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                                  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 March 31, 2005


                                       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)

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

      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 [_]    No [X]

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 as of May 3, 2005             42,489,396

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


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

                                     FIRST QUARTER 2005 FORM 10-Q REPORT

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


                                                                                                        PAGE
                                                                                                        ----
                                        PART I - FINANCIAL INFORMATION
<S>      <C>                                                                                            <C>
ITEM 1.  FINANCIAL STATEMENTS

         Consolidated Balance Sheets - March 31, 2005 and December 31, 2004 . . . . . . . . . . . . . .    1
         Consolidated Statements of Operations - Three months ended March 31, 2005 and 2004 . . . . . .    2
         Consolidated Statement of Changes in Stockholders' Equity - Three months ended March 31, 2005.    3
         Consolidated Statements of Cash Flows - Three months ended March 31, 2005 and 2004 . . . . . .    4
         Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . .    5

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

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . . . . . . . . . . . . . .   27

ITEM 4.  CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   28


                                         PART II - OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   29

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS. . . . . . . . . . . . . . . . . .   29

ITEM 3.  DEFALTS UPON SENIOR SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   29

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. . . . . . . . . . . . . . . . . . . . . .   29

ITEM 5.  OTHER INFORMATION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   29

ITEM 6.  EXHIBITS AND REPORTS OF FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   29

         SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .   31
</TABLE>


<PAGE>
PART I- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

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


                                                                                                     MARCH 31,      DECEMBER 31,
                                                                                                        2005            2004
                                                                                                   --------------  --------------
<S>                                                                                                <C>             <C>
                                                             ASSETS
Current assets:
  Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $       4,641   $       2,281
  Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         16,761          17,573
  Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .            449             239
  Other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .            673             901
                                                                                                   --------------  --------------
        Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         22,524          20,994
                                                                                                   --------------  --------------

Oil and natural gas properties, net (full cost method). . . . . . . . . . . . . . . . . . . . . .        279,424         261,979
Other property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          1,171           1,209
Deferred loan fees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          2,020           1,745
Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .            700             380
                                                                                                   --------------  --------------
        Total assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $     305,839   $     286,307
                                                                                                   ==============  ==============
                                              LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $      17,849   $      22,465
  Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          4,442           6,072
  Accrued drilling costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          9,152           6,099
  Participant advances received . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          2,684           3,633
  Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          3,389           2,225
                                                                                                   --------------  --------------
     Total current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         37,516          40,494
                                                                                                   --------------  --------------

Senior credit facility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         38,100          21,000
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, 485,379 and 475,986 shares issued and outstanding at March
  31, 2005 December 31, 2004, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . .          9,708           9,520
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         10,772           9,031
Other noncurrent liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          3,040           2,986

Commitments and contingencies (Note 4)

Stockholders' equity:
  Common stock, $.01 par value, 50 million shares authorized, 43,373,199 and 43,231,499
    shares issued and 42,154,822 and 42,034,351 shares outstanding at March 31, 2005 and
    December 31, 2004, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .            434             432
  Additional paid-in capital. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        176,266         175,270
  Treasury stock, at cost; 1,218,377 and 1,197,148 shares at March 31, 2005 and December 31,
    2004, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         (4,897)         (4,707)
  Unearned stock compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         (2,003)         (1,570)
  Accumulated other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .           (499)           (503)
  Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         17,402          14,354
                                                                                                   --------------  --------------
     Total stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        186,703         183,276
                                                                                                   --------------  --------------
       Total liabilities and stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . .  $     305,839   $     286,307
                                                                                                   ==============  ==============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


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

                                                              THREE MONTHS ENDED
                                                                   MARCH 31,
                                                          --------------------------
                                                              2005          2004
                                                          ------------  ------------
                                                                          RESTATED
<S>                                                       <C>           <C>
Revenues:
  Oil and natural gas sales. . . . . . . . . . . . . . .  $    16,703   $    16,819
  Other revenue. . . . . . . . . . . . . . . . . . . . .           43             1
                                                          ------------  ------------
                                                               16,746        16,820
                                                          ------------  ------------
Costs and expenses:
  Lease operating. . . . . . . . . . . . . . . . . . . .        2,218         1,409
  Production taxes . . . . . . . . . . . . . . . . . . .          802           863
  General and administrative . . . . . . . . . . . . . .        1,098         1,220
  Depletion of oil and natural gas properties. . . . . .        6,453         5,124
  Depreciation and amortization. . . . . . . . . . . . .          182           181
  Accretion of discount on asset retirement obligations.           39            37
                                                          ------------  ------------
                                                               10,792         8,834
                                                          ------------  ------------
        Operating income . . . . . . . . . . . . . . . .        5,954         7,986
                                                          ------------  ------------
Other income (expense):
  Interest income. . . . . . . . . . . . . . . . . . . .           39            14
  Interest expense, net. . . . . . . . . . . . . . . . .         (741)         (782)
  Other income (expense) . . . . . . . . . . . . . . . .         (531)          127
                                                          ------------  ------------
                                                               (1,233)         (641)
                                                          ------------  ------------
Income before income taxes . . . . . . . . . . . . . . .        4,721         7,345
                                                          ------------  ------------
Income tax expense:
  Current. . . . . . . . . . . . . . . . . . . . . . . .            -             -
  Deferred . . . . . . . . . . . . . . . . . . . . . . .       (1,673)       (2,420)
                                                          ------------  ------------
                                                               (1,673)       (2,420)
                                                          ------------  ------------

Net income . . . . . . . . . . . . . . . . . . . . . . .  $     3,048   $     4,925
                                                          ============  ============

Net income per share available to common stockholders:
  Basic. . . . . . . . . . . . . . . . . . . . . . . . .  $      0.07   $      0.13
                                                          ============  ============
  Diluted. . . . . . . . . . . . . . . . . . . . . . . .  $      0.07   $      0.12
                                                          ============  ============

Weighted average shares outstanding:
  Basic. . . . . . . . . . . . . . . . . . . . . . . . .       42,124        39,166
                                                          ============  ============
  Diluted. . . . . . . . . . . . . . . . . . . . . . . .       43,166        40,211
                                                          ============  ============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


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

                                                                                                               ACCUMULATED
                                       COMMON STOCK            ADDITIONAL                       UNEARNED          OTHER
                                ---------------------------     PAID IN         TREASURY         STOCK        COMPREHENSIVE
                                   SHARES        AMOUNTS        CAPITAL          STOCK        COMPENSATION    INCOME (LOSS)
                                ------------  -------------  --------------  --------------  --------------  ---------------
<S>                             <C>           <C>            <C>             <C>             <C>             <C>
Balance, December 31, 2004            43,231  $         432  $     175,270   $      (4,707)  $      (1,570)  $         (503)
Comprehensive income:
  Net income                               -              -              -               -               -                -
  Unrealized gain (losses)
    on cash flow hedges                    -              -              -               -               -             (609)
  Tax benefits related to
    cash flow hedges                       -              -              -               -               -               (3)
  Net losses included in net
    income                                 -              -              -               -               -              616

    Comprehensive income
Exercises of employee stock
  options                                 77              1            250               -               -                -
Vesting of restricted stock               65              1             (1)              -               -                -
Issuance of restricted stock               -              -            602               -            (602)               -
Tax benefit from the exercise
  of stock options                         -              -            145               -               -                -
Repurchases of common
  stock                                    -              -              -            (190)              -                -
Amortization of unearned
  stock compensation                       -              -              -               -             169                -
                                ------------  -------------  --------------  --------------  --------------  ---------------
Balance, March 31, 2005               43,373  $         434  $     176,266   $      (4,897)  $      (2,003)  $         (499)
                                ============  =============  ==============  ==============  ==============  ===============


                                                    TOTAL
                                  RETAINED      STOCKHOLDERS'
                                  EARNINGS         EQUITY
                                -------------  ---------------
<S>                             <C>            <C>
Balance, December 31, 2004      $      14,354  $      183,276
Comprehensive income:
  Net income                            3,048           3,048
  Unrealized gain (losses)
    on cash flow hedges                     -            (609)
  Tax benefits related to
    cash flow hedges                        -              (3)
  Net losses included in net
    income                                  -             616
                                               ---------------
    Comprehensive income                                3,052
Exercises of employee stock
  options                                   -             251
Vesting of restricted stock                 -               -
Issuance of restricted stock                -               -
Tax benefit from the exercise
  of stock options                          -             145
Repurchases of common
  stock                                     -            (190)
Amortization of unearned
  stock compensation                        -             169
                                -------------  ---------------
Balance, March 31, 2005         $      17,402  $      186,703
                                =============  ===============
</TABLE>

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


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

                                                                                                THREE MONTHS ENDED
                                                                                                     MARCH 31,
                                                                                             --------------------------
                                                                                                 2005          2004
                                                                                             ------------  ------------
                                                                                                           RESTATED(1)
<S>                                                                                          <C>           <C>
Cash flows from operating activities:
  Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $     3,048   $     4,925
  Adjustments to reconcile net income to cash provided by operating activities:
        Depletion of oil and natural gas properties . . . . . . . . . . . . . . . . . . . .        6,453         5,124
        Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .          182           181
        Interest paid through issuance of additional mandatorily redeemable preferred stock          188           175
        Amortization of deferred loan fees and debt issuance costs. . . . . . . . . . . . .          126           192
        Market value adjustment for derivative instruments. . . . . . . . . . . . . . . . .          606          (127)
        Accretion of discount on asset retirement obligations . . . . . . . . . . . . . . .           39            37
        Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        1,673         2,420
        Other noncash items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           12             -
        Changes in assets and liabilities:
          Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          812        (2,672)
          Other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .           85         2,704
          Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       (4,616)       (2,570)
          Royalties payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       (1,630)          843
          Participant advances received . . . . . . . . . . . . . . . . . . . . . . . . . .         (949)         (557)
          Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .          226        (2,017)
          Other noncurrent assets and liabilities . . . . . . . . . . . . . . . . . . . . .          (11)          (64)
                                                                                             ------------  ------------
            Net cash provided by operating activities . . . . . . . . . . . . . . . . . . .        6,244         8,594
                                                                                             ------------  ------------
Cash flows from investing activities:
  Additions to oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . .      (20,738)      (17,135)
  Additions to other property and equipment . . . . . . . . . . . . . . . . . . . . . . . .          (65)         (129)
  (Increase) Decrease in drilling advances paid . . . . . . . . . . . . . . . . . . . . . .          159           207
                                                                                             ------------  ------------
            Net cash used by investing activities . . . . . . . . . . . . . . . . . . . . .      (20,644)      (17,057)
                                                                                             ------------  ------------
Cash flows from financing activities:
  Increase in senior credit facility. . . . . . . . . . . . . . . . . . . . . . . . . . . .       17,100        10,200
  Deferred loan fees paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         (401)          (11)
  Proceeds from exercise of employee stock options. . . . . . . . . . . . . . . . . . . . .          251           310
  Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         (190)         (156)
                                                                                             ------------  ------------
            Net cash provided by financing activities . . . . . . . . . . . . . . . . . . .       16,760        10,343
                                                                                             ------------  ------------
Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . .        2,360         1,880
Cash and cash equivalents, beginning of year. . . . . . . . . . . . . . . . . . . . . . . .        2,281         5,779
                                                                                             ------------  ------------
Cash and cash equivalents, end of period. . . . . . . . . . . . . . . . . . . . . . . . . .  $     4,641   $     7,659
                                                                                             ============  ============
</TABLE>

(1)  Only individual line items in cash flows from operating activities have
     been restated. Total cash flows from operating, investing and financing
     activities were unaffected.

    The accompanying notes are an integral part of these consolidated financial
                                   statements.


                                        4
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


1.   ORGANIZATION  AND  NATURE  OF  OPERATIONS

     Brigham Exploration Company is a Delaware corporation formed on February
25, 1997 for the purpose of exchanging its common stock for the common stock of
Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the
"Partnership"). Hereinafter, Brigham Exploration Company and the Partnership are
collectively referred to as "Brigham." Brigham, Inc. is a Nevada corporation
whose only asset is its ownership interest in the Partnership. The Partnership
was formed in May 1992 to explore and develop onshore domestic oil and natural
gas properties using 3-D seismic imaging and other advanced technologies. Since
its inception, the Partnership has focused its exploration and development of
oil and natural gas properties primarily in the onshore Texas Gulf Coast, the
Anadarko Basin and West Texas.

2.   BASIS  OF  PRESENTATION

     The  accompanying  unaudited  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 limited partnerships
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
unaudited consolidated financial statements are presented in accordance with the
requirements of Form 10-Q and do not include all disclosures normally required
by accounting principles generally accepted in the United States of America.
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
2004 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 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).


                                        5
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


     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
(loss) and net income (loss) per share for the three month periods ended March
31, 2005 and 2004 would have been the pro forma amounts indicated below:

<TABLE>
<CAPTION>
                                                                        THREE MONTHS ENDED
                                                                              MARCH 31,
                                                                   -----------------------------
                                                                         2005           2004
                                                                   --------------  -------------
                                                                       (In thousands, except
                                                                          per share amounts)
<S>                                                                 <C>            <C>
Net income, as reported (as restated for 2004) . . . . . . . . . .  $      3,048   $      4,925
  Add back: Stock compensation expense previously included in net
    income . . . . . . . . . . . . . . . . . . . . . . . . . . . .           111            121
  Effect of total employee stock-based compensation expense,
    determined under fair value method for all awards. . . . . . .          (361)          (345)
                                                                   --------------  -------------
  Pro forma. . . . . . . . . . . . . . . . . . . . . . . . . . . .  $      2,798   $      4,701
                                                                    =============  =============

Net income per share:
  Basic, as reported . . . . . . . . . . . . . . . . . . . . . . .  $       0.07   $       0.13
  Basic, pro forma . . . . . . . . . . . . . . . . . . . . . . . .          0.07           0.12

     Diluted, as reported. . . . . . . . . . . . . . . . . . . . .  $       0.07   $       0.12
     Diluted, pro forma. . . . . . . . . . . . . . . . . . . . . .          0.06           0.12
</TABLE>

3.   RESTATEMENT

     Brigham utilizes the full cost method of accounting for its proved oil and
natural gas properties included in the consolidated financial statements. During
March 2005, in conjunction with preparation of the financial statements for the
year ended December 31, 2004, management evaluated the manner in which Brigham
historically accounted for depletion expense associated with our oil and natural
gas properties. Historically, Brigham had calculated a depletion rate at the end
of each period within the year based on its updated reserve estimate. This
depletion rate had then been retroactively applied to year-to-date production
with the adjustment to previously recorded depletion expense recorded in the
current quarter. Brigham determined that the revised depletion rate should have
been applied on a prospective basis to production in the most current quarterly
period only.  As a result, depletion of oil and natural gas properties for the
three months ending March 31, 2004, has been restated.

     The information in the quarterly financial statement information below
represents only those consolidated statements of operations line items affected
by the restatement (in thousands).

<TABLE>
<CAPTION>
                                                                      THREE MONTHS ENDED
                                                                         MARCH 31, 2004
                                                                  ----------------------------
                                                                   AS REPORTED     RESTATED
                                                                  -------------  -------------
<S>                                                               <C>            <C>
Consolidated Statements of Operations:
  Depletion of oil and natural gas properties. . . . . . . . . .  $      4,880   $      5,124
  Deferred income tax benefit (expense). . . . . . . . . . . . .        (2,500)        (2,420)
  Net income (loss) available to common stockholders . . . . . .         5,089          4,925
  Net income (loss) per share available to common stockholders:
    Basic. . . . . . . . . . . . . . . . . . . . . . . . . . . .  $       0.13   $       0.13
                                                                  =============  =============
    Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . .  $       0.13   $       0.12
                                                                  =============  =============
</TABLE>


                                        6
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


4.   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. The Petition claimed
Massey furnished defective casing to Brigham, which ultimately led to the casing
failure of its 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. The
amount of the settlement reduced capitalized well cost. In addition, Massey
agreed to drop its $445,819 counterclaim.

     On October 8, 2002, relatives of a contractor's employee filed a wrongful
death action against Brigham and three other contractors in the District Court
of Matagorda County, Texas in connection with the employee's death on Brigham's
Burkhart #1-R location. On March 23, 2004, a jury determined that Brigham had no
liability in the accidental death of the contractor's employee. The trial judge,
however, granted plaintiffs' motion for a new trial. Brigham expects the new
trial to take place in June 2005. Brigham believes it has adequate insurance to
cover any potential damage award (subject to a $5,000 deductible). At this point
in time, Brigham cannot predict the outcome of this case.

     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, claiming that contractor breached its contract with
Brigham and negligently performed services on the well. Brigham believes the
contractor's actions damaged Brigham by approximately $650,000. The contractor
counterclaimed, claiming it is entitled to recover approximately $315,000. In
April 2004, the parties settled the case, resulting in a payment by the
contractor to its co-participants and Brigham of $325,000. In addition, the
contractor dropped its counterclaim. Based on the amount of the settlement, the
additional costs that were covered by insurance, and the insurer being
subrogated to Brigham's claim, Brigham did not receive any incremental recovery
as a result of the settlement.

     Prior to drilling, the operator of the Stonehocker #1 well disputed
Brigham's ownership in the well. In March 2003, a Motion to Determine Election
was filed with the Oklahoma Corporation Commission. In January 2004, an
Administrative Law Judge with the Oklahoma Corporation Commission ruled in
Brigham's favor. The operator of the Stonehocker #1 appealed the ruling and the
Appellate Referee with the Oklahoma Corporation Commission affirmed the original
ruling in March 2004. The full Commission Panel reviewed the reports of the
Referee and the original Administrative Law Judge and affirmed those rulings.
The operator then filed an appeal with the Oklahoma Supreme Court. In January
2005, the parties settled the dispute. The operator agreed to recognize
Brigham's full interest in the Stonehocker well, and also agreed to reverse
certain charges made under the operating agreements of six additional wells in
which Brigham owns an interest.

     A company 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, this company filed a
lawsuit in the District Court of Brazoria County, Texas, against Brigham for
breach of contract. If the suit was successful, it could have resulted in a
judgment of as much as $700,000. In April 2004, Brigham settled the case,
agreeing to pay the company $350,000 in return for the company's assignment of
all its right, title and interest in the unit for the 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


                                        7
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


asserted a counterclaim against Brigham for alleged tortuous interference with
an existing business relationship between the company and its employee. In April
2004, Brigham settled the case. The company agreed not to compete against
Brigham in a specified area for two years, assigned Brigham a small overriding
royalty in three tracts, paid Brigham $50,000, and dropped its counterclaim.

     As of March 31, 2005, there are no known environmental or other regulatory
matters related to Brigham's operations that are reasonably expected to result
in a material liability to Brigham. Compliance with environmental laws and
regulations has not had, and is not expected to have, a material adverse effect
on Brigham's financial position, results of operations or cash flows.

5.   EARNINGS PER COMMON SHARE

     Basic earnings per share (EPS) is computed by dividing net income (the
numerator) by the weighted average number of common shares outstanding for the
period (the denominator). Diluted EPS is computed by dividing net income by the
weighted average number of common shares and potential common shares outstanding
(if dilutive) during each period.   Potential common shares include stock
options and restricted stock.  The number of potential common shares outstanding
relating to stock options and restricted stock is computed using the treasury
stock method.

     The  reconciliation  of  the  denominators  used to calculate basic EPS and
diluted  EPS  for  the three months ended March 31, 2005 and 2004 are as follows
(in  thousands):

<TABLE>
<CAPTION>
                                                                            THREE MONTHS ENDED
                                                                                 MARCH 31,
                                                                         ------------------------
                                                                            2005         2004
                                                                         -----------  -----------
<S>                                                                      <C>          <C>
Weighted average common shares outstanding - basic. . . . . . . . . . .       42,124       39,166
Plus:  Potential common shares
  Stock options and restricted stock. . . . . . . . . . . . . . . . . .        1,042        1,045
                                                                         -----------  -----------

Weighted average common shares outstanding - diluted. . . . . . . . . .       43,166       40,211
                                                                         ===========  ===========

Stock options excluded from diluted EPS due to the anti-dilutive effect      717,500       61,000
                                                                         ===========  ===========
</TABLE>

6.   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.


                                        8
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


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 month periods ended March 31, 2005 and 2004:

<TABLE>
<CAPTION>
                                                                 THREE MONTHS ENDED MARCH 31,
                                                                 ----------------------------
                                                                     2005           2004
                                                                 -------------  -------------
<S>                                                              <C>            <C>
NATURAL GAS
  Average price per Mcf as reported (including hedging results)  $       5.80   $       5.69
  Average price per Mcf realized (excluding hedging results). .  $       5.80   $       5.79
  Increase (decrease) in revenue (in thousands) . . . . . . . .  $        (10)  $       (216)
OIL
  Average price per Bbl as reported (including hedging results)  $      43.74   $      30.84
  Average price per Bbl realized (excluding hedging results). .  $      48.33   $      34.01
  Increase (decrease) in revenue (in thousands) . . . . . . . .  $       (541)  $       (505)
</TABLE>

     Ineffectiveness associated with Brigham's derivative commodity instruments
designated as cash flow hedges is included in other income (expense).  The
following table provides a summary of the impact on earnings from
ineffectiveness (in  thousands):

<TABLE>
<CAPTION>
                                                         THREE MONTHS ENDED MARCH 31,
                                                          ---------------------------
                                                              2005           2004
                                                          -------------  ------------
<S>                                                       <C>            <C>
  Increase (decrease) in earnings due to ineffectiveness  $       (616)  $        127
</TABLE>

NATURAL GAS AND CRUDE OIL DERIVATIVE CONTRACTS

CASH-FLOW HEDGES

     Brigham's cash-flow hedges consisted of costless collars (purchased put
options and written call options).  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.

     Derivative positions included written put options that are not designated
as hedges and are reflected at fair value on the balance sheet. These positions
were entered into in conjunction with a costless collar to offset the cost of
other option positions that are designated as hedges.  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 (expense).  At March 31, 2005 and 2004, the fair value of these
derivatives included in other current liabilities was approximately $23,000 and
$0, respectively.  For the three months ended March 31, 2005, and 2004, other
income (expense) included approximately $10,000 and $0, respectively, in
non-cash gains related to changes in the fair values of these derivative
contracts.


                                        9
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


The following table reflects open commodity derivative contracts at March 31,
2005, the associated volumes and the corresponding weighted average NYMEX
reference price.

<TABLE>
<CAPTION>
                                                                     NOTIONAL AMOUNT
                                                                     ---------------
                                                                                                   NYMEX
                              DERIVATIVE                          GAS              OIL           REFERENCE
SETTLEMENT PERIOD             INSTRUMENT    HEDGE STRATEGY      (MMBTU)         (BARRELS)          PRICE
--------------------------  --------------  --------------  ---------------  ---------------  ---------------
<S>                         <C>             <C>             <C>              <C>              <C>
COSTLESS COLLARS
  04/01/05 - 06/30/05. . .  Purchased put   Cash flow               318,500                   $          5.00
                            Written call    Cash flow               318.500                              7.40
  04/01/05 - 06/30/05. . .  Purchased put   Cash flow                                 11,830  $         29.00
                            Written call    Cash flow                                 11,830            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
  04/01/05 - 10/31/05. . .  Purchased put   Cash flow               420,000                   $          5.45
                            Written call    Cash flow               420,000                              8.00
THREE WAY COSTLESS COLLARS
  07/01/05 - 10/31/05. . .  Purchased put   Cash flow               400,000                   $          6.00
                            Written call    Cash flow               400,000                              7.20
                            Written put     Undesignated            400,000                              5.00
  07/01/05 - 12/31/05. . .  Purchased put   Cash flow                                 30,000  $         40.00
                            Written call    Cash flow                                 30,000            53.00
                            Written put     Undesignated                              30,000            30.00
  11/01/05 - 03/31/06. . .  Purchased put   Cash flow               250,000                   $          6.75
                            Written call    Cash flow               250,000                              8.80
                            Written put     Undesignated            250,000                              5.50
</TABLE>

     The following table reflects commodity derivative contracts entered
subsequent to March 31, 2005, the associated volumes and the corresponding
weighted average NYMEX reference price.

<TABLE>
<CAPTION>
                                                                     NOTIONAL AMOUNT
                                                                     ---------------
                                                                                                   NYMEX
                              DERIVATIVE                          GAS              OIL           REFERENCE
SETTLEMENT PERIOD             INSTRUMENT    HEDGE STRATEGY      (MMBTU)         (BARRELS)          PRICE
--------------------------  --------------  --------------  ---------------  ---------------  ---------------
<S>                         <C>             <C>             <C>              <C>              <C>
THREE WAY COSTLESS COLLARS
  06/01/05 - 03/31/06. . .  Purchased put   Cash flow                                 60,000  $         48.00
                            Written call    Cash flow                                 60,000            60.70
                            Written put     Undesignated                              60,000            38.00
  07/01/05 - 10/31/05. . .  Purchased put   Cash flow               240,000                   $          7.00
                            Written call    Cash flow               240,000                              7.76
                            Written put     Undesignated            240,000                              5.75
  11/01/05 - 03/31/06. . .  Purchased put   Cash flow               350,000                   $          8.00
                            Written call    Cash flow               350,000                              9.75
                            Written put     Undesignated            350,000                              6.50
</TABLE>

     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


                                       10
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


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 cash flow hedges 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 March 31, 2005, Brigham had an interest rate swap contract to pay a
fixed-rate of interest of 7.61% 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 March 31, 2005, approximately $481,000 of
unrealized gains are included in accumulated other comprehensive income (loss)
on the balance sheet which represents the fair value of the interest rate swap
agreement as of that date. 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.

     The fair value of 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 subsequent year (in thousands).

<TABLE>
<CAPTION>
                                                  MARCH 31,
                                          ------------------------
                                             2005         2004
                                          -----------  -----------
<S>                                       <C>          <C>
Other current liabilities. . . . . . . .  $   (1,808)  $   (3,111)
Other noncurrent liabilities . . . . . .           -         (374)
Other noncurrent assets. . . . . . . . .         482            3
                                          -----------  -----------
  Net fair value of derivative contracts  $   (1,326)  $   (3,482)
                                          ===========  ===========
</TABLE>

7.   ASSET RETIREMENT OBLIGATIONS

     Brigham has asset retirement obligations associated with the future
plugging and abandonment of proved properties and related facilities.  The fair
value of a liability for an asset retirement obligation is recorded 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 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 months ended March 31, 2005 and 2004 (in thousands):

<TABLE>
<CAPTION>
                                                             THREE MONTHS ENDED
                                                                   MARCH 31,
                                                         ---------------------------
                                                             2005          2004
                                                         ------------  -------------
<S>                                                      <C>           <C>
Beginning asset retirement obligations. . . . . . . . .  $      2,896  $      2,320
Liabilities incurred for new wells placed on production            26           101
Liabilities settled . . . . . . . . . . . . . . . . . .             -           (36)
Accretion of discount on asset retirement obligations .            39            37
                                                         ------------  -------------
                                                         $      2,961  $      2,422
                                                         ============  =============
</TABLE>


                                       11
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


8.   INCOME TAXES

     Realization of deferred tax assets associated with (i) net operating loss
carryforwards ("NOLs") and (ii) existing temporary differences between book and
taxable income is dependent upon generating sufficient taxable income within the
carryforward period available under tax law.  Management 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 (in thousands):

<TABLE>
<CAPTION>
                                                     MARCH 31,     DECEMBER 31,
                                                       2005            2004
                                                   -------------  --------------
<S>                                                <C>            <C>
Deferred tax assets
  Current:
     Unrealized hedging losses. . . . . . . . . .  $        268   $         271
     Derivative assets. . . . . . . . . . . . . .           196              11
                                                   -------------  --------------
        Current . . . . . . . . . . . . . . . . .           464             282
                                                   -------------  --------------

  Non-current:
     Net operating loss carryforwards . . . . . .        38,600          36,743
     Capital loss carryforwards . . . . . . . . .           634             634
     Stock compensation . . . . . . . . . . . . .           761             816
     Asset retirement obligations . . . . . . . .         1,036           1,014
     Other. . . . . . . . . . . . . . . . . . . .            31              31
                                                   -------------  --------------
        Gross non-current . . . . . . . . . . . .        41,062          39,238
        Valuation allowance . . . . . . . . . . .          (634)           (634)
                                                   -------------  --------------
           Non-current. . . . . . . . . . . . . .        40,428          38,604
                                                   -------------  --------------
              Gross deferred tax assets . . . . .        40,892          38,886
                                                   -------------  --------------

Deferred tax liabilities
  Current:
     Derivative liabilities . . . . . . . . . . .             -             (28)
     Gas imbalances . . . . . . . . . . . . . . .           (15)            (15)
                                                   -------------  --------------
        Current . . . . . . . . . . . . . . . . .           (15)            (43)
                                                   -------------  --------------

  Non-current:
     Depreciable and depletable property. . . . .       (51,163)        (47,635)
        Other . . . . . . . . . . . . . . . . . .           (37)              -
                                                   -------------  --------------
        Non-current . . . . . . . . . . . . . . .       (51,200)        (47,635)
                                                   -------------  --------------
           Gross deferred tax liabilities . . . .       (51,215)        (47,678)
                                                   -------------  --------------
Total deferred tax asset (liability). . . . . . .  $    (10,323)  $      (8,792)
                                                   =============  ==============

Reflected in the accompanying balance sheets as:
  Current deferred income tax asset . . . . . . .  $        449   $         239
  Non-current deferred income tax liability . . .       (10,772)         (9,031)
                                                   -------------  --------------
                                                   $    (10,323)  $      (8,792)
                                                   =============  ==============
</TABLE>

     At March 31, 2005, Brigham has regular tax NOLs of approximately $110.3
million and has approximately $96.6 million of alternative minimum tax ("AMT")
NOLs available as a deduction against future taxable income. The NOLs expire
from 2012 through 2025. The value of these NOLs depends on the ability of
Brigham to generate taxable income.

     In addition, at March 31, 2005, Brigham has capital loss carryforwards of
approximately $1.8 million that expire in varying years through 2007.


                                       12
<PAGE>
                          BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)


     Brigham believes an Internal Revenue Code Sec. 382 ownership change may
have occurred in March 2001, as a result of a potential 50% change in ownership
among its 5% shareholders over a three-year period. The minimum amount of the
limitation approximates $5.2 million annually, which can be increased by
recognized Built-in-Gains over five years following the ownership change.
Management believes that the limitation will not have a material impact on the
utilization of its NOL's.

9.   ACCOUNTING PRONOUNCEMENTS

     In December 2004, the Financial Accounting Standards Board (FASB) issued
SFAS No. 123R, "Share-Based Payment" (SFAS 123R), which is a revision of SFAS
123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based
payments to employees, including grants of employee stock options, to be valued
at fair value on the date of grant, and to be expensed over the applicable
vesting period. Pro forma disclosure of the income statement effects of
share-based payments is no longer an alternative.  In addition, companies must
also recognize compensation expense related to any awards that are not fully
vested as of the effective date. Compensation expense for the unvested awards
will be measured based on the fair value of the awards previously calculated in
developing the pro forma disclosures in accordance with the provisions of SFAS
123. The effective date of SFAS 123R is the first reporting period beginning
after June 15, 2005, which is the third quarter 2005 for calendar year
companies, although early adoption is allowed.  However, on April 14, 2005, the
Securities and Exchange Commission (SEC) announced that the effective date of
SFAS 123R will be suspended until January 1, 2006, for calendar year companies.
Brigham is currently assessing the impact of adopting SFAS 123R to its
consolidated financial statements.

     In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations" (FIN 47), which clarifies the impact
that uncertainty surrounding the timing or method of settling an obligation
should have on accounting for that obligation under SFAS No. 143.  FIN 47 is
effective no later than the end of the fiscal year ending after December 15,
2005, or December 31, 2005 for calendar year companies.  Brigham does not expect
the adoption of FIN 47 to have a material impact on its consolidated financial
statements.

     In September 2004, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin 106 (SAB 106) which provides guidance regarding the
interaction of SFAS 143 with the calculation of depletion and the full cost
ceiling test of oil and gas properties under the full cost accounting rules of
the SEC. The adoption of SAB 106 did not have a material effect on Brigham's
consolidated financial position, results of operations or cash flows.


                                       13
<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 2004 Annual Report on Form 10-K, and analyzes the changes in the results of
operations between the three month period ended March 31, 2005, and the
comparable period of 2004. For definitions of commonly used gas and oil terms as
used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms"
provided in our 2004 Annual Report on Form 10-K.

OVERVIEW OF FIRST QUARTER 2005

     The price of natural gas during the first quarter 2005 remained relatively
high to historical prices due to forecasts for continued production declines,
increasing natural gas demand and similarly high crude oil prices, which limits
fuel-switching flexibility.  The average sales price that we received for our
natural gas sales in the first quarter 2005 was $5.80 per Mcf.  The price of oil
also remained high relative to historical prices during the first quarter 2005.
The average sales price that we received for oil in the first quarter of 2005
was $48.33.

     For the quarter ended March 31, 2005, we spent $23.9 million in net capital
expenditures for oil and natural gas activities.  Our production for the first
quarter 2005 was 30 MMcfe/d compared to 33.9 MMcfe/d in the first quarter last
year.  The decrease in production is primarily due to natural decline of
existing production and the lack of significant wells reaching total depth and
coming on line during the quarter to materially contribute to production.

     Net income for the first quarter 2005 was $3 million, or $0.07 per diluted
share, on total revenues of $16.7 million.  This compares to reported net income
of $4.9 million, or $0.12 per diluted share on revenue of $16.8 million in the
first quarter last year.  The decrease in net income was primarily due to a
decrease in production combined with increases in our costs for production,
depletion and a non-cash loss related to the ineffective portion of our cash
flow hedges.  Net cash provided by operating activities, after a $6.1 million
reduction of changes in our working capital and other items, funded
approximately 30% of our capital expenditures.  We borrowed an additional $17.1
million under our senior credit facility to fund the increase in capital
expenditures.

     At March 31, 2005, we had $4.6 million in cash, total assets of $305.8
million and a debt to capitalization ratio of 27%.


                                       14
<PAGE>
CAPITAL COMMITMENTS

   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. Our capital expenditure program includes
the following:

     -    cost of acquiring and maintaining our lease acreage position and
          our seismic resources;
     -    cost of drilling and completing new oil and natural gas wells;
     -    cost of installing new production infrastructure;
     -    cost of maintaining, repairing and enhancing existing oil and
          natural gas wells;
     -    cost related to plugging and abandoning unproductive or
          uneconomic wells; and,
     -    indirect costs related to our exploration activities, including
          payroll and other expenses attributable our exploration professional
          staff.

     The table below summarizes our budgeted capital expenditures, the amount
spent through March 31, 2005 and the amount of our 2005 budget that remains to
be spent.

<TABLE>
<CAPTION>
                                                  AMOUNT
                                              SPENT THROUGH       AMOUNT
                               2005 BUDGET      03/31/2005     REMAINING (1)
                              --------------  --------------  --------------
                                              (IN THOUSANDS)
<S>                           <C>             <C>             <C>
Drilling . . . . . . . . . .  $       70,308  $       17,458  $       52,850
Net land and seismic . . . .          13,065           4,815           8,250
Capitalized interest and G&A           6,184           1,601           4,583
Asset retirement obligation.               -              26               -
Other assets . . . . . . . .             615              65             550
                              --------------  --------------  --------------
Total. . . . . . . . . . . .  $       90,172  $       23,965  $       66,233
                              ==============  ==============  ==============
</TABLE>

------------

(1)  Calculated as the amount budgeted for 2005 less amount spent through
     March 31, 2005.

     The capital that funds our drilling activities is allocated to individual
prospects based on the value potential of a prospect, as measured by a risked
net present value analysis. We start each year with a budget and reevaluate this
budget monthly. The primary factors that impact this value creation measure
include forecasted commodity prices, drilling and completion costs, and a
prospect's risked reserve size and risked initial producing rate. Other factors
that are also monitored throughout the year that influence the amount and timing
of all our budgeted expenditures include the level of production from our
existing oil and natural gas properties, the availability of drilling and
completion services, and the success and resulting production of our newly
drilled wells. The outcome of our monthly analysis results in a reprioritization
of our exploration and development well drilling schedule to ensure that we are
optimizing our capital expenditure plan.

     For 2005, we currently plan to spend approximately $34.7 million, or 38% of
our total budgeted capital expenditures to drill 17 exploratory wells and to
drill and complete wells that were in progress at December 31, 2004. We believe
that we possess a multi-year inventory of exploratory drilling prospects, the
majority of which have been internally generated by our staff. As a consequence
and considering the results that we have achieved in recent years, we expect
that we will continue to emphasize our prospect generation and drilling strategy
as our primary means of creating value for our stockholders.

     Due to our exploratory drilling success, over the last five years, a
growing percentage of our capital expenditures have been allocated to the
development of past field discoveries. For 2005, we currently plan to spend
approximately $35.6 million, or 39% of our total budgeted capital expenditures
on development activities, which include the drilling of 20 development wells.
We currently plan to allocate approximately $26.5 million of this capital to
develop our proved undeveloped reserves at December 31, 2004.

     For 2005, we expect to spend approximately $13.1 million or 14% of our
total capital expenditures on land and seismic activities.


                                       15
<PAGE>
     Additionally, we currently plan to capitalize approximately $6.2 million of
our forecasted total general and administrative cost and forecasted interest in
2005.

     The final determination with respect to our 2005 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.

     Statements in this section include forward-looking statements. See "-
Forward-Looking Statements."

   SENIOR CREDIT FACILITY

     As of March 31, 2005, we had $38.1 million in borrowings outstanding under
our senior credit facility.  During the first quarter of 2005 we borrowed an
additional $17.1 million of additional debt under our senior credit facility.
During the first quarter 2005, we utilized approximately 47% of our available
borrowing base, compared to 38% in the first quarter last year.  Borrowings
outstanding under our senior credit facility at April 28, 2005, were $43.6
million.

     Pursuant to our senior credit agreement, we are required to maintain a
current ratio of at least 1 to 1 and an interest coverage ratio for the four
most recent quarters of at least 3 to 1. Our current ratio at March 31, 2005 and
interest coverage ratio for the twelve-month period ending March 31, 2005, were
1.6 to 1 and 18.4 to 1, respectively. As of March 31, 2005, and for the
twelve-month period then ended, we were in compliance with all covenant
requirements in connection with our senior credit facility.

   SENIOR SUBORDINATED NOTES

     As of March 31, 2005, we had $20 million of senior subordinated notes
outstanding. Pursuant to our subordinated note agreement, we are required to
maintain a current ratio of at least 1 to 1, an interest coverage ratio for the
four most recent quarters of at least 3 to 1 and a Total Calculated NPV to Total
Debt Ratio of 1.5 to 1. Our current ratio at March 31, 2005, interest coverage
ratio for the twelve-month period ending March 31, 2005, and Total Calculated
NPV to Total Debt Ratio were 1.6 to 1, 18.4 to 1 and 3.4 to 1, respectively. At
March 31, 2005, and for the twelve-month period then ended, we were in
compliance with all covenant requirements in connection with our senior
subordinated notes.

   MANDATORILY REDEEMABLE PREFERRED STOCK

     As of March 31, 2005, we had $9.7 million in mandatorily redeemable Series
A preferred stock outstanding, which is held by merchant banking funds managed
by affiliates of CSFB Private Equity. During the first quarter of 2005 we issued
9,393 shares of additional shares of preferred stock to satisfy our first
quarter 2005 dividend requirements.  Brigham's ability to pay the mandatorily
redeemable Series A preferred stock dividends by issuing additional shares of
preferred stock expires on October 31, 2005.

CAPITAL RESOURCES

     We intend to fund our remaining 2005 capital expenditure program and
contractual commitments through cash flows from operations, borrowings under our
senior credit facility and, if required, alternative financing sources. Our
primary sources of cash during the first quarter 2005 were net cash provided by
operations and additional


                                       16
<PAGE>
borrowings under our senior credit facility.  We made aggregate cash payments of
$691,000 for interest in the first quarter of 2005.

   NET CASH PROVIDED BY OPERATING ACTIVITIES

     Net cash provided by operating activities is a function of the prices that
we receive from the sale of oil and natural gas, which are inherently volatile
and unpredictable, gains or losses related to the settlement of derivative
contracts, production, operating cost and our cost of capital. Our asset base,
as with other extractive industries, is a depleting one in which each Mcf of
natural gas or barrel of oil produced must be replaced or our ability to
generate cash flow, and thus sustain our exploration and development activities,
will diminish. Net cash provided by operating activities during the first
quarter 2005, after a $6.1 million reduction of changes in our working capital
and other items, funded 30% of our net cash used by investing activities
compared to 50% in the first quarter of 2004.

   SENIOR CREDIT FACILITY

     As of March 31, 2005, the unused committed borrowing capacity available
under our senior credit facility was $30.4 million. During the first quarter of
2005, our borrowing base for our senior credit facility was redetermined.
Effective May 2, 2005, our borrowing base increased from $68.5 million to $72
million.

     The future amounts of debt that we borrow under our senior credit facility
is dependent primarily on net cash provided by operating activities, proceeds
from other financing activities and proceeds generated from asset dispositions.
We strive to manage the borrowings outstanding under our senior credit facility
in order to maintain excess borrowing capacity.

   ACCESS TO CAPITAL MARKETS

     We currently have an effective universal shelf registration statement
covering the sale, from time to time, of our common stock, preferred stock,
depositary shares, warrants and debt securities, or a combination of any of
these securities. In July 2004, we sold 2,598,500 shares of our common stock
under the universal shelf registration statement. Following this sale, our
remaining capacity under the shelf registration statement is approximately
$176.9 million. However, our ability to raise additional capital using our shelf
registration statement may be limited due to overall conditions of the stock
market or the oil and natural gas industry.


                                       17
<PAGE>
RESULTS OF OPERATIONS

Comparison of the three-month periods ended March 31, 2005 and 2004

   PRODUCTION VOLUMES

<TABLE>
<CAPTION>
                                              THREE MONTHS ENDED MARCH 31,
                                    -----------------------------------------------
                                         2005           % CHANGE           2004
                                    --------------  ---------------  --------------
<S>                                 <C>             <C>              <C>
Oil (MBbls). . . . . . . . . . . .             118            (26%)             160
Natural gas (MMcf) . . . . . . . .           1,994             (5%)           2,093
Total (MMcfe)(1) . . . . . . . . .           2,700            (11%)           3,050
Average daily production (MMcfe/d)            30.0                             33.9
</TABLE>

------------

(1)  Mcfe is defined one million cubic feet equivalent of natural gas,
     determined using the ratio of six Mcf of natural gas to one Bbl of crude
     oil, condensate or natural gas liquids.

     Our net equivalent production volumes for the first quarter of 2005 were
2.7 Bcfe (30 MMcfe/d) compared to 3.1 Bcfe (33.9 MMcfe/d) in the first quarter
of 2004. The decrease in our production volumes was due to natural decline of
existing production and the lack of significant wells reaching total depth and
coming on line during the quarter to materially contribute to production.
Natural gas represented 74% of our first quarter 2005 production volumes
compared to 69% in the first quarter of last year.


HEDGING RESULTS

     The following table shows the type of derivative commodity contracts, the
volumes, the weighted average NYMEX reference price for those volumes, and the
associated gain /(loss) upon settlement of those contracts for the periods
indicated.

<TABLE>
<CAPTION>
                                                         THREE MONTHS ENDED MARCH 31,
                                              ---------------------------------------------------
                                                    2005            % CHANGE           2004
                                              ----------------  ---------------  ----------------
<S>                                           <C>               <C>              <C>
OIL SWAPS
Volumes (Bbls) . . . . . . . . . . . . . . .                -            (100%)           29,575
Average swap price ($per Bbl). . . . . . . .  $             -            (100%)  $         25.35
Gain /(loss) upon settlement ($in thousands)  $             -            (100%)  $          (290)
OIL COLLARS
Volumes (Bbls) . . . . . . . . . . . . . . .           27,450             (40%)           45,500
Average floor price ($per Bbl) . . . . . . .  $         25.56               11%  $         23.00
Average ceiling price ($per Bbl) . . . . . .  $         30.18              (1%)  $         30.43
Gain /(loss) upon settlement ($in thousands)  $          (541)             152%  $          (215)
TOTAL OIL
Volumes (Bbls) . . . . . . . . . . . . . . .           27,450             (63%)           75,075
Gain /(loss) upon settlement ($in thousands)  $          (541)               7%  $          (505)
NATURAL GAS SWAPS
Volumes (MMbtu). . . . . . . . . . . . . . .                -            (100%)          295,750
Average swap price ($per MMbtu). . . . . . .  $             -            (100%)  $          4.96
Gain /(loss) upon settlement ($in thousands)  $             -            (100%)  $          (216)
NATURAL GAS COLLARS
Volumes (MMbtu). . . . . . . . . . . . . . .          727,500               33%          546,000
Average floor price ($per MMbtu) . . . . . .  $          5.16               25%  $          4.13
Average ceiling price ($per MMbtu) . . . . .  $          7.26             (14%)  $          8.43
Gain /(loss) upon settlement ($in thousands)  $           (10)              NM   $             -
TOTAL NATURAL GAS
Volumes (MMbtu). . . . . . . . . . . . . . .          727,500             (14%)          841,750
Gain /(loss) upon settlement ($in thousands)  $           (10)            (95%)  $          (216)
</TABLE>

     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
qualify for cash flow hedge accounting treatment under SFAS 133.


                                       18
<PAGE>
     We utilize commodity swap, collar, three way costless collar 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.

     The effective portions of changes in the fair values of our derivative
commodity contracts that qualify for cash flow hedge accounting treatment under
SFAS 133 are recorded as increases or decreases to stockholders' equity until
the underlying contract is settled. Consequentially, changes in the effective
portions of these derivative contracts add volatility to our reported
stockholders' equity until the contract is settled or is terminated.

     Gains or losses related to the settlement and the changes in the fair
values of our derivative commodity contracts that do not qualify for cash flow
hedge accounting treatment under SFAS 133 are recognized in other income
(expense).


COMMODITY PRICES AND REVENUES

     The following table shows our revenue from the sale of oil and natural gas
for the periods indicated.

<TABLE>
<CAPTION>
                                                                 THREE MONTHS ENDED MARCH 31,
                                                      ---------------------------------------------------
                                                            2005            % CHANGE           2004
                                                      ----------------  ---------------  ----------------
                                                         (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS)
<S>                                                   <C>               <C>              <C>
REVENUE FROM THE SALE OF OIL AND NATURAL GAS:
Oil sales. . . . . . . . . . . . . . . . . . . . . .  $         5,689                5%  $         5,427
Gain (loss) due to hedging . . . . . . . . . . . . .             (541)               7%             (505)
                                                      ----------------                   ----------------
  Total revenue from the sale of oil . . . . . . . .  $         5,148                5%  $         4,922

Natural gas sales. . . . . . . . . . . . . . . . . .  $        11,565              (5%)  $        12,113
Gain (loss) due to hedging . . . . . . . . . . . . .              (10)            (95%)             (216)
                                                      ----------------                   ----------------
  Total revenue from the sale of natural gas . . . .  $        11,555              (3%)  $        11,897

Oil and natural gas sales. . . . . . . . . . . . . .  $        17,254              (2%)  $        17,540
Gain (loss) due to hedging . . . . . . . . . . . . .             (551)            (24%)             (721)
                                                      ----------------                   ----------------
  Total revenue from the sale of oil and natural gas  $        16,703              (1%)  $        16,819

AVERAGE PRICES:
Oil sales price (per Bbl). . . . . . . . . . . . . .  $         48.33               42%  $         34.01
Gain (loss) due to hedging (per Bbl) . . . . . . . .            (4.59)              45%            (3.17)
                                                      ----------------                   ----------------
  Realized oil price (per Bbl) . . . . . . . . . . .  $         43.74               42%  $         30.84

Natural gas sales price (per Mcf). . . . . . . . . .  $          5.80                0%  $          5.79
Gain (loss) due to hedging (per Mcf) . . . . . . . .            (0.00)           (100%)            (0.10)
                                                      ----------------                   ----------------
  Realized natural gas price (per Mcf) . . . . . . .  $          5.80                2%  $          5.69

Natural gas equivalent sales price (per Mcfe). . . .  $          6.39               11%  $          5.75
Gain (loss) due to hedging (per Mcfe). . . . . . . .            (0.20)            (17%)            (0.24)
                                                      ----------------                   ----------------
  Realized natural gas equivalent (per Mcfe) . . . .  $          6.19               12%  $          5.51
                                                      ================                   ================
</TABLE>

<TABLE>
<CAPTION>
                                                   2005
                                                 TO 2004
                                                ---------
<S>                                             <C>
CHANGE IN REVENUE FROM THE SALE OF OIL
Price variance impact. . . . . . . . . . . . .  $  1,686
Volume variance impact . . . . . . . . . . . .    (1,424)
Cash settlement of hedging contracts . . . . .       (36)
                                                ---------
  Total change . . . . . . . . . . . . . . . .  $    226
                                                =========
CHANGE IN REVENUE FROM THE SALE OF NATURAL GAS
Price variance impact. . . . . . . . . . . . .  $     20
Volume variance impact . . . . . . . . . . . .      (568)
Cash settlement of hedging contracts . . . . .       206
                                                ---------
  Total change . . . . . . . . . . . . . . . .  $   (342)
                                                =========
</TABLE>

     Our revenues from the sale of oil and natural gas for the first quarter of
2005 decreased by 1% when compared to revenues in first quarter of 2004. The
change in revenues was due to the following:


                                       19
<PAGE>
     -    An decrease in production volumes for the quarter resulted in a
          $2 million decrease in revenues from the sale of oil and natural gas;

     -    A 42% increase in the sales price we received from the sale oil
          and a slight increase in sales price we received from the sale of
          natural gas partially offset the decrease due to lower production by
          $1.7 million; and,

     -    A 24% decrease in losses from the cash settlement of derivative
          commodity contracts also partially offset the decrease in revenue due
          to a decrease in production.

     Other revenue.  Other revenue relates to fees that we charge other parties
who use our gas gathering systems that we own to move their production from the
wellhead to third party gas pipeline systems. Other revenue for the first
quarter of 2005 was $43,000 compared to $1,000 in the first quarter last year.
Costs related to our gas gathering systems are recorded in lease operating
expenses.

OPERATING COSTS AND EXPENSES

     Production costs.  Production costs include lease operating expenses and
production taxes.

<TABLE>
<CAPTION>
                                              THREE MONTHS ENDED MARCH 31,
                                  -------------------------------------------------
                                       2005           % CHANGE           2004
                                  ---------------  ---------------  ---------------
                                     (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS)
<S>                               <C>              <C>              <C>
PRODUCTION COST:
Operating & maintenance. . . . .  $         1,422              39%  $         1,026
Expensed workovers . . . . . . .              524             137%              221
Ad valorem taxes . . . . . . . .              272              68%              162
                                  ---------------                   ---------------
  Total lease operating expenses  $         2,218              57%  $         1,409

Production taxes . . . . . . . .              802             (7%)              863
                                  ---------------                   ---------------
  Total production expenses. . .  $         3,020              33%  $         2,272
                                  ===============                   ===============

PRODUCTION COST ($PER MCFE):
Operating & maintenance. . . . .  $          0.53              56%  $          0.34
Expensed workovers . . . . . . .             0.19             171%             0.07
Ad valorem taxes . . . . . . . .             0.10             100%             0.05
                                  ---------------                   ---------------
  Total lease operating expenses  $          0.82              78%  $          0.46

Production taxes . . . . . . . .             0.30               7%             0.28
                                  ---------------                   ---------------
  Total production expenses. . .  $          1.12              51%  $          0.74
                                  ===============                   ===============
</TABLE>

     Our first quarter 2005 production costs increased by 33% when compared to
production costs in the first quarter of 2004.  The change in our production
cost was due to the following:

     -    An increase in the number of wells we have producing. In the
          future we anticipate that our total production cost will increase as
          we add new wells and production facilities and continue to maintain
          production from existing maturing properties;

     -    An increase in expensed workover cost;

     -    An increase in cost for compressor rental and maintenance, salt
          water disposal, contract labor and measurement services, treating and
          miscellaneous operating and maintenance were the primary reasons for
          the increase in operating and maintenance expenses;

     -    An increase in ad valorem taxes due to higher oil and natural gas
          prices during 2004; and,

     -    A decrease in production taxes due to a decrease in production
          volumes that was partially offset by increases in commodity prices.


                                       20
<PAGE>
     We believe that per unit of production measures are the best way to
evaluate our production cost information. We use this information to evaluate
our performance relative to our peers and to internally evaluate our
performance.  For the first quarter of 2005, our unit production cost increased
51% when compared to 2004. The change in our unit production cost was due to the
following:

     -    A decline in first quarter 2005 production;

     -    An increase in cost for compressor rental and maintenance, salt
          water disposal, contract labor and measurement services, treating and
          miscellaneous operating and maintenance were the primary reason for
          the increase in operating and maintenance expenses;

     -    An increase in expensed workover cost; and,

     -    Ad valorem taxes increased due to higher oil and natural gas
          prices during 2004.

     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.

<TABLE>
<CAPTION>
                                                           THREE MONTHS ENDED MARCH 31,
                                                ---------------------------------------------------
                                                     2005            % CHANGE             2004
                                                ----------------  ---------------  ----------------
                                                    (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS)
<S>                                             <C>               <C>              <C>
General and administrative cost. . . . . . . .  $         2,303              (7%)  $         2,464
Capitalized general and administrative cost. .           (1,205)             (3%)           (1,244)
                                                ----------------                   ----------------
General and administrative expense . . . . . .  $         1,098             (10%)  $         1,220
                                                ================                   ================

General and administrative expense ($per Mcfe)  $          0.41                3%  $          0.40
</TABLE>

     For the first quarter of 2005, our general and administrative expenses
decreased by 10%. The changes in our general and administrative expenses were
due to the following:

     -    A decrease in costs for employee payroll and payroll taxes, rent,
          travel and entertainment and financial reporting; and,

     -    These decreases were partially offset by increases in costs for
          employee training and continuing education, corporate insurance and
          director fees and expenses.

     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.  Our 2004 information pertaining to depletion and accumulated
depletion that are part of our net proved oil and natural gas properties has
been restated.  See "Item 1. Financial Statements-Note 3" for further
discussion.

<TABLE>
<CAPTION>
                                                                 THREE MONTHS ENDED MARCH 31,
                                                      -------------------------------------------------
                                                           2005            % CHANGE          2004
                                                      ---------------  ---------------  ---------------
                                                                                          (RESTATED)
                                                         (IN THOUSANDS, EXCEPT PER UNIT MEASUREMENTS)
<S>                                                   <C>              <C>              <C>
Depletion of oil and natural gas properties. . . . .  $         6,453              26%  $         5,124

Depletion of oil and natural gas properties per Mcfe  $          2.39              42%  $          1.68
</TABLE>

     An increase in our depletion rate resulted in a $1.9 million increase in
depletion expense in the first quarter of 2005.  This increase was partially
offset by a $588,000 decrease to depletion expense due to a decrease in
production volumes.


                                       21
<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.

<TABLE>
<CAPTION>
                                                                 THREE MONTHS ENDED MARCH 31,
                                                       ---------------------------------------------------
                                                            2005            % CHANGE            2004
                                                       ----------------  ---------------  ----------------
                                                                          (IN THOUSANDS)
<S>                                                    <C>               <C>              <C>
Interest on senior credit facility. . . . . . . . . .  $           323              75%   $           185
Interest on senior subordinated notes . . . . . . . .              378             (14%)              439
Commitment fees . . . . . . . . . . . . . . . . . . .               38             (30%)               54
Dividend on mandatorily redeemable preferred stock. .              188               7%               175
Amortization of deferred loan and debt issuance cost.              126             (34%)              192
Other general interest expense. . . . . . . . . . . .                3             (63%)                8
Capitalized interest expense. . . . . . . . . . . . .             (315)             16%              (271)
                                                       ----------------                   ----------------
  Net interest expense. . . . . . . . . . . . . . . .  $           741              (5%)  $           782
                                                       ================                   ================

Weighted average debt outstanding . . . . . . . . . .  $        61,505              13%   $        54,671
Average interest rate on outstanding indebtedness(a).              6.1%                               6.3%
</TABLE>

----------

     (a)  Calculated as the sum of the interest expense on our outstanding
indebtedness, commitment fees that we pay on unused borrowing capacity and the
dividend on our mandatorily redeemable preferred stock divided by the weighted
average debt and preferred stock outstanding for the period.

     Our net interest expense for the first quarter of 2005 was 5% lower than
our net interest expense in the first quarter last year. The following were the
primary reasons for the changes first quarter 2005 net interest expense.

-    An increase in the interest rate that we paid on borrowings under our
     senior credit facility during the first quarter 2005. The lower margin that
     resulted from our January 21, 2005 amended and restated senior credit
     facility was more than offset by the higher Eurodollar rate in the first
     quarter of 2005;

-    A $5.5 million increase in the average debt outstanding under our senior
     credit facility in the first quarter of 2005 versus that in the first
     quarter of 2004;

-    A 7% increase in the dividends that we paid on our mandatorily redeemable
     preferred stock. We issued 9,393 shares of preferred stock to pay these
     dividends;

-    A decrease in the interest rate that we paid on our senior subordinated
     notes,

-    A decrease in deferred loan and debt issuance cost amortized during the
     first quarter 2005; and,

-    A 16% increase in the amount of interest that we capitalized during first
     quarter of 2005.

     Other income (expense).  Other income (expense) primarily includes non-cash
gains (losses) resulting from the change in fair market value of oil and gas
derivative contracts 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.

     Other income (expense) included:

<TABLE>
<CAPTION>
                                                                              THREE MONTHS ENDED MARCH 31,
                                                                   -------------------------------------------------
                                                                        2005            % CHANGE           2004
                                                                   ----------------  --------------  ---------------
                                                                                     (IN THOUSANDS)
<S>                                                                <C>               <C>             <C>
Non-cash gain (loss) due to change in fair market value of
derivative contracts not designated as cash flow hedges . . . . .  $            10              NM   $             -
Non-cash gain (loss) for ineffective portion of cash flow hedges.             (616)             NM               127
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .               75              NM                 -
                                                                   ----------------                  ---------------
  Other income (loss) . . . . . . . . . . . . . . . . . . . . . .  $          (531)             NM   $           127
                                                                   ================                  ===============
</TABLE>


                                       22
<PAGE>
     The following table shows the volumes and the weighted average NYMEX
reference price for those volumes for our derivative commodity contracts that we
did not designate as cash flow hedges for the periods indicated.

<TABLE>
<CAPTION>
                                                        THREE MONTHS ENDED MARCH 31,
                                              ------------------------------------------------
                                                   2005            % CHANGE         2004
                                              ---------------  --------------  ---------------
<S>                                           <C>              <C>             <C>
WRITTEN PUTS
Volumes (MMbtu). . . . . . . . . . . . . . .          210,000  NM                            -
Average price ($per  MMbtu). . . . . . . . .  $          5.50  NM              $             -
Gain /(loss) upon settlement ($in thousands)  $             -  NM              $             -
</TABLE>


     Income taxes:  A deferred tax liability or asset is recognized for the
estimated future tax effects attributable to (i) NOLs and (ii) existing
temporary differences between book and taxable income. Realization of net
deferred tax assets is dependent upon generating sufficient taxable income
within the carryforward period available under tax law.

     At March 31, 2005, we recognized a current period net deferred tax
liability of $1.5 million due to reversals of our existing temporary differences
between book and taxable income resulting mainly from our capital expenditures.
The $1.5 million net deferred tax liability consisted of a $1.7 million deferred
income tax expense, a $3,000 tax effect of unrealized hedging gains, and a
$145,000 credit to equity for the tax benefit from the exercise of stock
options.

     In 2004, we recognized a current year net deferred tax liability of $10.6
million due to reversals of our existing temporary differences between book and
taxable income resulting mainly from our capital expenditures. The $10.6 million
net deferred tax liability consisted of a $10.9 million deferred income tax
expense, a $0.3 million tax effect of unrealized hedging gains, and a $0.6
million credit to equity for the tax benefit from the exercise of stock options.

     At March 31, 2005, we believe it is more likely than not that capital loss
carryforwards of approximately $1.8 million may expire unused and, accordingly,
have established a valuation allowance of $0.6 million.


ANALYSIS OF CHANGES IN CASH AND CASH EQUIVALENTS

     The table below summarizes our sources and uses of cash during the periods
indicated.

<TABLE>
<CAPTION>
                                                        THREE MONTHS ENDED MARCH 31,
                                             ---------------------------------------------------
                                                   2005           % CHANGE            2004
                                             ----------------  ---------------  ----------------
                                                                                   (RESTATED)
                                                                (IN THOUSANDS)
<S>                                          <C>               <C>              <C>
Net income. . . . . . . . . . . . . . . . .  $         3,048             (38%)  $         4,925
Non-cash items. . . . . . . . . . . . . . .            9,279               16%            8,002
Changes in working capital and other items.           (6,083)              40%           (4,333)
                                             ----------------                   ----------------
Cash flows provided by operating activities  $         6,244             (27%)  $         8,594
Cash flows used by investing activities . .          (20,644)              21%          (17,057)
Cash flows provided by financing activities           16,760               62%           10,343
                                             ----------------                   ----------------
Net increase in cash and cash equivalents .  $         2,360               26%  $         1,880
                                             ================                   ================
</TABLE>


ANALYSIS OF NET CASH PROVIDED BY OPERATING ACTIVITIES

     Net cash provided by operating activities for the first quarter of 2005 was
27% lower than net cash provided by operating activities in the first quarter of
2004. The following were the primary reasons for this change.

-    Net cash provided by operating activities decreased by $116,000 due to a
     decrease in our revenue from the sale of oil and natural gas. This decrease
     in revenue was due to lower production volumes in the first quarter of
     2005. This decrease in revenue was partially offset by an increase in
     revenue due to an increase in the prices that we received for oil and
     natural gas and a decrease in losses on the settlement of our derivative
     contracts;

-    An increase in production cost for the first quarter 2005 resulted in a
     $748,000 decrease in net cash provided by operating activities. This
     increase in our production cost was partially offset by a $122,000 decrease
     in our first quarter 2005 general and administrative expenses;


                                       23
<PAGE>
-    The collection of accounts receivable in excess of the payment of accounts
     payable increased net cash provided by operating activities by $1.4
     million;

-    An increase in royalties paid in the first quarter 2005 when compared to
     the first quarter of 2004 resulted in a $2.5 million decrease in net cash
     provided by operating activities; and,

-    A decrease in advances paid to us by participants in our 3-D seismic
     projects and certain wells decreased net cash provided by operating
     activities by $392,000.


     WORKING CAPITAL

     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, royalties
payable and gas imbalances payable. Settlement of these payables will be funded
by cash flows from operations or, if necessary, by additional borrowing under
our senior credit facility.

     Our working capital deficit at March 31, 2005 was $15 million compared to a
working capital deficit of $19.5 million at December 31, 2004.  This deficit
included a liability of $1.8 million related to the fair value our derivative
contracts.

ANALYSIS OF CHANGES IN CASH FLOWS USED IN INVESTING ACTIVITIES

<TABLE>
<CAPTION>
                                                                     THREE MONTHS ENDED MARCH 31,
                                                           -------------------------------------------------
                                                                2005          % CHANGE             2004
                                                           ---------------  ---------------  ---------------
                                                                             (IN THOUSANDS)
<S>                                                        <C>              <C>              <C>
CAPITAL EXPENDITURES FOR OIL AND NATURAL GAS ACTIVITIES:
Drilling. . . . . . . . . . . . . . . . . . . . . . . . .  $        17,458              39%  $        12,568
Land and seismic. . . . . . . . . . . . . . . . . . . . .            4,815              71%            2,817
Capitalized cost (1). . . . . . . . . . . . . . . . . . .            1,601               1%            1,587
Asset retirement obligation . . . . . . . . . . . . . . .               26            (74%)              101
                                                           ---------------                   ---------------
  Total . . . . . . . . . . . . . . . . . . . . . . . . .  $        23,900              40%  $        17,073
                                                           ===============                   ===============
</TABLE>

------------

(1)  For 2005 includes $1.2 million in capitalized general and administrative
cost, $315,000 in capitalized interest cost and $81,000 of capitalized stock
compensation expense.  For 2004 includes $1.2 million in capitalized general and
administrative cost, $271,000 in capitalized interest cost and $71,000 of
capitalized stock compensation expense.


ANALYSIS OF CHANGES IN CASH FLOWS FROM FINANCING ACTIVITIES

     SENIOR CREDIT FACILITY

     During first three months of 2005 we borrowed an additional $17.1 million
under our senior credit facility and paid $371,000 in fees to amend and restate
of our senior credit facility on January 21, 2005.  This compares to $10.2
million borrowed under our senior credit facility in the first three months of
2004.

     SENIOR SUBORDINATED NOTES

     We paid $30,000 in fees to amend and restate our senior subordinated credit
agreement on January 21, 2005.


                                       24
<PAGE>
<TABLE>
<CAPTION>
COMMON STOCK TRANSACTIONS

                                    SHARES ISSUED     NET PROCEEDS
                                    --------------  ---------------
                                            (IN THOUSANDS)
<S>                                 <C>             <C>
2005 COMMON STOCK TRANSACTIONS:
Exercise of employee stock options          76,700  $           251

2004 COMMON STOCK TRANSACTIONS:
Exercise of employee stock options         126,600  $           310
</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 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 December 2004, the Financial Accounting Standards Board (FASB) issued
SFAS No. 123R, "Share-Based Payment" (SFAS 123R), which is a revision of SFAS
123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based
payments to employees, including grants of employee stock options, to be valued
at fair value on the date of grant, and to be expensed over the applicable
vesting period. Pro forma disclosure of the income statement effects of
share-based payments is no longer an alternative.  In addition, companies must
also recognize compensation expense related to any awards that are not fully
vested as of the effective date. Compensation expense for the unvested awards
will be measured based on the fair value of the awards previously calculated in
developing the pro forma disclosures in accordance with the provisions of SFAS
123. The effective date of SFAS 123R is the first reporting period beginning
after June 15, 2005, which is the third quarter 2005 for calendar year
companies, although early adoption is allowed.  However, on April 14, 2005, the
Securities and Exchange Commission (SEC) announced that the effective date of
SFAS 123R will be suspended until January 1, 2006, for calendar year companies.
We are currently assessing the impact of adopting SFAS 123R to our consolidated
financial statements.

     In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations" (FIN 47), which clarifies the impact
that uncertainty surrounding the timing or method of settling an obligation
should have on accounting for that obligation under SFAS No. 143.  FIN 47 is
effective no later than the end of the fiscal year ending after December 15,
2005, or December 31, 2005 for calendar year companies.  We do not expect the
adoption of FIN 47 to have a material impact on our consolidated financial
statements.

     In September 2004, the SEC issued Staff Accounting Bulletin 106 (SAB 106)
which provides guidance regarding the interaction of SFAS 143 with the
calculation of depletion and the full cost ceiling test of oil and gas


                                       25
<PAGE>
properties under the full cost accounting rules of the SEC. The adoption of SAB
106 did not have a material effect on our consolidated financial position,
results of operations or cash flows.


Forward  Looking  Information

     We or our representatives may make forward looking statements, oral or
written, including statements in this report, press releases and filings with
the SEC, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells we anticipate drilling during 2005 and our financial position, business
strategy and other plans and objectives for future operations. Although we
believe that the expectations reflected in these forward looking statements are
reasonable, there can be no assurance that the actual results or developments
anticipated by us will be realized or, even if substantially realized, that they
will have the expected effects on our business or operations. Among the factors
that could cause actual results to differ materially from our expectations are
general economic conditions, inherent uncertainties in interpreting engineering
data, operating hazards, delays or cancellations of drilling operations for a
variety of reasons, competition, fluctuations in oil and gas prices,
availability of sufficient capital resources to us or our project participants,
government regulations and other factors set forth among the risk factors noted
in the description of our business in Item 1 of our Form 10-K report for the
year ended December 31, 2004 or in our Management's Discussion Analysis of
Financial Condition in Item 7 of our Form 10-K report for the year ended
December 31, 2004.  All subsequent oral and written forward looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by these factors. We assume no obligation to update any of these
statements.


                                       26
<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, 2004. 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, 2004.

DERIVATIVE CONTRACTS

     The following table reflects open commodity derivative contracts at March
31, 2005, the associated volumes and the corresponding NYMEX reference price.

<TABLE>
<CAPTION>
                                                                      NOTIONAL AMOUNT
                                                                     ----------------
                                                                                                   NYMEX
                              DERIVATIVE                          GAS              OIL           REFERENCE
SETTLEMENT PERIOD             INSTRUMENT    HEDGE STRATEGY      (MMBTU)         (BARRELS)          PRICE
--------------------------  --------------  --------------  ---------------  ---------------  ---------------
<S>                         <C>             <C>             <C>              <C>              <C>
COSTLESS COLLARS
  04/01/05 - 06/30/05. . .  Purchased put   Cash flow               318,500                   $          5.00
                            Written call    Cash flow               318.500                              7.40
  04/01/05 - 06/30/05. . .  Purchased put   Cash flow                                 11,830  $         29.00
                            Written call    Cash flow                                 11,830            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
  04/01/05 - 10/31/05. . .  Purchased put   Cash flow               420,000                   $          5.45
                            Written call    Cash flow               420,000                              8.00
THREE WAY COSTLESS COLLARS
  07/01/05 - 10/31/05. . .  Purchased put   Cash flow               400,000                   $          6.00
                            Written call    Cash flow               400,000                              7.20
                            Written put     Undesignated            400,000                              5.00
  07/01/05 - 12/31/05. . .  Purchased put   Cash flow                                 30,000  $         40.00
                            Written call    Cash flow                                 30,000            53.00
                            Written put     Undesignated                              30,000            30.00
  11/01/05 - 03/31/06. . .  Purchased put   Cash flow               250,000                   $          6.75
                            Written call    Cash flow               250,000                              8.80
                            Written put     Undesignated            250,000                              5.50
</TABLE>

The following table reflects commodity derivative contracts entered subsequent
to March 31, 2005, the associated volumes and the corresponding weighted average
NYMEX reference price.

<TABLE>
<CAPTION>
                                                                      NOTIONAL AMOUNT
                                                                     ----------------
                                                                                                   NYMEX
                              DERIVATIVE                          GAS              OIL           REFERENCE
SETTLEMENT PERIOD             INSTRUMENT    HEDGE STRATEGY      (MMBTU)         (BARRELS)          PRICE
--------------------------  --------------  --------------  ---------------  ---------------  ---------------
<S>                         <C>             <C>             <C>              <C>              <C>
THREE WAY COSTLESS COLLARS
  06/01/05 - 03/31/06. . .  Purchased put   Cash flow                                 60,000  $         48.00
                            Written call    Cash flow                                 60,000            60.70
                            Written put     Undesignated                              60,000            38.00
  07/01/05 - 10/31/05. . .  Purchased put   Cash flow               240,000                   $          7.00
                            Written call    Cash flow               240,000                              7.76
                            Written put     Undesignated            240,000                              5.75
  11/01/05 - 03/31/06. . .  Purchased put   Cash flow               350,000                   $          8.00
                            Written call    Cash flow               350,000                              9.75
                            Written put     Undesignated            350,000                              6.50
</TABLE>


                                       27
<PAGE>
ITEM 4. CONTROLS AND PROCEDURES

MATERIAL CONTROL WEAKNESS PREVIOUSLY DISCLOSED

     In our 2004 Annual Report on Form 10-K, we reported that we did not
maintain effective control, as of December 31, 2004, over the accounting for
depletion expense and accumulated depletion. This resulted in a material control
weakness at December 31, 2004 related to accounting for depletion expense and
accumulated depletion. Specifically, our controls related to the preparation and
review of the quarterly depletion computations were not adequate to ensure that
that the changes in depletion rate estimates used to determine depletion expense
and the related accumulated depletion of net proved oil and natural gas
properties are only applied prospectively in accordance with accounting
principles generally accepted in the United States of America. The remedial
actions implemented in the first quarter 2005 related to this material weakness
are described below.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

     As of March 31, 2005, 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 CONTROL OVER FINANCIAL REPORTING

     During the first quarter of 2005, we have taken action to remediate the
material weakness identified at December 31, 2004 and update related accounting
policies and procedures. Due to such remediation, our depletion rate at each
respective period end has been applied to the respective current period
production only, as required by accounting principles generally accepted in the
United States of America. There were no other 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.


                                       28
<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 consolidated financial
condition, results of operations or cash flows.

ITEM 2. UNREGISTERD SALES OF EQITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

<TABLE>
<CAPTION>
                                    TOTAL NUMBER OF   AVERAGE PRICE PAID
               PERIOD               SHARES PURCHASED       PER SHARE
----------------------------------  ----------------  -------------------
<S>                                 <C>               <C>
January 1, 2005 - January 31, 2005            21,229  $              8.93
</TABLE>


No purchases were made under a publicly announced plan.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSON OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)       Exhibits:

<TABLE>
<CAPTION>
<S>   <C>

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>

(b)  Brigham Exploration Company filed the following reports on Form 8-K
     during the quarter covered by this Quarterly Report on Form 10-Q:

     (1)  Filed January 26, 2005 on Form 8-K Item 1.01 Entry into a
          Material Definitive Agreement and Item 2.03 Creation of a Direct
          Financial Obligation or an Obligation under and Off-Balance Sheet
          Arrangement of the Registrant, the Registrant announced that it had
          amended and restated its senior credit agreement and amended and
          restated its subordinated notes.

     (2)  Filed January 26, 2005 on Form 8-K Item 2.02 Results of Operation
          and Financial Condition and Item 9.01 Financial Statements and
          Exhibits, the Registrant issued a press release to announce
          discoveries and to provide an operational update.

     (3)  Filed March 3, 2005 on Form 8-K Item 2.02 Results of Operation
          and Financial Condition, Item. 7.01 Regulation FD Disclosure and Item
          9.01 Financial Statements and Exhibits, the Registrant


                                       29
<PAGE>
          issued a press release to announce its financial results for the
          quarter and year ended December 31, 2004, its proved reserve volumes
          at December 31, 2004, its forecasted results for the first quarter
          2005 and its forecasted production for the full year 2005.

     (4)  Filed March 4, 2005 a Form 8-K/A to amend the 8-K filed on March
          3, 2005 to correct income tax expense for the three month period ended
          December 31, 2004 contained in the press release attached as an
          exhibit.

     (5)  Filed March 21, 2005 on Form 8-K Item 2.02 Results of Operation
          and Financial Condition, Item 4.02 (a) Non-reliance on Previously
          Issued Financial Statements or a Related Audit Report or Completed
          Interim Period, Item. 7.01 Regulation FD Disclosure and Item 9.01
          Financial Statements and Exhibits, the Registrant issued press release
          dated March 17, 2005, which announced that it filed with the SEC a
          Form 12b-25, stating that it requires additional time to revise
          previously announced results of operations provided in its press
          release on March 3, 2005, assess the impact that a revision in its
          methodology for calculating depletion expense will have on its
          previously issued financial statements and file its 2004 Annual Report
          on Form 10-K.

     (6)  Filed March 31, 2005 on Form 8-K/A to amend Form 8-K to clarify
          that the registrant will restate consolidated financial statements for
          the years 2003 and 2002 filed in its 2004 Annual Report on Form 10-K.
          Also, with respect to each of the quarterly periods for 2004 and 2003,
          the registrant will include selected quarter data revised for the
          change in its depletion expense calculation in the unaudited
          supplemental quarterly financial information section to be included in
          its 2004 Annual Report on Form 10-K. Restated quarterly financial
          statements for the respective 2004 periods will be included in the
          registrants Forms 10-Q for 2005 for the corresponding periods.


                                       30
<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 May 6, 2005.


                                         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


                                       31