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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 September 30, 2002

[ ] 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 (Primary Standard Industrial (I.R.S. Employer
of incorporation or Classification Code Number) Identification
organization) Number)

6300 BRIDGEPOINT PARKWAY
BUILDING TWO, SUITE 500
AUSTIN, TEXAS 78730
(512) 427-3300
(Address, including zip code, and telephone number,
including area code, of Registrant's principal executive offices)

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 .
--- ---

As of November 8, 2002, 16,057,792 shares of Common Stock, $.01 per share, were
outstanding.

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BRIGHAM EXPLORATION COMPANY

THIRD QUARTER 2002 FORM 10-Q REPORT

TABLE OF CONTENTS
-----------------
PAGE
----
PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets - September 30, 2002 and December 31, 2001 . . . . . . . . . . . . . 1
Consolidated Statements of Operations - Three and nine months ended September 30, 2002 and 2001. 2
Consolidated Statement of Changes in Stockholders' Equity - Nine months ended September 30, 2002 3
Consolidated Statements of Cash Flows - Nine months ended September 30, 2002 and 2001. . . . . . 4
Notes to the Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . 5

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . . . . . . . . . . . . . . . 16

ITEM 4. DISCLOSURE CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

CERTIFICATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
(unaudited)

September 30, December 31,
2002 2001
--------------- --------------

ASSETS
Current assets:
Cash and cash equivalents $ 12,182 $ 5,112
Accounts receivable 12,100 9,325
Other current assets 4,295 2,531
--------------- --------------
Total current assets 28,577 16,968

Oil and natural gas properties, net (full cost method) 158,958 151,891
Other property and equipment, net 1,300 1,331
Deferred loan fees 2,438 3,166
Other noncurrent assets 512 52
--------------- --------------
$ 191,785 $ 173,408
=============== ==============

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 13,108 $ 8,267
Royalties payable 6,408 145
Accrued drilling costs 972 1,969
Other current liabilities 9,189 4,885
--------------- --------------
Total current liabilities 29,677 15,266
--------------- --------------

Notes payable 75,000 75,000
Senior subordinated notes 21,506 16,721
Other noncurrent liabilities 353 206

Commitments and contingencies

Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and
redemption value, 2,250,000 shares authorized, 1,730,238 and 1,630,692 shares
issued and outstanding at September 30, 2002 and December 31, 2001, respectively 18,778 16,614

Stockholders' equity:
Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000
are designated as Series A - -
Common stock, $.01 par value, 50 million shares authorized, 17,175,379 and
17,127,650 shares issued and 16,052,492 and 16,016,113 shares outstanding
at September 30, 2002 and December 31, 2001, respectively 172 171
Additional paid-in capital 78,962 80,466
Unearned stock compensation (285) (494)
Accumulated other comprehensive income (loss) (3,327) 351
Accumulated deficit (24,845) (26,728)
Treasury stock, at cost, 1,122,887 and 1,111,537 shares at September 30, 2002
and December 31, 2001, respectively (4,206) (4,165)
--------------- --------------
Total stockholders' equity 46,471 49,601
--------------- --------------
$ 191,785 $ 173,408
=============== ==============

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

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
------------------------ ------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------

Revenues:
Oil and natural gas sales $ 9,434 $ 8,848 $ 24,637 $ 26,220
Other 15 23 42 198
----------- ----------- ----------- -----------
9,449 8,871 24,679 26,418
----------- ----------- ----------- -----------

Costs and expenses:
Lease operating 761 842 2,428 2,332
Production taxes 475 415 1,327 1,503
General and administrative 1,099 934 3,781 2,708
Depletion of oil and natural gas properties 3,587 3,244 10,118 8,903
Depreciation and amortization 103 140 307 375
----------- ----------- ----------- -----------
6,025 5,575 17,961 15,821
----------- ----------- ----------- -----------
Operating income 3,424 3,296 6,718 10,597
----------- ----------- ----------- -----------

Other income (expense):
Interest income 12 63 105 230
Interest expense, net (1,614) (1,595) (4,684) (5,180)
Other income (expense) (87) 1,842 (256) 7,827
----------- ----------- ----------- -----------
(1,689) 310 (4,835) 2,877
----------- ----------- ----------- -----------

Income before income taxes 1,735 3,606 1,883 13,474
Income taxes - - - -
----------- ----------- ----------- -----------

Net income 1,735 3,606 1,883 13,474

Accretion and dividends on redeemable preferred stock 746 659 2,165 1,776
----------- ----------- ----------- -----------

Net income (loss) available to common stockholders $ 989 $ 2,947 $ (282) $ 11,698
=========== =========== =========== ===========

Net income (loss) per share available to common stockholders:
Basic $ 0.06 $ 0.18 $ (0.02) $ 0.73
Diluted $ 0.06 $ 0.17 $ (0.02) $ 0.67

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

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(in thousands)
(unaudited)

Accumulated
Common Stock Additional Unearned Other
------------------ Paid-in Stock Comprehensive Accumulated Treasury
Shares Amounts Capital Compensation Income (Loss) Deficit Stock
-------- -------- --------- -------------- --------------- ------------- ----------

Balance, December 31, 2001 17,128 $ 171 $ 80,466 $ (494) $ 351 $ (26,728) $ (4,165)

Exercise of employee
stock options 47 1 112 - - - -
Expiration of employee
stock options - - (46) - - - -
Forfeitures of employee
restricted stock - - (1) 15 - - (41)
Revision of terms of
employee stock options - - 596 - - - -
Dividends on Series A
mandatorily redeemable
preferred stock - - (1,991) - - - -
Accretion on Series A
mandatorily redeemable
preferred stock - - (174) - - - -
Amortization of unearned
stock compensation - - - 194 - - -
Net income - - - - - 1,883 -
Other comprehensive loss:
Unrealized losses on cash
flow hedges - - - - (3,784) - -
Losses on ineffective portion
of cash flow hedges - - - - 106 - -
Comprehensive loss
-------- -------- --------- -------------- --------------- ------------- ----------
Balance, September 30, 2002 17,175 $ 172 $ 78,962 $ (285) $ (3,327) $ (24,845) $ (4,206)
======== ======== ========= ============== =============== ============= ==========

Total
Stockholders' Comprehensive
Equity Loss
--------------- ---------------

Balance, December 31, 2001 $ 49,601

Exercise of employee
stock options 113
Expiration of employee
stock options (46)
Forfeitures of employee
restricted stock (27)
Revision of terms of
employee stock options 596
Dividends on Series A
mandatorily redeemable
preferred stock (1,991)
Accretion on Series A
mandatorily redeemable
preferred stock (174)
Amortization of unearned
stock compensation 194
Net income 1,883 $ 1,883
Other comprehensive loss:
Unrealized losses on cash
flow hedges (3,784) (3,784)
Losses on ineffective portion
of cash flow hedges 106 106
--------------- ---------------
Comprehensive loss $(1,795)
===============
Balance, September 30, 2002 $ 46,471
===============

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

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

Nine Months Ended
September 30,
------------------------
2002 2001
----------- -----------

Cash flows from operating activities:
Net income $ 1,883 $ 13,474
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties 10,118 8,903
Depreciation and amortization 307 375
Interest paid through the issuance of additional senior subordinated notes 785 498
Amortization of deferred loan fee and debt issuance costs 888 1,029
Market value and other adjustments for derivative instruments (278) (9,217)
Stock option compensation expense 596 -
Changes in working capital and other items:
Accounts receivable (2,775) (3,851)
Other current assets (2,065) (1,452)
Accounts payable 4,841 162
Royalties payable 6,263 (377)
Other current liabilities 1,637 4,331
Other (5) (10)
----------- -----------
Net cash provided by operating activities 22,195 13,865
----------- -----------

Cash flows from investing activities:
Additions to oil and natural gas properties (18,737) (27,020)
Proceeds from sale of assets 617 -
Additions to other property and equipment (218) (257)
Increase (decrease) in drilling advances paid (512) 959
----------- -----------
Net cash used by investing activities (18,850) (26,318)
----------- -----------

Cash flows from financing activities:
Proceeds from exercise of employee stock options 113 180
Proceeds from issuance of preferred stock and warrants, net - 9,838
Proceeds from issuance of senior subordinated notes 4,000 9,000
Principal payments on capital lease obligations (28) (86)
Deferred loan fees paid (360) -
----------- -----------
Net cash provided by financing activities 3,725 18,932
----------- -----------

Net increase in cash and cash equivalents 7,070 6,479
Cash and cash equivalents, beginning of period 5,112 837
----------- -----------
Cash and cash equivalents, end of period $ 12,182 $ 7,316
=========== ===========

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1. ORGANIZATION AND NATURE OF OPERATIONS

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

2. BASIS OF PRESENTATION

The accompanying 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
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 2001 Annual
Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934.

3. COMMITMENTS AND CONTINGENCIES

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

On November 20, 2001, Brigham filed a lawsuit in the District Court of
Travis County, Texas against Steve Massey Company, Inc. ("Massey") for breach of
contract. The Petition claims Massey furnished defective casing to Brigham,
which ultimately led to the casing failure of the Palmer "347" No. 5 well (the
"Palmer #5") and the loss of the Palmer #5 as a producing well. Brigham believes
the amount of damages incurred due to the loss of the Palmer #5 may exceed $5
million. Massey joined as additional defendants to the lawsuit other parties
that had responsibility for the manufacture, importation or fabrication of the
casing for its use in the Palmer #5. The case is currently in discovery and the
trial has been set for May 2003.

On February 20, 2002, Massey filed an Original Petition to Foreclose Lien
in Brooks County, Texas. Massey's Petition claims Brigham breached its contract
for failure to pay for the casing it furnished Brigham for the Palmer #5 (and
that Brigham's claim is defective, forming the basis of the lawsuit described in
the paragraph above). Massey's Petition claims Brigham owes Massey a total of
$445,819. Brigham's Motion to Transfer Venue to Travis County, Texas, was
recently granted. Once transfer is completed, Brigham will file a motion to
consolidate Massey's claim with Brigham's suit against Massey pending in Travis
County. If Massey is successful in its claim, Massey would have the right to
foreclose its lien against the well, associated equipment and Brigham's
leasehold interest. At this point in time, Brigham cannot predict the outcome of
either its Travis County case or Massey's claim.

On July 11, 2002, there was an accidental death of an employee of a
contractor on a Brigham well. The United States Department of Labor Occupational
Safety & Health Administration is currently investigating the accident. That
investigation could result in a fine assessed against Brigham, although at this
point in time, Brigham cannot predict the outcome of that investigation. On
October 8, 2002, a wrongful death action was filed against Brigham and three of
its contractors in connection with this accidental death. Although no specific
amounts are asked for in this action, plaintiffs seek both actual and punitive
damages. At this point in time, Brigham cannot predict the outcome of this case.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

4. NET INCOME (LOSS) PER SHARE

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

The following table reconciles the numerators and denominators of the basic
and diluted earnings per common share computations for net income (loss)
available to common stockholders for the three and nine months ended September
30, 2002 and 2001:

Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- ---------------------
2002 2001 2002 2001
--------- --------- ---------- ---------

BASIC EARNINGS PER SHARE:
Income (loss) available to common stockholders $ 989 $ 2,947 $ (282) $ 11,698
========= ========= ========== =========

Common shares outstanding 16,057 15,984 16,037 15,983
========= ========= ========== =========

Basic earnings per share $ 0.06 $ 0.18 $ (0.02) $ 0.73
========= ========= ========== =========

DILUTED EARNINGS PER SHARE:
Income (loss) available to common stockholders $ 989 $ 2,947 $ (282) $ 11,698

Adjustments for assumed conversions:
Amortization of compensation expense on stock options 4 2 - 11
--------- --------- ---------- ---------

Adjusted income (loss) available to common stockholders - diluted $ 993 $ 2,949 $ (282) $ 11,709
========= ========= ========== =========

Common shares outstanding 16,057 15,984 16,037 15,983

Effect of dilutive securities:
Warrants 947 788 - 1,071
Stock options 333 264 - 415
--------- --------- ---------- ---------
Potentially dilutive common shares 1,280 1,052 - 1,486
--------- --------- ---------- ---------

Adjusted common shares outstanding - diluted 17,337 17,036 16,037 17,469
========= ========= ========== =========

Diluted earnings per share $ 0.06 $ 0.17 $ (0.02) $ 0.67
========= ========= ========== =========

Options and warrants to purchase 14.5 million shares and 14.7 million
shares of common stock were outstanding but not included in the calculation of
diluted earnings (loss) per share for the three months ended September 30, 2002
and 2001, respectively, and options and warrants to purchase 19.1 million shares
and 14.3 million shares of common stock were outstanding but not included in the
calculation of diluted earnings (loss) per share for the nine months ended
September 30, 2002 and 2001, respectively, because the effects would have been
anti-dilutive.

5. DERIVATIVE INSTRUMENTS

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) support its capital budgeting plans, and
(iii) lock-in prices to protect the economics related to certain capital
projects.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

At September 30, 2002, the fair value of cash flow hedging contracts
included in other liabilities was $3.4 million of which $154,000 was classified
as noncurrent. In the three months ended September 30, 2002 and 2001, Brigham
recognized cash settlement losses of $501,000 and $28,000, respectively, which
were recorded as reductions of oil and natural gas sales. In the nine months
ended September 30, 2002 and 2001, Brigham recognized cash settlement losses of
$804,000 and $8.2 million, respectively, which were recorded as reductions of
oil and natural gas sales. For the three and nine months ended September 30,
2002, other income (expense) included $106,000 of non-cash losses from the
ineffective portion of the cash flow hedges. During the three and nine months
ended September 30, 2001, there was no ineffective portion of the losses on the
cash flow hedges. Based on market prices at September 30, 2002, approximately
$3.2 million of the balance in accumulated other comprehensive income (loss)
would be expected to transfer to earnings during the next 12 months.

The following tables summarize Brigham's outstanding oil and natural gas
cash flow hedging contracts as of September 30, 2002:

OIL CONTRACTS
2002 2003
-------------------- -----------------
VOLUMES CONTRACT VOLUMES CONTRACT
FIXED PRICE PRICING REMAINING HEDGED PRICE HEDGED PRICE
SWAPS BASIS CONTRACT TERM (BBLS) ($/BBL) (BBLS) ($/BBL)
- ------------- ------- ------------- -------- ---------- ------- --------

Contract #1 NYMEX 10/02 - 12/02 23,000 $ 24.50 - -

Contract #2 NYMEX 01/03 - 03/03 - - 22,500 $ 23.92

Contract #3 NYMEX 04/03 - 06/03 - - 22,750 $ 23.50

Contract #4 NYMEX 07/03 - 09/03 - - 23,000 $ 23.15

Contract #5 NYMEX 10/03 - 12/03 - - 23,000 $ 22.90

Contract #6 NYMEX 10/02 - 12/02 29,900 $ 25.39 - -

Contract #7 NYMEX 01/03 - 03/03 - - 27,000 $ 24.79

Contract #8 NYMEX 04/03 - 06/03 - - 18,200 $ 24.30

Contract #9 NYMEX 07/03 - 09/03 - - 23,000 $ 23.89

Contract #10 NYMEX 10/03 - 12/03 - - 18,400 $ 23.59

Contract #11 NYMEX 10/02 - 12/02 27,600 $ 29.28 - -

Contract #12 NYMEX 01/03 - 03/03 - - 18,000 $ 27.74

Contract #13 NYMEX 04/03 - 06/03 - - 9,100 $ 26.20

Contract #14 NYMEX 07/03 - 09/03 - - 9,200 $ 25.00

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

OIL CONTRACTS, CONTINUED 2002 2003
---------------------------- ----------------------------
PRICE PRICE
VOLUMES ------------------- VOLUMES -------------------
PRICING REMAINING HEDGED FLOOR CEILING HEDGED FLOOR CEILING
COLLARS BASIS CONTRACT TERM (BBLS) ($/BBL) ($/BBL) (BBLS) ($/BBL) ($/BBL)
- ---------- ------- ------------- ------- -------- --------- ------- -------- ---------

Collar #1 NYMEX 10/02 -12/02 23,000 $ 18.00 $ 22.35 - - -

Collar #2 NYMEX 10/02 - 06/03 23,000 $ 18.00 $ 22.56 45,250 $ 18.00 $ 22.56

NATURAL GAS CONTRACTS
2002 2003
-------------------- --------------------
VOLUMES CONTRACT VOLUMES CONTRACT
FIXED PRICE REMAINING HEDGED PRICE HEDGED PRICE
SWAPS PRICING BASIS CONTRACT TERM (MMBTU) ($/MMBTU) (MMBTU) ($/MMBTU)
- ------------ ------------- ------------- -------- ---------- -------- ----------

Contract #1 NYMEX 10/02 - 12/02 230,000 $ 2.900 - -

Contract #2 NYMEX 10/02 - 06/03 230,000 $ 3.000 452,500 $ 3.000

Contract #3 NYMEX 10/02 - 12/02 92,000 $ 3.455 - -

Contract #4. NYMEX 01/03 - 03/03 - - 225,000 $ 3.700

Contract #5. NYMEX 04/03 - 06/03 - - 91,000 $ 3.400

Contract #6. NYMEX 07/03 - 09/03 - - 230,000 $ 3.450

Contract #7. NYMEX 10/03 - 12/03 - - 92,000 $ 3.670

Contract #8. NYMEX 10/02 - 12/02 230,000 $ 3.755 - -

Contract #9. NYMEX 01/03 - 03/03 - - 225,000 $ 3.895

Contract #10 NYMEX 04/03 - 06/03 - - 227,500 $ 3.515

Contract #11 NYMEX 07/03 - 09/03 - - 230,000 $ 3.555

Contract #12 NYMEX 09/03 - 12/03 - - 230,000 $ 3.755

Contract #13 NYMEX 10/02 - 12/02 299,000 $ 3.780 - -

Contract #14 NYMEX 01/03 - 03/03 - - 157,500 $ 4.060

Contract #15 NYMEX 04/03 - 06/03 - - 45,500 $ 3.790

Derivative instruments not qualifying as hedging contracts are recorded at
fair value on the balance sheet. At each balance sheet date, the value of
derivatives not qualifying as hedging contracts is adjusted to reflect current
fair value and any gains or losses are recognized as other income or expense. As
of July 1, 2002, Brigham's derivative instruments not qualifying as hedging
contracts had expired. In the three months ended September 30, 2002 and 2001,
Brigham did not recognize any non-cash or cash gains or losses related to
changes in the fair values of these derivative contracts. In the nine months
ended September 30, 2002 and 2001, Brigham recognized $384,000 and $9.2 million,
respectively, in non-cash gains related to changes in the fair values of these
derivative contracts and $559,000 and $1.4 million, respectively, in cash losses
related to cash settlement payments made by Brigham to the counterparty.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

6. EMPLOYEE STOCK OPTIONS

In May 2002, Brigham accelerated the vesting of certain employee stock
options and extended the time limitation for exercising certain employee stock
options following termination of employment. These revisions resulted in the
immediate recognition of stock compensation cost as measured at the effective
date of the changes. Accordingly, a non-cash charge to general and
administrative expense in the amount of $596,000 was recorded during the second
quarter of 2002.

7. RECENT ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Standards No. 143, "Asset Retirement Obligations" ("SFAS
143") which establishes accounting requirements for retirement obligations
associated with tangible long-lived assets including the timing of the liability
recognition, initial measurement of the liability, allocation of asset
retirement cost to expense, subsequent measurement of the liability and
financial statement disclosures. SFAS 143 requires that an asset retirement cost
be capitalized as part of the cost of the related long-lived asset and
subsequently allocated to expense using a systematic, rational method. Brigham
plans to adopt SFAS 143 no later than January 1, 2003, as required. The
transition adjustment resulting from the adoption will be reported as a
cumulative effect of a change in accounting principle. Brigham is currently
evaluating the effect of the adoption of SFAS 143 on its financial position,
results of operations or cash flows.

In April 2002, the FASB issued Statement of Financial Standards No. 145,
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13 and Technical Corrections" ("SFAS 145") which is effective for fiscal years
beginning after May 15, 2002. Prior to the adoption of the provisions of SFAS
145, gains or losses on the early extinguishment of debt were required to be
classified as extraordinary gains or losses, net of associated income taxes,
below the determination of income or loss from continuing operations. SFAS 145
changes this accounting (except in the case of events or transactions of a
highly unusual and infrequent nature) and requires that gains or losses from the
early extinguishment of debt be classified as components of income or loss from
continuing operations. Brigham will adopt the provisions of SFAS 145 on January
1, 2003. The adoption of the provisions of SFAS 145 is not expected to affect
Brigham's future financial position or liquidity. When Brigham adopts the
provisions of SFAS 145, gains or losses from the early extinguishment of debt
recognized in the consolidated statements of operations for prior years will be
reclassified to other revenues or other expense and included in the
determination of the income (loss) from continuing operations of those periods.

In July 2002, the FASB issued Statement of Financial Standard No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146")
which requires companies to recognize costs associated with exit or disposal
activities when they are incurred rather than at the date of commitment to an
exit or disposal plan. Examples of costs covered by SFAS 146 include lease
termination costs and certain employee severance costs that are associated with
a restructuring, discontinued operations, or other exit or disposal activity.
SFAS 146 replaces Emerging Task Force Issue No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)". The provisions of SFAS
146 are effective for exit and disposal activities that are initiated after
December 31, 2002. Brigham will account for exit or disposal activities
initiated after December 31, 2002 in accordance with the provisions of SFAS 146.

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

RESULTS OF OPERATIONS

Comparison of the three-month periods ended September 30, 2002 and 2001

Production. Our net equivalent production volumes for the three months ended
September 30, 2002 were 2,599 MMcfe (28.9 MMcfe per day) compared to 2,596 MMcfe
(28.8 MMcfe per day) for the same period of 2001. The increase in our production
for the three-month period is due to the completion of wells drilled during the
second and third quarters of 2002 and was partially offset by the natural
decline of existing production. For the three months ended September 30, 2002,
production of natural gas represented 56% of our total production compared to
69% for the same period of 2001. Natural gas production declined 18% from 1,790
MMcf (19.9 MMcf per day) in the third quarter 2001 to 1,463 MMcf (16.3 MMcf per
day) for the third quarter 2002. Oil production for the third quarter 2002
increased 41% to 189 MBbls (2,104 Bbls per day) compared to 134 MBbls (1,493
Bbls per day) for the same period of 2001.

Revenue from the sale of oil and natural gas. Our revenues from the sale of oil
and natural gas for the third quarter 2002 were $9.4 million and increased over
third quarter 2001 revenue by $586,000. Increased production volumes represented
$394,000 of this increase and a 6% increase in our average equivalent realized
sales price for oil and natural gas represents the remaining increase.

Total revenues from the sale of oil for the third quarter 2002 were $4.7
million. Revenues from the sale of oil in the third quarter 2002 were $1.3
million higher than revenues from the sale of oil in the same quarter of 2001.
Our average realized sales price for oil for the third quarter 2002 was $24.85
per Bbl or 2% lower than our average realized sales price for oil in the third
quarter of 2001. Revenues from the sale of oil and our average realized oil
sales price were negatively affected by hedging losses of $414,000 ($2.18 per
Bbl) in the third quarter 2002 and hedging losses of $28,000 ($0.21 per Bbl) for
the same period of 2001.

Total revenue from the sale of natural gas for the third quarter 2002 was $4.7
million. Revenues from the sale of natural gas in the third quarter of 2002 were
$726,000 lower than revenue from the sale of natural gas in the third quarter
2001. Our average realized sales price for natural gas for the third quarter
2002 was $3.23 per Mcf or 6% higher than our average realized sales price for
natural gas in the third quarter 2001. Cash settlements on natural gas hedging
contracts of $87,000 ($0.06 per Mcf) negatively impacted our revenue from the
sale of natural gas and our average realized natural gas sales price for the
third quarter of 2002. There were no cash settlements on natural gas hedging
contracts during the third quarter 2001.

Lease operating expenses. Lease operating expenses for the third quarter were
$761,000, or 10% lower than lease operating expenses for the third quarter 2001.
Lease operating expenses on a per unit of equivalent production basis were $0.29
per Mcfe, down 9% from $0.32 per Mcfe for the third quarter of 2001. The
decrease in lease operating expenses was primarily due a decrease in expense
workovers and repairs and maintenance.

Production taxes. Production taxes for the third quarter 2002 increased 14% to
$475,000 compared to $415,000 in the third quarter of 2001. This increase is
primarily due to a 12% increase in the average pre-hedge equivalent price we
received for oil and natural gas. On a per unit of equivalent production basis,
production taxes for the third quarter of 2002 increased by 13% to $0.18 per
Mcfe compared to $0.16 per Mcfe for the same period of 2001.

General and administrative expenses. General and administrative expenses for the
third quarter of 2002 were $1.1 million compared to $934,000 in the third
quarter of 2001. This increase was primarily due to an increase in employee
benefit costs, office rent and other expenses. On a per unit of equivalent
production basis, general and administrative expenses increased from $0.36 per
Mcfe in the third quarter of 2001 to $0.42 per Mcfe in the third quarter of
2002.

Depletion of oil and natural gas properties. Depletion of oil and natural gas
properties for the third quarter 2002 was $3.6 million compared to $3.2 million
for the third quarter of last year. Approximately $337,000 of this increase was
the result of an increase in our depletion rate. On a per unit of equivalent
production basis, depletion expense increased 10% from $1.25 per Mcfe in the
third quarter of 2001 to $1.38 per Mcfe in the third quarter of 2002. The
increase in the depletion rate per unit of equivalent production is primarily
due to an increase in the estimated cost required to fully develop our Home Run
Field.

Interest expense. Interest expense for the third quarter 2002 remained
unchanged from the third quarter 2001 at $1.6 million. The weighted average
interest rate on our outstanding indebtedness during the third quarter 2002 was
7.4% compared to 9.0% for third quarter 2001. This decrease is primarily due to
a decrease in LIBOR for the third quarter of 2002 as compared to the third
quarter of 2001. Our weighted average outstanding debt balance for the third
quarter 2002 was $96.4 million compared to $91.4 million for the same period
last year. Interest expense for the third quarter 2002 included (i) $288,000 of
interest expense that was paid in kind through the issuance of additional debt
in lieu of cash, and (ii) $303,000 of non-cash charges related to the
amortization of deferred loan fees. Interest expense is reflected net of
capitalized interest of $492,000 and $205,000 in the third quarter 2001 and
2002, respectively.

Other income (expense). Other expense for the third quarter 2002 was $87,000
compared to other income of $1.8 million during the third quarter last year. We
recognize other income or expense primarily related to the change in the fair
market value and the related cash flows of certain oil and natural gas
derivative contracts that do not qualify for hedge accounting treatment and for
the ineffective portion of cash flow hedging contracts. For the third quarter
2001, other income (expense) includes $2.2 million of non-cash income related to
the change in the fair market values of these derivative contracts and was
partially offset by $347,000 of cash expense related to cash settlement of these
derivative contracts. Other income (expense) for the third quarter of 2002
included $106,000 of non-cash expense related to the ineffective portion of cash
flow hedging contracts and did not include income or expense related to the
change in the fair market value and the related cash flows of certain oil and
natural gas derivative contracts as all of our existing derivative instruments
qualified as hedging contracts.

Comparison of the nine-month periods ended September 30, 2002 and 2001

Production. Our net equivalent production volumes for the nine months ended
September 30, 2002 were 7,332 MMcfe (27.2 MMcfe per day) compared to 7,311 (27.1
Mcfe per day) for the same period of 2001. Production of natural gas represented
59% of our total equivalent production volumes for the nine months ended
September 30, 2002, compared to 72% for the same period of 2001. Natural gas
production declined 18% from 5,266 MMcf (19.5 MMcf per day) for the nine months
of 2001 to 4,307 MMcf (16.0 MMcf per day) for first nine months of 2002. Oil
production for first nine months of 2002 increased 48% to 504 MBbls (1,867 Bbls
per day) compared to 341 MBbls (1,262 Bbls per day) for the same period of 2001.

Revenue from the sale of oil and natural gas. Oil and natural gas sales for the
first nine months 2002 decreased $1.6 million from the first nine months of 2001
to $24.6 million. A 6% decrease in our average equivalent realized sales price
for oil and natural gas represented $2.7 million of this decline and was
partially offset by $1.1 million increase due to increased production volumes.

Total revenues from the sale of oil for the first three quarters of 2002 were
$11.6 million. Revenues from the sale of oil for the first nine months of 2002
were $2.8 million higher than revenue from the sale of oil during the first nine
months of 2001. Our average realized sales price for oil for the first nine
months of 2002 was $23.04 per Bbl and 11% lower than our average realized sales
price for oil in the same period last year. Revenue from the sale of oil and our
average realized sales price for oil was negatively impacted by hedging losses
of $735,000 ($1.46 per Bbl) in the first nine months of 2002 and $153,000 ($0.45
per Bbl) in the first nine months of 2001.

Total revenue from the sale of natural gas for the first three quarters of 2002
was $13.0 million. Revenues from the sale of natural gas for the first nine
months of 2002 were $4.4 million lower than revenue from the sale of natural gas
in the same period of 2001. Our average realized sales price for natural gas for
the first nine months of 2002 was $3.02 per Mcf and 8% lower than our average
realized sales price for natural gas in the same time period last year. Revenue
from the sale of natural gas and our average realized natural gas sales price
was negatively impacted by cash settlements on natural gas hedging contracts of
$69,000 ($0.02 per Mcf) in the first nine months of 2002 and $8.0 million ($1.52
per Mcf) in the first nine months of 2001.

Lease operating expenses. Lease operating expenses for the first nine months of
2002 were $2.4 million and 4% higher than lease operating expenses for the same
period of 2001. The increase in lease operating expenses was primarily due to an
increase in the number of producing wells during nine months of 2002 as compared
with the same period of 2001. Lease operating expenses on a per unit of
equivalent production basis for the nine months of 2002 were $0.33 per Mcfe, up
3% from $0.32 per Mcfe for the same period of 2001.

Production taxes. Production taxes for the first nine months of 2002 decreased
12% to $1.3 million from $1.5 million for the first nine months of 2001. The
decrease is primarily due to a 26% decrease in the average pre-hedge equivalent
price received for oil and natural gas. On a per unit of equivalent production
basis, production taxes for the first nine months of 2002 were $0.18 per Mcfe
compared to $0.21 per Mcfe for the same period in 2001.

General and administrative expenses. General and administrative expenses for
the first nine months of 2002 were $3.8 million compared to $2.7 million for the
first nine months of 2001. Of the increase, $596,000 is related to a non-cash
stock option compensation expense. The remainder of the increase is primarily
due to an increase in payroll, employee benefits and office rent expense. On a
per unit of equivalent production basis, general and administrative expenses
increased from $0.37 per Mcfe for the first nine months of 2001 to $0.52 per
Mcfe for the first nine months of 2002. Of the increase, $0.08 per Mcfe is
related to the non-cash stock compensation charge.

Depletion of oil and natural gas properties. Depletion of oil and natural gas
properties for the nine months of 2002 was $10.1 million compared to $8.9
million for the same period last year. Approximately $1.2 million of the
increase resulted from an increase in our depletion rate. On a per unit of
equivalent production basis, depletion expense increased 13% from $1.22 per Mcfe
for the nine months of 2001 to $1.38 per Mcfe for the same period of 2002. The
increase in the depletion rate per unit of equivalent production is primarily
due to an increase in the estimated cost required to fully develop our Home Run
Field.

Interest expense. Interest expense for the first nine months of 2002 was $4.7
million and 10% lower than interest expense for the first nine months of 2001.
The decline in interest expense is primarily due to lower interest rates on
outstanding debt borrowings for the first nine months of 2002 as compared to the
same period of 2001. The decline related to lower interest rates is partially
offset by an increase in outstanding debt for the first nine months of 2002
compared to the first nine months of 2001. The weighted average interest rate on
our outstanding indebtedness during the first nine months of 2002 was 7.4%
versus 9.8% for the first nine months of 2001. This decrease is primarily due to
lower LIBOR for the first nine months of 2002 as compared to the first nine
months of 2001. Our weighted average outstanding debt balance for the first nine
months of 2002 was $95.6 million compared to $90.3 million for the same period
last year. Interest expense for the first nine months of 2002 included (i)
$785,000 of interest expense that was paid in kind through the issuance of
additional debt in lieu of cash, and (ii) $888,000 of non-cash charges related
to the amortization of deferred loan fees. Interest expense is reflected net of
capitalized interest of $1.5 million and $655,000 for the first nine months of
2001 and 2002, respectively.

Other income (expense). Other expense for the first nine months of 2002 was
$256,000 compared to other income of $7.8 million for the nine months of 2001.
We recognize other income or expense primarily related to the change in the fair
market value and the related cash flows of certain oil and natural gas
derivative contracts that do not qualify for hedge accounting treatment and for
the ineffective portion of cash flow hedging contracts. For the nine months of
2002, other income (expense) included $384,000 of non-cash income related to the
changes in the fair market values of these derivative contracts, $559,000 of
cash expense related to cash settlements pursuant to these derivative contracts,
and $106,000 non-cash expense related to the ineffective portion of cash flow
hedging contracts. Other income (expense) for the first nine months of 2001
included $9.2 million of non-cash income related to the changes in the fair
market values of these derivative contracts and was partially offset by $1.4
million of cash expense related to the cash settlement of these derivative
contracts. As of July 1, 2002, all of our existing derivative instruments
qualify as hedging contracts.

LIQUIDITY AND CAPITAL RESOURCES

2002 Capital Expenditure Program

Our current total net capital spending budget for 2002 is $26.9 million. We
spent $17.4 million in total net capital during the first nine months of 2002.
Total net capital spending for the first nine months of 2002 was partially
offset by $1.9 million from insurance reimbursements for costs related to the
loss of surface control on the Burkhart #1. For the remainder of 2002, we plan
to spend approximately $9.5 million. Spending will be funded by our cash flow
and current cash balance. Estimated capital expenditures for the remainder of
2002 represent an increase of approximately 13% from our original 2002 budget.
This increase is primarily attributable to a forecasted increase in production

volumes, currently forecasted oil and natural gas prices and projected growth in
cash flows. The final determination with respect to drilling the currently
budgeted wells may depend on a number of factors including the following:

- the results of exploration efforts and the review and analysis of our
3-D seismic data,
- the availability of sufficient capital resources by us and other
participants for drilling prospects,
- economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for natural gas and oil and the
availability of drilling equipment,
- the availability of leases on reasonable terms for the potential
drilling locations, and
- the availability of more economically attractive prospects.

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

Senior Credit Facility

Interest expense on our senior credit facility for the third quarter 2002 was
$1.1 million. This includes $130,000 of non-cash charges related to the
amortization of deferred loan fees. Accrued interest expense for our senior
credit facility at September 30, 2002 was $27,000.

Interest expense on our senior credit facility for the first nine months of 2002
was $3.1 million. This includes $387,000 of non-cash charges related to the
amortization of deferred loan fees. The interest rate on our senior credit
facility on November 8, 2002 was 4.81%. We were in compliance with our covenants
at September 30, 2002.

Subordinated Notes Facility

We borrowed an additional $4.0 million under our subordinated notes facility in
March 2002. Total debt outstanding pursuant to our subordinated notes facility
on September 30, 2002 was $21.5 million. Approximately $1.5 million of this
outstanding balance is subordinated notes that were issued to satisfy interest
obligations on our subordinated notes facility. We have no remaining borrowing
availability under our subordinated notes facility.

Interest expense on our subordinated notes facility for the third quarter 2002
was $753,000. This includes $172,000 of non-cash charges related to the
amortization of deferred loan fees. During the third quarter 2002, we exercised
our option to satisfy 50% of the interest payment obligation on our subordinated
notes facility through the issuance of additional subordinated notes in lieu of
cash by issuing approximately $288,000 of additional subordinated notes. Accrued
interest expense for our subordinated notes facility at September 30, 2002 was
$386,000.

Interest expense on our subordinated notes facility for the first nine months of
2002 was $2.2 million. This includes $501,000 of non-cash charges related to the
amortization of deferred loan fees. For the first nine months of 2002, we issued
approximately $785,000 in additional subordinated notes to satisfy 50% of the
interest obligations on our senior subordinated notes facility. We were in
compliance with our covenants at September 30, 2002.

Series A Preferred Stock

Dividends and accretion on our Series A Preferred Stock for the third quarter of
2002 were $746,000. This includes $62,000 of non-cash charges related to the
accretion of the preferred stock and $684,000 of dividends that were
paid-in-kind through the issuance of additional Series A Preferred Stock.
Dividends and accretion on our Series A Preferred Stock for the first three
quarters of 2002 were $2.2 million. This includes $174,000 of non-cash charges
related to the accretion of the preferred stock and $2.0 million of dividends
that were paid in kind through the issuance of additional Series A Preferred
Stock.

The liquidation value of our outstanding Series A Preferred Stock at September
30, 2002 was $34.6 million. Approximately $4.6 million of this outstanding
balance represents additional Series A Preferred Stock issued to satisfy our
dividend payments.

Cash Flow Analysis

Cash Flows from Operating Activities. Cash flows provided by operating
activities for the first nine months of 2002 were $22.2 million compared to
$13.9 million for the first nine months of 2001. The increased cash flows from
operating activities for 2002 is primarily due to a $7.9 million increase in
cash from working capital for the first nine months of 2002 versus a cash
decrease of $1.2 million from working capital during the first nine months of
2001. This increase was partially offset by a $763,000 decrease in operating
cash flow before changes in working capital for the first nine months of 2002
when compared to the first nine months of 2001. The decrease in operating cash
flow before changes in working capital is primarily the result of a 6% decrease
in our average equivalent realized sales price for oil and natural gas and an
18% increase in our cash general and administrative expense for the first nine
months of 2002. These increases were partially offset by a 12% decrease in our
production taxes for the first nine months of 2002.

Cash Flows from Investing Activities. Cash flows used by investing activities
for the first nine months of 2002 were $18.9 million compared to $26.3 for the
first nine months of 2001. The decrease in cash used by investing activities for
2002 is primarily due to lower capital expenditures for exploration and
development activities during the first nine months of 2002 and $617,000 in cash
proceeds from the sale of assets during the first nine months of 2002.

Cash Flows from Financing Activities. Cash flows provided by financing
activities for the first nine months of 2002 were $3.7 million compared to $18.9
million during the first nine months of 2001. This decrease is primarily due to
the borrowings under our subordinated notes facility and the financing
transaction that we completed during the first nine months of 2001. During the
first nine months of 2001, we borrowed an additional $9.0 million under our
subordinated notes facility compared to an additional $4.0 million during the
first nine months of 2002. We also issued Series A Preferred Stock and warrants
that resulted in net proceeds of $9.8 million during the first nine months of
2001.

OTHER MATTERS

Derivative Instruments

Total natural gas sold subject to swap arrangements was 920,000 MMBtu in the
third quarter of 2002. None of the natural gas we sold during the third quarter
2001 was subject to swap arrangements. We sold 920,000 MMBtu of natural gas
subject to a floor contract during the third quarter of 2001. We accounted for
these transactions as hedging activities and, accordingly, adjusted the price we
received for natural gas production during the period the hedged transactions
occurred. Adjustments to the price we received for natural gas under these
hedging arrangements resulted in a decrease in natural gas revenues of $87,000
in the third quarter of 2002. There were no adjustments to the price we received
for natural gas during the third quarter of 2001.

For the first nine months of 2002, total natural gas sold subject to swap
arrangements was 2,277,500 MMBtu compared to 1,800,000 MMBtu during the first
nine months of 2001. We also sold 535,000 MMBtu subject to a floor contract
during the first nine months of 2001. We accounted for these transactions as
hedging activities and, accordingly, adjusted the price received for natural gas
production during the period the hedged transactions occurred. Adjustments to
the price we received for natural gas under these hedging arrangements resulted
in a decrease in natural gas revenues of $69,000 during the first nine months of
2002 and a decrease in natural gas revenues of $8.0 million during the first
nine months of 2001.

During the third quarter of 2002, 46,000 Bbls of oil sold were subject to swap
arrangements and 46,000 Bbls of oil sold were subject to collars. No oil sold
during the third quarter of 2001 was subject to swap arrangements and 18,400
Bbls of oil sold was subject to collars. We also accounted for these
transactions as hedging activities and, as a result, our oil revenues were
reduced by $414,000 in the third quarter of 2002 and $28,000 in the third
quarter of 2001.

During the first nine months of 2002, 46,000 Bbls of oil sold were subject to
swap arrangements and 159,000 Bbls sold were subject to collars. No oil sold
during the first nine months of 2001 was subject to swap arrangements and 91,000
Bbls were sold subject to collars. As a result of these hedging activities, our
oil revenues for the first nine months of 2002 were reduced by $735,000 and by
$153,000 for the same period of 2001.

Derivative instruments not qualifying as hedging contracts are recorded at fair
value on the balance sheet. At each balance sheet date, the value of derivatives
not qualifying as hedging contracts is adjusted to reflect current fair value
and any gains or losses are recognized as other income or expense. Our
derivative instruments that did not qualify as hedging contracts expired at the
end of the second quarter 2002. During the third quarter 2001, we recognized
$2.2 million in non-cash gains related to changes in the fair values of
derivative contracts and $347,000 in cash losses related to cash settlement
payments made by us to our counterparty. For the nine months ended September 30,
2002 and 2001, we recognized $384,000 and $9.2 million, respectively, in
non-cash gains related to changes in the fair values of these derivative
contracts and $599,000 and $1.4 million, respectively, in cash losses related to
cash settlement payments made by us to our counterparty.

See Note 5 to the Consolidated Financial Statements for information regarding
our outstanding crude oil and natural gas derivative contracts.

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 June 2001, the Financial Accounting Standards Board issued Statement of
Financial Standards No. 143, "Asset Retirement Obligations" ("SFAS 143") which
establishes accounting requirements for retirement obligations associated with
tangible long-lived assets including the timing of the liability recognition,
initial measurement of the liability, allocation of asset retirement cost to
expense, subsequent measurement of the liability and financial statement
disclosures. SFAS 143 requires that an asset retirement cost be capitalized as
part of the cost of the related long-lived asset and subsequently allocated to
expense using a systematic, rational method. Brigham plans to adopt SFAS 143 no
later than January 1, 2003, as required. The transition adjustment resulting
from the adoption will be reported as a cumulative effect of a change in
accounting principle. Brigham is currently evaluating the effect of the adoption
of SFAS 143 on its financial position, results of operations or cash flows.

Forward Looking Information

Brigham or its 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 it anticipates drilling during 2002 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 its 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 and our project participants, government regulations and other factors set
forth among the risk factors noted in this report, in the description of our
business in Item 1 of our Form 10-K report for the year ended December 31, 2001
(see page 1 of our 2001 Form 10-K) or in our Management's Discussion Analysis of
Financial Condition in our Form 10-K report for the year ended December 31, 2001
(see page 29 of our 2001 Form 10-K). 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

In Part II, Item 7A of our Form 10-K report for the year ended December 31, 2001
(see page 54 of Brigham's 2001 Form 10-K), we provide a discussion of our market
risk. See Note 5 to the Consolidated Financial Statements regarding our market
risk associated with our derivative instruments at September 30, 2002. There
were no material changes during the third quarter of 2002 in our exposures to
loss from possible future changes in the prices of oil and natural gas or in
interest rates, other than those described in our 2001 Form 10-K report, and in
Note 5 to the Consolidated Financial Statements in this Form 10-Q.

ITEM 4. DISCLOSURE CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures. Within 90 days prior
to the filing date of this Form 10-Q, Brigham's principal executive officer
("CEO") and principal financial officer ("CFO") carried out an evaluation of the
effectiveness of Brigham's disclosure controls and procedures. Based on this
evaluation, the CEO and CFO believe that Brigham's disclosure controls and
procedures are designed to ensure that information required to be disclosed by
Brigham in the reports it files under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods specified
in the Securities and Exchange Commission's rules and forms and that such
information is accumulated and communicated to Brigham's management, including
the CEO and CFO, as appropriate to allow timely decisions regarding required
disclosure; and that Brigham's disclosure controls and procedures are effective.

(b) Changes in internal controls. There have been no significant changes in
Brigham's internal controls or in other factors that could significantly affect
Brigham's internal controls subsequent to the evaluation referred to in Item 4.
(a), above, nor have there been any corrective actions with regard to
significant deficiencies or material weaknesses.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:

None

(b) Reports on Form 8-K:

We filed a report on Form 8-K on July 16, 2002 to report the announcements
on July 11, 2002 of the successful completion our Providence Field
confirmation well and West Texas Fusselman discovery. The Form 8-K included
a copy of the press release that provided this announcement.

We filed a report on Form 8-K on August 12, 2002, to report the
announcement on August 5, 2002 of our operational results for the second
quarter of 2002 and to report the announcement on August 6, 2002 of our
financial results for the second quarter of 2002. The Form 8-K included a
copy of the press releases that provided these announcements.

We filed a report on Form 8-K on August 22, 2002 submitting certifications
dated August 14, 2002 by our chief executive officer and our chief
financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
in correspondence to the SEC accompanying Brigham's quarterly report on
Form 10-Q for the quarter ended June 30, 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized on November 13, 2002.

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.
Senior Vice President and Chief
Financial Officer

BRIGHAM EXPLORATION COMPANY

CERTIFICATIONS

I, Ben M. Brigham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Brigham Exploration
Company ("Brigham"):

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of circumstances under which such statements were
made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of
Brigham as of, and for, the periods presented in this quarterly report;

4. Brigham's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for Brigham and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to Brigham, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

b) evaluated the effectiveness of Brigham's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. Brigham's other certifying officer and I have disclosed, based on our
most recent evaluation, to Brigham's auditors and the audit committee of
Brigham's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect Brigham's ability to record, process,
summarize and report financial data and have identified for Brigham's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in Brigham's internal controls; and

6. Brigham's other certifying officer and I have indicated in this quarterly
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

November 13, 2002

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

BRIGHAM EXPLORATION COMPANY

CERTIFICATIONS

I, Eugene B. Shepherd, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Brigham Exploration
Company ("Brigham"):

b) evaluated the effectiveness of Brigham's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in Brigham's internal controls; and

November 13, 2002

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

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

In connection with this quarterly report on Form 10-Q of Brigham Exploration
Company ("Brigham") for the period ending September 30, 2002 (the "Report"), I,
Ben M. Brigham, President, Chief Executive Officer and Chairman of the Board of
Brigham, certify that to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or
78o(d)); and

2. The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of Brigham.

Dated: November 13, 2002 /s/ BEN M. BRIGHAM
------------------------------
Ben M. Brigham,
President, Chief Executive Officer
and Chairman of the Board

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

In connection with this quarterly report on Form 10-Q of Brigham Exploration
Company ("Brigham") for the period ending September 30, 2002 (the "Report"), I,
Eugene B. Shepherd, Jr., Senior Vice President and Chief Financial Officer of
Brigham, certify that to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or
78o(d)); and

2. The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of Brigham.

Dated: November 13, 2002 /s/ EUGENE B SHEPHERD, JR.
------------------------------
Eugene B. Shepherd, Jr.
Senior Vice President
and Chief Financial Officer