGE
                                                       ---------  ----------  ------------  ----------  ------------  ------------
<S>                                                    <C>        <C>         <C>           <C>         <C>           <C>
                                                                                   (IN THOUSANDS)

Oil sales . . . . . . . . . . . . . . . . . . . . . .  $  6,304   $   4,847            30%  $  17,058   $    17,459           (2%)
Loss due to hedging . . . . . . . . . . . . . . . . .      (843)       (356)          137%     (2,018)       (1,554)           30%
                                                       ---------  ----------                ------------------------
  Total revenues from the sale of oil . . . . . . . .  $  5,461   $   4,491            22%  $  15,040   $    15,905           (5%)
                                                       =========  =========                ========================

Natural gas sales . . . . . . . . . . . . . . . . . .  $ 12,169   $   9,428            29%  $  38,185   $    28,627            33%
Loss due to hedging . . . . . . . . . . . . . . . . .      (390)       (738)         (47%)     (1,250)       (4,585)         (73%)
                                                       ---------  ----------                ------------------------
  Total revenues from the sale of natural gas . . . .  $ 11,799   $   8,690            36%  $  36,935   $    24,042            54%
                                                       =========  =========                ========================

Oil and natural gas sales . . . . . . . . . . . . . .  $ 18,473   $  14,275            29%  $  55,243   $    46,086            20%
Loss due to hedging . . . . . . . . . . . . . . . . .    (1,233)     (1,094)           13%     (3,268)       (6,139)         (47%)
                                                       ---------  ----------                ------------------------
  Total revenues from the sale of oil and natural gas  $ 17,240   $  13,181            31%  $  51,975   $    39,947            30%
                                                       =========  =========                ========================

AVERAGE PRICES:
                                                                                     (PER BBL)
Oil sales . . . . . . . . . . . . . . . . . . . . . .  $  42.50   $   30.30            40%  $   38.01   $     31.08            22%
Loss due to hedging . . . . . . . . . . . . . . . . .     (5.68)      (2.22)          156%      (4.50)        (2.77)           62%
                                                       ---------  ----------                ------------------------
  Realized Oil price. . . . . . . . . . . . . . . . .  $  36.82   $   28.08            31%  $   33.51   $     28.31            18%
                                                       =========  =========                ========================

                                                                                     (PER MCF)
Natural gas sales . . . . . . . . . . . . . . . . . .  $   5.62   $    5.72           (2%)  $    5.87   $      6.16           (5%)
Loss due to hedging . . . . . . . . . . . . . . . . .     (0.18)      (0.45)         (60%)      (0.19)        (0.99)         (81%)
                                                       ---------  ----------                ------------------------
  Realized natural gas price. . . . . . . . . . . . .  $   5.44   $    5.27             3%  $    5.68   $      5.17            10%
                                                       =========  =========                ========================

                                                                                     (PER MCFE)
Natural gas equivalent sales. . . . . . . . . . . . .  $   6.04   $    5.47            10%  $    6.01   $      5.75             5%
Loss due to hedging . . . . . . . . . . . . . . . . .     (0.40)      (0.42)          (5%)      (0.36)        (0.77)         (53%)
                                                       ---------  ----------                ------------------------
  Realized natural gas equivalent price . . . . . . .  $   5.64   $    5.05            12%  $    5.65   $      4.98            13%
                                                       =========  =========                ========================
</TABLE>

     Total revenues from the sale of oil and natural gas for the third quarter
2004 were 31% higher than revenues in same period of 2003.  The increase was
primarily due the following:

-    A $2.6 million increase to total revenues from the sale of oil and natural
     gas due to a 17% increase in production volumes for the third quarter 2004.
-    A $1.6 million increase to total revenues from the sale of oil and natural
     gas due to a 10% increase in the average sales price we received for oil
     and natural gas.
-    A 13% increase in losses related to the settlement of hedging contracts
     resulted in a $139,000 decrease in total revenues from the sale of oil and
     natural gas.

     Total revenues from the sale of oil and natural gas for the first nine
months of 2004 were 30% higher than revenues in the same period of 2003.  The
increase was primarily due to the following:


                                       21
<PAGE>
-    An $7.9 million increase to total revenues from the sale of oil and natural
     gas due to a 15% increase in production volumes during the first nine
     months of 2004.
-    A $1.2 million increase in total revenues from the sale of oil and natural
     gas due to a 5% increase in the average sales price we received for oil and
     natural gas during the first nine months of 2004.
-    A 47% decrease in losses related to the settlement of hedging contracts
     resulted in a $2.9 million increase in total revenues from the sale of oil
     and natural gas.

     The table below presents our derivative commodity contracts, the volumes,
the weighted average NYMEX reference price for those volumes, and the associated
gain or loss upon settlement of those contracts during the third quarter and
first nine months of 2004 and 2003.

<TABLE>
<CAPTION>
                                       THREE MONTHS ENDED  SEPTEMBER 30,         NINE MONTHS ENDED  SEPTEMBER 30,
                                     ---------------------------------------  --------------------------------------
                                                                     %                                       %
                                          2004         2003        CHANGE        2004         2003         CHANGE
                                     --------------  ---------  ------------  -----------  -----------  ------------
<S>                                  <C>             <C>        <C>           <C>          <C>          <C>

OIL SWAPS
Volumes (Bbls). . . . . . . . . . .         13,800     55,200          (75%)      63,850      184,125          (65%)
Average swap price (per Bbl). . . .  $       23.91   $  23.77             1%  $    24.77   $    24.81           (0%)
Loss upon settlement (in thousands)  $        (275)  $   (356)         (23%)  $     (848)  $   (1,157)         (27%)

OIL COLLARS
Volumes (Bbls). . . . . . . . . . .         48,760          -             -      144,310       45,250           219%
Average floor price (per Bbl) . . .  $       26.43   $      -             -   $    24.51   $    18.00            36%
Average ceiling price (per Bbl) . .          32.20          -             -        31.09        22.56            38%
Loss upon settlement (in thousands)  $        (568)  $      -             -   $   (1,170)  $     (397)          195%

NATURAL GAS SWAPS
Volumes (MMbtu) . . . . . . . . . .        138,000    598,000          (77%)     661,250    2,249,500          (71%)
Average swap price (per MMbtu). . .  $       4.180   $  3.867             8%  $    4.555   $    3.772            21%
Loss upon settlement (in thousands)  $        (230)  $   (738)         (69%)  $     (836)  $   (4,585)         (82%)

NATURAL GAS COLLARS
Volumes (MMbtu) . . . . . . . . . .        722,200          -             -    1,777,800            -             -
Average floor price (per MMbtu)      $       4.613   $      -             -   $    4.319   $        -             -
Average ceiling price (per MMbtu)            6.476          -             -        6.847            -             -
Loss upon settlement (in thousands)  $        (160)  $      -             -   $     (414)  $        -             -

NATURAL GAS FLOORS
Volumes (MMbtu) . . . . . . . . . .              -    460,000         (100%)           -      610,000         (100%)
Average floor price (per MMbtu) . .  $           -   $   4.50         (100%)  $        -   $    4.500         (100%)
Loss upon settlement (in thousands)  $           -   $      -             -   $        -   $        -             -
</TABLE>

     Other revenue.  Fees that we charge other parties who use our two gas
gathering systems to move their production from the wellhead to third party gas
pipeline systems are recorded as other revenue. These gathering systems are
owned by us and located in the Texas Gulf Coast. One of the gathering systems
connects a single well and the other connects two wells. Other revenue for the
third quarter of 2004 was $27,000 compared to $32,000 in the third quarter last
year.  Other revenue for the nine months of 2004 was $69,000 compared to
$113,000 during the first nine months of 2003.


                                       22
<PAGE>
     Production cost.  Production costs include lease operating expenses and
production taxes.  The following table presents our production cost for the
third quarter and first nine months of 2004 and 2003.

<TABLE>
<CAPTION>
                                         THREE MONTHS ENDED SEPTEMBER 30,               NINE MONTHS ENDED SEPTEMBER 30,
                                    -------------------------------------------  ------------------------------------------
                                                                        %                                            %
                                        2004            2003         CHANGE         2004            2003          CHANGE
                                    ------------  -------------  --------------  -----------  -------------  --------------
<S>                                 <C>           <C>            <C>             <C>          <C>            <C>
                                                                       (IN THOUSANDS)

Operating and maintenance expenses  $      1,201  $       1,061             13%  $     3,248  $       2,678             21%
Workover expenses. . . . . . . . .           278            563           (51%)          617            860           (28%)
Ad valorem taxes . . . . . . . . .           169            169              0%          497            499            (0%)
                                    ------------  -------------                  --------------------------
    Lease operating expenses . . .  $      1,648  $       1,793            (8%)  $     4,362  $       4,037              8%

Production taxes . . . . . . . . .           675            553             22%        2,434          2,297              6%
                                    ------------  -------------                  --------------------------
    Total production cost. . . . .  $      2,323  $       2,346            (1%)  $     6,796  $       6,334              7%
                                    ============  =============                  ==========================

                                                                         (PER MCFE)

Operating and maintenance expenses  $       0.39  $        0.41            (5%)  $      0.35  $        0.33              6%
Workover expenses. . . . . . . . .          0.09           0.22           (59%)         0.07           0.11           (36%)
Ad valorem taxes . . . . . . . . .          0.06           0.06              0%         0.05           0.06           (17%)
                                    ------------  -------------                  --------------------------
    Lease operating expenses . . .  $       0.54  $        0.69           (22%)  $      0.47  $        0.50            (6%)

Production taxes . . . . . . . . .          0.22           0.21              5%         0.26           0.29           (10%)
                                    ------------  -------------                  --------------------------
    Total production cost. . . . .  $       0.76  $        0.90           (16%)  $      0.73  $        0.79            (8%)
                                    ============  =============                  ==========================
</TABLE>


Lease operating expenses
------------------------

     Lease operating expenses are comprised of several components which include:
the cost of labor and supervision to operate the wells and related equipment;
repairs and maintenance; related materials, supplies, fuel, and supplies
utilized in operating the wells and related equipment and facilities; insurance
applicable to wells and related facilities and equipment; workover cost; and ad
valorem taxes.  Lease operating expenses are driven in part by the type of
commodity produced, the level of workover activity and the geographical location
of the properties. Oil is inherently more expensive to produce than natural gas.

     Local taxing authorities such as school districts, cities, and counties or
boroughs generally impose the ad valorem taxes we pay. The amount of the tax is
based on the value of the property assessed or determined by the taxing
authority on an annual basis, and a percent of value. When oil and natural gas
commodity prices rise, the value of our underlying property interests increase.
This results in higher ad valorem taxes.

     Lease operating expenses for the third quarter 2004 were 8% lower than
lease operating expenses in the third quarter last year.  The change was
primarily due to the following:

-    A decrease in the cost of expensed workovers led to a 51% decrease in
     workover costs for the third quarter of this year.
-    This decrease was partially offset by an increase in our operating and
     maintenance expenses due to an increase in the number of producing wells.

     On a unit basis, lease operating expenses for the third quarter 2004 were
22% lower than in the third quarter last year due to the decrease in workover
cost and an increase in production volumes.


                                       23
<PAGE>
     Lease operating expenses for the first nine months of 2004 were 8% higher
than lease operating expenses during the first nine months of 2003.  The change
was primarily due to the following:

-    An increase in the number of producing wells in the first nine months of
     2004.
-    An increase in the amount spent for compressor rental and maintenance and
     saltwater disposal.
-    These increases were partially offset by a decrease in the cost of expensed
     workovers during the first nine months of 2004.

     On a unit basis, lease operating expenses for the first nine months of 2004
were 6% lower than our per unit lease operating expenses in the same period of
the prior year.  The change in our per unit lease operating expense was
primarily due an increase in production volumes during the first nine months of
2004 combined with the following:

-    A decrease in the cost of expensed workovers during the first nine months
     of 2004.
-    A $0.01 increase in our unit cost for both compressor and rental
     maintenance and saltwater disposal.


Production taxes
----------------

     There are a variety of state and federal taxes levied on the production of
our oil and natural gas. These are commonly grouped together and referred to as
production taxes. The majority of our production tax expense is based on a
percent of gross value at the well at the time the production is sold or removed
from the lease. As a result, our production tax expense increases with increases
in crude oil and natural gas commodity prices.

     Historically, taxing authorities have occasionally encouraged oil and gas
industry to explore for new oil and natural gas reserves, or develop high cost
reserves through reduced tax rates or credits. These incentives have been narrow
in scope and short-lived. A small number of our wells currently qualify for
reduced production taxes because they are discoveries based on the use of 3-D
seismic or high cost wells.

     An increase in our third quarter 2004 production volumes combined with a
10% increase in the average pre-hedge sales price that we received for our oil
and natural gas in the third quarter 2004 were the primary reasons for the
increase in production taxes.  These increases were partially offset by reduced
tax rates or tax credits on certain wells.  Production taxes for the third
quarter 2004 were 3.7% of revenue from the sale of oil and natural gas before
gains and losses due to hedging, compared to 3.9% in the third quarter last
year.

     The increase in production taxes for the first nine months of 2004 was
primarily due to an increase in production volumes during the first nine months
of 2004.  This increase was partially offset by reduced tax rates or tax credits
on certain wells.  Production taxes for the first nine months of 2004 were 4.4%
of revenue from the sale of oil and natural gas before gains and losses due to
hedging, compared to 5% in the first nine months of last year.


                                       24
<PAGE>
General and administrative expenses.  We capitalize a portion of our general and
administrative costs. The costs capitalized represent the cost of technical
employees, who work directly on capital projects. An engineer designing a well
is an example of a technical employee working on a capital project.  The cost of
a technical employee includes associated technical organization costs such as
supervision, telephone and postage.  The following table presents general and
administrative expenses for the third quarter and first nine months of 2004 and
2003.

<TABLE>
<CAPTION>
                                            THREE MONTHS ENDED SEPTEMBER 30,           NINE MONTHS ENDED SEPTEMBER 30,
                                      -----------------------------------------  -------------------------------------------
                                                                       %                                            %
                                         2004          2003          CHANGE         2004           2003          CHANGE
                                      ----------  -------------  --------------  ------------  -------------  --------------
<S>                                   <C>         <C>            <C>             <C>           <C>            <C>
                                                                         (IN THOUSANDS)

General and administrative expenses.  $    1,304  $       1,094             19%  $      3,723  $       3,420              9%

                                                                          (PER MCFE)

General and administrative expenses.  $     0.43  $        0.42              2%  $       0.40  $        0.43            (7%)
</TABLE>


     General and administrative expenses for the third quarter of 2004 were 19%
higher than general and administrative expenses in the third quarter last year.
The change in our general and administrative expenses for the for the third
quarter 2004 was due to the following:

-    A 19% increase in payroll and employee benefit expenses net of amounts
     charged to joint ventures to cover the costs of managing these joint
     operations represented approximately 35% of the total increase.
-    A 162% increase in expenses paid to outside consultants and our independent
     public accountants. These increases, which were represented approximately
     40% of the total increase in our general and administrative expenses, were
     related to additional costs associated with the implementation of
     Sarbanes-Oxley Section 404.
-    An increase in expenses paid to our external reserve engineers represented
     approximately 11% of the total increase in our general and administrative
     expenses.
-    These increases were partially offset by a decrease in financial reporting
     expenses, a decrease in office rent and a decrease in legal fees.

     General and administrative expenses for the first nine months of 2004
increased by 9% over general and administrative expenses during the first nine
months of 2003.  The change in our general and administrative expenses for the
for the first nine months of 2004 was due to the following:

-    An 11% increase in payroll and employee benefit expenses net of amounts
     charged to joint ventures to cover the costs of managing these joint
     operations represented approximately 58% of the total increase.
-    A 60% increase in expenses paid to our independent public accountants
     primarily related to additional cost associated with the implementation of
     Sarbanes-Oxley Section 404 represented approximately 14% of the total
     increase.
-    An increase in expenses paid to our external reserve engineers represented
     approximately 12% of the total increase in general and administrative
     expenses.
-    An increase in expenses for corporate insurance expense represented
     approximately 5% of the increase.
-    These increases were partially offset by a decrease in cost for financial
     reporting and fees paid to our directors.


                                       25
<PAGE>
Depletion of oil and natural gas properties.  Our full-cost depletion expense is
driven by many factors including certain costs spent in the exploration and
development of producing reserves, production levels, and estimates of proved
reserve quantities and future developmental costs at the end of the year.  The
following table presents depletion expense for the third quarter and first nine
months of 2004 and 2003.

<TABLE>
<CAPTION>
                                                 THREE MONTHS ENDED SEPTEMBER 30,         NINE MONTHS ENDED SEPTEMBER 30,
                                              --------------------------------------  --------------------------------------
                                                                            %                                       %
                                                 2004        2003         CHANGE         2004        2003         CHANGE
                                              -----------  ---------  --------------  ----------------------  --------------
<S>                                           <C>          <C>        <C>             <C>          <C>        <C>
                                                                              (IN THOUSANDS)

Depletion of oil and natural gas properties.  $     5,871  $   3,952             49%  $    16,374  $  11,853             38%

                                                                                (PER MCFE)

Depletion rate . . . . . . . . . . . . . . .  $      1.92  $    1.52             26%  $      1.78  $    1.48             20%
</TABLE>


     Increased  production  volumes  combined  with  a  $0.40  increase  in  our
depletion  rate  resulted  in a 49% increase in our third quarter 2004 depletion
expense.  Higher  production  volumes  accounted  for  approximately 36% of this
increase  while  the  increase  in  our  depletion rate accounted for 64% of the
increase.  The  increase  in  our  depletion  rate  was  primarily the result of
increased  cost  of  reserve  additions  during  the  first nine months of 2004.

     Increased  production  volumes  combined  with  a  $0.30  increase  in  our
depletion rate resulted in a 20% increase in our depletion expense for the first
nine  months of 2004.  Higher production volumes accounted for approximately 39%
of  the  increase  while  the  increase  in our depletion rate accounted for the
remaining  61%.  The  increase in our depletion rate was primarily the result of
increased  cost  of  reserve  additions  during  the  first nine months of 2004.


                                       26
<PAGE>
Net interest expense.  We capitalize interest expense on borrowings associated
with major capital projects prior to their completion.  Capitalized interest is
added to the cost of the underlying assets and is amortized over the lives of
the assets.  The following table presents interest expense for the third quarter
and first nine months of 2004 and 2003.

<TABLE>
<CAPTION>
                                                               THREE MONTHS ENDED SEPTEMBER 30,         NINE MONTHS ENDED
                                                           ----------------------------------------  -----------------------
                                                                                           %
                                                               2004         2003         CHANGE         2004         2003
                                                           ------------  ----------  --------------  -----------  ----------
<S>                                                        <C>           <C>         <C>             <C>          <C>
                                                                                        (IN THOUSANDS)

Interest on senior credit facility. . . . . . . . . . . .  $       215   $     418            (49%)  $      649   $   1,563
Interest on senior subordinated notes (a) . . . . . . . .          436         612            (29%)       1,320       1,792
Commitment fees . . . . . . . . . . . . . . . . . . . . .           64          10             540%         171          45
Dividend on mandatorily redeemable
    preferred stock (b)(c). . . . . . . . . . . . . . . .          184         161              14%         538         161
Amortization of deferred loan and debt issuance cost. . .          191         276            (31%)         574         809
Other general interest expense. . . . . . . . . . . . . .            6           6               0%          20          34
Capitalized interest expense. . . . . . . . . . . . . . .         (224)       (212)              6%        (764)       (627)
                                                           ------------  ----------                  -----------------------
Net interest expense. . . . . . . . . . . . . . . . . . .  $       872   $   1,271            (31%)  $    2,508   $   3,777
                                                           ============  ==========                  =======================

Weighted average debt outstanding . . . . . . . . . . . .  $    54,508   $  79,659            (32%)  $   57,275   $  77,070
Average interest rate on outstanding indebtedness (d) . .          6.6%        6.0%                         6.2%        6.2%

(a) Interest expense on our senior subordinated notes
    paid in kind through the issuance of additional
    debt in lieu of cash.  Our option to pay interest in
    kind on our senior subordinated notes expired in
    October 2003. . . . . . . . . . . . . . . . . . . . .  $         -   $     306                   $        -   $     896

(b) Shares of mandatorily redeemable Series A
    preferred stock issued to satisfy dividends paid in
    kind.  The dividend on our Seri1es A preferred
    stock in the first two quarters of 2003 was
    recorded as dividends in dividends and accretion.
    Our option to pay dividends in kind on our Series
    A preferred stock expires in October 2005.  See
    further discussion later in net interest expense
    section and in dividends and accretion section. . . .        9,202      37,024                       26,877     107,852

(c) Shares of mandatorily redeemable Series
    Bpreferred stock issued to satisfy dividends paid
    in kind.  The dividend on our Series B preferred
    stock in the first two quarters of 2003 was
    recorded as dividends in dividends and accretion.
    In the fourth quarter of 2003, CSFB Private
    Equity used a portion of our mandatorily
    redeemable Series B preferred stock that it held
    to pay for the exercise of warrants.  We
    redeemed the remaining balance of Series B
    preferred stock that was not used to pay for the
    exercise.  See further discussion later in net
    interest expense section and in dividends and
    accretion section . . . . . . . . . . . . . . . . . .            -      10,086                            -      30,603


                                                           SEPTEMBER 30,
                                                           --------------
                                                                 %
                                                               CHANGE
                                                           --------------
<S>                                                        <C>

Interest on senior credit facility. . . . . . . . . . . .           (58%)
Interest on senior subordinated notes (a) . . . . . . . .           (26%)
Commitment fees . . . . . . . . . . . . . . . . . . . . .            280%
Dividend on mandatorily redeemable
    preferred stock (b)(c). . . . . . . . . . . . . . . .            234%
Amortization of deferred loan and debt issuance cost. . .           (29%)
Other general interest expense. . . . . . . . . . . . . .           (41%)
Capitalized interest expense. . . . . . . . . . . . . . .             22%

Net interest expense. . . . . . . . . . . . . . . . . . .           (34%)


Weighted average debt outstanding . . . . . . . . . . . .           (26%)
Average interest rate on outstanding indebtedness (d)

(a) Interest expense on our senior subordinated notes
    paid in kind through the issuance of additional
    debt in lieu of cash.  Our option to pay interest in
    kind on our senior subordinated notes expired in
    October 2003.

(b) Shares of mandatorily redeemable Series A
    preferred stock issued to satisfy dividends paid in
    kind.  The dividend on our Seri1es A preferred
    stock in the first two quarters of 2003 was
    recorded as dividends in dividends and accretion.
    Our option to pay dividends in kind on our Series
    A preferred stock expires in October 2005.  See
    further discussion later in net interest expense
    section and in dividends and accretion section

(c) Shares of mandatorily redeemable Series
    Bpreferred stock issued to satisfy dividends paid
    in kind.  The dividend on our Series B preferred
    stock in the first two quarters of 2003 was
    recorded as dividends in dividends and accretion.
    In the fourth quarter of 2003, CSFB Private
    Equity used a portion of our mandatorily
    redeemable Series B preferred stock that it held
    to pay for the exercise of warrants.  We
    redeemed the remaining balance of Series B
    preferred stock that was not used to pay for the
    exercise.  See further discussion later in net
    interest expense section and in dividends and
    accretion section
</TABLE>

(d) Calculated as the sum of interest expense on outstanding indebtedness,
    commitment fees and dividend on our Series A mandatorily redeemable
    preferred stock divided by the weighted average debt and preferred stock
    outstanding for the period.


                                       27
<PAGE>
     Interest expense for the third quarter 2004 was 34% lower than interest
expense in the same quarter of the prior year.  The change in interest expense
was primarily due to the following:

-    A decrease in the weighted average debt outstanding under our senior credit
     facility resulted in a $203,000 decrease in interest expense for the third
     quarter of 2004. This decrease was offset by a $54,000 increase in the
     commitment fees we paid on the unused portion of our borrowing base.
-    A decrease in the amount of subordinated notes outstanding during the third
     quarter this year combined with a decrease in the interest rate we paid on
     our senior subordinated notes resulted in a $176,000 decrease in interest
     expense.
-    An increase in the amount of interest we capitalized.
-    An increase in the dividend that we paid on our mandatorily redeemable
     preferred stock.

     Interest expense for the first nine months of 2004 was 34% lower than
interest expense during the first nine months of 2003.  The change was due to
the following:

-    A decrease in the weighted average debt outstanding under our senior credit
     facility combined with a decrease in the interest rate that we paid on
     those borrowings resulted in a $914,000 decrease in interest expense. This
     decrease was partially offset by a $126,000 increase in the commitment fees
     that we paid on the unused portion of our borrowing base.
-    A decrease in the amount of subordinated notes outstanding combined with a
     decrease in the interest rate we paid on our senior subordinated notes
     resulted in a $472,000 decrease in interest expense.
-    An increase in the amount of interest we capitalized.
-    An increase in the dividend that we paid on our manadatorily redeemable
     preferred stock. Upon our adoption of SFAS 150 in July 2003, we
     reclassified approximately $8 million of our then outstanding mandatorily
     redeemable Series A and Series B preferred stock, which had no equity
     conversion features and must be settled with our assets, to long-term debt.
     As part of this reclassification, we now report the dividends on the
     mandatorily redeemable preferred stock that was reclassified as interest
     expense. Prior to this reclassification, the dividend on our mandatorily
     redeemable preferred stock was reported as dividends in dividend and
     accretion of mandatorily redeemable preferred stock.


     Other income (expense). Other income (expense) primarily includes non-cash
gains (losses) resulting from the change in fair market value of oil and natural
gas derivative contracts that were not designated as cash flow hedges, cash
gains (losses) on the settlement of these contracts and non-cash gains (losses)
related to charges for the ineffective portions of cash flow hedges.

<TABLE>
<CAPTION>
                                                       THREE MONTHS ENDED SEEMBER 30,          NNE MONTHS ENDED SEEMBER 30,
                                                   --------------------------------------  ------------------------------------
                                                                                  %                                     %
                                                       2004         2003        CHANGE        2004        2003        CHANGE
                                                   ------------  ----------  ------------  ----------------------  ------------
<S>                                                <C>           <C>         <C>           <C>          <C>        <C>
                                                                                   (IN THOUSANDS)

Market value adjustment for derivative contracts.  $      (167)  $     (80)          109%  $     (227)  $   (250)          (9%)
Other income. . . . . . . . . . . . . . . . . . .           (1)          -             -           68          -              -

                                                   ------------  ----------                ----------------------
  Total other income (expense). . . . . . . . . .  $      (168)  $     (80)          110%  $     (159)  $   (250)         (36%)
                                                   ============  ==========                ======================
</TABLE>


                                       28
<PAGE>
     Income taxes. Since inception, we have not been required to recognize any
current income taxes.  Furthermore, we do not expect to recognize significant,
if any, current income taxes in 2004.  Since inception, we have generated net
operating losses (NOLs) due mainly to intangible drilling and other property
related deductions, which have exceeded taxable income.  Our regular NOLs are
$101.8 million, and our alternative minimum tax NOLs are $87.6 million.  To
date, we have not utilized any of our NOLs.  In future periods, our NOLs will be
used to offset taxable income.

     Since  1997 through the third quarter of 2003, we have not been required to
recognize  any  deferred income taxes. Due to the level of projected net taxable
income,  we expect to evolve from a net deferred tax asset to a net deferred tax
liability  position during 2004. It is management's belief that we will begin to
utilize  our  NOLs  and  will  have  reversals of existing temporary differences
between  book  and  taxable  income  such  that  a net deferred tax liability is
expected  at  year-end  2004,  as  well  as  in  future  years.  Accordingly, we
recognized  deferred tax expense of $7.2 million during the first nine months of
2004.

Dividends and accretion of mandatorily redeemable preferred stock. We are
required to pay dividends on our Series A and were required to pay dividends on
our Series B preferred stock prior to its redemption. At our option, these
dividends could be paid in cash at a rate of 6% per annum or paid in kind
through the issuance of additional shares of preferred stock in lieu of cash at
a rate of 8% per annum. We elected to pay dividends in kind in each quarter of
2004 and 2003.

     Upon our adoption of SFAS 150 in July 2003, approximately $8 million of our
then outstanding mandatorily redeemable Series A and Series B preferred stock
that must be settled with our assets, was reclassified to long-term debt. As
part of the reclassification, the dividend paid on the reclassified amount since
July 2003 has been reported as interest expense.

     In November and December 2003, CSFB Private Equity used a portion of our
mandatorily redeemable Series A and Series B preferred stock that it held to pay
for the exercise of the associated warrants.  We also redeemed the remaining
balance of Series B preferred stock that was not used to pay for the exercise.

     The following table shows the effect for the three and nine-month periods
ended September 30, 2004 and 2003, of the issuance of additional shares of
preferred stock in lieu of paying cash dividends.

<TABLE>
<CAPTION>
                                            THREE MONTHS ENDED SEPTEMBER 30,      NINE MONTHS ENDED SEPTEMBER 30,
                                         ------------------------------------  ------------------------------------
                                                                      %                                     %
                                            2004        2003        CHANGE        2004        2003        CHANGE
                                         -----------  ---------  ------------  ----------------------  ------------
<S>                                      <C>          <C>        <C>           <C>          <C>        <C>
                                                                        (IN THOUSANDS)

Dividends . . . . . . . . . . . . . . .  $         -  $     789             -  $         -  $   2,606             -
Accretion of redeemable preferred stock            -        115             -            -        321             -
                                         -----------  ---------                ----------------------
  Total dividends and accretion . . . .  $         -  $     904             -  $         -  $   2,927             -
                                         ===========  =========                ======================
</TABLE>


OTHER MATTERS

Effects of Inflation and Changes in Prices

     Our results of operations and cash flows are affected by changing oil and
gas prices. If the price of oil and natural gas increases (decreases), there
could be a corresponding increase (decrease) in revenues as well as the
operating costs that we are required to bear for operations. Inflation has had a
minimal effect on us.

Environmental and Other Regulatory Matters

     Our business is subject to certain federal, state and local laws and
regulations relating to the exploration for and the development, production and
marketing of oil and natural gas, as well as environmental and safety matters.
Many


                                       29
<PAGE>
of these laws and regulations have become more stringent in recent years,
often imposing greater liability on a larger number of potentially responsible
parties. Although we believe we are in substantial compliance with all
applicable laws and regulations, the requirements imposed by laws and
regulations are frequently changed and subject to interpretation, and we cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations. Any suspensions, terminations or inability to meet applicable
bonding requirements could materially adversely affect our financial condition
and operations. Although significant expenditures may be required to comply with
governmental laws and regulations applicable to us, compliance has not had a
material adverse effect on our earnings or competitive position.  Future
regulations may add to the cost of, or significantly limit, drilling activity.


New  Accounting  Pronouncements

     In September 2004, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin No. 106. This pronouncement will require companies
that use the full cost method for accounting for their oil and gas producing
activities to include an estimate of future asset retirement costs to be
incurred as a result of future development activities on proved reserves in
their calculation of depreciation, depletion and amortization. This
pronouncement will also require these companies to exclude any future cash
outflows associated with settling asset retirement liabilities from their full
cost ceiling test calculation. This standard will also require these companies
to disclose the impact of their asset retirement obligations on their oil and
gas producing activities, ceiling test calculations and depreciation, depletion
and amortization calculations. We will adopt the provisions of this
pronouncement in the fourth quarter of 2004 and are currently evaluating the
impact, if any, on our consolidated financial statements.

Risk Factors Related to Our Business

     -    Our level of indebtedness may adversely affect our cash available for
          operations, thus limiting our growth, our ability to make interest and
          principal payments on our indebtedness as they become due and our
          flexibility to respond to market changes.
     -    We have substantial capital requirements for which we may not be able
          to obtain adequate financing.
     -    Oil and natural gas prices fluctuate widely and low prices could have
          a material adverse impact on our business and financial results by
          limiting our liquidity and flexibility to accelerate our drilling
          program.
     -    Our hedging transactions could reduce revenues in a rising commodity
          price environment or expose us to other risks.
     -    Exploratory drilling is a speculative activity that may not result in
          commercially productive reserves and may require expenditures in
          excess of budgeted amounts.
     -    We are subject to various operating and other casualty risks that
          could result in liability exposure or the loss of production and
          revenues.
     -    We may not have enough insurance to cover all of the risks we face,
          which could result in significant financial exposure.
     -    We cannot control the activities on properties we do not operate and
          are unable to ensure their proper operation and profitability.
     -    The marketability of our natural gas production depends on facilities
          that we typically do not own or control, which could result in a
          curtailment of production and revenues.
     -    Lower oil and natural gas prices may cause us to record ceiling
          limitation write-downs which would reduce our stockholders' equity.
     -    We have had operating losses in the past and may not be profitable in
          the future.
     -    Our future operating results may fluctuate and significant declines in
          them would limit our ability to invest in projects.
     -    The failure to replace reserves in the future would adversely affect
          our production and cash flows.
     -    We are subject to uncertainties in reserve estimates and future net
          cash flows.
     -    We face significant competition, and many of our competitors have
          resources in excess of our available resources.


                                       30
<PAGE>
     -    We are subject to various governmental regulations and environmental
          risks which may cause us to incur substantial costs.
     -    Our business may suffer if we lose key personnel.

Disclosure Regarding Forward-Looking Statements

     Statements included in this report which are not historical facts
(including any statements concerning plans and objectives of management for
future operations or economic performance, or assumptions or forecasts related
thereto), are forward-looking statements. These statements can be identified by
the use of forward-looking terminology including "may," "believe," "will,"
"expect," "anticipate," "estimate," "continue" or other similar words. These
statements discuss future expectations, contain projections of results of
operations or of financial condition or state other "forward-looking"
information.

     These forward-looking statements are made based upon management's current
plans, expectations, estimates, assumptions and beliefs concerning future events
impacting us and therefore involve a number of risks and uncertainties. We
caution that forward-looking statements are not guarantees and that actual
results could differ materially from those expressed or implied in the
forward-looking statements.

     Because these forward-looking statements involve risks and uncertainties,
actual results could differ materially from those expressed or implied by these
forward-looking statements for a number of important reasons, including those
discussed under "Risk Factors Related to Our Business," and elsewhere in this
report.

     You should read these statements carefully because they discuss our
expectations about our future performance, contain projections of our future
operating results or our future financial condition, or state other
"forward-looking" information. You should be aware that the occurrence of any of
the events described in "Risk Factors Related to Our Business" and elsewhere in
this report could substantially harm our business, results of operations and
financial condition and that upon the occurrence of any of these events, the
trading price of our common shares could decline.


                                       31
<PAGE>
ITEM 3.     QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

     The following quantitative and qualitative disclosures about market risk
are supplementary to the quantitative and qualitative disclosures provided in
our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. As
such, the information contained herein should be read in conjunction with the
related disclosures in our Annual Report on Form 10-K for the fiscal year ended
December 31, 2003.

DERIVATIVE CONTRACTS

CASH-FLOW HEDGES

     Our cash-flow hedges consisted of fixed-price swaps and costless collars
(purchased put options and written call options). The fixed-price swap
agreements are used to fix the prices of anticipated future oil and natural gas
production. The costless collars are used to establish floor and ceiling prices
on anticipated future oil and natural gas production. There were no net premiums
received when we entered into these option agreements.

DERIVATIVES NOT DESIGNATED AS HEDGES

     Our derivative positions included option contracts that are not designated
as hedges. These positions were entered into to offset the cost of other option
positions that are designated as hedges.

<TABLE>
<CAPTION>
                                                  NOTIONAL AMOUNT
                                                --------------------    NYMEX
    SETTLEMENT      DERIVATIVE       HEDGE         GAS        OIL     REFERENCE
      PERIOD        INSTRUMENT      STRATEGY     (MMBTU)   (BARRELS)    PRICE
-----------------  -------------  ------------  ---------  ---------  ----------
<S>                <C>            <C>           <C>        <C>        <C>

10/01/04-12/31/04  Swap           Cash flow        92,000             $     4.36
10/01/04-12/31/04  Swap           Cash flow                    9,200       23.80

COSTLESS COLLARS

10/01/04-10/31/04  Purchased put  Cash flow        34,100             $     4.00
                   Written call   Cash flow        34,100                   6.83
10/01/04-10/31/04  Purchased put  Cash flow                    6,200       26.00
                   Written call   Cash flow                    6,200       33.50
10/01/04-12/31/04  Purchased put  Cash flow        92,000                   4.00
                   Written call   Cash flow        92,000                   5.62
10/01/04-12/31/04  Purchased put  Cash flow        92,000                   4.25
                   Written call   Cash flow        92,000                   5.51
10/01/04-12/31/04  Purchased put  Cash flow        46,000                   4.25
                   Written call   Cash flow        46,000                   6.05
10/01/04-12/31/04  Purchased put  Cash flow       322,000                   5.25
                   Written call   Cash flow       322,000                   7.41
10/01/04-12/31/04  Purchased put  Cash flow                    9,200       23.00
                   Written call   Cash flow                    9,200       25.39
10/01/04-12/31/04  Purchased put  Cash flow                    6,900       23.00
                   Written call   Cash flow                    6,900       27.30
10/01/04-12/31/04  Purchased put  Cash flow                   11,960       32.00
                   Written call   Cash flow                   11,960       38.15
01/01/05-03/31/05  Purchased put  Cash flow        90,000                   4.00
                   Written call   Cash flow        90,000                   7.25


                                       32
<PAGE>
                                                  NOTIONAL AMOUNT
                                                --------------------    NYMEX
    SETTLEMENT      DERIVATIVE       HEDGE         GAS        OIL     REFERENCE
      PERIOD        INSTRUMENT      STRATEGY     (MMBTU)   (BARRELS)    PRICE
-----------------  -------------  ------------  ---------  ---------  ----------
01/01/05-03/31/05  Purchased put  Cash flow        67,500                   4.25
                   Written call   Cash flow        67,500                   5.90
01/01/05-03/31/05  Purchased put  Cash flow        45,000                   4.25
                   Written call   Cash flow        45,500                   6.50
01/01/05-03/31/05  Purchased put  Cash flow                    9,000       23.00
                   Written call   Cash flow                    9,000       25.07
01/01/05-03/31/05  Purchased put  Cash flow                    6,750       23.00
                   Written call   Cash flow                    6,750       26.90
01/01/05-06/30/05  Purchased put  Cash flow       633,500                   5.00
                   Written call   Cash flow       633,500                   7.40
01/01/05-06/30/05  Purchased put  Cash flow                   23,530       29.00
                   Written call   Cash flow                   23,530       36.00
04/01/05-06/30/05  Purchased put  Cash flow        91,000                   4.00
                   Written call   Cash flow        91,000                   5.40

04/01/05-06/30/05  Purchased put  Cash flow        45,500                   4.25
                   Written call   Cash flow        45,500                   4.52
04/01/05-06/30/05  Purchased put  Cash flow                    6,825       23.00
                   Written call   Cash flow                    6,825       26.45

THREE WAY COSTLESS

11/01/04-3/31/05   Purchased put  Cash flow       350,000             $     6.40
                   Written call   Cash flow       350,000                   7.64
                   Written put    Undesignated    350,000                   5.50
</TABLE>


ITEM 4.     CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

     As of the end of period covered by this report, our principal executive
officer and principal financial officer carried out an evaluation of the
effectiveness of our disclosure controls and procedures. Based on their
evaluation, they have concluded that our disclosure controls and procedures
effectively ensure that the information required to be disclosed in the reports
we file with the SEC is recorded, processed, summarized and reported within the
time periods specified by the SEC.

CHANGES IN INTERNAL CONTROLS

     There were no changes in our internal controls or in other factors that
have materially affected, or are reasonably likely to materially affect, our
internal controls subsequent to the date of their evaluation of our disclosure
controls and procedures.


                                       33
<PAGE>
                           PART II - OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

     As discussed in Note 3 of Notes to the Consolidated Financial Statements
included in Part I. Financial Information, Brigham is party to various legal
actions arising in the ordinary course of business and does not expect these
matters to have a material adverse effect on its financial condition, results of
operations or cash flow.

ITEM 2.     UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

No purchases were made under a publicly announced plan.


ITEM 6.     EXHIBITS AND REPORTS ON FORM 8-K

<TABLE>
<CAPTION>
<C>   <S>
31.1  Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities
      Exchange Act of 1934

31.2  Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities
      Exchange Act of 1934

32.1  Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. Sec. 1350

32.2  Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. Sec. 1350
</TABLE>


                                       34
<PAGE>
                                   SIGNATURES


     Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized on November 9, 2004.

                                         BRIGHAM EXPLORATION COMPANY


                                         By:  /s/ BEN M. BRIGHAM
                                              ------------------
                                              Ben M. Brigham
                                              Chief Executive Officer, President
                                              and Chairman of the Board



                                         By:  /s/ EUGENE B. SHEPHERD, JR.
                                              ---------------------------
                                              Eugene B. Shepherd, Jr.
                                              Executive Vice President and
                                              Chief Financial Officer


                                       35
<PAGE>