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

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

                                    FORM 10-K

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

(Mark One)

      |X|   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
            EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000

            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
    (State or other jurisdiction of                     75-2692967
    incorporation or organization)                   (I.R.S. Employer
       6300 Bridge Point Parkway                    Identification No.)
         Building 2, Suite 500
            Austin, Texas                                  78730
(Address of principal executive offices)                (Zip Code)

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

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          Securities registered pursuant to Section 12(b) of the Act:

                                                 Name of Each Exchange on
          Title of Each Class                        Which Registered
          -------------------                    ------------------------
                 None                                      None

           Securities registered pursuant to Section 12(g) of the Act:
                          Common Stock, $.01 par value
                                (Title of Class)

      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 12 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 if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. |_|

      As of March 20, 2001, the Registrant had 15,988,118 shares of common stock
outstanding. The aggregate market value of the common stock held by
non-affiliates of the Registrant, based upon the closing sale price of the
common stock on March 20, 2001, as reported on The Nasdaq Stock MarketSM, was
$22.7 million. For purposes of determination of the foregoing amount, only
directors, executive officers and 10% or greater stockholders have been deemed
affiliates.

                       DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the definitive proxy statement for the Registrant's 2001
Annual Meeting of Stockholders to be held on May 10, 2001, are incorporated by
reference in Part III of this Form 10-K. Such definitive proxy statement will be
filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2000.

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                                TABLE OF CONTENTS

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                                     PART I

ITEM 1.    BUSINESS .......................................................    1

ITEM 2.    PROPERTIES .....................................................    9

ITEM 3.    LEGAL PROCEEDINGS ..............................................   18

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS .............   18

EXECUTIVE OFFICERS OF THE REGISTRANT ......................................   19

                                     PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY
           AND RELATED STOCKHOLDER MATTERS ................................   21

ITEM 6.    SELECTED FINANCIAL DATA ........................................   22

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS
           OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ...............   23

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK .....   43

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ....................   44

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
           ON ACCOUNTING AND FINANCIAL DISCLOSURE .........................   44

                                    PART III

ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT .............   45

ITEM 11.   EXECUTIVE COMPENSATION .........................................   45

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN
           BENEFICIAL OWNERS AND MANAGEMENT ...............................   45

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS ...........   45

                                     PART IV

ITEM 14.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES
           AND REPORTS ON FORM 8-K ........................................   46

GLOSSARY OF OIL AND GAS TERMS .............................................   47

SIGNATURES.................................................................   49

INDEX TO FINANCIAL STATEMENTS .............................................  F-1


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                           BRIGHAM EXPLORATION COMPANY

                         2000 ANNUAL REPORT ON FORM 10-K

ITEM 1. BUSINESS

Overview

      Brigham Exploration Company ("Brigham" or the "Company") is an independent
exploration and production company that applies 3-D seismic imaging and other
advanced technologies to systematically explore and develop onshore oil and
natural gas provinces in the United States. Brigham focuses its activity in
provinces where it believes 3-D technology may be effectively applied to
generate relatively large potential reserve volumes per well and per field, high
potential production rates and multiple producing objectives. Brigham's
exploration activities are concentrated primarily in three core provinces:

      o     the Anadarko Basin of western Oklahoma and the Texas Panhandle;

      o     the onshore Texas Gulf Coast; and

      o     West Texas.

      Brigham pioneered the acquisition of large-scale onshore 3-D seismic
surveys for exploration, obtaining extensive 3-D seismic data and experience in
capturing undiscovered oil and natural gas reserves. As of December 31, 2000,
Brigham has acquired 5,122 square miles (3.3 million acres) of 3-D seismic data
and has drilled 498 wells in its 3-D project areas. Brigham generates most of
its exploratory projects and, therefore, has the ability to retain a sizeable
working interest in these projects.

      From inception in 1990 through 2000, Brigham has drilled 407 exploratory
and 91 development wells on its 3-D generated prospects with an aggregate 66%
completion rate and an average working interest of 30%. As of December 31, 2000,
Brigham has added 162 Bcfe of net proved reserves to its reserve base,
approximately 139 net Bcfe of which were discovered by Brigham through its
systematic 3-D exploration drilling activities at an average net drilling cost
of $0.75 per Mcfe. In 1999 and 2000, Brigham's average net drilling cost was
$0.62 per Mcfe and its all-in net finding and development cost was $0.85 per
Mcfe.

      Brigham's estimated net proved reserves as of December 31, 2000 were 95
Bcfe having an aggregate Present Value of Future Net Revenues of $498 million,
compared to estimated net proved reserves as of December 31, 1996 of 22 Bcfe
having an aggregate Present Value of Future Net Revenues of $45 million.
Brigham's net proved reserve volumes at December 31, 2000 are 82% natural gas
and 52% proved developed.

Business Strategy

      Brigham's principal objective and business strategy is to achieve superior
growth in shareholder value through the application of its systematic
exploration approach, which emphasizes the integrated use of 3-D seismic imaging
and other advanced technologies to reduce drilling risks and finding costs. From
its inception in 1990 through 1998, Brigham achieved rapid growth in its
acquisition of 3-D seismic data, identification of potential drilling locations,
discovery of proved reserves and production of oil and natural gas volumes.
Having acquired in excess of 5,100 square miles of 3-D seismic data in proven
producing trends during this period, Brigham has been focusing its activities
since 1999 on generating tangible value from its high quality inventory of 3-D
delineated prospect locations through disciplined exploration and development
drilling activities and selective non-producing asset sales.


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      Brigham completed its initial public offering of common stock in May 1997,
raising approximately $24 million to fund its accelerated 3-D seismic
acquisition and exploration drilling activities. Key elements of Brigham's
long-term growth strategy at its initial public offering included:

      o     acquiring 3-D seismic data in proven producing trends to identify
            and capture potential drilling locations;

      o     retaining significant working interests in its exploration projects
            to capture a greater share of the reserves discovered;

      o     identifying higher potential, higher impact prospects; and

      o     monetizing the value of its 3-D seismic investments by drilling its
            inventory of identified prospect locations.

      During 1997 and 1998, Brigham acquired 2,360 square miles of 3-D seismic
data at an average working interest of 73%, which nearly doubled its inventory
of onshore 3-D seismic data to 5,122 square miles as compared to year-end 1996.
Brigham's overall level of 3-D seismic acquisition during 1997 and 1998 was the
most active in its history, in which Brigham generated 3-D projects where it
retained higher working interests. The vast majority of this newly acquired data
was located in Brigham's higher potential Anadarko Basin and Gulf Coast
provinces where it has historically achieved lower average finding costs for
drilling than in its West Texas province. As a result of these significant
investments in 3-D seismic acquisition, processing and interpretation in proven
natural gas producing trends, Brigham believes it has assembled a significant
competitive knowledge base and strategic position in each of its two most active
exploration provinces. Brigham further believes it has captured a high quality
inventory of 3-D delineated potential drilling locations that can be monetized
through the drill bit at attractive finding costs over the next several years,
thereby providing opportunities for future reserve, production and cash flow
growth.

      Brigham's current business strategy consists of the following key
elements:

      o     focus resources on drilling of its established 3-D delineated
            project inventory, most of which target natural gas prospects in
            proven producing trends;

      o     maintain an active, high potential exploration program, yet continue
            to allocate an increasing percentage of drilling expenditures toward
            the development of previous exploration successes;

      o     improve cash flow margins and return on invested capital by
            continuing efforts to reduce per unit finding and operating cost
            components; and

      o     selectively monetize non-producing assets to recoup capital
            investments and improve project rates of return.

Focus on Drilling

      During the first eight years of its history, Brigham directed a
significant portion of its resources toward the establishment of a sizeable
inventory of 3-D seismic projects within proven natural gas producing trends in
the Anadarko Basin and Gulf Coast. As a result of these efforts, Brigham
believes it has assembled a significant asset base within these two core
exploration provinces that it has only begun to monetize through drilling
efforts to date. During 1999 and 2000, Brigham focused the majority of its
resources toward drilling activities within its established 3-D seismic projects
to generate proved reserves, production volumes and cash flow from these
investments. This capital allocation focus resulted in average drilling and
all-in finding and development costs for the period 1999 - 2000 of $0.62 per
Mcfe and $0.85 per Mcfe, respectively.


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      Continuing to exploit its existing 3-D seismic project assets, Brigham's
primary objective in 2001 is to drill the highest-grade locations within its
inventory of identified drilling locations to generate continued growth in
proved reserves and cash flow. Approximately 85% of Brigham's planned $26
million exploration and development capital expenditure budget for 2001 is
targeted for drilling activities within its Anadarko Basin, Texas Gulf Coast and
West Texas 3-D seismic projects. With the significant competitive advantages
afforded by Brigham's prior investments in 3-D seismic data within its core
provinces, Brigham expects that drilling capital expenditures should represent
at least 80% of its annual exploration and development capital expenditures for
the foreseeable future.

Execute Active, High-Potential Drilling Program Balanced With Development of
Prior Discoveries

      From 1990 to 1999, the majority of Brigham's historical drilling
expenditures were directed toward exploration-oriented projects. Leveraging
several potentially significant new field discoveries during 1999 and 2000,
Brigham's 2000 and planned 2001 drilling programs consist of a more balanced
blend of exploration and development projects in trends where Brigham has
achieved historical drilling success. These focus trends include the Springer
Bar, Springer Channel and Hunton trends in the Anadarko Basin and the Frio and
Vicksburg trends in the Texas Gulf Coast province. Of Brigham's $22 million
drilling budget planned for 2001, 34% of the expenditures relate to exploration
projects and 66% are for development drilling projects that are either currently
planned or contingent upon drilling success during the year. In addition, over
80% of Brigham's 2001 planned drilling budget is concentrated in five project
areas where it experienced significant drilling success during 2000.

Improve Operating Margins and Return on Invested Capital

      Brigham seeks to improve its return on invested capital by achieving low
finding and development costs and by reducing and controlling its per unit
operating costs. Brigham has achieved average drilling costs of $0.75 per Mcfe
during the past ten years. By focusing its 1999 and 2000 drilling programs
within areas where it had previously experienced drilling success, Brigham
achieved improved returns on its drilling investments with average drilling
costs of $0.62 per Mcfe. Importantly, Brigham's all-in finding and development
costs during 1999 and 2000 were $0.85 per Mcfe, a substantial improvement from
its average finding and development costs of $1.59 per Mcfe from inception
through 1998 due to:

      o     Brigham's considerable prior investments in 3-D seismic and land,
            principally during 1997 and 1998;

      o     significantly lower non-drilling capital expenditures in 1999 and
            2000;

      o     improved drilling returns achieved during 1999 and 2000; and

      o     sales of interests in certain 3-D seismic projects and prospects in
            1999 and 2000 that provided reimbursements of previously incurred
            expenditures.

      Brigham expects this trend toward convergence of its all-in finding and
development costs and drilling costs to continue in 2001 as it continues to
capitalize on its extensive inventory of 3-D delineated prospects by allocating
a substantial majority of its capital expenditures to drilling within its
existing 3-D seismic project areas.

      During the past few years, Brigham's low per unit lease operating expenses
can be attributed to:

      o     the relatively new nature of many of its producing wells;

      o     focused operations in three core provinces; and

      o     operating a greater percentage of the wells that it drills.


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      Brigham intends to continue to maintain low per unit operating expenses
by:

      o     monitoring and controlling production efficiency from its existing
            producing wells;

      o     adding new producing wells that typically cost less to operate than
            more mature wells; and

      o     seeking to achieve operating cost efficiencies through increased
            economies of scale resulting from a greater concentration of
            producing assets within its core project areas.

Monetize Non-Producing Assets

      In addition to supporting a multi-year drilling program, Brigham believes
that its substantial investments in 3-D seismic data and undeveloped acreage
provide a significant competitive advantage to attract participants to invest in
its projects, thereby recouping a portion of its initial capital investments,
typically on a promoted basis. Brigham has been effective at raising capital and
attaining promoted working interests in its 3-D seismic projects throughout its
history. During 1999 and 2000, Brigham raised in excess of $15 million through
the sales of interests in various 3-D seismic projects or individual drilling
prospects to fund a portion of its capital expenditure program and satisfy
working capital requirements. Brigham expects to continue to market interests in
certain 3-D seismic projects or individual prospects during 2001 to provide
incremental sources of capital for reinvestment in its drilling program, to
limit its risk exposure and to improve its project economics.

3-D Seismic Technology

      Brigham's strategy is to use 3-D seismic and other advanced technologies,
including computer-aided exploration ("CAEX"), to systematically explore and
develop domestic onshore oil and natural gas provinces. In general, 3-D seismic
is the process of acquiring seismic data along multiple lines and grids. The
primary advantage of 3-D seismic over 2-D seismic is that it provides
information with respect to multiple horizontal and vertical points within a
geologic formation instead of information on a single vertical line or multiple
vertical lines within the formation. Acquiring larger amounts of data relating
to a geologic formation allows a user to better correlate the data and, in some
cases, to obtain a greater understanding and image of the formation. Although it
is impossible to predict with certainty the specific configuration or
composition of any underground geologic formation, the use of 3-D seismic data
provides clearer and more accurate projected images of complex geologic
formations, which can assist a user in evaluating whether to drill for oil and
natural gas reserves. If a decision to drill is made, 3-D seismic data can also
help in determining the optimal location to drill.

      CAEX is the process of accumulating and analyzing the various seismic,
production and other data obtained relating to a geographic area. In general,
CAEX involves accumulating various 2-D and 3-D seismic data with respect to a
potential drilling location, correlating that data with historical well control
and production data from similar properties and analyzing the available data
through computer programs and modeling techniques to project the likely geologic
composition of a potential drilling location and potential locations of
undiscovered oil and natural gas reserves. This process relies on a comparison
of data with respect to the potential drilling location and historical data with
respect to the density and sonic characteristics of different types of rock
formations, hydrocarbons and other subsurface minerals, resulting in a projected
three dimensional image of the subsurface. This modeling is performed through
the use of advanced interactive computer workstations and various combinations
of available computer programs that have been developed solely for this
application.

Exploration and Operating Approach

      Brigham has acquired 3-D seismic data covering 5,122 square miles (3.3
million acres) in over 20 geologic trends in seven basins and seven states.
Through this activity, Brigham has developed expertise in the selection of
geologic trends that are suitable for 3-D seismic exploration. Brigham uses
experience that it gains within a trend to enhance the quality of subsequent
projects in the same trend and other analogous trends, contributing to lower
finding and


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development costs, compressed project cycle times and increased project rates of
return.

      Brigham typically acquires 3-D seismic data in and around existing
producing fields where it can benefit from the imaging of producing analogs.
These 3-D defined analogs, combined with Brigham's experience in drilling nearly
500 wells in its 3-D project areas, provide Brigham with a knowledge base to
evaluate other potential geologic trends, 3-D seismic projects within trends and
prospective 3-D delineated drilling locations. Brigham's knowledge base assists
in identifying geologic trends where Brigham believes it can find and develop
economic volumes of oil and natural gas.

      Brigham has experience exploring with 3-D seismic in a wide range of
reservoir types and geologic trapping styles, both stratigraphic and structural
(including reefs, salt domes, channel sands, complex faulted and fractured
reservoirs and pinchout plays). Occasionally, Brigham seeks to supplement its
knowledge base with the best local geologic expertise available for a particular
geologic trend. In addition, Brigham typically acquires digital data bases for
integration on its CAEX workstations, including digital land grids, well
information, log curves, production information, geologic studies, geologic top
data bases and existing 2-D seismic data.

      Brigham uses its knowledge base, local geological expertise and digital
data bases integrated with 3-D seismic data to create maps of producing and
potentially productive reservoirs. Brigham believes its 3-D generated maps are
more accurate than previous reservoir maps (which generally were based on
subsurface geological information and 2-D seismic surveys), enabling it to more
precisely evaluate recoverable reserves and the economic feasibility of projects
and drilling locations.

      Brigham has acquired most of its raw 3-D seismic data using seismic
acquisition vendors on either a proprietary basis or through alliances affording
the alliance members the exclusive right to interpret and use data for extended
periods of time. In addition, Brigham has participated in non-proprietary group
shoots of 3-D seismic data (commonly referred to as "spec data") when it
believes the expected full cycle project economics are justified. In most of its
proprietary 3-D data acquisitions and alliances, Brigham has selected the sites
of projects, primarily guided by its knowledge and experience in the core
provinces it explores; established and monitored the seismic parameters of each
project for which data was shot; and typically selected the equipment that was
used. The acquisition of 3-D seismic data has generally been priced on the basis
of the number of square miles shot.

      Brigham's operations personnel (including management) includes five
petroleum engineers that have reservoir and operations engineering experience
primarily within Brigham's three core areas of operations. These engineers work
closely with Brigham's explorationists and are integrally involved in all phases
of the exploration and development process, including preparation of pre- and
post-drill reserve estimates, analysis of full cycle risked drilling economics,
well design and production management. Brigham conducts field operations for its
operated oil and natural gas properties through third party contract personnel.
In an effort to retain better control of its project timing, drilling and
operational costs and production volumes, Brigham has significantly increased
the percentage of the wells that it operates during the past several years.
Brigham operated 55% of the gross and 82% of the net wells it participated in
during 2000, as compared with 10% and 17%, respectively, of its wells drilled
during 1996. As a result of its increased operational control in recent years,
Brigham-operated wells constituted 73% of the PV10% value of its proved
developed producing reserves at year-end 2000, as compared with only 8% at
year-end 1996.

Technical Staff

      Brigham's experienced technical staff (excluding management) includes five
geophysicists, six geologists, four petroleum engineers, four computer
applications specialists, four geophysical/geological/engineering technicians,
three landmen and two lease and division order analysts. Brigham's geophysicists
have different but complementary backgrounds, and their diversity of experience
in varied geological and geophysical settings, combined with various technical
specializations (from hardware and systems to software and seismic data
processing), provide Brigham with valuable technical intellectual resources.
Brigham's team of explorationists has over 210 years of exploration experience,
or an average of more than 19 years per person, most of which was acquired at
Brigham and various major and large independent oil companies. Brigham's team of
technical specialists was assembled according to the expertise that these


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individuals have within producing basins where Brigham focuses its exploration
and development activities. By integrating both geologic and geophysical
expertise within its project teams, Brigham believes it possesses a competitive
advantage in its exploration approach. Occasionally, Brigham will complement and
leverage its exploration staff by seeking out alliances or retainer
relationships with geologists and other technical professionals who have
extensive experience in a particular area of interest.

Oil and Natural Gas Marketing and Major Customers

      Most of Brigham's oil and natural gas production is sold under price
sensitive or spot market contracts. The revenues generated by Brigham's
operations are highly dependent upon the prices of and demand for oil and
natural gas. The price received by Brigham for its oil and natural gas
production depends on numerous factors beyond Brigham's control, including
seasonality, competition, the condition of the United States economy, foreign
imports, political conditions in other oil-producing and natural gas-producing
countries, the actions of the Organization of Petroleum Exporting Countries, and
domestic government regulation, legislation and policies. Decreases in the
prices of oil and natural gas could have an adverse effect on the carrying value
of Brigham's proved reserves and its revenues, profitability and cash flow.
Although Brigham is not currently experiencing any significant involuntary
curtailment of its oil or natural gas production, market, economic and
regulatory factors may in the future materially affect Brigham's ability to sell
its oil or natural gas production. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations", "-- Risk Factors --
Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are
Volatile" and "-- Risk Factors -- The Marketability Of Our Production Is
Dependent On Facilities That We Typically Do Not Own Or Control." For the year
ended December 31, 2000, sales to Highland Energy Company and Lantern Petroleum
Corporation were approximately 36% and 20%, respectively, of Brigham's oil and
natural gas revenues. Due to the availability of other markets and pipeline
connections, Brigham does not believe that the loss of any single oil or natural
gas customer would have a material adverse effect on its results of operations.

Competition

      The oil and gas industry is highly competitive in all of its phases.
Brigham encounters competition from other oil and gas companies in all areas of
its operations, including the acquisition of seismic and leasing options and oil
and natural gas leases on properties. Brigham's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of its
competitors are large, well established companies with substantially larger
operating staffs and greater capital resources than Brigham. Such companies may
be able to pay more for seismic and lease options on oil and natural gas
properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than Brigham's financial
or human resources permit. Brigham's ability to acquire additional properties
and to discover reserves in the future will be dependent upon its ability to
evaluate and select suitable properties and to consummate transactions in a
highly competitive environment. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Risk Factors -- We
Face Significant Competition" and "-- Risk Factors -- We Have Substantial
Capital Requirements."

Operating Hazards and Uninsured Risks

      Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by Brigham will be productive or that Brigham
will recover all or any portion of its investment. Drilling for oil and natural
gas may involve unprofitable efforts, not only from dry wells, but also from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost and timing of
drilling, completing and operating wells is often uncertain. Brigham's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond Brigham's control, including title problems,
weather conditions, delays by project participants, compliance with governmental
requirements and shortages or delays in the delivery of equipment and services.
Brigham's future drilling activities may not be successful and, if unsuccessful,
such failure may have a material adverse effect on its business, financial
condition or results of operations. See "Item 7. Management's Discussion and
Analysis of Financial Condition


                                     - 6 -

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and Results of Operations -- Risk Factors -- Exploratory Drilling Is A
Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are
Dependent On Exploratory Drilling Activities." In addition, use of 3-D seismic
technology requires greater pre-drilling expenditures than traditional drilling
strategies. Although Brigham believes that its use of 3-D seismic technology
will increase the probability of drilling success, some unsuccessful wells are
likely, and there can be no assurance that unsuccessful drilling efforts will
not have a material adverse effect on Brigham's business, financial condition or
results of operations.

      Brigham's operations are subject to hazards and risks inherent in drilling
for and producing and transporting oil and natural gas, such as fires, natural
disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of Brigham and others. Brigham maintains insurance
against some but not all of the risks described above. In particular, the
insurance maintained by Brigham does not cover claims relating to failure of
title to oil and natural gas leases, trespass during 3-D survey acquisition or
surface change attributable to seismic operations, business interruption or loss
of revenues due to well failure. Furthermore, in certain circumstances in which
insurance is available, Brigham may not purchase it. The occurrence of an event
that is not covered, or not fully covered, by insurance could have a material
adverse effect on Brigham's business, financial condition and results of
operations.

Employees

      On March 20, 2001, Brigham had 49 full-time employees. None is represented
by any labor union. Brigham believes its relations with its employees are good.
In addition, Brigham relies on several regional consulting service companies to
provide field landmen to support Brigham on a project-by-project basis. One of
these companies, Brigham Land Management, is owned by Vincent M. Brigham, who is
the brother of Ben M. Brigham, the Company's Chief Executive Officer, President
and Chairman of the Board.

Facilities

      Brigham's principal executive offices are located in Austin, Texas, where
it leases approximately 34,330 square feet of office space at 6300 Bridge Point
Parkway, Building 2, Suite 500, Austin, Texas 78730. In an effort to reduce
corporate overhead expenses, Brigham has subleased approximately 5,300 square
feet of excess office space at its principal executive offices to a third party
for a two-year term beginning in November 1999.

Title to Properties

      Brigham believes it has satisfactory title, in all material respects, to
substantially all of its producing properties in accordance with standards
generally accepted in the oil and gas industry. Brigham's properties are subject
to royalty interests, standard liens incident to operating agreements, liens for
current taxes and other inchoate burdens which Brigham believes do not
materially interfere with the use of or affect the value of such properties.
Brigham's Senior Credit Facility (as defined) is secured by a first lien against
substantially all of Brigham's oil and natural gas properties and other tangible
assets, and Brigham's Subordinated Notes Facility (as defined) is secured by a
second lien against all collateral pledged by Brigham as security under its
Senior Credit Facility. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations."

Governmental Regulation

      Brigham's oil and natural gas exploration, production and marketing
activities are subject to extensive laws, rules and regulations promulgated by
federal and state legislatures and agencies. Failure to comply with such laws,
rules and regulations can result in substantial penalties. The legislative and
regulatory burden on the oil and gas industry increases Brigham's cost of doing
business and affects its profitability. Although Brigham believes it is in
substantial compliance with all applicable laws and regulations, Brigham is
unable to predict the future cost or impact of complying with such laws and
regulations because they are frequently amended, interpreted and reinterpreted.


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      The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and natural gas.
These states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from wells and the
regulation of spacing, plugging and abandonment of such wells.

Environmental Matters

      Brigham's operations and properties are, like the oil and gas industry in
general, subject to extensive and changing federal, state and local laws and
regulations relating to environmental protection, including the generation,
storage, handling, emission, transportation and discharge of materials into the
environment, and relating to safety and health. The recent trend in
environmental legislation and regulation generally is toward stricter standards,
and this trend will likely continue. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences and for certain other activities; limit or prohibit seismic
acquisition, construction, drilling and other activities on certain lands lying
within wilderness and other protected areas; and impose substantial liabilities
for pollution resulting from Brigham's operations. The permits required for
various of Brigham's operations are subject to revocation, modification and
renewal by issuing authorities. Governmental authorities have the power to
enforce compliance with their regulations, and violations are subject to fines
or injunction, or both. In the opinion of management, Brigham is in substantial
compliance with current applicable environmental laws and regulations, and
Brigham has no material commitments for capital expenditures to comply with
existing environmental requirements. Nevertheless, changes in existing
environmental laws and regulations or in interpretations thereof could have a
significant impact on Brigham, as well as the oil and gas industry in general.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA") and comparable state statutes impose strict and arguably joint and
several liability on owners and operators of certain sites and on persons who
disposed of or arranged for the disposal of "hazardous substances" found at such
sites. It is not uncommon for the neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. The Resource Conservation
and Recovery Act ("RCRA") and comparable state statutes govern the disposal of
"solid waste" and "hazardous waste" and authorize imposition of substantial
fines and penalties for noncompliance. Although CERCLA currently excludes
petroleum from its definition of "hazardous substance," state laws affecting
Brigham's operations impose clean-up liability relating to petroleum and
petroleum related products. In addition, although RCRA classifies certain oil
field wastes as "non-hazardous," such exploration and production wastes could be
reclassified as hazardous wastes thereby making such wastes subject to more
stringent handling and disposal requirements.

      Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. For onshore and
offshore facilities that may affect waters of the United States, the OPA
requires an operator to demonstrate financial responsibility. Regulations are
currently being developed under federal and state laws concerning oil pollution
prevention and other matters that may impose additional regulatory burdens on
Brigham. In addition, the Clean Water Act and analogous state laws require
permits to be obtained to authorize discharge into surface waters or to
construct facilities in wetland areas. With respect to certain of its
operations, Brigham is required to maintain such permits or meet general permit
requirements. The Environmental Protection Agency ("EPA") has in place
regulations concerning discharges of storm water runoff. This program requires
covered facilities to obtain individual permits, participate in a group or seek
coverage under an EPA general permit. Brigham believes that it will be able to
obtain, or be included under, such permits, where necessary, and to make minor
modifications to existing facilities and operations that would not have a
material effect on Brigham.

      Brigham has acquired leasehold interests in numerous properties that for
many years have produced oil and natural gas. Although Brigham believes that the
previous owners of these interests have used operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on


                                     - 8 -

<PAGE>

or under the properties. In addition, some of Brigham's properties are operated
by third parties over whom it has little control. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Other Matters" and "-- Risk Factors -- We Are Subject To Various Governmental
Regulations And Environmental Risks."

ITEM 2. PROPERTIES

Primary Exploration Provinces

      Brigham focuses its 3-D seismic exploration efforts in oil and natural gas
producing provinces where it believes 3-D technology may be effectively applied
to generate relatively large potential reserve volumes per well and per field,
high potential production rates and multiple producing objectives. Brigham's
exploration activities are concentrated primarily in three core provinces: the
Anadarko Basin of western Oklahoma and the Texas Panhandle; the onshore Texas
Gulf Coast; and West Texas. During the past four years, Brigham has concentrated
the majority of its 3-D seismic and drilling activities on natural gas projects
in the Anadarko Basin and Gulf Coast provinces primarily due to the higher
expected rates of return provided by these opportunities relative to its more
mature West Texas oil projects. However, in response to strong crude oil prices
in late 2000 and to date in 2001, Brigham has recently begun to selectively
drill certain of its higher grade, 3-D delineated West Texas prospects.


      In 1997 and 1998, Brigham made significant investments in the acquisition
of 3-D seismic and prospective acreage in its Anadarko Basin and Gulf Coast
provinces. Through these investments, Brigham believes it has assembled an
inventory of potential drilling locations that will support a multi-year
drilling program, thereby providing attractive opportunities for long-term
growth. From inception in 1990 through 2000, Brigham achieved net drilling costs
of $0.75 per Mcfe added through its 3-D seismic exploration efforts. In
addition, the vast majority of Brigham's estimated potential drilling locations
are in its currently most active Anadarko Basin and Gulf Coast provinces where
Brigham has achieved inception-to-date average net drilling costs of $0.53 and
$0.91 per Mcfe, respectively.

      Continuing its strategic focus implemented during 1999 and 2000, Brigham
intends to direct substantially all of its efforts and available capital
resources in 2001 to the drilling and monetization of the highest grade
prospects within its over 5,000 square mile inventory of 3-D seismic data.
Employing this emphasis during the past two years, Brigham achieved average
drilling and all-in finding and development costs of $0.62 per Mcfe and $0.85
per Mcfe, respectively, in 1999 - 2000.

      Brigham's planned 2001 exploration and development capital expenditure
budget is estimated to be approximately $26 million, which includes $22 million
to drill 25 planned wells with an average working interest of approximately 40%.
Brigham's planned 2001 drilling program represents a balanced blend of capital
investments consisting of both development projects to recent discoveries and
high potential exploration prospects. Approximately 66% of budgeted drilling
expenditures are allocated to development activities with the remaining 34%
targeted for exploratory drilling of its highest-grade prospects. In addition,
over 80% of Brigham's budgeted drilling expenditures are focused in five project
areas in the Springer and Hunton trends of the Anadarko Basin and the Vicksburg
and Frio trends of the Texas Gulf Coast. Each of these five 3-D projects are in
areas that Brigham has experienced its most significant recent exploration and
development drilling successes. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."

      Brigham's actual capital expenditures in 2001 may differ from the
estimates discussed herein based upon cash flow and capital availability during
the year. There can be no assurance that any potential drilling locations
identified by Brigham will be drilled at all or within the expected time frame.
The final determination with respect to the drilling of any well, including
those currently budgeted, will depend on a number of factors, including:

      o     the results of exploration and development efforts and the
            continuing review and analysis of the seismic data;


                                     - 9 -

<PAGE>

      o     the availability of sufficient capital resources by Brigham and
            other participants for drilling prospects;

      o     economic and industry conditions at the time of drilling, including
            prevailing and anticipated prices for oil and natural gas and the
            availability of drilling rigs and crews;

      o     Brigham's future financial results; and

      o     the availability of leases on reasonable terms and permitting for
            the potential drilling location.

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

Anadarko Basin

      The Anadarko Basin is a prolific natural gas province that Brigham
believes offers a combination of lower risk exploration and development
opportunities in shallower horizons and deeper, higher potential objectives that
have been relatively under explored. This province has produced in excess of 90
Tcfe to date from numerous, historically elusive stratigraphic targets, such as
the Red Fork, Upper Morrow and Springer channel sands, as well as from deeper,
higher potential structural objectives, such the Lower Morrow sandstones and the
Hunton and Arbuckle carbonates. In some cases, these objectives have produced in
excess of 50 Bcf of natural gas from a single well at rates of up to 30 MMcf of
natural gas per day. In addition, drilling economics in the Anadarko Basin are
enhanced by the multi-pay nature of many of the prospects in this province, with
secondary or tertiary targets serving as either incremental value or bailout
potential relative to the primary target zone.

      Each of the stratigraphic and structural objectives in the Anadarko Basin
can provide excellent targets for 3-D seismic imaging. Brigham has assembled an
extensive digital data base in this province, including geologic studies, basin
wide geologic tops, production data, well data, geographic data and over 8,400
miles of 2-D seismic data. Brigham's explorationists integrate this data with
their extensive expertise and knowledge base to generate 3-D projects in the
Anadarko Basin.

      As of December 31, 2000, Brigham had acquired 2,062 square miles (1.3
million acres) of 3-D seismic data in the Anadarko Basin. Through its drilling
efforts in this region from 1994 through 2000, Brigham had completed 92 wells in
119 attempts (77% completion rate) in the Anadarko Basin and had found
cumulative net proved reserves of 79 Bcfe at an average net drilling cost of
$0.53 per Mcfe. In its Anadarko Basin drilling program in 1999 and 2000, Brigham
completed 21 wells in 24 attempts (88% completion rate) with an average working
interest of 42% that contributed to the addition of 32 net Bcfe of proved
reserves (including revisions to previous estimates) at an average net drilling
cost of $0.30 per Mcfe.

      Brigham intends to focus the majority of its exploration and development
drilling expenditures in its Anadarko Basin province in the following key
project areas during 2001:

      Huskie and Boilermaker Projects

      Brigham's Huskie and Boilermaker Projects consist of 103 and 96 square
miles, respectively, of continuous 3-D seismic data covering approximately
127,000 acres in Blaine County, Oklahoma. These projects target stratigraphic
fluvial sand channels in the Springer-aged Old Woman and Britt intervals.
Brigham initiated acquisition of data in its Huskie Project in 1996 where it
retained a 37.5% working interest and, based upon the prospect density and
reserve potential interpreted from this initial data set, Brigham subsequently
acquired data in its adjacent Boilermaker Project in 1998 where it retained a
100% working interest.

      Brigham completed three Springer wells in three attempts in its Huskie
Project during 2000. The first of these Springer channel sand tests was drilled
to a depth of approximately 10,300 feet and encountered 41 feet of net pay. This


                                     - 10 -

<PAGE>

discovery well began producing in May 2000 at a pipeline-curtailed daily rate of
3.5 MMcf of natural gas and 350 barrels of condensate, or 3.1 MMcfe net to
Brigham's revenue interest. Upon completion of a pipeline expansion in December
2000, daily production from this well was increased to 6.5 MMcf of natural gas
and 250 barrels of condensate, or 3.8 MMcfe net to Brigham. Its most recent
discovery in this project was drilled to a total depth of approximately 9,750
feet in December 2000 to test an analogous 3-D delineated Springer channel
objective. Brigham completed this well in February 2001 at an initial test rate
of 7.4 MMcf of natural gas and 90 barrels of condensate per day, or 1.6 MMcfe
per day net to Brigham's 20% revenue interest. Brigham operates this discovery
and began producing the well in mid-March 2001 at a pipeline-curtailed rate of
approximately 2.2 MMcf of natural gas and 75 barrels of oil per day, or 0.5
MMcfe net to Brigham.

      Based on the success of its 2000 drilling activity in this project area,
Brigham plans to drill four to six Springer channel tests in its Huskie Project
in 2001. These wells target similar objectives as its three 2000 producers, and
Brigham expects to retain an working interest of approximately 50% in these
planned wells.

      Wildcat and Panther Projects

      Brigham's Wildcat and Panther Projects consist of 47 and 99 square miles,
respectively, of continuous 3-D seismic data covering approximately 93,440 acres
in the southern portion of the Texas Panhandle in Wheeler County, Texas and
Beckham County, Oklahoma. The primary exploration targets within these projects
are high potential, structural features at depths ranging from 7,500 to 25,000
feet. Brigham initiated acquisition of data in its Wildcat Project in 1997 where
it retained a 37.5% working interest. Based upon the interpretation of this
initial data set, Brigham subsequently acquired data in its adjacent Panther
Project in 1998 where it retained a 100% working interest.

      In July 2000, Brigham spud a high potential Hunton test (64% working
interest) that offsets a currently producing Hunton well that has produced over
15 Bcfe to date in its Wildcat Project. Drilled to a total depth of over 25,000
feet, Brigham completed the well in the targeted Hunton formation in late
December 2000. The well encountered approximately 1,200 feet of gross pay and
340 feet of measured depth net pay (240 feet of calculated true vertical net
pay) in three Hunton intervals. The well began producing to sales from one
Hunton interval in early January 2001 at rates of approximately 9.5 MMcf of
natural gas and 90 barrels of condensate per day, or 5.1 MMcfe per day net to
Brigham's 51% revenue interest. Current plans include stimulation of the two
remaining Hunton pay intervals in the discovery well, and the drilling of at
least one development well during 2001. Brigham has booked estimated proved
reserves of approximately 21 gross Bcfe (or 10.7 net Bcfe) attributable to this
Hunton producer at December 31, 2000. While ultimate recoverable reserves from
this field discovery will be determined by the productivity of this initial well
and future offset locations, Brigham believes this Hunton field could ultimately
produce up to 250 Bcfe of gross unrisked reserves. In addition to this
discovery, Brigham has also assembled a significant acreage position along trend
and may drill another high potential exploratory Hunton test in early 2002.

      Bearcat Project

      Brigham's Bearcat Project consists of approximately 59 square miles of 3-D
seismic data covering approximately 37,760 acres in the prolific Carter-Knox
anticline in Grady County, Oklahoma. This project targets 3-D seismic
amplitude-related shallow Pennsylvanian-aged channel sands and deep marine bar
sands in the Springer section.

      During its 2000 drilling program, Brigham participated in three wells that
have confirmed the discovery of a potentially significant Springer Bar field
that is estimated to be approximately nine miles long and two miles wide. The
initial exploratory test of this 3-D delineated Springer Bar objective, the Nix
#1-20 (20% working interest), encountered approximately 90 feet of Springer-aged
sand that confirmed Brigham's seismic interpretation of this feature. Subsequent
to this initial discovery, Brigham participated in two development wells in this
new field. The Pitchford #1 (32% working interest) reached a total depth of
15,140 feet and logged approximately 31 feet of pay (greater than 8% density
porosity) in the targeted Britt section with significant porosity improvement
relative to the Nix #1-20. After fracture stimulation of this Britt interval,
the well began producing to sales at a rate of approximately 2.2 MMcf of natural
gas and 140 barrels of condensate per day, or approximately 3 MMcfe per day, in
December 2000. The second development


                                     - 11 -

<PAGE>

well, the McCasland Farms #1 (23% working interest) was spud in late October
2000 and is currently being completed and fracture stimulated prior to
commencement of production expected by the end of March 2001. This well logged
32 feet of porosity density greater than 8%, which is comparable to that logged
in the producing Pitchford #1 well.

      Brigham currently owns over 2,500 net acres in nine sections over this
Springer Bar feature, and anticipates participating in up to ten additional
wells to fully develop the field. In its 2001 drilling program, Brigham plans to
participate in the drilling of up to five development wells in this Springer Bar
field with working interests generally ranging from 20% to 25%.

Texas Gulf Coast

      The onshore Texas Gulf Coast region is a high potential, multi-pay
province that lends itself to 3-D seismic exploration due to its substantial
structural and stratigraphic complexity. Brigham was attracted to the Gulf Coast
province because of the opportunity to apply its established 3-D seismic
exploration approach and its exploration staff's extensive Gulf Coast experience
to a prolific, structurally complex province with the potential to discover
significant natural gas reserves and high rate production. Brigham has assembled
a digital data base including geographical, production, geophysical and
geological information that it evaluates on CAEX workstations. Brigham's team of
explorationists has assembled projects in the Expanded Wilcox and Expanded
Vicksburg trends in South Texas, and the Miocene and Upper, Middle, and Lower
Frio trends of the mid-to-southern regions of the Texas Gulf Coast, each of
which are active 3-D seismic exploration trends. The majority of Brigham's
recent activity in this province has been focused in the Expanded Vicksburg and
Frio trends.

      A portion of Brigham's 3-D seismic data acquisition in the Gulf Coast has
been accomplished through participation in certain non-proprietary, or
speculative, seismic programs. By converting certain of Brigham's proprietary
seismic projects in core exploration areas to speculative data, Brigham was able
to leverage these proprietary projects for access to substantially larger
non-proprietary speculative data for minimal or no additional cost. While
increasing its exposure to competition in speculative seismic programs, Brigham
believes this 3-D seismic acquisition strategy in the Gulf Coast, in certain
circumstances, can accelerate the addition of attractive potential drilling
locations in targeted trends at costs that are considerably less than those
associated with proprietary 3-D seismic programs, thereby enhancing expected
project rates of return.

      As of December 31, 2000, Brigham had acquired 1,096 square miles (701,440
acres) of 3-D seismic data in its Texas Gulf Coast province. Through its
drilling efforts in this region from 1996 through 2000, Brigham had completed 46
wells in 60 attempts (77% completion rate) in the Gulf Coast and had discovered
cumulative net proved reserves of approximately 37 Bcfe at an average net
drilling cost of $0.91 per Mcfe. In its Gulf Coast drilling program in 1999 and
2000, Brigham completed 21 wells in 28 attempts (75% completion rate) with an
average working interest of 28% that contributed to the addition of
approximately 13 net Bcfe of proved reserves (including revisions to previous
estimates) at an average net drilling cost of $1.49 per Mcfe.

      Brigham intends to focus the majority of its Texas Gulf Coast province
exploration and development drilling expenditures in the following key project
areas during 2001:

      Diablo Project

      Brigham's Diablo Project covers 57 square miles in Brooks County, Texas,
and targets shallow Frio and deep Vicksburg producing horizons. Brigham is
involved in a joint venture with a major integrated oil company in its Diablo
Project. The project participants jointly control a significant acreage block
and are actively exploring and developing for potential pay below 10,000 feet in
the Vicksburg formation in this project area. Brigham has retained a 34% working
interest in this joint exploration project in which the project participants
control approximately 10,000 gross and net acres of leasehold. However, in
prospective zones above 10,000 feet, primarily the Frio, Brigham has retained a
100% working interest in its original 4,000 acre lease block.


                                     - 12 -

<PAGE>

      In the fourth quarter of 1999, Brigham confirmed a major Lower Vicksburg
field discovery, the Home Run Field, in the Diablo Project with the completion
of the Brigham-operated Palmer State #2 well. The Palmer State #2 encountered
productive reservoirs in four Lower Vicksburg intervals with 210 feet of
potential pay. After completion of successive operations to fracture stimulate
each of these intervals during January and February 2000, the well was
successfully commingled to produce simultaneously from all four Lower Vicksburg
intervals. The Palmer State #2 began flowing to sales as a commingled producer
in late February 2000 at average daily production rates of 10.1 MMcf of natural
gas and 650 barrels of condensate, or approximately 4 MMcfe in total net to
Brigham's 29% revenue interest. In mid-March 2001, this well was producing 3.1
MMcfe per day, or 0.9 MMcfe net to Brigham's revenue interest.

      Brigham spud three development wells in the Home Run Field during 2000.
The first development well, the Palmer State #3, began producing in early August
2000 at an initial rate of 12.3 MMcf of natural gas and 450 barrels of
condensate per day, or 4.4 MMcfe net to Brigham's 29% revenue interest. In late
October 2000, Brigham spud the second development well in the Home Run Field,
the Palmer State #4, which is an updip offset to the Palmer State #2 field
confirmation well. The Palmer State #4 is currently being completed and fracture
stimulated in the target Lower Vicksburg objectives and is expected to be
producing through commingled completions by the end of March 2001. The third
Home Run field development well, the D.J. Sullivan #C-25, was spud in late
December 2000 and is currently being completed with expected commingled
production to sales by April 2001. Brigham retains net revenue interests ranging
from 26% to 29% in each of these three Home Run Field development wells.

      Brigham's 3-D interpretative mapping indicates that the Home Run Field
reservoirs have over 500 feet of relief and cover approximately 1,100 acres with
estimated potential gross reserves ranging from a minimum of 80 Bcfe to over 200
Bcfe (or 23 Bcfe to 58 Bcfe net). Brigham had 16.5 net Bcfe of estimated proved
reserves attributable to the Home Run Field as of December 31, 2000. In addition
to the expected production volume additions from the Palmer State #4 and D.J.
Sullivan #C-25 wells, Brigham's planned drilling program includes two additional
development wells to be drilled in the Home Run Field during 2001.

      The 1,100 acre Home Run Field is located upthrown from two large, untested
3-D delineated Vicksburg structures (Mariposa and Floyd) in adjacent fault
blocks that cover approximately 1,200 acres. Brigham currently plans to spud an
exploratory test of the estimated 1,000 acre Mariposa fault block in the second
quarter of 2001. This 3-D delineated Vicksburg structure is located beneath the
shallower Mariposa Field that has produced in excess of 187 Bcf of natural gas
from the Frio. The estimated 200 acre Floyd fault block is an apparent four-way
Lower Vicksburg closure that Brigham plans to test in early 2002. Brigham
believes that its Home Run Field discovery and subsequent development efforts to
date have significantly enhanced the prospectiveness of each of these large
structural closures. Additional exploratory fault blocks in this project area
are currently being interpreted and may be tested in 2002 and beyond.

      Hawkins Ranch and Millenium Projects

      Brigham's Hawkins Ranch and Millenium Projects consist of 344 square miles
of contiguous non-proprietary 3-D seismic data in the prolific Miocene/Frio
trend in Matagorda County, Texas. Identified prospects in these project areas
target potential in the shallow, nonpressured Frio sands as well as the deeper,
pressured Frio sands. Operators have been actively leasing and drilling within
this acreage during the past three years. This activity has resulted in the
completion of 24 wells in 39 attempts, including the discovery of a 3-D
delineated field that is estimated to contain gross reserves of approximately 40
Bcfe from three wells that have produced at rates in excess of 30 MMcf of
natural gas per day per well. Sustaining these high production rates, these
three wells have produced in excess of 37 Bcfe in less than eighteen months.

      During the fourth quarter of 2000, Brigham participated in the drilling of
a 3-D delineated Frio bright spot discovery in its Millenium Project. This well
was completed in the targeted Frio objective in late December 2000 at daily
rates of approximately 10 MMcf of natural gas and 200 barrels of condensate per
day, or 2.1 MMcfe net to Brigham's 18.75% revenue interest. Based on the success
of this recent discovery, Brigham spud an offsetting Frio bright spot test in
late February 2001. This well was completed in early March 2001 and began
producing at a rate of 17.5 MMcf of natural gas and 290 barrels of condensate
per day, or 4.4 MMcfe net to Brigham's 23% net revenue interest. In addition


                                     - 13 -

<PAGE>

to these recent discoveries, Brigham spud an additional Frio bright spot test in
March 2001 in which it retained a 34% working interest.

      Including the recently spud offset Frio test, Brigham's 2001 drilling
program includes three 3-D seismic amplitude-supported prospects in its Hawkins
Ranch and Millenium Projects that target combined gross unrisked reserve
potential of 18 Bcfe. Brigham expects to retain an average working interest of
approximately 40% in these three planned Frio wells.

West Texas

      Brigham's drilling activity in its West Texas province has been focused
primarily in the Horseshoe Atoll, the Midland Basin and the Eastern Shelf of the
Permian Basin and in the Hardeman Basin. In response to reduced market prices
for oil and comparatively higher potential natural gas projects in its Anadarko
Basin and Gulf Coast provinces, Brigham substantially reduced its 3-D seismic
acquisition and drilling activities in West Texas during 1998 and 1999. Based on
improved oil prices during 2000 and in early 2001, Brigham has begun to
selectively drill certain of its highest grade oil prospects in its West Texas
3-D seismic projects. To date, Brigham has been able to participate in the
drilling of many of these wells saleby selling a portion of its working interest
to industry participants on a promoted basis in which the participants pay a
disproportionate share of the drilling costs.

      As of December 31, 2000, Brigham had acquired 1,689 square miles (1.1
million acres) in the West Texas region. Through its drilling efforts in this
region from 1990 through 2000, Brigham had completed 186 wells in 300 attempts
(62% completion rate) in its West Texas province with an average working
interest of 24% and had found cumulative net proved reserves of 23 Bcfe at an
average net drilling cost of $1.23 per Mcfe. In its substantially reduced
drilling activity in this province during 1999 and 2000, Brigham completed one
well in two attempts (50% completion rate) with an average working interest of
84% that contributed to the addition of 2.9 net Bcfe of proved reserves
(including revisions to previous estimates) at an average net drilling cost of
$0.14 per Mcfe. In December 2000, Brigham spud a Canyon Reef test that was
drilled to a total depth of 9,400 feet. The well was completed as a successful
oil producer in February 2001 after logging over 90 feet of oil pay. In early
March 2001, this well was producing 200 barrels of oil per day, or approximately
140 barrels per day net to Brigham's 71% revenue interest.

      During 2001, Brigham plans to drill three to five wells in its West Texas
3-D project areas. In January 2001, Brigham spud a Fusselman test in its West
Texas province in which it retained a 55% working interest. This well logged
nine feet of pay and is expected to be completed as a producer by the end of
March 2001.

Oil and Natural Gas Reserves

      Brigham's estimated total net proved reserves of oil and natural gas as of
December 31, 1998, 1999 and 2000 and the present values attributable to these
reserves as of those dates were as follows:

<TABLE>
<CAPTION>
                                                             As of December 31,
                                                   ------------------------------------
                                                     1998         1999           2000
                                                   --------     ---------     ---------
      <S>                                          <C>          <C>           <C>
      Estimated net proved reserves:
        Natural gas (MMcf) ....................      71,166        65,457        78,167
        Oil (MBbls) ...........................       4,433         3,027         2,870
        Natural gas equivalent (MMcfe) ........      97,764        83,618        95,388
      Proved developed reserves as a percentage
        of proved reserves ....................          57%           48%           52%
      Present Value of Future Net Revenues
        (in thousands) ........................    $ 81,741     $ 114,466     $ 497,666
      Standardized Measure (in thousands) .....    $ 81,649     $ 113,546     $ 359,228
</TABLE>

      The reserve estimates reflected above were prepared by Cawley, Gillespie &
Associates, Inc. ("Cawley Gillespie"), Brigham's petroleum consultants, and are
part of reports on Brigham's oil and natural gas properties prepared by Cawley


                                     - 14 -

<PAGE>

Gillespie. The base sales prices for Brigham's reserves were $2.12 per Mcf for
natural gas and $9.50 per Bbl for oil as of December 31, 1998, $2.35 per Mcf for
natural gas and $22.75 per Bbl for oil as of December 31, 1999, and $10.42 per
Mcf for natural gas and $26.83 per Bbl for oil as of December 31, 2000. These
base prices were adjusted to reflect applicable transportation and quality
differentials on a well-by-well basis to arrive at realized sales prices used to
estimate Brigham's reserves at these dates.

      In accordance with applicable requirements of the SEC, estimates of
Brigham's proved reserves and future net revenues are made using sales prices
estimated to be in effect as of the date of such reserve estimates and are held
constant throughout the life of the properties (except to the extent a contract
specifically provides for escalation). Estimated quantities of proved reserves
and future net revenues therefrom are affected by oil and natural gas prices,
which have fluctuated widely in recent years. There are numerous uncertainties
inherent in estimating oil and natural gas reserves and their estimated values,
including many factors beyond Brigham's control. The reserve data set forth in
this Form 10-K represent only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geologic
interpretation and judgment. As a result, estimates of different engineers,
including those used by Brigham, may vary. In addition, estimates of reserves
are subject to revision based upon actual production, results of future
development and exploration activities, prevailing oil and natural gas prices,
operating costs and other factors. The revisions may be material. Accordingly,
reserve estimates are often different from the quantities of oil and natural gas
that are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based. Brigham's estimated proved reserves have
not been filed with or included in reports to any federal agency. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Risk Factors -- We Are Subject To Uncertainties In Reserve
Estimates And Future Net Cash Flows."

      Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations in the estimated reserves that may
be substantial.


                                     - 15 -

<PAGE>

Drilling Activities

      Brigham drilled, or participated in the drilling of, the following number
of wells during the periods indicated:

                                                Year Ended December 31,
                                    --------------------------------------------
                                         1998            1999         2000 (1)
                                    -------------   -------------  -------------
                                    Gross     Net   Gross     Net  Gross     Net
                                    -----     ---   -----     ---  -----     ---
Exploratory Wells (2):
Natural gas .....................     30     15.6      8      3.4     6      1.9
Oil .............................      7      2.5      2      0.1     3      0.9
Non-productive ..................     17      8.0      7      2.4     2      1.0
                                      --     ----     --      ---    --      ---
    Total .......................     54     26.1     17      5.9    11      3.8
                                      ==     ====     ==      ===    ==      ===
Development Wells (3):
Natural gas .....................     10      6.6      8      2.3    14      5.7
Oil .............................      3      1.5      1      0.5     1      0.7
Non-productive ..................      5      3.4      1      0.6     1      0.8
                                      --     ----     --      ---    --      ---
    Total .......................     18     11.5     10      3.4    16      7.2
                                      ==     ====     ==      ===    ==      ===

----------
(1)   Excludes one gross (1.0 net) exploratory well that was temporarily
      abandoned during drilling due to operational difficulties encountered
      prior to reaching total depth, and one gross (0.1 net) development well
      that was in the process of drilling at March 20, 2001. Brigham plans to
      re-enter the temporarily abandoned well to test the target natural gas
      objective during 2001.
(2)   From January 1, 2001 through March 20, 2001, Brigham drilled, or
      participated in the drilling of, five gross (2.4 net) exploratory wells,
      of which two gross (1.3 net) were completed as oil wells, two gross net)
      were non-productive, and one gross (0.3 net) was in the process of
      drilling at March 20, 2001.
(3)   From January 1, 2001 through March 20, 2001, Brigham drilled, or
      participated in the drilling of, five gross net) development wells, of
      which one gross (0.3 net) was completed as a natural gas well, one gross
      (0.04 net) was non-productive, and three gross (1.5 net) were in the
      process of drilling at March 20, 2001.

      Brigham does not own any drilling rigs, and the majority of its drilling
activities have been conducted by industry participant operators or independent
contractors under standard drilling contracts. Consistent with its business
strategy, Brigham has continued to retain operations of an increasing number of
the wells it drills. Brigham operated 55% of the gross and 82% of the net wells
it participated in during 2000.


                                     - 16 -

<PAGE>

Productive Wells and Acreage

Productive Wells

      The following table sets forth Brigham's ownership interest as of December
31, 2000 in productive oil and natural gas wells in the areas indicated.

<TABLE>
<CAPTION>
                                                  Natural Gas          Oil          Total
                                                 -------------    ------------    -----------
                                                 Gross     Net    Gross    Net    Gross   Net
                                                 -----     ---    -----    ---    -----   ---
      <S>                                        <C>     <C>     <C>    <C>     <C>    <C>
      Province:
      Anadarko Basin .........................    63      21.3     10     2.8     73    24.1
      Texas Gulf Coast .......................    23       7.9     12     2.0     35     9.9
      West Texas .............................    12       1.7     76    22.4     88    24.1
      Other ..................................    --        --      2     0.7      2     0.7
                                                  --      ----    ---    ----    ---    ----
          Total ..............................    98      30.9    100    27.9    198    58.8
                                                  ==      ====    ===    ====    ===    ====
</TABLE>

      Productive wells consist of producing wells and wells capable of
production, including wells waiting on pipeline connection. Wells that are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, none had multiple completions.

Acreage

      Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves. The following table sets forth the approximate
developed and undeveloped acreage in which Brigham held a leasehold, mineral or
other interest at December 31, 2000:

<TABLE>
<CAPTION>
                                                     Developed          Undeveloped             Total
                                                 ----------------    -----------------    -----------------
                                                  Gross      Net      Gross      Net       Gross      Net
                                                 -------   ------    -------    ------    -------    ------
      <S>                                        <C>       <C>       <C>        <C>       <C>        <C>
      Province:
      Anadarko Basin ........................    29,387    11,269     55,601    36,850     84,988    48,119
      Gulf Coast ............................     2,484     1,050     24,335    13,925     26,819    14,975
      West Texas ............................     6,089     1,784     13,372     4,735     19,461     6,519
      Other .................................       480       148      7,350     2,576      7,830     2,724
                                                 ------    ------    -------    ------    -------    ------
          Total .............................    38,440    14,251    100,658    58,086    139,098    72,337
                                                 ======    ======    =======    ======    =======    ======
</TABLE>

      All the leases for the undeveloped acreage summarized in the preceding
table will expire at the end of their respective primary terms unless the
existing leases are renewed, production has been obtained from the acreage
subject to the lease prior to that date, or some other "savings clause" is
implicated. The following table sets forth the minimum remaining terms of leases
for the gross and net undeveloped acreage:

                                                                 Acres Expiring
                                                               -----------------
                                                                Gross       Net
                                                               -------    ------
      Twelve Months Ending:
      December 31, 2001 ...................................     52,860    31,645
      December 31, 2002 ...................................     10,831     5,366
      December 31, 2003 ...................................      3,534     1,689
      Thereafter ..........................................     33,433    19,386
                                                               -------    ------
          Total ...........................................    100,658    58,086
                                                               =======    ======


                                     - 17 -

<PAGE>

      In addition, Brigham had lease options as of December 31, 2000 to acquire
an additional 622 gross and net acres, all of which expire in April 2001.

Volumes, Prices and Production Costs

      The following table sets forth the production volumes, average prices
received and average production costs associated with Brigham's sale of oil and
natural gas for the periods indicated.

<TABLE>
<CAPTION>
                                                                                 Year Ended December 31,
                                                                          -----------------------------------
                                                                            1998         1999         2000
                                                                          ---------    ---------    ---------
      <S>                                                                 <C>          <C>          <C>
      Production:
         Natural gas (MMcf) ..................................                4,269        4,197        4,431
         Oil (MBbls) .........................................                  396          346          362
         Natural gas equivalent (MMcfe) ......................                6,644        6,270        6,600
      Average sales price:
         Natural gas (per Mcf) ...............................            $    2.04    $    2.11    $    1.94
         Oil (per Bbl) .......................................            $   12.85    $   17.79    $   29.17
      Average production costs:
         Lease operating expenses (per Mcfe) .................            $    0.33    $    0.36    $    0.32
         Production taxes (per Mcfe) .........................            $    0.13    $    0.15    $    0.27
</TABLE>

Costs Incurred

      The costs incurred in oil and natural gas acquisition, exploration and
development activities are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                              Year Ended December 31,
                                                                      ----------------------------------
                                                                         1998       1999 (1)     2000 (2)
                                                                      --------     --------     --------
      <S>                                                             <C>          <C>          <C>
      Exploration .............................................       $ 68,214     $ 19,224     $ 14,238
      Property acquisition ....................................         16,245        3,462        2,540
      Development .............................................         10,475        4,632       12,555
      Proceeds from participants ..............................        (10,502)      (2,439)         (40)
                                                                      --------     --------     --------
            Costs incurred ....................................       $ 84,432     $ 24,879     $ 29,293
                                                                      ========     ========     ========
</TABLE>

----------
(1)   Excludes $27.1 million of proceeds from the sale of interests in
      properties, projects and prospects in 1999.
(2)   Excludes $3.9 million of proceeds from the sale of interests in
      properties, projects and prospects in 2000.

      Costs incurred represent amounts incurred by Brigham for exploration,
property acquisition and development activities. Periodically, Brigham will
receive reimbursement of certain costs from participants in its projects
subsequent to project initiation in return for an interest in the project. These
payments are described as "Proceeds from participants" in the table above.

ITEM 3. LEGAL PROCEEDINGS

      Brigham is not a party to any material legal proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

      No matter was submitted to a vote of Brigham's securityholders during the
fourth quarter of 2000.


                                     - 18 -

<PAGE>

EXECUTIVE OFFICERS OF THE REGISTRANT

      Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this report.

      The following table sets forth certain information concerning Brigham's
executive officers as of March 20, 2001:

<TABLE>
<CAPTION>
                     Name               Age                          Position
              --------------------     ------   -----------------------------------------------------
              <S>                       <C>     <C>
              Ben M. Brigham            41      Chief Executive Officer, President and Chairman
              Curtis F. Harrell         37      Executive Vice President, Chief Financial Officer and
                                                Director
              David T. Brigham          40      Senior Vice President - Land and Administration,
                                                Corporate Secretary
              A. Lance Langford         38      Senior Vice President - Operations
              Jeffery E. Larson         42      Senior Vice President - Exploration
              Karen E. Lynch            39      Vice President - Legal and General Counsel
              Christopher A. Phelps     30      Vice President - Finance and Strategic Planning
</TABLE>

      Set forth below is a description of the backgrounds of Brigham's executive
officers.

      Ben M. "Bud" Brigham has served as Chief Executive Officer, President and
Chairman of the Board since founding the Company in 1990. From 1984 to 1990, Mr.
Brigham served as an exploration geophysicist with Rosewood Resources, an
independent oil and gas exploration and production company. Mr. Brigham began
his career in Houston as a seismic data processing geophysicist for Western
Geophysical, a provider of 3-D seismic services, after earning his B.S. in
Geophysics from the University of Texas. Mr. Brigham is the husband of Anne L.
Brigham, Director, and the brother of David T. Brigham, Vice President -- Land
and Administration and Corporate Secretary.

      Curtis F. Harrell has served as Chief Financial Officer and Director of
Brigham since August 1999, and as Executive Vice President since March 2001.
From 1997 to August 1999, he was Executive Vice President and Partner at R.
Chaney & Company, Inc., an equity investment firm focused on the energy
industry, where he managed the firm's investment origination efforts in the
U.S., focusing on investments in corporate equity securities of energy companies
in the exploration and production and oilfield service industry segments. From
1995 to 1997, Mr. Harrell was a Director of Domestic Corporate Finance for Enron
Capital & Trade Resources, Inc., where he was responsible for initiating and
executing a variety of debt and equity financing transactions for independent
exploration and production companies. Before joining Enron Capital & Trade
Resources, Mr. Harrell spent eight years working in corporate finance and
reservoir engineering positions for two public independent exploration and
production companies, Kelley Oil & Gas Corporation and Pacific Enterprises Oil
Company, Inc. He has a B.S. in Petroleum Engineering from the University of
Texas at Austin and an M.B.A. from Southern Methodist University.

      David T. Brigham joined the Company in 1992 and has served as Senior Vice
President -- Land and Administration and Corporate Secretary since March 2001.
Mr. Brigham served as Vice President -- Land and Administration and Corporate
Secretary from February 1998 to March 2001, and as Vice President -- Land and
Legal of the Company from 1994 until February 1998. From 1987 to 1992, Mr.
Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels &
Wooldridge. Before attending law school, Mr. Brigham was a landman for Wagner &
Brown Oil and Gas Producers, an independent oil and gas exploration and
production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from
the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is
the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman
of the Board.

      A. Lance Langford joined Brigham as Manager of Operations in 1995 and has
served as Vice President -- Operations from January 1997 to March 2001, and as
Senior Vice President - Operations since March 2001. From 1987 to 1995, Mr.
Langford served in various engineering capacities with Meridian Oil Inc.,
handling a variety of reservoir, production and drilling responsibilities. Mr.
Langford holds a B.S. in Petroleum Engineering from Texas Tech University.


                                     - 19 -

<PAGE>

      Jeffery E. Larson joined Brigham in 1997 and has served as Vice President
-- Exploration from August 1999 to March 2001, and as Senior Vice President --
Exploration since March 2001. Mr. Larson joined Brigham in October 1997 as Gulf
Coast Exploration Manager in its Houston office where he co-managed Brigham's
expansion into the onshore Gulf Coast province through the initiation and
assemblage of 3-D seismic projects and drilling opportunities. In November 1998,
Mr. Larson relocated to Brigham's corporate office in Austin where he assumed an
expanded role in directing Brigham's exploration activities in the Anadarko
Basin, in addition to the further advancement of its Gulf Coast activities.
Prior to joining Brigham, Mr. Larson was an explorationist in the Offshore
Department of Burlington Resources, a large independent exploration company,
where he was responsible for generating exploration and development drilling
opportunities. Mr. Larson worked at Burlington for seven years in various roles
of increasing responsibility within its exploration department. Prior to
Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and
Research Scientist. He has a B.S. in Earth Science from St. Cloud State
University in Minnesota and a M.S. in Geology from the University of Montana.

      Karen E. Lynch joined Brigham in October 1997 as General Counsel and has
served as Vice President -- Legal and General Counsel since February 1998. Prior
to joining Brigham, Ms. Lynch was a shareholder in the Dallas-based law firm of
Thompson & Knight, P.C., where she practiced in the energy area since joining
the firm in 1987. Ms. Lynch holds a B.B.A. in Petroleum Land Management from the
University of Texas and a J.D. from the University of Oklahoma.

      Christopher A. Phelps joined Brigham as Manager of Finance and Investor
Relations in January 1998 and has served as Vice President -- Finance and
Strategic Planning since August 1999. Prior to joining Brigham, Mr. Phelps was a
Vice President in the Investment Banking Department of Bear, Stearns & Co. Inc.,
a major international securities brokerage and investment banking firm, where he
spent over five years executing a variety of capital raising and mergers and
acquisition transactions principally for independent exploration and production
companies. He holds a B.B.A. in Finance from the University of Texas at Austin.


                                     - 20 -

<PAGE>

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

      Brigham's common stock has been publicly traded on The Nasdaq Stock
Market(SM) under the symbol "BEXP" since Brigham's initial public offering
effective May 8, 1997. The following table summarizes the high and low last
reported sales prices of Brigham's common stock on Nasdaq for each quarterly
period during the past two fiscal years:

<TABLE>
<CAPTION>
                                                                    1999                 2000
                                                             -----------------    -----------------
                                                              High        Low     High         Low
                                                             -----       -----    -----       -----
      <S>                                                    <C>         <C>      <C>         <C>
      First Quarter...................................       $6.00       $2.75    $2.88       $1.47
      Second Quarter..................................       $3.25       $0.88    $2.88       $1.88
      Third Quarter...................................       $3.31       $1.94    $3.50       $2.00
      Fourth Quarter..................................       $2.72       $1.00    $6.00       $2.00
</TABLE>

      The closing market price of Brigham's common stock on March 20, 2001 was
$4.00 per share. As of March 20, 2001, there were an estimated 118 record owners
of Brigham's common stock.


      No dividends have been declared or paid on Brigham's common stock to date.
Brigham intends to retain all future earnings for the development of its
business. In addition, the Senior Credit Facility (as defined) and the
Subordinated Notes Facility (as defined) restrict Brigham's ability to pay
dividends on its common stock.

      On November 2, 2000, Brigham announced that it had entered into a series
of financing agreements to provide funding (i) to repurchase all the debt and
equity securities in Brigham held by affiliates of Enron North America at a
substantial discount and (ii) to continue and expand Brigham's planned drilling
program into 2001. These transactions included the issuance of the securities
described below. No underwriters were involved, and therefore no underwriting
commissions or discounts were paid in connection with the privately placed
notes, preferred stock and warrants. The sales of these securities were made in
reliance upon the exemption from the registration provisions of the Securities
Act of 1933, as amended, provided by Section 4(2) thereof for transactions not
involving a public offering.

      Subordinated Notes Facility and Warrants. On October 31, 2000, Brigham
entered into a new subordinated notes facility with Shell Capital Inc. that
provided for $20 million in borrowings. In connection with this new credit
facility, Brigham issued to Shell Capital warrants to purchase an aggregate of
1,250,000 shares of Brigham common stock at an exercise price of $3.00 per
share. Terms of the warrants are described below under "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources -- Refinancing Transactions."

      Series A Preferred Stock and Warrants. On November 1, 2000, Brigham issued
to affiliates of Credit Suisse First Boston (USA), Inc. an aggregate of
1,000,000 shares of its Series A Preferred Stock and warrants to purchase an
aggregate of 6,666,667 shares of Brigham common stock at an exercise price of
$3.00 per share, for a cash purchase price of $20 million. Terms of the warrants
are described below under "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital Resources
-- Refinancing Transactions."

                                     - 21 -

<PAGE>

ITEM 6. SELECTED FINANCIAL DATA

      The following selected consolidated financial data should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Brigham's consolidated financial
statements and related notes included in "Item 8. Financial Statements and
Supplementary Data."

<TABLE>
<CAPTION>
(in thousands, except per share data)                                                       Year Ended December 31,
                                                                       ------------------------------------------------------------
                                                                         1996         1997         1998         1999         2000
                                                                       --------     --------     --------     --------     --------
<S>                                                                    <C>          <C>          <C>          <C>          <C>
Statement of Operations Data:
Revenues:
Oil and natural gas sales .........................................    $  6,141     $  9,184     $ 13,799     $ 14,992     $ 19,143
Workstation revenue ...............................................         627          637          390          285           53
                                                                       --------     --------     --------     --------     --------
     Total revenues ...............................................       6,768        9,821       14,189       15,277       19,196

Costs and expenses:
Lease operating ...................................................         726        1,151        2,172        2,259        2,139
Production taxes ..................................................         362          549          850          968        1,786
General and administrative ........................................       2,199        3,570        4,672        3,481        3,100
Depletion of oil and natural gas properties .......................       2,323        2,743        8,483        7,792        7,920
Depreciation and amortization .....................................         487          306          413          525          507
Capitalized ceiling impairment ....................................          --           --       25,926           --           --
Amortization of stock compensation ................................          --          388          372            1          113
                                                                       --------     --------     --------     --------     --------
     Total costs and expenses .....................................       6,097        8,707       42,888       15,026       15,565
                                                                       --------     --------     --------     --------     --------

     Operating income (loss) ......................................         671        1,114      (28,699)         251        3,631

Other income (expense):
Interest expense, net .............................................      (1,173)      (1,190)      (5,968)      (9,697)      (9,906)
Interest income ...................................................          52          145          136          176          108
Other expense .....................................................          --           --           --         (163)      (9,488)
Loss on sale of oil and natural gas properties ....................          --           --           --      (12,195)          --
                                                                       --------     --------     --------     --------     --------
     Total other income (expense) .................................      (1,121)      (1,045)      (5,832)     (21,879)     (19,286)
                                                                       --------     --------     --------     --------     --------

Income (loss) before income taxes and extraordinary item ..........        (450)          69      (34,531)     (21,628)     (15,655)
Income tax benefit (expense) ......................................          --       (1,186)       1,186           --           --
                                                                       --------     --------     --------     --------     --------
     Loss before extraordinary item ...............................        (450)      (1,117)     (33,345)     (21,628)     (15,655)
Extraordinary item - gain on refinancing of debt, net of tax ......          --           --           --           --       32,267
                                                                       --------     --------     --------     --------     --------
     Net income (loss) ............................................        (450)      (1,117)     (33,345)     (21,628)      16,612
Preferred dividend and accretion ..................................          --           --           --           --          275
                                                                       --------     --------     --------     --------     --------
     Net income (loss) attributable to common stockholders ........    $   (450)    $ (1,117)    $(33,345)    $(21,628)    $ 16,337
                                                                       ========     ========     ========     ========     ========

Net income (loss) per share - basic and diluted ...................    $  (0.05)    $  (0.10)    $  (2.64)    $  (1.53)    $   1.01
Weighted average shares outstanding - basic and diluted ...........       8,929       11,081       12,626       14,152       16,241

Statement of Cash Flows Data:
Net cash provided (used) by operating activities ..................    $  3,710     $  9,806     $ 14,774     $  2,578     $ (4,635)
Net cash provided (used) by investing activities ..................     (11,796)     (57,300)     (86,227)       1,644      (26,071)
Net cash provided (used) by financing activities ..................       7,731       47,748       72,321       (4,049)      28,801

Other Financial Data:
Oil and natural gas capital expenditures ..........................    $ 13,612     $ 57,170     $ 85,207     $ 25,560     $ 28,910

<CAPTION>
                                                                                             As of December 31,
                                                                       ------------------------------------------------------------
                                                                         1996         1997         1998         1999         2000
                                                                       --------     --------     --------     --------     --------
<S>                                                                    <C>          <C>          <C>          <C>          <C>
Balance Sheet Data:
Cash and cash equivalents .........................................    $  1,447     $  1,701     $  2,569     $  2,742     $    837
Oil and natural gas properties, net ...............................      28,005       84,294      134,317      112,066      129,490
Total assets ......................................................      33,614       92,519      150,516      125,683      146,911
Long-term debt, net ...............................................      24,000       32,000       94,786       97,341       82,000
Total stockholders' equity ........................................       3,244       43,313       24,681        8,998       34,757
</TABLE>


                                     - 22 -

<PAGE>

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

Overview

      Brigham is an independent exploration and production company that applies
3-D seismic imaging and other advanced technologies to systematically explore
and develop onshore oil and natural gas provinces in the United States. From
inception in 1990 through December 31, 2000, Brigham acquired 5,122 square miles
of 3-D seismic data and drilled 498 wells delineated by 3-D seismic analysis.
Through its 3-D seismic-based drilling efforts, Brigham has discovered an
aggregate of 139 Bcfe of net proved reserves as of December 31, 2000, at an
average net drilling cost of $0.75 per Mcfe.

      Combining its geologic and geophysical expertise with a sophisticated land
effort, Brigham manages the majority of its projects from conception through 3-D
acquisition, processing and interpretation and leasing. In addition, Brigham
manages the negotiation and drafting of most of its geophysical exploration
agreements, resulting in reduced contract risk and more consistent deal terms.
Because it generates most of its projects, Brigham can often control the size of
the working interest that it retains as well as the selection of the operator
and the non-operating participants. Consistent with its business strategy,
Brigham has increased the working interest it retained in its projects, based on
capital availability and perceived risk. Brigham's average working interest in
its 3-D seismic projects acquired during 1996, 1997 and 1998 was 37%, 66% and
81%, respectively, while its average working interest in its wells drilled
during this period was 24%, 39% and 52%, respectively. Brigham did not acquire
any new 3-D seismic in 1999 and 2000, and its average working interest in its
wells drilled during these periods was 34% and 42%, respectively. Beginning in
1995, Brigham has managed operations through the drilling and production phases
on an increasing portion of its 3-D seismic projects. Brigham operated 55% of
its gross wells and 82% of its net wells drilled in 2000 as compared with 10% of
its gross wells and 17% of its net wells drilled in 1996.

      Expenditures made in oil and natural gas exploration vary from project to
project depending primarily on the costs related to seismic acquisition, land
and drilling, and the working interest retained by Brigham. Prior to 1997,
Brigham's participants typically bore a disproportionate share of the costs of
optioning available acreage and acquiring, processing and interpreting the 3-D
seismic data, and Brigham and its participants each typically incurred leasing,
drilling and completion costs in proportion to their ownership interests. In
1997 and 1998, Brigham retained majority working interests in its new 3-D
seismic projects, and thereby reduced the financial leverage it historically
received on the costs of optioning available acreage and acquiring, processing
and interpreting the 3-D seismic data on its projects.

      From inception through 1996, Brigham acquired 2,762 gross (781 net) square
miles of 3-D seismic data. Initially, Brigham focused its exploration efforts in
West Texas. Since 1996, Brigham has devoted the majority of its resources to the
Anadarko Basin and Gulf Coast. With this shift in regional focus, the majority
of Brigham's production volumes have shifted from oil to natural gas. To finance
these project generation and drilling activities, Brigham supplemented cash flow
from operations with private placements of debt and equity, commercial bank
credit facilities and placements of working interests in projects with industry
participants. As Brigham's cash flows from operations and other sources of
capital have increased during this period, it retained larger average working
interests in its projects.

      In 1997 and 1998, Brigham acquired 2,360 gross (1,727 net) square miles of
3-D seismic and continued to focus the majority of its 3-D exploration efforts
in the Anadarko Basin and the Gulf Coast. During these two years, Brigham
acquired 1,196 square miles (51%) of 3-D seismic in the Anadarko Basin, making
this basin its most active 3-D seismic acquisition province. Brigham also
significantly increased its Gulf Coast activity, acquiring 942 square miles
(40%) of 3-D seismic during this period. During 1997 and 1998, Brigham drilled
145 gross (65.9 net) wells based on its 3-D seismic data analysis. In addition
to its drilling activities, Brigham acquired 21.3 net Bcfe of proved reserves
and an interest in undeveloped acreage (the "Chitwood Acquisition") at the
northern end of the Carter-Knox anticline in Grady County, Oklahoma for $13.4
million in November 1997. As a result of these activities, Brigham's net oil and
natural gas production increased from 2.1 Bcfe in 1996 to 6.6 Bcfe in 1998.
Brigham's net production volumes consisted of 79% natural gas on an equivalent
basis during the fourth quarter 1998 as compared with 36% during the fourth
quarter 1996.


                                     - 23 -

<PAGE>

Brigham supplemented cash flow from operations in 1997 and 1998 with borrowings
under commercial bank credit facilities, $24 million raised in its initial
public offering of common stock in May 1997, $47.5 million raised through the
placement of debt and equity securities in August 1998 and the placement of
working interests in projects to industry participants to finance its project
generation, property acquisition and drilling activities.

     Brigham implemented a number of strategic initiatives during 1999 and 2000
to generate capital resources to fund its continuing exploration program while
reducing its level of indebtedness. These objectives and results accomplished
for each include:

o     Focusing All Planned Exploration Efforts to the Drilling of Highest-Grade
      3-D Prospects in its Anadarko Basin and Gulf Coast Projects. During 1999
      and 2000, Brigham directed the vast majority of its resources to the
      drilling of identified prospects within natural gas trends where it had
      achieved historical drilling success. In addition, Brigham's drilling
      program during this time period consisted of a more balanced mix of
      exploration and development drilling projects as compared with prior
      drilling activity that was predominately exploratory in nature. This
      focused drilling emphasis contributed to substantially improved returns on
      Brigham's drilling investments during 1999 and 2000, with average drilling
      costs of $0.62 per Mcfe and average all-in finding costs of $0.85 per Mcfe
      in this two-year period.

o     Eliminating Substantially All Seismic and Land Expenditures for New
      Projects. In an effort to devote the majority of its capital resources to
      the drilling of its identified prospect locations, Brigham did not acquire
      any new 3-D seismic data in 1999 and 2000. In addition to executing a
      high-graded drilling program, Brigham's staff of explorationists continued
      to interpret previously acquired 3-D seismic data within existing projects
      to further delineate and refine pre-drill analysis of potential drilling
      locations in its focus project areas.

o     Divesting Certain Producing Oil and Natural Gas Properties. In June 1999,
      Brigham sold interests in certain non-operated properties in two project
      areas (the Chitwood Field and the Red Deer Creek Field) in its Anadarko
      Basin province for a total of $17.1 million. These properties had
      estimated net proved reserves of 36 Bcfe as of June 1, 1999, of which
      approximately 67% were non-producing, and were producing an estimated 2.8
      net MMcfe per day at the time of the sales. After application of the net
      proceeds received from these sales to the repayment of a portion of its
      outstanding borrowings under its bank credit facility, Brigham was able to
      increase its available borrowings under its bank credit facility by $8
      million. The increase in bank borrowing capacity resulting primarily from
      these property sales was utilized to fund a substantial portion of
      Brigham's capital expenditures during the second half of 1999.

o     Restructuring its Senior and Subordinated Debt Agreements. Working closely
      with its senior and subordinated lenders in 1999 and early 2000, Brigham
      was able to amend its senior credit facility and the indenture for its
      then outstanding subordinated notes due 2003 to provide for increased
      borrowing availability and financial flexibility to preserve cash flow to
      fund its exploration activities. During 2000, Brigham completed several
      financing transactions, including the refinancing of its subordinated
      notes due 2003 at a substantial discount, that resulted in lower debt
      levels while providing funding for its 2000 and 2001 capital expenditure
      programs. See "-- Liquidity and Capital Resources."

o     Implementing an Overhead Reduction Plan. Brigham implemented several
      initiatives during 1999 that were designed to reduce general and
      administrative expenses and thereby increase cash flow from operations.
      These cost reduction initiatives included a company-wide salary reduction
      effective in May 1999, the elimination of employee bonuses for 1999,
      subleasing a portion of Brigham's office space, certain personnel
      reductions and the elimination or reduction of various other discretionary
      expenses. As a result of these actions, Brigham's total general and
      administrative expenses (including amounts capitalized) were reduced 33%
      from the fourth quarter 1998 to the fourth quarter 1999, while per unit
      net general and administrative expenses decreased 43% from $0.92 per Mcfe
      to $0.52 per Mcfe during these same periods. Brigham continued its focus
      on minimizing discretionary overhead expenses during 2000. These
      continuing efforts resulted in a 6% reduction in total general and
      administrative expenses (including amounts capitalized) in 2000 as
      compared with 1999, while per unit net general and


                                     - 24 -

<PAGE>

      administrative expenses were further reduced by 16% from $0.56 per Mcfe to
      $0.47 per Mcfe during these same periods.

o     Raising Equity Capital. During 1999 and 2000, Brigham raised in excess of
      $15 million through the sale of interests in non-producing assets,
      primarily project and prospect equity sales to industry participants. In
      addition, Brigham issued $4.2 million of common stock to Veritas DGC Land,
      Inc. ("Veritas") to satisfy payment obligations due to Veritas for seismic
      acquisition and processing services performed prior to 1999 and certain
      seismic processing services performed during 1999. In connection with its
      series of financing transactions effected in 2000 to fund its exploration
      and development program and to refinance its subordinated notes due 2003,
      Brigham raised $24.5 million through private placements of common and
      preferred stock. See "-- Liquidity and Capital Resources."

      Brigham uses the full cost method of accounting for oil and natural gas
properties. Under this method, all acquisition, exploration and development
costs, including payroll, interest, and other internal costs, incurred for the
purpose of finding oil and natural gas reserves are capitalized. Internal costs
capitalized are directly attributable to acquisition, exploration and
development activities and do not include costs related to production, general
corporate overhead or similar activities. Costs associated with production and
general corporate activities are expensed in the period incurred. Proceeds from
the sale of oil and natural gas properties are applied to reduce the capitalized
costs of oil and natural gas properties unless the sale would significantly
alter the relationship between capitalized cost and proved reserves, in which
case a gain or loss is recognized.

      To the extent that the costs capitalized in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate and based on period-end oil and natural
gas prices) of estimated future net after-tax cash flows from proved oil and
natural gas reserves plus the capitalized cost of unproved properties, such
costs are charged to operations as a writedown of the carrying value of oil and
natural gas properties, or a "capitalized ceiling impairment" charge. The risk
that Brigham will be required to write down the carrying value of its oil and
gas properties increases when oil and gas prices are depressed, even if such
prices are temporary. In addition, capitalized ceiling impairment charges may
occur if Brigham experiences poor drilling results or has substantial downward
revisions in its estimated proved reserves. A capitalized ceiling impairment is
a charge to earnings that does not impact cash flows, but does impact operating
income and stockholders' equity. Once incurred, a capitalized ceiling impairment
charge to oil and natural gas properties cannot be reversed at a later date.
Primarily as a result of the significant declines in both oil and natural gas
prices at December 31, 1998 and disappointing drilling results on several high
working interest wells in 1998, Brigham recorded a capitalized ceiling
impairment charge at December 31, 1998 of $25.9 million. No assurance can be
given that Brigham will not experience a capitalized ceiling impairment charge
in future periods. See "-- Risk Factors -- Exploratory Drilling Is A Speculative
Activity Involving Numerous Risks And Uncertain Costs; We Are Dependent On
Exploratory Drilling Activities"; "-- Risk Factors -- Volatility Of Oil And Gas
Markets Affects Us; Oil And Natural Gas Prices Are Volatile"; and "-- Risk
Factors -- We Are Subject To Uncertainties In Reserve Estimates And Future Net
Cash Flows."


                                     - 25 -

<PAGE>

Results of Operations

      The following table sets forth certain operating data for the periods
presented.

<TABLE>
<CAPTION>
                                                                                           Year Ended December 31,
                                                                              -----------------------------------------------
                                                                                 1998              1999               2000
                                                                              ---------          ---------          ---------
      <S>                                                                     <C>                <C>                <C>
      Production:
           Natural gas (MMcf) .......................................             4,269              4,197              4,431
           Oil (MBbls) ..............................................               396                346                362
           Natural gas equivalent (MMcfe) ...........................             6,644              6,270              6,600
           % Natural gas ............................................                64%                67%                67%
      Average sales prices per unit (1):
           Natural gas (per Mcf) ....................................         $    2.04          $    2.11          $    1.94
           Oil (per Bbl) ............................................             12.85              17.79              29.17
           Natural gas equivalent (per Mcfe) ........................              2.08               2.39               2.90
      Costs and expenses per Mcfe:
           Lease operating ..........................................         $    0.33          $    0.36          $    0.32
           Production taxes .........................................              0.13               0.15               0.27
           General and administrative ...............................              0.70               0.56               0.47
           Depletion of oil and natural gas properties ..............              1.28               1.24               1.20
</TABLE>

----------
(1)   Reflects the effects of Brigham's hedging activities. See "Item 7.
      Management's Discussion and Analysis of Financial Condition and Results of
      Operations -- Other Matters -- Derivative Instruments."

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

      Oil and natural gas sales. Oil and natural gas sales increased 28% from
$15.0 million in 1999 to $19.1 million in 2000. An increase in the average
equivalent sales price received for oil and natural gas sales accounted for $3.4
million of this increase and the remaining $780,000 of this increase was the
result of higher net equivalent production volumes.

      Natural gas production volumes increased 6% from 4,197 MMcf in 1999 to
4,431 MMcf in 2000, while the average price received for natural gas decreased
8% from $2.11 per Mcf in 1999 to $1.94 per Mcf in 2000. Natural gas production
volumes during 1999 included 442 MMcf attributable to properties sold by Brigham
in June 1999. Excluding production attributable to these divested properties,
natural gas production volumes increased 18% in 2000 as compared with adjusted
production volumes in 1999.

      Oil production volumes increased 5% from 346 MBbls in 1999 to 362 MBbls in
2000, while the average price received for oil increased 64% from $17.79 per Bbl
in 1999 to $29.17 per Bbl in 2000. Oil production volumes during 1999 included
22 MBbls attributable to properties sold by Brigham in June 1999. Excluding
production attributable to these divested properties, oil production volumes
increased 12% in 2000 as compared with adjusted production volumes in 1999.

      Oil and natural gas sales in 2000 were increased by higher realized
equivalent oil and natural gas prices and production from wells completed during
2000, offset partially by the natural decline of existing production and losses
from oil and natural gas hedges. See "-- Overview." As a result of hedging
activities, natural gas revenues were reduced by $9.4 million ($2.12 per Mcf) in
2000, compared to a decrease in natural gas revenues of $486,000 ($0.12 per Mcf)
in 1999. Oil revenues were reduced by $107,000 ($0.30 per Bbl) due to hedging
losses in 2000. There were no gains or losses on crude oil hedges during 1999.
See "-- Other Matters -- Derivative Instruments."

      Workstation revenue. Workstation revenue decreased 81% from $285,000 in
1999 to $53,000 in 2000. Brigham recognizes workstation revenue as industry
participants in its seismic programs are charged an hourly rate for the work
Brigham performs on its 3-D seismic interpretation workstations. This decrease
in 2000 is primarily attributable a


                                     - 26 -

<PAGE>

reduction in the volume of 3-D seismic interpretation activity billable to
industry participants as compared with 1999.

      Lease operating expenses. Lease operating expenses decreased 5% from $2.3
million ($0.36 per Mcfe) in 1999 to $2.1 million ($0.32 per Mcfe) in 2000. This
decrease was primarily due to a decrease in the number of producing wells in
2000 as compared with 1999 that was attributable to Brigham's June 1999 property
divestitures and the plugging and abandonment of certain uneconomic wells. See
"-- Overview."

      Production taxes. Production taxes increased 85% from $968,000 ($0.15 per
Mcfe) in 1999 to $1.8 million ($0.27 per Mcfe) in 2000 primarily due to higher
average oil and natural gas sales prices and revenues before the effects of
hedging gains or losses. The effective average production tax rate decreased
from 6.3% of pre-hedge oil and natural gas sales in 1999 to 6.2% in 2000
resulting primarily from changes in the geographic distribution of Brigham's
producing wells.

      General and administrative expenses. Net general and administrative
expenses decreased 11% from $3.5 million ($0.56 per Mcfe) in 1999 to $3.1
million ($0.47 per Mcfe) in 2000. This decrease was primarily attributable to
the reduction of various administrative costs, including lower office rent due
to the subleasing of a portion of Brigham's headquarters space, reduced
equipment rental and maintenance expenses, and lower employee payroll and
benefits expenses. See "-- Overview."

      Depletion of oil and natural gas properties. Depletion of oil and natural
gas properties increased 2% from $7.8 million ($1.24 per Mcfe) in 1999 to $7.9
million ($1.20 per Mcfe) in 2000. Of this increase, $396,000 was attributable to
higher production volumes, partially offset by $268,000 due to the reduction in
the depletion rate per unit of production. The decrease in depletion rate per
unit of production was primarily the result of the addition of oil and natural
gas reserves at lower average capital costs due to improved average finding
costs during 2000.

      Interest expense. Interest expense increased from $9.7 million in 1999 to
$9.9 million in 2000 due to higher effective interest rates that were partly
offset by lower outstanding debt balances. Brigham's weighted average
outstanding debt balance decreased 2% from $99.5 million in 1999 to $97.4
million in 2000. This reduction in debt was primarily attributable to Brigham's
refinancing of its senior subordinated notes due 2003 in November 2000. The
effective annual interest rate on Brigham's outstanding indebtedness increased
slightly from 12.6% in 1999 to 12.7% in 2000. In addition, interest expense in
2000 included (i) $4.6 million of interest expenses that were paid in kind
through the issuance of additional debt in lieu of cash, and (ii) $2.0 million
of non-cash charges related to the amortization of deferred loan fees and the
amortization of discount on senior subordinated notes. Borrowings under
Brigham's senior credit facility had an effective annual interest rate of 9.68%
at December 31, 2000. In November 2000, Brigham refinanced its senior
subordinated notes due 2003 at a substantial discount to the principal amount
then outstanding. This refinancing reduced Brigham's outstanding debt borrowings
and is expected to result in lower average interest rates during 2001. See "--
Liquidity and Capital Resources -- Refinancing Transactions."

      Other expense. Other expense increased from $163,000 in 1999 to $9.5
million in 2000. Brigham recognizes other income or expense primarily related to
the changes in the fair market values and the related cash flows of certain oil
and natural gas derivative contracts that do not qualify for hedge accounting
treatment. Other expense in 1999 included (i) $115,000 of non-cash expenses
related to the changes in the fair market values of these derivative contracts
during the period, and (ii) $48,000 of expenses related to cash settlements
incurred during the period pursuant to these derivative contracts. Other expense
in 2000 included (i) $8.9 million of non-cash expenses related to the changes in
the fair market values of these derivative contracts during the period, and (ii)
$603,000 of expenses related to cash settlements incurred during the period
pursuant to these derivative contracts.

      Extraordinary gain on refinancing of senior subordinated notes. In
November 2000, Brigham repurchased all of the debt and equity securities in
Brigham held by affiliates of Enron North America (the "Enron Affiliates") at a
substantial discount. With a portion of the proceeds from two new financing
transactions, Brigham repurchased all of the Enron Affiliates' interests in
Brigham, which included (i) $51.2 million of senior subordinated notes due 2003
(which bore interest at annual rates of 12% to 14%) and associated accrued
interest obligations, (ii) warrants to purchase an


                                     - 27 -

<PAGE>

aggregate of one million shares of common stock at $2.43 per share, and (iii)
1,052,632 shares of common stock (collectively, the "Enron Securities"), for
total cash consideration of $20 million. As a result of the repurchase of the
senior subordinated notes due 2003 at a discount to the principal amount
outstanding, Brigham recorded an extraordinary gain of $32.3 million in the
fourth quarter of 2000.

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

      Oil and natural gas sales. Oil and natural gas sales increased 9% from
$13.8 million in 1998 to $15 million in 1999. An increase in the average sales
price received for oil and natural gas sales accounted for $2 million of this
increase and was offset by $797,000 from a decrease in net production volumes.
Production volumes for natural gas decreased 2% from 4,269 MMcf in 1998 to 4,197
MMcf in 1999, while the average price received for natural gas increased 3% from
$2.04 per Mcf in 1998 to $2.11 per Mcf in 1999. Production volumes for oil
decreased 13% from 396 MBbls in 1998 to 346 MBbls in 1999, while the average
price received for oil increased 38% from $12.85 per Bbl in 1998 to $17.79 per
Bbl in 1999. Oil and natural gas sales in 1999 were increased by higher realized
oil and natural gas prices and production from wells completed during 1999,
offset partially by the natural decline of existing production and from the sale
of certain producing wells in the Company's mid-1999 property divestitures. See
"-- Overview." As a result of hedging activities, natural gas revenues were
reduced by $486,000 ($0.12 per Mcf) in 1999, compared to an increase in natural
gas revenues of $555,000 ($0.13 per Mcf) in 1998. See "-- Other Matters --
Derivative Instruments."

      Workstation revenue. Workstation revenue decreased 27% from $390,000 in
1998 to $285,000 in 1999. This decrease is primarily attributable to Brigham's
increased working interests in its 3-D seismic projects in 1997 and 1998, which
reduced the amount of workstation interpretation costs billable to Brigham's
project participants.

      Lease operating expenses. Lease operating expenses increased 4% from $2.2
million ($0.33 per Mcfe) in 1998 to $2.3 million ($0.36 per Mcfe) in 1999. This
increase was primarily due to higher average working interests in its producing
wells and increased well repair and workover activity in 1999 as compared with
1998, offset in part by the elimination of lease operating expenses related to
wells sold by Brigham in its mid-1999 property divestitures. See "-- Overview."

      Production taxes. Production taxes increased 14% from $850,000 ($0.13 per
Mcfe) in 1998 to $968,000 ($0.15 per Mcfe) in 1999 primarily due to higher
average oil and natural gas sales prices and revenues. The effective average
production tax rate increased from 6.2% of oil and natural gas sales revenues in
1998 to 6.5% in 1999 resulting from changes in the geographic distribution of
Brigham's producing wells.

      General and administrative expenses. Net general and administrative
expenses decreased 25% from $4.7 million ($0.70 per Mcfe) in 1998 to $3.5
million ($0.56 per Mcfe) in 1999. This decrease was primarily attributable to a
series of cost reduction initiatives implemented by Brigham during 1999 to
reduce overhead expense levels. These initiatives included a company-wide salary
reduction effective in May 1999, the elimination of employee bonuses for 1999, a
sublease of a portion of Brigham's headquarters space effective in November
1999, certain personnel reductions and the elimination or reduction of various
other discretionary expenses.

      Depletion of oil and natural gas properties. Depletion of oil and natural
gas properties decreased 8% from $8.5 million ($1.28 per Mcfe) in 1998 to $7.8
million ($1.24 per Mcfe) in 1999. Of this decrease, $464,000 was attributable to
the lower production volumes during the period and $227,000 was due to the
reduction in the depletion rate per unit of production. The decrease in
depletion rate per unit of production was primarily the result of the addition
of oil and natural gas reserves at lower average capital costs due to improved
average finding costs during 1999, partially offset by an increase in the
percentage of Brigham's total full cost pool subject to depletion attributable
to an increase in the estimate of the evaluated portion of Brigham's oil and
natural gas properties.

      Interest expense. Interest expense increased from $6 million in 1998 to
$9.7 million in 1999 due to higher outstanding debt balances in 1999 at higher
effective interest rates. Brigham's weighted average outstanding debt balance
increased 51% from $66 million in 1998 to $99.5 million in 1999. This increase
in debt was incurred primarily to fund


                                     - 28 -

<PAGE>

Brigham's increased capital expenditures and working capital needs, net of
operating cash flow, during 1998 and 1999. The effective annual interest rate on
Brigham's outstanding indebtedness increased from 10.6% in 1998 to 12.6% in
1999, primarily due to Brigham's issuance of $40 million of senior subordinated
notes due 2003 in August 1998, which bore interest at an annual rate of 12% when
paid in cash and 13% when paid "in kind" through the issuance of additional
subordinated notes. In addition, interest expense in 1999 included (i) $5.5
million of interest expenses related to the subordinated notes due 2003 that was
paid in kind through the issuance of additional subordinated notes in lieu of
cash, and (ii) $2.3 million of non-cash charges related to the amortization of
deferred loan fees and the amortization of discount on the subordinated notes.
Borrowings under Brigham's senior credit facility had an effective annual
interest rate of 9.5% at December 31, 1999. See "-- Liquidity and Capital
Resources."

      Loss on sale of oil and natural gas properties. In June 1999, Brigham sold
all of its interests in certain producing and non-producing oil and natural gas
properties for a total sales price of $17.1 million. Due to the magnitude of the
reserve volumes that were attributable to these properties relative to Brigham's
remaining net reserve volumes, Brigham recognized a $12.2 million non-cash loss
to reflect the difference between the sales price received (after adjustment for
transaction costs) and the $28.9 million basis allocated to the divested
properties in accordance with the full-cost method of accounting for oil and gas
properties. No property divestitures occurred during 1998 for which recognition
of gain or loss was appropriate.

Liquidity and Capital Resources

      Brigham's primary sources of capital have been credit facility and other
debt borrowings, public and private equity financings, the sale of interests in
projects and properties and funds generated by operations. Brigham's primary
capital requirements are 3-D seismic acquisition, processing and interpretation
costs, land acquisition costs and drilling expenditures.

Credit Facility

      In January 1998, Brigham entered into a revolving credit agreement (as
amended, the "Senior Credit Facility"), which provided for an initial borrowing
availability of $75 million. The Senior Credit Facility was amended in March
1999 to reduce the borrowing availability, extend the date of borrowing base
redetermination, modify certain financial covenants, include certain additional
covenants that place restrictions on Brigham's ability to incur certain capital
expenditures, and to increase the interest rate on outstanding borrowings.

      As a result of the completion of the majority of Brigham's strategic
initiatives to improve its capital resources, including its June 1999 property
divestitures and the application of the net sales proceeds to reduce borrowings
outstanding under the Senior Credit Facility, Brigham and its senior lenders
entered into an amendment to the Senior Credit Facility in July 1999. This
amendment provided Brigham with borrowing availability of $56 million. As
consideration for this amendment, in July 1999 Brigham issued to its senior
lenders warrants to purchase an aggregate of 1,000,000 shares of Brigham common
stock at an exercise price of $2.25 per share. The warrants have a seven-year
term from the date of issuance and are exercisable at the holders' option at any
time. An estimated value of $1.2 million was attributed to these warrants by
Brigham and was recognized as additional deferred loan fees that will be
amortized and included in interest expense over the remaining period to maturity
of the Senior Credit Facility.

      In February 2000, Brigham entered into an amended and restated Senior
Credit Facility with its existing senior lenders and a new senior lender. The
Senior Credit Facility was further amended in October 2000. The amended and
restated Senior Credit Facility provides Brigham with $75 million in borrowing
availability for a three-year term.

      As a result of the February 2000 amendments, $30 million of the Senior
Credit Facility held by one of the lenders is convertible into shares of Brigham
common stock (the "Convertible Notes") in the following amounts and prices: (i)
$10 million is convertible at $3.90 per share, (ii) $10 million is convertible
at $6.00 per share and (iii) $10 million is convertible at $8.00 per share. As
of December 31, 2000, Brigham had $75 million in borrowings outstanding under
the Senior Credit Facility, of which the Convertible Notes are $30 million.


                                     - 29 -

<PAGE>

      In connection with Brigham's refinancing of its subordinated notes due
2003 (see "-- Subordinated Notes" and "-- Refinancing Transactions") in October
2000, Brigham entered into an amendment to the Senior Credit Facility that,
among other things, permitted the issuance of new subordinated notes and new
preferred stock to provide funding for the repurchase of the subordinated notes
due 2003 and equity interests in Brigham held by the Enron Affiliates. In
addition, the minimum interest coverage ratio (as defined) tests of the Senior
Credit Facility were amended to reflect Brigham's expected cash flow and
interest expense beginning in the fourth quarter of 2000 subsequent to the
Refinancing Transactions (as defined), and Brigham conditionally waived certain
rights to force conversion of the portion of the borrowings under the Senior
Credit Facility that are convertible at $3.90 per share.

      If the Senior Credit Facility is repaid at maturity or is prepaid prior to
maturity without payment of cash premiums, the warrants to purchase Brigham
common stock issued to the new participant in the Senior Credit Facility become
exercisable. Further, to the extent Brigham chooses to prepay any of the
Convertible Notes without the warrants becoming exercisable, and also assuming
the lender chooses not to convert to equity upon notice of such prepayment,
Brigham will be required to a pay a premium above the face value of the
Convertible Notes to the lender. Such premium amounts would range from 150% to
110%, depending upon the timing of the prepayment. Such prepayment, however,
would require prior approval of the original lenders to the Senior Credit
Facility. In addition, certain financial covenants of the Senior Credit Facility
were amended or added in the July 1999, February 2000 and October 2000
amendments. In connection with the February 2000 amendment, Brigham reset the
price of the warrants previously issued to its existing senior lenders to
purchase one million shares of Brigham common stock from the then current
exercise price of $2.25 per share to $2.02 per share.

      Principal outstanding under the Senior Credit Facility is due at maturity
on December 31, 2002, with interest due monthly for base rate tranches or
periodically as LIBOR tranches mature. The annual interest rate for borrowings
under the Senior Credit Facility is either the lender's base rate or LIBOR plus
3.00%, at Brigham's option. Obligations under the Senior Credit Facility are
secured by substantially all of Brigham's oil and natural gas properties and
other tangible assets. At March 20, 2001, Brigham had $75 million in borrowings
outstanding under the Senior Credit Facility, which bear interest at an annual
rate of approximately 8.35%.

      The Senior Credit Facility has certain financial covenants, including
current and interest coverage ratios, as defined. Brigham and its senior lenders
effected the amendments to the Senior Credit Facility described above in part to
enable Brigham to comply with certain financial covenants of the Senior Credit
Facility, including the minimum current ratio (as defined), minimum interest
coverage ratio (as defined), and the limitation on capital expenditures related
to seismic and land activities. Should Brigham be unable to comply with certain
of the financial or other covenants, its senior lenders may be unwilling to
waive compliance or amend the covenants in the future. In such instance,
Brigham's liquidity may be adversely affected, which could in turn have an
adverse impact on its future financial position and results of operations.

Subordinated Notes

      In August 1998, Brigham issued $50 million of debt and equity securities
to affiliates of Enron Corp. The securities issued by Brigham in connection with
this financing transaction included: (i) $40 million of subordinated notes due
2003, (ii) warrants to purchase an aggregate of one million shares of Brigham
common stock at a price of $10.45 per share, and (iii) 1,052,632 shares of
Brigham common stock at a price of $9.50 per share.

      As described below, Brigham repurchased the subordinated notes due 2003,
together with all equity interests in Brigham held by the Enron Affiliates, for
$20 million in cash in November 2000 (see "-- Refinancing Transactions").

Refinancing Transactions

      On October 31, 2000 and November 1, 2000, Brigham entered into a series of
financing agreements to provide funding (i) to repurchase all the debt and
equity securities in Brigham held by affiliates of Enron North America at a


                                     - 30 -

<PAGE>

substantial discount, and (ii) to continue and expand Brigham's planned drilling
program into 2001.

      Financing and Repurchase Transactions. Brigham raised an aggregate of $40
million in these financing transactions through the issuance of (i) $20 million
in new subordinated notes and warrants to purchase Brigham common stock to Shell
Capital Inc., and (ii) $20 million in new mandatorily redeemable preferred stock
and warrants to purchase Brigham common stock to affiliates of Credit Suisse
First Boston (USA), Inc. (the "CSFB Affiliates"). With a portion of the proceeds
from these two financing transactions, Brigham purchased all of the Enron
Affiliates' interests in Brigham, which included (i) $51.2 million of
outstanding subordinated notes due 2003 and associated accrued interest
obligations, (ii) warrants to purchase one million shares of common stock at
$2.43 per share, and (iii) 1,052,632 shares of common stock (collectively, the
"Enron Securities"), for total cash consideration of $20 million. The remaining
approximate $17.5 million in net capital availability raised from these
financing transactions, after the repurchase of the Enron Securities and the
payment of fees and expenses, was available for Brigham to fund its planned
drilling program into 2001.

      Subordinated Notes Facility. The $20 million of new subordinated notes
issued to Shell Capital Inc. (the "SCI Notes") bear interest at 10.75% per annum
and have no principal repayment obligations until maturity in 2005. The SCI
Notes will be issued pursuant a multi-draw facility (the "Subordinated Notes
Facility") at borrowing increments of at least $1 million, and such funds cannot
be redrawn once they have been repaid. At Brigham's option, up to 50% of the
interest payments on the SCI Notes during the first two years can be satisfied
by payment-in-kind ("PIK") through the issuance of additional SCI Notes in lieu
of cash. The SCI Notes are secured obligations ranking junior to Brigham's
existing $75 million Senior Credit Facility. The SCI Notes have a five-year
maturity, are redeemable at Brigham's option for face value at anytime, and have
certain financial and other covenants. The warrants to purchase an aggregate of
1,250,000 shares of Brigham common stock issued to Shell Capital Inc. (the "SCI
Warrants") have a term of seven years, an exercise price of $3.00 per share and
a cashless exercise feature. For financial reporting purposes, the SCI Warrants
were valued using the Black-Scholes valuation model and the estimated value of
$2.9 million was recorded as deferred loan costs that will be amortized over the
five year term of the SCI Notes. As of December 31, 2000 and March 20, 2001,
Brigham had $7 million and $16 million, respectively, of borrowings outstanding
under the Subordinated Notes Facility.

      Series A Preferred Stock. The $20 million of mandatorily redeemable
preferred stock (the "Series A Preferred Stock") issued to the CSFB Affiliates
bears dividends at a rate of 6% per annum if paid in cash and 8% per annum if
paid-in-kind through the issuance of additional Series A Preferred Stock in lieu
of cash. At Brigham's option, up to 100% of the dividend payments on the Series
A Preferred Stock during the first five years can be satisfied through the
issuance of PIK dividends. The Series A Preferred Stock has a ten-year maturity
and is redeemable at Brigham's option at 100% or 101% of par value (depending
upon certain conditions) at anytime prior to maturity. The warrants to purchase
an aggregate of 6,666,667 shares of Brigham common stock issued to the CSFB
Affiliates (the "Series A Warrants") have a term of ten years, an exercise price
of $3.00 per share and must be exercised, if Brigham so requires, in the event
that Brigham common stock trades at or above $5.00 per share for 60 consecutive
trading days. The exercise price of the Series A Warrants is payable either in
cash or in shares of Series A Preferred Stock, valued at liquidation value plus
accrued dividends. If Brigham requires exercise of the Series A Warrants,
proceeds from the exercise of the Series A Warrants will be used to fund the
redemption of a similar value of then outstanding Series A Preferred Stock. For
financial reporting purposes, the Series A Warrants were valued at $11.5 million
using the Black-Scholes valuation model and were recorded as additional paid-in
capital in the year ended December 31, 2000. Pursuant to the terms of the
securities purchase agreement related to the Series A Preferred Stock, Brigham
agreed to nominate one representative of one of the CSFB Affiliates to serve as
a member of Brigham's board of directors so long as the CSFB Affiliates or their
affiliates own at least 10% of the Series A Preferred Stock issued in November
2000, or at least 5% of the outstanding shares of Brigham common stock. In March
2001, Brigham sold an additional $10 million of Series A Preferred Stock to
affiliates of CSFB (see "-- Equity Placements -- Private Placement of Preferred
Stock"). As of December 31, 2000 and March 20, 2001, Brigham had $20.3 million
and $30.3 million (liquidation value), respectively, of Series A Preferred Stock
outstanding.


                                     - 31 -

<PAGE>

Sales of Interests in Projects and Oil and Natural Gas Properties

      Duke Project Financing. In February 1999, Brigham entered into a project
financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund
the continued exploration of five Anadarko Basin projects covered by
approximately 200 square miles of 3-D seismic data acquired in 1998. In this
transaction, Brigham conveyed 100% of its working interest (land and seismic) in
these project areas to a newly formed limited liability company (the
"Brigham-Duke LLC") for total consideration of $10 million. Brigham entered into
this project financing arrangement to enable it to recoup substantially all of
its pre-seismic land and seismic data acquisition costs incurred in these
project areas and to provide the capital to fund the drilling of the first six
wells within these projects. Brigham served as the managing member of the
Brigham-Duke LLC with a 1% interest, and Duke was the sole remaining member with
a 99% interest. Pursuant to the terms of the Brigham-Duke LLC agreement, Brigham
paid 100% of the drilling and completion costs for all wells drilled by the
Brigham-Duke LLC within the designated project areas in exchange for a 70%
working interest in the wells (and their allocable drilling and spacing units),
with the remaining 30% working interest remaining in the Brigham-Duke LLC,
subject in each instance to proportionate reduction by any ownership rights held
by third parties. Upon 100% project payout, Brigham had the right to back-in for
80% of the Brigham-Duke LLC's working interest in all of the then producing
wells (and their allocable drilling and spacing units) and a 94% working
interest in any wells (and their allocable drilling and spacing units) drilled
after payout within the designated project areas governed by the Brigham-Duke
LLC agreement, thereby increasing Brigham's effective working interest in the
Brigham-Duke LLC wells from 70% to 94%. In February 2001, Duke, as majority
member of the Brigham-Duke LLC, elected to dissolve the Brigham-Duke LLC. As a
result, any ownership of remaining undeveloped land and/or seismic data within
the Brigham-Duke LLC project areas will be transferred to Duke following the
dissolution of the Brigham-Duke LLC.

      Mid-1999 Property Sales. In June 1999, Brigham sold certain producing and
non-producing oil and natural gas properties located in its Anadarko Basin
province to two separate parties for a total of $17.1 million. The divested
properties were located in two fields operated by third parties - the Chitwood
Field in Grady County, Oklahoma (originally acquired by Brigham for $13.4
million in the Chitwood Acquisition in November 1997), and the Red Deer Creek
Field in Roberts County, Texas. Brigham's independent reservoir engineers
estimated net proved reserve volumes attributable to the properties as of June
1, 1999 of approximately 36 Bcfe, of which 33% were classified as proved
developed producing reserves and 59% were natural gas. Brigham estimated that
net production volumes from the divested properties were 2.8 MMcfe per day at
the time of the sales. Brigham used the proceeds from these transactions to
reduce borrowings under its credit facility, which contributed to provide $8
million in borrowing availability under Brigham's then existing credit facility
that was used to fund working capital needs and capital expenditures during the
second half of 1999. The effective date of each transaction was June 30, 1999.

Equity Placements

      Veritas Equity Issuances. On March 30, 1999, Brigham entered into an
agreement with Veritas DGC Land, Inc. to exchange 1,002,865 shares of newly
issued Brigham common stock valued at $3.50 per share for approximately $3.5
million of payment obligations due to Veritas in 1999 for certain seismic
acquisition and processing services previously performed. In addition, this
agreement provided for the payment by Brigham of up to $1 million in future
seismic processing services to be performed by Veritas in newly issued shares of
Brigham common stock valued at $3.50 per share, in the event that Brigham did
not elect to pay for such services in cash. The settlement of these future
seismic processing services was determined on a quarterly basis through
September7 30, 1999. Pursuant to this agreement, Brigham issued a total of
1,211,580 shares of common stock to Veritas to satisfy $4.2 million in aggregate
payment obligations due to Veritas for seismic acquisition and processing
services performed prior to 1999 and certain seismic processing services
performed during 1999.

     Private Placement of Common Stock. On February 22, 2000, Brigham entered
into an agreement to issue 2,195,122 shares of common stock and 731,707 warrants
to purchase common stock for total consideration of $4.5 million in a private
placement to a group of institutional investors led by affiliates of two members
of Brigham's board of directors. The equity sale consisted of units that include
one share of common stock priced at $2.0525 per share and one-third of


                                     - 32 -

<PAGE>

a warrant to purchase Brigham common stock at an exercise price of $2.5625 per
share with a three-year term. Pricing of this private equity placement was based
on the average market price of Brigham common stock during a twenty trading day
period prior to issuance. Net proceeds from this equity placement were used to
fund a portion of Brigham's capital expenditures and working capital obligations
during 2000.

      Private Placement of Preferred Stock. On March 5, 2001, Brigham sold $10
million of additional Series A Preferred Stock and warrants (the "New CSFB
Warrants") to affiliates of CSFB in a private placement transaction. The
conditions to Brigham's receipt of the process from this transaction were
fulfilled on March 22, 2001. The New CSFB Warrants to purchase an aggregate of
2,105,263 shares of Brigham common stock have a term of ten years, an exercise
price of $4.75 per share and must be exercised, if Brigham so requires, in the
event that Brigham common stock trades at an average of at least 150% of the
exercise price (currently, $7.125 per share) for 60 consecutive trading days.
The exercise price of the New CSFB Warrants is payable either in cash or in
shares of Series A Preferred Stock, valued at liquidation value plus accrued
dividends. If Brigham requires exercise of the New CSFB Warrants, proceeds from
the exercise of the New CSFB Warrants will be used to fund the redemption of a
similar value of then outstanding Series A Preferred Stock. For financial
reporting purposes, the New CSFB Warrants were valued at approximately $4.5
million using the Black-Scholes valuation model and were recorded as additional
paid-in capital in March 2001.

Cash Flow Analysis

      Cash Flows from Operating Activities. Cash flows provided (used) by
operating activities were ($4.6) million in 2000, $2.6 million in 1999, and
$14.8 million in 1998. The decrease in cash flows for 2000 as compared to 1999
was primarily attributable to changes in working capital (a $13.2 million
reduction in cash flow from working capital items in 2000 compared to a $5
million reduction in cash flow from working capital items in 1999), offset in
part by a $1.1 million increase in cash flow from operations before working
capital. Cash flow from operations before working capital changes were $8.6
million in 2000 as compared to $7.5 million in 1999. The decrease in cash flows
for 1999 compared to 1998 was primarily attributable to changes in working
capital (a $5 million reduction in cash flow from working capital items in 1999
compared to an $11.9 million increase in cash flow from working capital items in
1998).

      Cash Flows from Investing Activities. Cash flows provided (used) by
investing activities were ($26.1) million in 2000, $1.6 million in 1999 and
($86.2) million in 1998. The decrease in cash flow from investing activities in
2000 were primarily attributable to (i) an increase in Brigham's capital
expenditures related to exploration and development activities, and (ii) a
reduction in proceeds received from the sale of oil and natural gas properties,
as compared with those in 1999. The increase in net cash flow from investing
activities in 1999 was due to the combined effects of significantly reduced net
capital expenditures and a total of $27.1 million of proceeds received from the
sales of oil and natural gas properties, which consisted principally of
Brigham's mid-1999 producing property divestitures and its sales of promoted
interests in certain 3-D seismic projects and drilling prospects in its Anadarko
Basin and Texas Gulf Coast regions. Capital expenditures (before the application
of net proceeds received from the sales of interests in projects) were $28.9
million in 2000, $25.6 million in 1999 and $85.2 million in 1998.

      After acquiring 2,361 gross (1,727 net) square miles of 3-D seismic data
in 1997 and 1998, Brigham did not acquire any new 3-D seismic data during 1999
and 2000. Brigham's drilling efforts during the past three years resulted in the
completion of 24 ([9.2] net) wells in 2000, 19 (6.3 net) wells in 1999, and 50
(26.3 net) wells in 1998, which contributed to aggregate net increases in proved
reserve volumes (net of revisions to previous estimates) of 18.4 Bcfe in 2000,
28.7 Bcfe in 1999 and 31.2 Bcfe in 1998. In addition, Brigham sold interests in
certain 3-D seismic data for $3.9 million in 2000, sold interests in certain
producing and non-producing properties in 1999 for a total of $27.1 million, and
acquired certain producing properties and related interests for $1 million in
1998.

      Cash Flows from Financing Activities. Cash flows provided by financing
activities in 2000 were $28.8 million, principally due to the combined effects
of increased borrowings under its Senior Credit Facility and Subordinated Notes
Facility, the repurchase of its senior subordinated notes due 2003, the issuance
of $20 million of mandatorily redeemable preferred stock and warrants, and the
placement of common stock that provided $4.2 million. Cash flows used by
financing activities in 1999 were $4.1 million, principally due to the net
repayment of borrowings outstanding under Brigham's Senior Credit Facility and
the payment of deferred loan fees. Cash flows provided by financing activities
in


                                     - 33 -

<PAGE>

1998 were $72.3 million, primarily as a result of borrowings under the Brigham's
Senior Credit Facility, the issuance of the senior subordinated notes due 2003
and the sale of $10 million of common stock.

Capital Expenditures

      Continuing its strategy initiated in 1999 to harvest its prior 3-D seismic
project investments, Brigham intends to focus substantially all of its efforts
and available capital resources in 2001 to the drilling and monetization of its
highest grade prospects within its over 5,000 square mile inventory of 3-D
seismic data. Brigham's planned 2001 capital expenditure budget is estimated to
be $32 million, which includes approximately $22 million for drilling projects,
$4 million for acreage leasing and G&G activities, and $6 million for
capitalized overhead and interest costs. Brigham's planned 2001 drilling program
consists of a balanced blend of higher potential exploration tests and lower
risk development drilling projects, driven to a large extent by the development
of several significant exploratory discoveries completed during 2000.
Approximately 34% of budgeted 2001 drilling expenditures are targeted for
exploratory prospects, 52% for development locations and the remaining 14% for
development locations that are contingent upon drilling success during the year.
In addition, over 80% of Brigham's budgeted drilling expenditures are focused in
five project areas in the Springer and Hunton trends of the Anadarko Basin and
the Vicksburg and Frio trends of the Texas Gulf Coast. Brigham intends to fund
its budgeted capital expenditures through a combination of cash flow from
operations, available borrowings under its Subordinated Notes Facility and the
net proceeds from its private placements of Series A Preferred Stock in November
2000 and March 2001. Additionally, Brigham will continue to seek opportunities
to supplement its available capital resources through selective sales of
interests in non-producing assets, including interests in its 3-D seismic
projects and promoted interests in future drilling prospects or locations. See
"Item 2. Properties -- Primary Exploration Provinces."

      Due to its active exploration and development activities, Brigham has
experienced and expects to continue to experience substantial working capital
requirements. While Brigham believes that cash flow from operations and
borrowings under its Subordinated Notes Facility should allow it to finance its
planned operations through 2001 based on current conditions and expectations,
additional financing will be required in the future to fund Brigham's
exploration and development activities. In the event additional financing is not
available, Brigham may be required to curtail or delay its planned activities.

Other Matters

Derivative Instruments

      Brigham believes that hedging, although not free of risk, allows it to
reduce its exposure to oil and natural gas sales price fluctuations and thereby
to achieve more predictable cash flows. However, hedging arrangements, when
utilized, may limit the benefit to Brigham of increases in the prices of the
hedged commodity. Moreover, Brigham's hedging arrangements generally do not
apply to all of its production and thus provide only partial price protection
against declines in commodity prices. Brigham expects that the amount of its
hedges will vary from time to time. See "-- Risk Factors -- Our Hedging
Transactions May Not Prevent Losses" and "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk."

      In 1998, Brigham began using natural gas swap arrangements in an attempt
to reduce its sensitivity to volatile commodity prices as its production base
became increasingly weighted toward natural gas. Pursuant to these arrangements,
Brigham exchanges a floating market price for a fixed contract price. Brigham
makes payments when the floating price exceeds the fixed price for a contract
month, and Brigham receives payments when the fixed price exceeds the floating
price. Settlements of these swaps are based on the difference between regional
market index prices for a contract month and the fixed contract price for the
same month.

      Total natural gas purchased and sold subject to swap arrangements entered
into by Brigham was 2,750,000 MMBtu in 1998, 5,025,000 MMBtu in 1999, and
5,490,000 MMBtu in 2000. Brigham accounted for these transactions as hedging
activities and, accordingly, adjusted the price received for oil and natural gas
production during the period the


                                     - 34 -

<PAGE>

hedged transactions occurred. Adjustments to the price received for natural gas
under these swap arrangements resulted in an increase in natural gas revenues of
$555,000 in 1998 and decreases in natural gas revenues of $486,000 in 1999 and
$9.4 million in 2000. In addition, Brigham's oil revenues were reduced by
$107,000 in 2000 as a result of its crude oil collar hedging arrangements
outstanding during the year. Brigham did not have any outstanding crude oil
hedging contracts during 1998 and 1999.

      In September 1999, Brigham sold call options on a portion of its future
oil and natural gas production. Brigham applied the proceeds from the sale of
these call options to increase the effective fixed swap price on its then
existing natural gas hedging contracts during the months of October 1999 through
January 2000 by an average of $0.57 per MMBtu. For accounting purposes, the
improvement in Brigham's fixed natural gas swap price attributable to these
transactions was not reflected in reported revenues. Rather, it was reflected in
(i) other income (expense) on the income statement, and (ii) amortization of
deferred loss on derivatives instruments and market value adjustment for
derivatives instruments on the cash flow statement.

      The following tables summarize Brigham's outstanding oil and natural gas
derivative contracts as of December 31, 2000:

<TABLE>
<CAPTION>
      Natural Gas Derivative Contracts                                        2001                      2002
                                                                    -----------------------    ----------------------
                                                                                   Average                  Average
                                                                     Volumes      Contract      Volumes     Contract
                                                     Monthly          Hedged        Price        Hedged       Price
                               Pricing Basis      Contract Term      (MMBtu)      ($/MMBtu)     (MMBtu)     ($/MMBtu)
                               -------------      -------------     ----------    ---------    ---------    ---------
      <S>                       <C>               <C>                <C>           <C>        <C>            <C>
      Fixed Price Swaps:

         Contract #1                ANR           January 2001 -       600,000     $2.0650            --          --
                                  Oklahoma          April 2001

                                  Houston         January 2001 -
         Contract #2            Ship Channel        April 2001         600,000     $2.1500            --          --

         Contract #3               TETCO          January 2001 -       600,000     $2.0575            --          --
                                South Texas         April 2001

      Fixed Price Cap               ANR             May 2001 -       2,450,000     $2.5498     1,810,000     $2.6326
                                  Oklahoma          June 2002

      Fixed Price Floor             ANR             May 2001 -         765,000     $1.8000            --          --
                                  Oklahoma        December 2001
<CAPTION>
      Crude Oil Derivative Contracts                                          2001                      2002
                                                                     ------------------------   --------------------
                                                                                                             Average
                                                                     Volumes       Average      Volumes      Contract
                                                     Monthly          Hedged      Contract       Hedged       Price
                               Pricing Basis      Contract Term       (Bbls)    Price ($/Bbl)    (Bbls)      ($/Bbl)
                               -------------      -------------      --------   -------------   --------     -------
      <S>                          <C>            <C>                <C>           <C>              <C>         <C>

      Fixed Price Cap              NYMEX          January 2001 -     109,200       $26.15           --           --
                                                  December 2001

      Fixed Price Floor            NYMEX          January 2001 -     109,200       $17.36           --           --
                                                  December 2001

</TABLE>
                                     - 35 -

<PAGE>

Effects of Inflation and Changes in Prices

      Brigham's results of operations and cash flows are affected by changing
oil and natural 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 Brigham is required to bear for operations.
Inflation has had a minimal effect on Brigham.

Environmental and Other Regulatory Matters

      Brigham's 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 Brigham believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by laws and
regulations are frequently changed and subject to interpretation, and Brigham is
unable to predict the ultimate cost of compliance with these requirements or
their effect on its operations. Any suspensions, terminations or inability to
meet applicable bonding requirements could materially adversely affect Brigham's
financial condition and operations. Although significant expenditures may be
required to comply with governmental laws and regulations applicable to Brigham,
compliance has not had a material adverse effect on the earnings or competitive
position of Brigham. Future regulations may add to the cost of, or significantly
limit, drilling activity. See "-- Risk Factors -- We Are Subject To Various
Governmental Regulations And Environmental Risks," "Item 1. Business --
Governmental Regulation" and "Item 1. Business -- Environmental Matters."

Recent Accounting Pronouncements

      In June 1998, the Financial Accounting Standards Board (the "FASB") issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("FAS 133"). The FASB has subsequently
issued Statements of Financial Accounting Standards No. 137 and 138, which are
amendments to FAS 133. FAS 133, as amended, is effective for fiscal years
beginning after June 15, 2000. Brigham adopted FAS 133 on January 1, 2001.

      FAS 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. All derivative instruments
will be recorded on the balance sheet at fair value and changes in the fair
value of derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if it is, depending on the type of hedge transaction.
Brigham's derivative contracts consist primarily of cash flow hedge transactions
in which Brigham is hedging the variability of cash flows related to a
forecasted transaction. Changes in the fair value of these derivative
instruments will be reported in other comprehensive income and will be
reclassified as earnings in the periods in which earnings are impacted by the
variability of the cash flows of the hedged item. The ineffective portion of all
hedges will be recognized in current period earnings.

      In January 2001, Brigham recorded a net of tax cumulative effect
adjustment of $11.8 million to other comprehensive income to recognize the fair
value (liability) of all derivative instruments which qualify for hedge
accounting treatment in accordance with FAS 133.

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 2001 and Brigham's financial position,
business strategy and other plans and objectives for future operations. Although
Brigham believes that the expectations reflected in these forward looking
statements are reasonable, there can be no assurance that the actual results or
developments anticipated by Brigham will be realized or, even if substantially
realized, that they will have the expected effects on its


                                     - 36 -

<PAGE>

business or operations. Among the factors that could cause actual results to
differ materially from Brigham's 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 Brigham and its project participants, government
regulations and other factors set forth among the risk factors noted below or in
the description of Brigham's business in Item 1 of this report. All subsequent
oral and written forward looking statements attributable to Brigham or persons
acting on its behalf are expressly qualified in their entirety by these factors.
Brigham assumes no obligation to update any of these statements.

Risk Factors

We Are Substantially Leveraged

      Our outstanding long-term debt was $82 million as of December 31, 2000,
and $91 million as of March 20, 2001. The credit agreements related to our
Senior Credit Facility and Subordinated Notes Facility limit the amount of
additional debt borrowings, including borrowings under these facilities or other
senior or subordinated indebtedness. As of March 20, 2001, we had no additional
borrowing availability under our Senior Credit Facility and $4 million in
additional permitted borrowing availability under our Subordinated Notes
Facility. In addition, Brigham held as cash $9.9 million in net proceeds from
the March 2001 private placement of Series A Preferred Stock.

      Our level of indebtedness will have several important effects on our
operations, including those listed below.

      o     We will dedicate a substantial portion of our cash flow from
            operations to the payment of interest on our indebtedness and to the
            payment of our other current obligations, and will not have these
            cash flows available for other purposes.

      o     The covenants in our credit facilities limit our ability to borrow
            additional funds or dispose of assets and may affect our flexibility
            in planning for, and reacting to, changes in business conditions.

      o     Our ability to obtain additional financing in the future for working
            capital, capital expenditures, acquisitions, general corporate
            purposes or other purposes may be impaired.

      We may also be required to alter our capitalization significantly to
accommodate future exploration, development or acquisition activities. These
changes in capitalization may significantly alter our leverage and dilute the
equity interests of existing stockholders. Our ability to meet our debt service
obligations and to reduce our total indebtedness will be dependent upon our
future performance, which will be subject to general economic conditions and to
financial, business and other factors affecting our operations, many of which
are beyond our control. We cannot assure you that our future performance will
not be harmed by such economic conditions and financial, business and other
factors. See "-- Liquidity and Capital Resources."

We Have Substantial Capital Requirements

      We make and will continue to make substantial capital expenditures in our
exploration and development projects. While we believe that our cash flow from
operations and borrowings under our Subordinated Notes Facility should allow us
to finance our planned operations through 2001 based on current conditions and
expectations, additional financing will be required in the future to fund our
exploration and development activities. We cannot assure you that we will be
able to secure additional financing on reasonable terms or at all, or that
financing will continue to be available to us under our existing or new
financing arrangements. Without additional capital resources, our drilling and
other activities may be limited and our business, financial condition and
results of operations may suffer. See "-- Liquidity and Capital Resources."


                                     - 37 -

<PAGE>

Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are
Volatile

      Our revenues, operating results and future rate of growth depend highly
upon the prices we receive for our oil and natural gas production. Historically,
the markets for oil and natural gas have been volatile and are likely to
continue to be volatile in the future. Market prices of oil and natural gas
depend on many factors beyond our control, including:

      o     worldwide and domestic supplies of oil and natural gas;

      o     the ability of the members of the Organization of Petroleum
            Exporting Countries to agree to and maintain oil price and
            production controls;

      o     political instability or armed conflict in oil-producing regions;

      o     the price and level of foreign imports;

      o     the level of consumer demand;

      o     the price and availability of alternative fuels;

      o     the availability of pipeline capacity;

      o     weather conditions;

      o     domestic and foreign governmental regulations and taxes; and

      o     the overall economic environment.

      We cannot predict future oil and natural gas price movements with
certainty. During 2000, the high and low settlement prices for oil on the NYMEX
were $37.20 per Bbl and $23.85 per Bbl, and the high and low settlement prices
for natural gas on the NYMEX were $9.98 per MMBtu and $2.17 per MMBtu.
Significant declines in oil and natural gas prices for an extended period may
have the following effects on our business:

      o     limit our financial condition, liquidity, ability to finance planned
            capital expenditures and results of operations;

      o     reduce the amount of oil and natural gas that we can produce
            economically;

      o     cause us to delay or postpone some of our capital projects;

      o     reduce our revenues, operating income and cash flow; and

      o     reduce the carrying value of our oil and natural gas properties.

Our Hedging Transactions May Not Prevent Losses

      In an attempt to reduce our sensitivity to energy price volatility, we use
swap and collar hedging arrangements that generally result in a fixed price or a
range of minimum and maximum price limits over a specified monthly time period.
If we do not produce our oil and natural gas reserves at rates equivalent to our
hedged position, we would be required to satisfy our obligations under hedging
contracts on potentially unfavorable terms without the ability to hedge that
risk through sales of comparable quantities of our own production. This
situation occurred during a portion of 1999 and again during portions of 2000,
due in part to our sale of certain producing reserves in mid-1999. As a result,
our cash flow was significantly reduced, particularly during 2000. Because the
terms of our hedging contracts are based on


                                     - 38 -

<PAGE>

assumptions and estimates of numerous factors such as cost of production and
pipeline and other transportation and marketing costs to delivery points,
substantial differences between the hedged prices and actual results could harm
our anticipated profit margins and our ability to manage the risk associated
with fluctuations in oil and natural gas prices. Hedging contracts limit the
benefits we will realize if actual prices rise above the contract prices. We
could be financially harmed if the other party to the hedging contracts proves
unable or unwilling to perform its obligations under such contracts. See "--
Other Matters -- Derivative Instruments" and "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk."

Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And
Uncertain Costs; We Are Dependent On Exploratory Drilling Activities

      Our revenues, operating results and future rate of growth depend highly
upon the success of our exploratory drilling program. Exploratory drilling
involves numerous risks, including the risk that we will not encounter
commercially productive natural gas or oil reservoirs. We cannot always predict
the cost of drilling, and we may be forced to limit, delay or cancel drilling
operations as a result of a variety of factors, including:

      o     unexpected drilling conditions;

      o     pressure or irregularities in formations;

      o     equipment failures or accidents;

      o     adverse weather conditions;

      o     compliance with governmental requirements; and

      o     shortages or delays in the availability of drilling rigs and the
            delivery of equipment.

      We may not be successful in our future drilling activities because even
with the use of 3-D seismic and other advanced technologies, exploratory
drilling is a speculative activity. We could incur losses because our use of 3-D
seismic data and other advanced technologies requires greater predrilling
expenditures than traditional drilling strategies. Even when fully utilized and
properly interpreted, our 3-D seismic data and other advanced technologies only
assist us in identifying subsurface structures and do not indicate whether
hydrocarbons are in fact present in those structures. Because we interpret the
areas desirable for drilling from 3-D seismic data gathered over large areas, we
may not acquire option and lease rights until after the seismic data is
available and, in some cases, until the drilling locations are also identified.
Although we have identified numerous potential drilling locations, we cannot
assure you that we will ever lease, drill or produce oil or natural gas oil from
these or any other potential drilling locations. We cannot assure you that we
will be successful in our drilling activities, that our overall drilling success
rate for activity within a particular province will not decline, or that our
completed wells will ultimately produce our estimated economically recoverable
reserves. Unsuccessful drilling activities could materially harm our operations
and financial condition.

We Are Subject To Various Casualty Risks

      Our operations are subject to hazards and risks inherent in drilling for
and producing and transporting oil and natural gas, such as:

      o     fires;

      o     natural disasters;

      o     formations with abnormal pressures;


                                     - 39 -

<PAGE>

      o     blowouts, cratering and explosions; and

      o     pipeline ruptures and spills.

      Any of these hazards and risks can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to our
properties and the property of others. See "Item 1. Business -- Operating
Hazards and Uninsured Risks."

We May Not Have Enough Insurance To Cover Some Operating Risks

      We maintain insurance coverage against some, but not all, potential losses
in order to protect against operating hazards. We may elect to self-insure if
our management believes that the cost of insurance, although available, is
excessive relative to the risks presented. We generally maintain insurance for
the hazards and risks inherent in drilling for and producing and transporting
oil and natural gas and believe this insurance is adequate. If an event occurs
that is not covered, or not fully covered, by insurance, it could harm our
financial condition and results of operations. In addition, we cannot fully
insure against pollution and environmental risks.

The Marketability Of Our Production Is Dependent On Facilities That We Typically
Do Not Own Or Control

      The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own. Our ability to produce and market
oil and natural gas could be harmed by any dramatic change in market factors or
by:

      o     federal and state regulation of oil and natural gas production and
            transportation;

      o     tax and energy policies;

      o     changes in supply and demand; and

      o     general economic conditions.

We Have Historical Operating Losses And Our Future Results May Vary; We Have
Incurred Net Losses In Each Year Of Operation

      We cannot assure you that we will be profitable in the future. At December
31, 2000, we had an accumulated deficit of $38.4 million and total stockholders'
equity of $34.8 million. We have recognized the following annual net losses
before extraordinary items since 1995: $1.6 million in 1995, $450,000 in 1996,
$1.1 million (including a net $1.2 million non-cash deferred income tax charge
incurred in connection with our conversion from a partnership to a corporation)
in 1997, $33.3 million (including a $25.9 million non-cash writedown in the
carrying value of our oil and natural gas properties) in 1998, $21.6 million
(including a $12.2 million non-cash loss on the sale of oil and natural gas
properties) in 1999, and $15.7 million in 2000. See "Item 6. Selected Financial
Data."

Our Future Operating Results May Fluctuate

      Our future operating results may fluctuate significantly depending upon a
number of factors, including:

      o     industry conditions;

      o     prices of oil and natural gas;

      o     rates of drilling success;


                                     - 40 -

<PAGE>

      o     capital availability;

      o     rates of production from completed wells; and

      o     the timing and amount of capital expenditures.

      This variability could cause our business, financial condition and results
of operations to suffer. In addition, any failure or delay in the realization of
expected cash flows from operating activities could limit our ability to invest
and participate in economically attractive projects.

Maintaining Reserves And Revenues In The Future Depends On Successful
Exploration And Development

      In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Except to the extent we conduct successful exploration and
development activities or acquire properties containing proved reserves, or
both, our proved reserves will decline as reserves are produced. Our future oil
and natural gas production depends highly upon our ability to economically find,
develop or acquire reserves in commercial quantities.

      The business of exploring for or developing reserves is capital intensive.
Reductions in our cash flow from operations and limitations on or unavailability
of external sources of capital may impair our ability to make the necessary
capital investment to maintain or expand our asset base of oil and natural gas
reserves. In addition, we cannot be certain that our future exploration and
development activities will result in additional proved reserves or that we will
be able to drill productive wells at acceptable costs. Furthermore, although
significant increases in prevailing prices for oil and natural gas could cause
increases in our revenues, our finding and development costs could also
increase. Finally, we participate in a percentage of our wells as a
non-operator. The failure of an operator of our wells to adequately perform
operations, or an operator's breach of the applicable agreements, could harm us.

We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows

      There is substantial uncertainty in estimating quantities of proved
reserves and projecting future production rates and the timing of development
expenditures. No one can measure underground accumulations of oil and natural
gas in an exact way. Accordingly, oil and natural gas reserve engineering
requires subjective estimations of those accumulations. Estimates of other
engineers might differ widely from those of our independent petroleum engineers.
Accuracy of reserve estimates depends on the quality of available data and on
engineering and geological interpretation and judgment. Our independent
petroleum engineers may make material changes to reserve estimates based on the
results of actual drilling, testing, and production. As a result, our reserve
estimates often differ from the quantities of oil and natural gas we ultimately
recover. Also, we make certain assumptions regarding future oil and natural gas
prices, production levels, and operating and development costs that may prove
incorrect. Any significant variance from these assumptions could greatly affect
our estimates of reserves, the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, the
classifications of reserves based on risk of recovery and estimates of the
future net cash flows. See "Item 2. Properties -- Oil and Natural Gas Reserves."

      Actual future net cash flows from our oil and natural gas properties also
will be affected by factors such as:

      o     the amount and timing of actual production;

      o     supply and demand for oil and natural gas;

      o     limits or increases in consumption by gas purchasers; and

      o     changes in governmental regulations or taxation.


                                     - 41 -

<PAGE>

      The timing of both our production and our incurrence of expenses in
connection with the development and production of oil and natural gas properties
will affect the timing of actual future net cash flows from proved reserves, and
thus their actual present value. In addition, the 10% discount factor we use
when calculating discounted future net cash flows in compliance with the SEC
reporting requirements may not necessarily be the most appropriate discount
factor based on interest rates in effect from time to time and risks associated
with us or the oil and gas industry in general.

We Face Significant Competition

      We operate in the highly competitive areas of oil and natural gas
exploration, exploitation, acquisition and production with other companies. We
face intense competition from a large number of independent, technology-driven
companies as well as both major and other independent oil and natural gas
companies in a number of areas such as:

      o     seeking to acquire desirable producing properties or new leases for
            future exploration;

      o     marketing our oil and natural gas production; and

      o     seeking to acquire the equipment and expertise necessary to operate
            and develop those properties.

      Many of our competitors have financial and other resources substantially
in excess of those available to us. This highly competitive environment could
harm our business. See "Item 1. Business -- Competition."

We Are Subject To Various Governmental Regulations And Environmental Risks

      Our business is subject to 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 safety matters. Although we believe we are
in substantial compliance with all applicable laws and regulations, legal
requirements are frequently changed and subject to interpretation, and we are
unable to predict the ultimate cost of compliance with these requirements or
their effect on our operations. We may be required to make significant
expenditures to comply with governmental laws and regulations.

      Our operations are subject to complex environmental laws and regulations
adopted by federal, state and local governmental authorities. Environmental laws
and regulations change frequently, and the implementation of new, or the
modification of existing, laws or regulations could harm us. The discharge of
natural gas, oil, or other pollutants into the air, soil or water may give rise
to significant liabilities on our part to the government and third parties and
may require us to incur substantial costs of remediation. We cannot be certain
that existing environmental laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations will not harm our
results of operations and financial condition. See "Item 1. Business --
Governmental Regulation; and -- Environmental Matters."

Our Business May Suffer If We Lose Key Personnel

      We have assembled a team of geologists, geophysicists and engineers who
have considerable experience in applying 3-D imaging technology to explore for
and to develop oil and natural gas. We depend upon the knowledge, skills and
experience of these experts to provide 3-D imaging and to assist us in reducing
the risks associated with our participation in oil and natural gas exploration
and development projects. In addition, the success of our business depends, to a
significant extent, upon the abilities and continued efforts of our management,
particularly Ben M. Brigham, our Chief Executive Officer, President and Chairman
of the Board. We have an employment agreement with Ben M. Brigham, but do not
have an employment agreement with any of our other employees. We have key man
life insurance on Mr. Brigham in the amount of $2 million. If we lose the
services of our key management personnel or technical experts, or are unable to
attract additional qualified personnel, our business, financial condition,
results of operations, development efforts and ability to grow could suffer. We
cannot assure you that we will be successful in attracting and retaining such
executives, geophysicists, geologists and engineers. See "Item 1. Business --
Technical Staff" and "Executive Officers of the Registrant."


                                     - 42 -

<PAGE>

Control By Certain Stockholders And Certain Anti-Takeover Provisions May Affect
You; Certain Of Our Affiliates Control A Majority Of The Outstanding Common
Stock

      As of March 20, 2001, our directors, executive officers and principal
stockholders, and certain of their affiliates, beneficially owned approximately
77% of our outstanding common stock. Accordingly, these stockholders, as a
group, will be able to control the outcome of stockholder votes, including votes
concerning the election of directors, the adoption or amendment of provisions in
our certificate of incorporation or bylaws, and the approval of mergers and
other significant corporate transactions. The existence of these levels of
ownership concentrated in a few persons makes it unlikely that any other holder
of common stock will be able to affect our management or direction. These
factors may also have the effect of delaying or preventing a change in our
management or voting control.

Certain Anti-Takeover Provisions May Affect Your Rights As A Stockholder

      Our certificate of incorporation authorizes our Board of Directors to
issue up to 10 million shares of preferred stock without stockholder approval
and to set the rights, preferences and other designations, including voting
rights, of those shares as the Board of Directors may determine. These
provisions, alone or in combination with the other matters described in the
preceding paragraph may discourage transactions involving actual or potential
changes in our control, including transactions that otherwise could involve
payment of a premium over prevailing market prices to holders of our common
stock. We are also subject to provisions of the Delaware General Corporation Law
that may make some business combinations more difficult.

The Market Price Of Our Stock Price Is Volatile

      The trading price of our common stock and the price at which we may sell
securities in the future is subject to large fluctuations in response to any of
the following: limited trading volume in our stock, changes in government
regulations, quarterly variations in operating results, our involvement in
litigation, general market conditions, the prices of oil and natural gas,
announcements by us and our competitors, our liquidity, our ability to raise
additional funds and other events.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

      Brigham limits its use of derivative instruments principally to commodity
price hedging activities, whereby gains and losses are generally offset by price
changes in the underlying commodity. Brigham's use of derivative instruments for
hedging activities could materially affect its results of operations in
particular quarterly or annual periods since such instruments can limit
Brigham's ability to benefit from favorable oil and natural gas price movements.

Commodity Price Risk

      Brigham's primary commodity market risk exposure is to changes in the
prices related to the sale of its oil and natural gas production. The market
prices for oil and natural gas have been volatile and are likely to continue to
be volatile in the future. As such, Brigham employs established policies and
procedures to manage its exposure to fluctuations in the sales prices it
receives for its oil and natural gas production through hedging activities. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Other Matters -- Derivative Instruments."

      Brigham believes that hedging, although not free of risk, allows it to
reduce its exposure to oil and natural gas sales price fluctuations and thereby
to achieve more predictable cash flows. However, hedging arrangements, when
utilized, may limit the benefit to Brigham of increases in the prices of the
hedged commodity. Moreover, Brigham's hedging arrangements generally do not
apply to all of its production and thus provide only partial price protection
against declines in commodity prices. Brigham expects that the amount of its
hedges will vary from time to time.


                                     - 43 -

<PAGE>

Interest Rate Risk

      Brigham is subject to interest rate risk as borrowings under its Senior
Credit Facility ($75 million outstanding as of December 31, 2000) accrue
interest at floating rates based on the lender's base rate or LIBOR. Brigham
does not utilize derivative instruments to protect against changes in interest
rates on debt borrowings. Based on Brigham's $75 million of outstanding
borrowings under its Senior Credit Facility at December 31, 2000, an adverse
change (defined as a hypothetical 1% and 2% increase in interest rates on such
borrowings) would reduce cash flow by approximately $750,000 and $1.5 million,
respectively, from currently projected levels.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

      Brigham's Consolidated Financial Statements required by this item are
included on the pages immediately following the Index to Financial Statements
appearing on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

      None.


                                     - 44 -

<PAGE>

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information required by this item is incorporated by reference to
information under the caption "Proposal One -- Election of Directors" and to the
information under the caption "Section 16(a) Beneficial Ownership Reporting
Compliance" in Brigham's definitive Proxy Statement (the "2001 Proxy Statement")
for its annual meeting of stockholders to be held on May 10, 2001. The 2001
Proxy Statement will be filed with the Securities and Exchange Commission (the
"Commission") not later than 120 days subsequent to December 31, 2000.


     Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to Brigham's executive officers is set forth in Part I of this
report.

ITEM 11.     EXECUTIVE COMPENSATION

      The information required by this item is incorporated herein by reference
to the 2001 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2000.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

      The information required by this item is incorporated herein by reference
to the 2001 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2000.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

      The information required by this item is incorporated herein by reference
to the 2001 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2000.


                                     - 45 -

<PAGE>

                                     PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)   1.    Consolidated Financial Statements:

            See Index to Financial Statements on page F-1.

      2.    Financial Statement Schedules:

            See Index to Financial Statements on page F-1.

      3.    Exhibits:

            The exhibits listed in the accompanying Index to Exhibits are filed
            or incorporated by reference as part of the annual report.

(b)   The following reports on Form 8-K were filed by Brigham during the last
      quarter of the period covered by this Annual Report on Form 10-K:

      Brigham filed a report on Form 8-K on November 3, 2000 (and a subsequent
      amendment thereto on November 8, 2000) to report a series of financing
      agreements.


                                     - 46 -

<PAGE>

                         GLOSSARY OF OIL AND GAS TERMS

     The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry and in this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet of natural gas equivalent. In reference to natural
gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural
gas to 1 Bbl of oil, condensate of natural liquids.

CAEX. Computer-aided exploration.

Completion. The installation of permanent equipment for the production of oil or
natural gas.

Completion Rate. The number of wells on which production casing has been run for
a completion attempt as a percentage of the number of wells drilled.

Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling Costs. The costs associated with the drilling and completing a well
(exclusive of seismic and land acquisition costs for that well and future
development costs associated with proved undeveloped reserves added by the well)
divided by total proved reserve additions.

Dry Well. A well found to be incapable of producing either oil or natural gas in
sufficient quantities to justify completion of an oil or gas well.

Exploratory Well. A well drilled to find and produce oil or natural gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.

Finding and Development Costs. Capital costs incurred in the acquisition,
exploration and development of proved oil and natural gas reserves divided by
total proved reserve additions.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in
which the Company has a working interest.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet of natural gas equivalents.

MMBbl. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is
the quantity of heat required to raise the temperature of one pound of water by
one degree Fahrenheit.

MMcf. One million cubic feet of natural gas.

MMcfe. One million cubic feet of natural gas equivalents.


                                     -47-



<PAGE>

Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the
percentage working interest owned by the Company.

Net Production. Production that is owned by the Company less royalties and
production due others.

Oil. Crude oil, condensate or other liquid hydrocarbons.

Operator. The individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.

Present Value of Future Net Revenues or PV10%. The pretax present value of
estimated future revenues to be generated from the production of proved reserves
calculated in accordance with SEC guidelines, net of estimated production and
future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.

Proved Development Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

Proved Reserves. The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion.

Royalty. An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.

Spud. Start drilling a new well (or restart).

Standardized Measure. The aftertax present value of estimated future revenues to
be generated from the production of proved reserves calculated in accordance
with SEC guidelines, net of estimated production and future development costs,
using prices and costs as of the date of estimation without future escalation,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.

2-D Seismic. The method by which a cross-section of the earth's subsurface is
created through the interpretation of reflecting seismic data collected along a
single source profile.

3-D Seismic. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of reflection seismic data
collected over surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do conventional surveys and contribute
significantly to field appraisal, development and production.

Working Interest. An interest in an oil and gas lease that gives the owner of
the interest the right to drill for and produce oil and natural gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations.

                                     -48-
<PAGE>

                                  SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, hereunder duly authorized, as of March 22, 2001.

                                      BRIGHAM EXPLORATION COMPANY


                                      By:         /s/ Ben M. Brigham
                                           ----------------------------------
                                           Ben M. Brigham
                                           Chief Executive Officer and President

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below as of March 22, 2001, by the following persons on
behalf of the Registrant and in the capacity indicated.


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


/s/ Curtis F. Harrell
----------------------------------------------------------
Curtis F. Harrell
Chief Financial Officer and Director
(principal financial and accounting officer)

/s/ Anne L. Brigham
----------------------------------------------------------
Anne L. Brigham
Director

/s/ Harold D. Carter
----------------------------------------------------------
Harold D. Carter
Director

/s/ Alexis M. Cranberg
----------------------------------------------------------
Alexis M. Cranberg
Director

/s/ Stephen P. Reynolds
----------------------------------------------------------
Stephen P. Reynolds
Director

/s/ Steven A. Webster
----------------------------------------------------------
Steven A. Webster
Director

                                     -49-
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page
                                                                            ----
Report of Independent Accountants .......................................    F-2
Consolidated Balance Sheets as of December 31, 2000 and 1999 ............    F-3
Consolidated Statements of Operations for the Years Ended
   December 31, 2000, 1999 and 1998 .....................................    F-4
Consolidated Statements of Stockholders' Equity for the Years Ended
   December 31, 2000, 1999 and 1998 .....................................    F-5
Consolidated Statements of Cash Flows for the Years Ended
   December 31, 2000, 1999 and 1998 .....................................    F-6
Notes to the Consolidated Financial Statements ..........................    F-7


                                       F-1
<PAGE>

                        REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors
  and Stockholders of Brigham Exploration Company

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of changes in stockholders' equity and of
cash flows present fairly, in all material respects, the financial position of
Brigham Exploration Company and its subsidiaries at December 31, 2000 and 1999,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.


PricewaterhouseCoopers LLP

Dallas, Texas
February 23, 2001


                                       F-2
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                           CONSOLIDATED BALANCE SHEETS
                                 (in thousands)

<TABLE>
<CAPTION>
                                                                                          December 31,
                                                                                     -----------------------
                                                                                        2000         1999
                                                                                     ---------     ---------
<S>                                                                                  <C>           <C>
                                     ASSETS

Current assets:
     Cash and cash equivalents                                                       $     837     $   2,742
     Accounts receivable                                                                 9,277         4,945
     Other current assets                                                                  559           577
                                                                                     ---------     ---------
          Total current assets                                                          10,673         8,264
                                                                                     ---------     ---------

Oil and natural gas properties, at cost
     Unproved                                                                           41,617        40,518
     Proved                                                                            162,482       138,237
Accumulated depletion                                                                  (74,609)      (66,689)
                                                                                     ---------     ---------
                                                                                       129,490       112,066
                                                                                     ---------     ---------

Other property and equipment, at cost, net                                               1,341         1,686
Drilling advances paid                                                                     960            23
Deferred loan fees                                                                       4,338         3,481
Other noncurrent assets                                                                    109           163
                                                                                     ---------     ---------
                                                                                     $ 146,911     $ 125,683
                                                                                     =========     =========

                      LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
     Accounts payable                                                                $   9,211        14,851
     Accrued drilling costs                                                                792           541
     Participant advances received                                                         136           850
     Other current liabilities                                                           7,760         1,502
                                                                                     ---------     ---------
          Total current liabilities                                                     17,899        17,744
                                                                                     ---------     ---------

Notes payable                                                                           75,000        56,000
Senior subordinated notes                                                                7,000        41,341
Other noncurrent liabilities                                                             3,697         1,600

Commitments and contingencies

Mandatorily redeemable preferred stock, Series A Preferred Stock, $.01 par value,
     $20 stated value, 1.5 million shares authorized, 1 million shares issued and
     outstanding at December 31, 2000, redemption value of $20 million                   8,558            --

Stockholders' equity:
     Preferred stock, $.01 par value, 10 million shares authorized, none
        issued and outstanding                                                              --            --
     Common stock, $.01 par value, 50 million shares authorized, 17,030,176
        and 14,517,786 issued at December 31, 2000 and 1999, respectively                  170           145
     Additional paid-in capital                                                         78,274        64,171
     Treasury stock, at cost; 1,052,632 shares at December 31, 2000                     (3,950)           --
     Unearned stock compensation                                                        (1,321)         (290)
     Accumulated deficit                                                               (38,416)      (55,028)
                                                                                     ---------     ---------
          Total stockholders' equity                                                    34,757         8,998
                                                                                     ---------     ---------
                                                                                     $ 146,911     $ 125,683
                                                                                     =========     =========
</TABLE>

  Oil and natural gas properties are accounted for using the full cost method.
        See accompanying notes to the consolidated financial statements.


                                       F-3
<PAGE>

                          BRIGHAM EXPLORATION COMPANY

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

<TABLE>
<CAPTION>
                                                                          Year Ended December 31,
                                                                    ----------------------------------
                                                                      2000         1999         1998
                                                                    --------     --------     --------
<S>                                                                 <C>          <C>          <C>
Revenues:
     Oil and natural gas sales                                      $ 19,143     $ 14,992     $ 13,799
     Workstation revenue                                                  53          285          390
                                                                    --------     --------     --------
                                                                      19,196       15,277       14,189
                                                                    --------     --------     --------

Costs and expenses:
     Lease operating                                                   2,139        2,259        2,172
     Production taxes                                                  1,786          968          850
     General and administrative                                        3,100        3,481        4,672
     Depletion of oil and natural gas properties                       7,920        7,792        8,483
     Depreciation and amortization                                       507          525          413
     Capitalized ceiling impairment                                       --           --       25,926
     Amortization of stock compensation                                  113            1          372
                                                                    --------     --------     --------
                                                                      15,565       15,026       42,888
                                                                    --------     --------     --------
           Operating income (loss)                                     3,631          251      (28,699)
                                                                    --------     --------     --------

Other income (expense):
     Interest income                                                     108          176          136
     Interest expense, net                                            (9,906)      (9,697)      (5,968)
     Loss on sale of oil and natural gas properties                       --      (12,195)          --
     Other expense                                                    (9,488)        (163)          --
                                                                    --------     --------     --------
                                                                     (19,286)     (21,879)      (5,832)
                                                                    --------     --------     --------

Loss before income taxes and extraordinary item                      (15,655)     (21,628)     (34,531)
Income tax benefit                                                        --           --        1,186
                                                                    --------     --------     --------

Loss before extraordinary item                                       (15,655)     (21,628)     (33,345)
Extraordinary item - gain on refinancing of senior subordinated
     notes, net of $0 tax                                             32,267           --           --
                                                                    --------     --------     --------

Net income (loss)                                                     16,612      (21,628)     (33,345)

Less accretion and dividends on redeemable preferred stock               275           --           --
                                                                    --------     --------     --------

Net income (loss) attributable to common stockholders               $ 16,337     $(21,628)    $(33,345)
                                                                    ========     ========     ========

Net income (loss) per share attributable to common stockholders:
     Basic/Diluted
           Loss before extraordinary item                           $  (0.98)    $  (1.53)    $  (2.64)
           Extraordinary item                                       $   1.99     $     --     $     --
                                                                    --------     --------     --------
                                                                    $   1.01     $  (1.53)    $  (2.64)
                                                                    ========     ========     ========

Weighted average common shares outstanding:
     Basic/Diluted                                                    16,241       14,152       12,626
                                                                    ========     ========     ========
</TABLE>

        See accompanying notes to the consolidated financial statements.


                                       F-4
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

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

<TABLE>
<CAPTION>
                                   Common Stock     Additional   Unearned                      Treasury Stock
                                ---------------      Paid-in       Stock     Accumulated     -------------------
                                Shares    Amounts    Capital    Compensation    Deficit      Shares      Amounts       Total
                                ------     ----     --------      -------      --------      ------      -------      --------
<S>                             <C>        <C>      <C>           <C>          <C>           <C>         <C>          <C>
Balance, December 31, 1997      12,253     $123     $ 44,919      $(1,674)     $    (55)         --      $    --      $ 43,313
Net loss                            --       --           --           --       (33,345)         --           --       (33,345)
Issuance of common stock         1,053       10        9,419           --            --          --           --         9,429
Issuance of warrants                --       --        4,500           --            --          --           --         4,500
Amortization of unearned
    stock compensation              --       --           --          784            --          --           --           784
                                ------     ----     --------      -------      --------      ------      -------      --------

Balance, December 31, 1998      13,306      133       58,838         (890)      (33,400)         --           --        24,681

Net loss                            --       --           --           --       (21,628)         --           --       (21,628)
Issuance of common stock         1,212       12        4,228           --            --          --           --         4,240
Forfeiture of stock options         --       --         (602)         602            --          --           --            --
Revision in terms of warrants       --       --          479           --            --          --           --           479
Issuance of warrants                --       --        1,228           --            --          --           --         1,228
Amortization of unearned
    stock compensation              --       --           --           (2)           --          --           --            (2)
                                ------     ----     --------      -------      --------      ------      -------      --------

Balance, December 31, 1999      14,518      145       64,171         (290)      (55,028)         --           --         8,998

Net income                          --       --           --           --        16,612          --           --        16,612
Issuance of common stock         2,203       22        4,185           --            --          --           --         4,207
Issuance of restricted stock       309        3        1,137       (1,140)           --          --           --            --
Issuance of stock options           --       --          185         (185)           --          --           --            --
Forfeiture of stock options         --       --          (60)          10            --          --           --           (50)
Issuance of warrants                --       --       13,910           --            --          --           --        13,910
Cancellation of warrants            --       --       (4,979)          --            --          --           --        (4,979)
Amortization of unearned
    stock compensation              --       --           --          284            --          --           --           284
Purchase of treasury stock          --       --           --           --            --      (1,053)      (3,950)       (3,950)
Dividends on Series A
    Preferred Stock                 --       --         (267)          --            --          --           --          (267)
Accretion on Series A
    Preferred Stock                 --       --           (8)          --            --          --           --            (8)
                                ------     ----     --------      -------      --------      ------      -------      --------

Balance, December 31, 2000      17,030     $170     $ 78,274      $(1,321)     $(38,416)     (1,053)     $(3,950)     $ 34,757
                                ======     ====     ========      =======      ========      ======      =======      ========
</TABLE>

        See accompanying notes to the consolidated financial statements.


                                       F-5
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (in thousands)

<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                              -------------------------------------
                                                                                2000          1999           1998
                                                                              --------      --------      ---------
<S>                                                                           <C>           <C>           <C>
Cash flows from operating activities:
    Net income (loss)                                                         $ 16,612      $(21,628)     $ (33,345)
    Adjustments to reconcile net income (loss) to cash provided (used) by
    operating activities:
      Depletion of oil and natural gas properties                                7,920         7,792          8,483
      Depreciation and amortization                                                507           525            413
      Capitalized ceiling impairment                                                --            --         25,926
      Amortization of stock compensation                                           113             1            372
      Interest paid through issuance of additional senior subordinated
      notes                                                                      4,575         5,459             --
      Amortization of deferred loan fees and debt issuance costs                 1,283         1,739            726
      Amortization of discount on senior subordinated notes                        673           575            286
      Amortization of deferred loss on derivative instruments                      280           759             --
      Market value adjustment for derivative instruments                         8,885           115             --
      Extraordinary gain on refinancing of senior subordinated notes           (32,267)           --             --
      Loss on sale of oil and natural gas properties                                --        12,195             --
      Changes in working capital and other items:
        (Increase) decrease in accounts receivable                              (4,332)        2,993         (3,029)
        (Increase) decrease in other current assets                               (262)       (1,046)           (10)
        Increase (decrease) in accounts payable                                 (7,290)       (1,136)         7,991
        Increase (decrease) in participant advances received                      (714)           86            275
        Increase (decrease) in other current liabilities                          (640)         (115)           862
        Increase (decrease) in deferred tax liability                               --            --         (1,186)
        Other noncurrent assets                                                     54          (151)             6
        Other noncurrent liabilities                                               (32)       (5,585)         7,004
                                                                              --------      --------      ---------
              Net cash provided (used) by operating activities                  (4,635)        2,578         14,774
                                                                              --------      --------      ---------

Cash flows from investing activities:
    Additions to oil and natural gas properties                                (28,910)      (25,560)       (85,207)
    Proceeds from sale of oil and natural gas properties                         3,938        27,143             --
    Additions to other property and equipment                                     (162)         (146)          (868)
    (Increase) decrease in drilling advances paid                                 (937)          207           (152)
                                                                              --------      --------      ---------
              Net cash provided (used) by investing activities                 (26,071)        1,644        (86,227)
                                                                              --------      --------      ---------

Cash flows from financing activities:
    Proceeds from issuance of common stock                                       4,207            --          9,429
    Proceeds from issuance of preferred stock and warrants                      20,060            --             --
    Proceeds from issuance of senior subordinated notes and warrants             7,000            --         40,000
    Increase in notes payable                                                   19,000        13,750        105,800
    Repayment of notes payable                                                      --       (16,750)       (78,800)
    Principal payments on senior subordinated notes                            (20,354)           --             --
    Principal payments on capital lease obligations                               (210)         (253)          (236)
    Deferred loan fees paid                                                       (902)         (796)        (3,872)
                                                                              --------      --------      ---------
              Net cash provided (used) by financing activities                  28,801        (4,049)        72,321
                                                                              --------      --------      ---------

Net increase (decrease) in cash and cash equivalents                            (1,905)          173            868
Cash and cash equivalents, beginning of year                                     2,742         2,569          1,701
                                                                              --------      --------      ---------
Cash and cash equivalents, end of year                                        $    837      $  2,742      $   2,569
                                                                              ========      ========      =========
</TABLE>

        See accompanying notes to the consolidated financial statements.


                                       F-6
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 the "Company." 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 West Texas, the Anadarko Basin and
the onshore Gulf Coast.

      Pursuant to an exchange agreement dated February 26, 1997 (the "Exchange
Agreement") and upon the initial filing on February 27, 1997 of a registration
statement with the Securities and Exchange Commission (the "SEC") for the public
offering of common stock (the "Offering"), the shareholders of Brigham, Inc.
transferred all of the outstanding stock of Brigham, Inc. to the Company in
exchange for 3,859,821 shares of common stock of the Company. Pursuant to the
Exchange Agreement, the Partnership's other general partner and the limited
partners also transferred all of their partnership interests to the Company in
exchange for 3,314,286 shares of common stock of the Company. Furthermore, the
holders of the Partnership's subordinated convertible notes transferred these
notes to the Company in exchange for 1,754,464 shares of common stock. These
transactions are referred to as "the Exchange." In completing the Exchange, the
Company issued 8,928,571 shares of common stock to the stockholders of Brigham,
Inc., the partners of the Partnership and the holder of the Partnership's
subordinated notes payable. As a result of the Exchange, the Company now owns
all the partnership interests in the Partnership. In May 1997, the Company sold
3,325,000 shares of its common stock in the Offering at a price of $8.00 per
share.

2. Summary of Significant Accounting Policies

Basis of Accounting

      The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results may differ from those estimates.

Principles of Consolidation

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

Cash and Cash Equivalents

      The Company considers all highly liquid financial instruments with an
original maturity of three months or less to be cash equivalents.


                                       F-7
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Property and Equipment

      The Company uses the full cost method of accounting for oil and natural
gas properties. Under this method, all acquisition, exploration and development
costs, including payroll, interest, and other internal costs, incurred for the
purpose of finding oil and natural gas reserves are capitalized. Internal costs
capitalized are directly attributable to acquisition, exploration and
development activities and do not include costs related to production, general
corporate overhead or similar activities. Costs associated with production and
general corporate activities are expensed in the period incurred.

      Proceeds from the sale of oil and natural gas properties are applied to
reduce the capitalized costs of oil and natural gas properties unless the sale
would significantly alter the relationship between capitalized cost and proved
reserves, in which case a gain or loss is recognized.

      Capitalized costs associated with impaired properties and capitalized
costs related to properties having proved reserves, plus the estimated costs of
future development, dismantlement, restoration and abandonment costs, net of
estimated salvage values, are amortized using the unit-of-production method
based on proved reserves. Capitalized costs of oil and natural gas properties,
net of accumulated amortization, are limited to the total of estimated future
net cash flows from proved oil and natural gas reserves, discounted at ten
percent, plus the cost of unevaluated properties. There are many factors,
including global events, that may influence the production, processing,
marketing and valuation of oil and natural gas. A reduction in the valuation of
oil and natural gas properties resulting from declining prices or production
could adversely impact depletion rates and capitalized cost limitations.

      Other property and equipment, which primarily consists of 3-D seismic
interpretation workstations, are depreciated on a straight-line basis over the
estimated useful lives of the assets after considering salvage value. Estimated
useful lives are as follows:

      Furniture and fixtures.......................................     10 years
      Machinery and equipment......................................      5 years
      3-D seismic interpretation workstations and software.........      3 years

      Betterments and major improvements that extend the useful lives are
capitalized while expenditures for repairs and maintenance of a minor nature are
expensed as incurred.

Revenue Recognition

      The Company recognizes oil and natural gas sales from its interests in
producing wells under the sales method of accounting. Under the sales method,
the Company recognizes revenues based on the amount of oil or natural gas sold
to purchasers which may differ from the amounts to which the Company is entitled
based on its interest in the properties. Gas balancing obligations as of
December 31, 2000, 1999 and 1998 were not significant.

      Industry participants in the Company's seismic programs are charged on an
hourly basis for the work performed by the Company on its 3-D seismic
interpretation workstations. The Company recognizes workstation revenue as
service is provided.


                                       F-8
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Financial Instruments

      The Company periodically enters into commodity contracts, including price
swaps, caps and/or floors, which require payments to (or receipts from)
counterparties based on the differential between a fixed price and a variable
price for a fixed quantity of natural gas or crude oil without the exchange of
underlying volumes. The notional amounts of these financial instruments are
based on expected production from existing wells. The Company uses these
financial instruments to manage market risks resulting from fluctuations in
commodity prices.

      Correlation of the commodity contracts is determined by evaluating whether
the contract gains and losses will substantially offset the effects of price
changes on the underlying natural gas and crude oil sales volumes. To the extent
that correlation exists between the contracts and the underlying natural gas and
crude oil sales volumes, realized gains or losses and related cash flows arising
from the contracts are recognized as a component of oil and natural gas sales in
the same period as the sale of the underlying volumes. To the extent that
correlation does not exist between the contracts and the underlying natural gas
and crude oil sales volumes, realized gains or losses and related cash flows
arising from the contracts are recognized in the period incurred as a component
of other income. The fair market value of any contract that does not meet the
correlation test outlined above is recorded as a deferred gain or loss on the
balance sheet and is adjusted to current market value at each balance sheet date
with any deferred gains or losses recognized as a component of other income.

      In the event that management decides to terminate a contract, generally
accepted accounting principles require that any gains or losses upon termination
be deferred and recognized as oil and natural gas sales in the period in which
the underlying volumes are sold.

Stock Based Compensation

      The Company 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, the Company has adopted
the disclosure-only provisions of Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"). See Note 13 for
the pro forma disclosures of compensation expense determined under the
fair-value provisions of FAS 123.

Income Taxes

      The Company follows the provisions of Financial Accounting Standard No.
109, "Accounting for Income Taxes" ("FAS 109"). Under the asset and liability
method of FAS 109, deferred tax assets and liabilities are recognized for the
estimated future tax consequences attributable to the differences between the
financial statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred tax assets and liabilities are measured
using the tax rate in effect for the year in which those temporary differences
are expected to be recovered or settled. Under FAS 109, the effect of a change
in tax rates of deferred tax assets and liabilities is recognized in income in
the year of the enacted rate change.

Segment Information

      All of the Company's oil and natural gas properties and related operations
are located in the United States and management has determined that the Company
has one reportable segment.


                                       F-9
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Treasury Stock

      Treasury stock purchases are recorded at cost. Upon reissuance, the cost
of treasury shares held is reduced by the average purchase price per share of
the aggregate treasury shares held.

New Pronouncements

      In June 1998, the Financial Accounting Standards Board (the "FASB") issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("FAS 133"). The FASB has subsequently
issued Statements of Financial Accounting Standards No. 137 and 138, which are
amendments to FAS 133. FAS 133, as amended, is effective for fiscal years
beginning after June 15, 2000. The Company adopted FAS 133 on January 1, 2001.

      FAS 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. All derivative instruments
will be recorded on the balance sheet at fair value and changes in the fair
value of derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if it is, depending on the type of hedge transaction.
The Company's derivative contracts consist primarily of cash flow hedge
transactions in which the Company is hedging the variability of cash flows
related to a forecasted transaction. Changes in the fair value of these
derivative instruments will be reported in other comprehensive income and will
be reclassified as earnings in the periods in which earnings are impacted by the
variability of the cash flows of the hedged item. The ineffective portion of all
hedges will be recognized in current period earnings.

      In January 2001, the Company recorded a net of tax cumulative effect
adjustment of $11.8 million to other comprehensive income to recognize the fair
value (liability) of all derivative instruments which qualify for hedge
accounting treatment in accordance with FAS 133.

Reclassifications

      Certain reclassifications have been made to the prior year balances to
conform to current year presentation.

3. Asset Dispositions

      In February 1999, the Company entered into a project financing arrangement
with Duke Energy Financial Services, Inc. ("Duke") to fund the continued
exploration of five projects covered by approximately 200 square miles of 3-D
seismic data acquired in 1998. In this transaction, the Company conveyed 100% of
its working interest in land and seismic in these project areas to a newly
formed limited liability company (the "Duke LLC") for a total consideration of
$10 million. The Company is the managing member of the Duke LLC with a 1%
interest and Duke is the sole remaining member with a 99% interest. Pursuant to
the terms of the Duke LLC agreement, the Company pays 100% of the drilling and
completion costs for all wells drilled by the Duke LLC in exchange for a 70%
working interest in the wells and their associated drilling and spacing units
and allocable seismic data. Upon 100% project payout, the Company has certain
rights to back-in for up to a 94% effective working interest in the Duke LLC
properties. See Note 16 regarding dissolution of the Duke LLC in February 2001.

      In June 1999, the Company sold its entire interest in certain producing
and non-producing oil and natural gas properties located in its Anadarko Basin
province to two parties for a combined sales price of $17.1 million. Total


                                      F-10
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

proceeds, net of transaction costs, were $16.7 million and were used to repay a
portion of the Company's notes payable. Due to the magnitude of the reserve
volumes that were attributable to these properties relative to the Company's
remaining net reserve volumes, the Company recognized a loss of $12.2 million,
which was the difference between the sales price received, after adjustment for
transaction costs, and the $28.9 million basis allocated to the divested
properties in accordance with the full-cost method of accounting for oil and
natural gas properties.

4. Property and Equipment

      Property and equipment, at cost, are summarized as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                      December 31,
                                                                                -----------------------
                                                                                   2000          1999
                                                                                ---------     ---------
      <S>                                                                       <C>           <C>
      Oil and natural gas properties .....................................      $ 204,099     $ 178,755
      Accumulated depletion ..............................................        (74,609)      (66,689)
                                                                                ---------     ---------
                                                                                  129,490       112,066
                                                                                ---------     ---------
      Other property and equipment:
          3-D seismic interpretation workstations and software ...........          2,277         2,248
          Office furniture and equipment .................................          2,015         1,909
          Accumulated depreciation .......................................         (2,951)       (2,471)
                                                                                ---------     ---------
                                                                                    1,341         1,686
                                                                                ---------     ---------
                                                                                $ 130,831     $ 113,752
                                                                                =========     =========
</TABLE>

      The Company capitalizes certain payroll and other internal costs directly
attributable to acquisition, exploration and development activities as part of
its investment in oil and natural gas properties over the periods benefited by
these activities. During the years ended December 31, 2000, 1999 and 1998, these
capitalized costs amounted to $3.4 million, $3.3 million and $4.6 million,
respectively. Capitalized costs do not include any costs related to production,
general corporate overhead, or similar activities. Interest costs of $2.8
million, $3.0 million and $1.2 million were capitalized in 2000, 1999 and 1998,
respectively.

5. Notes Payable and Senior Subordinated Notes Payable

Notes Payable

      In January 1998, the Company entered into a reserve-based revolving credit
facility (the "Credit Facility") which originally provided for initial borrowing
availability of $75 million. Principal outstanding under the Credit Facility was
due at maturity on January 26, 2001 with interest due monthly for base rate
tranches or periodically as LIBOR tranches mature. Amounts outstanding under the
Credit Facility accrued interest at either the lender's Base Rate or LIBOR plus
2.25%, at the Company's option. In connection with the origination of the Credit
Facility, certain bank fees and other expenses totaling approximately $1.9
million were recorded as deferred costs and are amortized over the life of the
loan.

      The Credit Facility was amended in March 1999 to reduce the borrowing
availability, extend the date of borrowing base redetermination, modify certain
financial covenants, include certain additional covenants that place significant
restrictions on the Company's ability to make certain capital expenditures, and
to change the interest rate on outstanding borrowings to either the lender's
Base Rate or LIBOR plus 3.0%, at the Company's option. The Company incurred a
$500,000 transaction fee due to the lender over a ten-month period.


                                      F-11
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

      In July 1999, the Credit Facility was amended to provide the Company with
borrowing availability of $56 million. As consideration for this amendment, in
July 1999 the Company issued to its senior lenders one million warrants to
purchase the Company's common stock at an exercise price of $2.25 per share. An
estimated value of $1.2 million was attributed to these warrants by the Company
and was recognized as additional deferred loan fees to be amortized over the
remaining period to maturity of the Credit Facility. The Company's obligations
under the Credit Facility are secured by substantially all of the oil and
natural gas properties and other tangible assets of the Company.

      In February 2000, the Company entered into an amended and restated Credit
Facility with its existing senior lenders and a new senior lender. The Credit
Facility was further amended in October 2000. The amended and restated Credit
Facility provides the Company with $75 million in senior borrowing availability
for a three-year term. The Credit Facility includes a provision whereby certain
amounts held by one of the lenders, not to exceed $30 million of the outstanding
borrowings, are convertible into shares of the Company's common stock
("Convertible Notes") to the extent total borrowings exceed $45 million. As of
December 31, 2000, the outstanding balance of the Convertible Notes totaled $30
million.

      The Credit Facility provides that the Convertible Notes can be converted
into shares of the Company's common stock at the following amounts and prices:
(i) the first $10 million of borrowings is convertible at $3.90 per share, (ii)
the second $10 million is convertible at $6.00 per share, and (iii) the final
$10 million is convertible at $8.00 per share. The Convertible Notes could
result in a beneficial conversion feature based on the relationship between the
Company's stock price at the time of a borrowing and the share price at which
the Company can force conversion of the relative portion of the Convertible
Notes. The value assigned to the beneficial conversion feature would be recorded
as a component of interest expense to the extent the Convertible Notes are
immediately convertible. Due to the fact that the Company could force conversion
of any portion of the Convertible Notes before February 17, 2001, and also given
that the share prices at which the Company can force conversion were in excess
of the market price of the Company's common stock at each draw date since the
amendment of the Credit Facility, no beneficial conversion feature was recorded
in 2000. If the Credit Facility is repaid at maturity or is prepaid prior to
maturity without payments of cash premiums, the warrants issued to the new
participant in the Credit Facility to purchase the Company's common stock become
exercisable. Further, to the extent the Company prepays any of the Convertible
Notes, it will be required to pay a premium above the face value of the
Convertible Notes to the lender. Such premium amounts range from 150% to 110%,
depending on the timing of the prepayment. Such prepayment, however, would
require the prior approval of the original lenders to the Credit Facility. In
addition, certain financial covenants of the Credit Facility were amended or
added in February 2000 and in October 2000. In connection with the February 2000
amendment, the Company reset the price of the warrants previously issued to two
of its senior lenders to purchase one million shares of the Company's common
stock from an exercise price of $2.25 per share to $2.02 per share.

      Principal outstanding under the Credit Facility is due at maturity on
December 31, 2002 with interest due monthly for base rate tranches or
periodically as LIBOR tranches mature. The annual interest rate for borrowings
is either the lender's base rate or LIBOR plus 3%, at the Company's option. The
obligation is secured by substantially all of the Company's oil and natural gas
properties and other tangible assets. At December 31, 2000, the Company had $75
million in borrowing outstanding under the Credit Facility.

      The Credit Facility has certain financial covenants, including current and
interest coverage ratios, minimum current ratio, minimum interest coverage
ratio, and the limitation on capital expenditures related to seismic and land
activities.


                                      F-12
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Senior Subordinated Notes Payable

      In August 1998, the Company issued $50 million of debt and equity
securities to two affiliated institutional investors. The financing transaction
consisted of the issuance of $40 million of senior subordinated secured notes
(the "Subordinated Notes") with warrants (the "Warrants") to purchase the
Company's common stock and the sale of $10 million of the Company's common
stock, or 1,052,632 shares at a price of $9.50 per share. The combined sale of
the Subordinated Notes and common stock of the Company generated proceeds, net
of transaction costs, of approximately $47.5 million that was used to repay a
portion of the then outstanding borrowings under the Credit Facility.

      Principal outstanding under the Subordinated Notes was due at maturity on
August 20, 2003. Interest on the Subordinated Notes was payable quarterly at
rates that vary depending upon whether accrued interest was paid in cash or "in
kind" through the issuance of additional Subordinated Notes. Interest was
payable in cash at interest rates of 12%, 13%, and 14% during the years one
through three, year four and year five, respectively, of the term of the
Subordinated Notes; provided, however, that the Company was permitted to pay
interest in kind for a cumulative total of seven (or potentially eight)
quarterly interest payments at interest rates of 13%, 14% and 15% during the
years one through three, year four and year five, respectively, of the term of
the Subordinated Notes. The Company was permitted to repay the Subordinated
Notes in full without premium at any time prior to maturity. The indenture
governing the Subordinated Notes contained certain covenants including, but not
limited to, limitations or restrictions on indebtedness, distributions,
affiliate transactions, liens and sale and leaseback transactions. The indenture
prohibited all dividends on the Company's stock. Warrants to purchase 1 million
shares of the Company's common stock exercisable during a period of seven years
at a price of $10.45 per share were issued in connection with the Subordinated
Notes.

      Concurrent with the issuance of the Subordinated Notes, the Company
recorded a discount on the Subordinated Notes of $4.5 million to reflect the
estimated value of the Warrants. Also, in connection with the issuance of the
Subordinated Notes, certain fees and expenses totaling approximately $1.8
million were recorded as deferred costs. The Subordinated Note discount and
deferred fees were amortized over the five-year term of the Subordinated Notes.

      In March 1999, the indenture governing the Subordinated Notes was amended
to provide the Company with the option to pay interest due on the Subordinated
Notes in kind, for any reason, through the second quarter of 2000. The amendment
also provided for a reduction in the exercise price per share of the Warrants
from $10.45 per share to $3.50 per share. The discount on the Subordinated Notes
was decreased by $479,000 to reflect the change in value attributed to the
Warrants as a result of the revision in the terms of the Warrants.

      In February 2000, the indenture governing the Subordinated Notes was
amended to, among other things, provide the Company with an extension of its
right to pay interest through the issuance of additional Subordinated Notes in
lieu of cash (or "in kind") through the third quarter of 2000 and potentially
through the fourth quarter of 2000 if certain conditions were met. In exchange
for granting these amendments, the Company (i) reset the price of the warrants
previously issued to the holders of the Subordinated Notes to purchase one
million shares of the Company's common stock from an exercise price of $3.50 per
share to $2.43 per share and (ii) granted to the holders of the Subordinated
Notes a term overriding royalty interest that provided for the limited right to
receive 4%, or 3% if certain conditions were met, of the Company's net
production revenue to reduce any outstanding Subordinated Notes issued as
interest paid in kind. As payments were made pursuant to the term overriding
royalty interest, they were recorded by the Company as a reduction of the
balance payable pursuant to the Subordinated Notes.

      On November 1, 2000, the Subordinated Notes, the term overriding royalty
interest and all of the equity securities of the Company held by the holders of
the Subordinated Notes were purchased by the Company for $20 million cash


                                      F-13
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

resulting in an extraordinary gain of $32.3 million, net of transaction costs of
$1.7 million.

      In October 2000, the Company issued $20 million of new subordinated notes
to Shell Capital Inc. (the "SCI Notes") and 1,250,000 warrants to purchase the
Company's common stock (the "SCI Warrants"). The SCI Notes bear interest at
10.75% per annum and have no principal repayment obligations until maturity in
2005. The SCI Notes are issued pursuant a multi-draw facility at borrowing
increments of at least $1 million, and such funds cannot be redrawn once they
have been repaid. Interest is payable quarterly on the last day of each January,
April, July and October. At the Company's option, up to 50% of the interest
payments during the first two years can be satisfied by payment-in-kind ("PIK")
through the issuance of additional SCI Notes in lieu of cash. The SCI Notes are
secured obligations ranking junior to the Company's existing $75 million Credit
Facility, have a five-year maturity, are redeemable at the Company's option for
face value at anytime and have certain financial and other covenants. The SCI
Warrants have a term of seven years, an exercise price of $3.00 per share and a
cashless exercise feature. The Company valued the SCI Warrants using the
Black-Scholes valuation model and recorded the estimated value of $2.9 million
as deferred loan costs which are amortized over the five year term of the SCI
Notes. As of December 31, 2000, the outstanding balance of the SCI Notes totaled
$7 million.

6. Series A Preferred Stock

      On October 31, 2000, the Company issued one million shares of mandatorily
redeemable preferred stock (the "Series A Preferred Stock") and 6,666,667
warrants to purchase the Company's common stock (the "Series A Warrants") for
net proceeds of $19.8 million. The proceeds from the issuance of the Series A
Preferred Stock and Series A Warrants were used to purchase the Subordinated
Notes, the term overriding royalty interest and all of the equity securities of
the Company held by the holder of the Subordinated Notes as described in Note 5.

      The Company designated 1.5 million shares of preferred stock as Series A
Preferred Stock, which has a par value of $.01 per share and a stated value of
$20 per share, in October 2000. The Series A Preferred Stock is cumulative and
pays dividends quarterly at a rate of 6% per annum of the stated value if paid
in cash or 8% per annum of the stated value if paid-in-kind ("PIK") through the
issuance of additional Series A Preferred Stock in lieu of cash. At the
Company's option, up to 100% of the dividend payments on the Series A Preferred
Stock can be paid by the issuance of PIK dividends until November 2005. The
Series A Preferred Stock matures in November 2010 and is redeemable at the
Company's option at 100% or 101% of par value (depending upon certain
conditions) at anytime prior to maturity. As of December 31, 2000, the Company
had one million shares of Series A Preferred Stock issued and outstanding with a
$20 million liquidation value.

      The Series A Warrants have a term of ten years, an exercise price of $3.00
per share and must be exercised, if the Company so requires, in the event the
Company's common stock trades at or above $5.00 per share for 60 consecutive
trading days. The exercise price of the Series A Warrants is payable either in
cash or in shares of the Series A Preferred Stock valued at liquidation value
plus accrued dividends. If the Company requires exercise of the Series A
Warrants, proceeds will be used to fund the redemption of a similar value of
then outstanding Series A Preferred Stock. The Series A Warrants were valued at
$11.5 million using the Black-Scholes valuation model and were recorded as
additional paid-in capital in the year ended December 31, 2000.


                                      F-14
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

7. Issuance of Common Stock

      In February 2000, the Company issued 2,195,122 shares of common stock and
731,707 warrants to purchase the Company's common stock for total net proceeds
of $4.2 million in a private placement to a group of institutional investors led
by affiliates of two members of the Company's board of directors. The equity
sale consisted of units that included one share of common stock and one-third of
a warrant to purchase the Company's common stock at an exercise price of $2.5625
per share.

8. Capital Lease Obligations

      Property under capital leases consists of the following (in thousands):

<TABLE>
<CAPTION>
                                                                                   December 31,
                                                                            ------------------------
                                                                              2000             1999
                                                                            --------        --------
      <S>                                                                   <C>             <C>
      3-D seismic interpretation workstations and software ............     $    601        $    607
      Office furniture and equipment ..................................          167             167
                                                                            --------        --------
                                                                                 768             774
      Accumulated depreciation and amortization .......................         (587)           (410)
                                                                            --------        --------
                                                                            $    181        $    364
                                                                            ========        ========
</TABLE>

      The obligations under capital leases are at fixed interest rates ranging
from 7.5% to 17.9% and are collateralized by property, plant and equipment. The
future minimum lease payments under the capital leases and the present value of
the net minimum lease payments at December 31, 2000 are as follows (in
thousands):

      2001 .........................................................    $   115
      2002 .........................................................         27
                                                                        -------
      Total minimum lease payments .................................        142
          Estimated executory costs included in capital leases .....         (7)
                                                                        -------
      Net minimum lease payments ...................................        135
          Amounts representing interest ............................         (9)
                                                                        -------
      Present value of net minimum lease payments ..................        126
      Less:  current portion .......................................       (102)
                                                                        -------
      Noncurrent portion ...........................................    $    24
                                                                        =======


                                      F-15
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

9. Income Taxes

      The provision for income taxes consists of the following (in thousands):

                                                                Year ended
                                                               December 31,
                                                          ---------------------
                                                             2000          1999
                                                          --------     --------
      Current income taxes:
          Federal ..............................          $     --     $     --
          State ................................                --           --
      Deferred income taxes:
          Federal ..............................                --           --
          State ................................                --           --
                                                          --------     --------
                                                          $     --     $     --
                                                          ========     ========
      The difference in income taxes provided and the amounts determined by
applying the federal statutory tax rate to income before income taxes result
from the following (in thousands):

                                                                Year ended
                                                               December 31,
                                                          ---------------------
                                                             2000          1999
                                                          --------     --------
      Tax at statutory rate ....................          $  5,814     $ (7,570)
      Add the effect of:
          Nondeductible expenses ...............                12            8
          Valuation allowance ..................            (5,826)       7,562
                                                          --------     --------
                                                          $     --     $     --
                                                          ========     ========


      The components of deferred income tax assets and liabilities are as
follows (in thousands):

                                                              December 31,
                                                          ---------------------
                                                            2000         1999
                                                          --------     --------
      Deferred tax assets:
          Net operating loss carryforwards .....          $ 26,329     $ 18,796
          Amortization of stock compensation ...               305          266
          Derivatives ..........................             3,434           --
          Other ................................                26           27
                                                          --------     --------
                                                            30,094       19,089
      Deferred tax liability:
          Depreciable and depletable property ..           (17,578)        (484)
          Valuation allowance ..................           (12,516)     (18,605)
                                                          --------     --------
                                                          $     --     $     --
                                                          ========     ========


                                      F-16
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

      At December 31, 2000, the Company has regular tax net operating loss
carryforwards of approximately $75.2 million of which $13.2 million expires in
2012, $26.4 million expires in 2018, $22.2 expires in 2019 and $13.4 million
expires in 2020. In addition, at December 31, 2000, the Company has alternative
minimum tax net operating loss carryforwards of approximately $63.3 million of
which $8.6 million expires in 2012, $23.2 million expires in 2018, $21.6 million
expires in 2019 and $9.9 million expires in 2020.

10. Net Income (Loss) Per Share

      The Company accounts for its earnings per share in accordance with
Statement of Financial Accounting Standards No. 128, "Earnings per Share" which
replaced the calculation of primary and fully diluted earnings per share with
basic and diluted earning per share. Basic earnings per share is 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 or
converted into common stock or resulted in the issuance of common stock that
would then share in the earnings of the Company. The number of common share
equivalents outstanding is computed using the treasury stock method.

      At December 31, 2000, 1999, and 1998, options and warrants to purchase
approximately 11.1 million, 3.5 million and 2.2 million shares of common stock,
respectively, were outstanding but were not included in the computation of
diluted income (loss) per share because the effect of including the options and
warrants would have been anti-dilutive.

11. Contingencies, Commitments and Factors Which May Affect Future Operations

Litigation

      The Company 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 the Company.

      As of December 31, 2000, there were no known environmental or other
regulatory matters related to the Company's operations which are reasonably
expected to result in a material liability to the Company. Compliance with
environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on the Company's capital expenditures, earnings or
competitive position.

Operating Lease Commitments

      The Company leases office equipment and space under operating leases
expiring at various dates through 2002. The future minimum annual rental
payments under the noncancelable terms of these leases at December 31, 2000 are
as follows (in thousands):

      2001...................................................       $        790
      2002...................................................                395
                                                                    ------------
                                                                    $      1,185
                                                                    ============

      Rental expense for the years ended December 31, 2000, 1999 and 1998 was
approximately $805,000, $938,000 and $875,000, respectively.


                                      F-17
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Major Customers

      The following purchasers accounted for 10% or more of the Company's oil
and natural gas sales for the years ended December 31, 2000, 1999 and 1998:

                                                  2000         1999         1998
                                                  ----         ----         ----

      Purchaser A .............................    36%          26%          25%
      Purchaser B .............................    20%          16%          11%
      Purchaser C .............................    --           11%          --
      Purchaser D .............................    --           --           15%
      Purchaser E .............................    --           --           11%

      Due to the availability of other purchasers, the Company does not believe
that the loss of any one of these individual purchasers would adversely affect
the Company's result of operations.

Factors Which May Affect Future Operations

      Since the Company's major products are commodities, significant changes in
the prices of oil and natural gas could have a significant impact on the
Company's results of operations for any particular year.

12. Financial Instruments

      The Company periodically enters into commodity price swap agreements which
require payments to (or receipts from) counterparties based on the differential
between a fixed price and a variable price for a fixed quantity of natural gas
or crude oil without the exchange of the underlying volumes. The notional
amounts of these derivative financial instruments are based on planned
production from existing wells. The Company uses these derivative financial
instruments to manage market risks resulting from fluctuations in commodity
prices. Commodity price swaps are effective in minimizing these risks by
creating essentially equal and offsetting market exposures.

      In February 1998, the Company entered into a hedging contract whereby
10,000 MMBtu per day of natural gas was purchased and sold subject to a fixed
price swap agreement for monthly periods from April 1998 through October 1999.
Pursuant to these arrangements the Company exchanged a floating market price for
a contract month and payments were received when the fixed price exceeded the
floating price. Total natural gas subject to this hedging contract was 3,040,000
MMBtu in 1999 and 2,750,000 MMBtu in 1998.

      In August 1998, the Company entered into a hedging contract whereby 5,000
MMBtu per day of natural gas was purchased and sold subject to a fixed price
swap agreement for monthly periods from April 1999 through October 1999.
Pursuant to these arrangements the Company exchanged a floating market price for
a fixed contract price of $2.015 per MMBtu. Payments were made by the Company
when the floating price exceeded the fixed price for a contract month and
payments were received when the fixed price exceeded the floating price. Total
natural gas subject to this hedging contract was 1,070,000 MMBtu in 1999.

      In January 1999, the Company entered into a swap agreement with terms
similar to existing agreements which related to production for monthly periods
from November 1999 through March 2000. Pursuant to these arrangements, 15,000
MMBtu per day of natural gas was purchased and sold subject to a fixed price
swap agreement, and the


                                      F-18
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Company exchanged a floating market price for a fixed contract price of $2.065
per MMBtu. Total natural gas volumes subject to this agreement were 1,365,000
MMBtu in 2000 and 915,000 MMBtu in 1999.

      As a result of these arrangements, the Company realized an increase
(decrease) in oil and natural gas revenues of approximately $(482,000),
$(486,000), and $555,000 for the years ending December 31, 2000, 1999, and 1998,
respectively. To the extent that notional amounts covered by these arrangements
exceed actual production quantities, a corresponding portion of the contracts
has been recorded on the balance sheet at fair value which approximated $0 and
$291,000 as of December 31, 2000 and 1999, respectively. Additionally, the
mark-to-market adjustments and related cash flows associated with this portion
of these contracts of approximately $291,000 and $(429,000) have been recorded
as a component of other income (expense) on the 2000 and 1999 statements of
operations, respectively.

      In September 1999, the Company amended the fixed contract price from
$2.065 per MMBtu to a range from $2.509 to $2.678 per MMBtu for natural gas
volumes for the months of October 1999 through January 2000 under the then
outstanding swap agreement. This resulted in a deferred loss of $1.1 million to
be amortized to oil and natural gas revenues and other income (expense) over the
original contract period of October 1999 through January 2000. For the year
ended December 31, 2000, approximately $285,000 was amortized to oil and natural
gas revenues and, for the year ended December 31, 1999, approximately $645,000
was amortized to oil and natural gas revenues and approximately $129,000 was
amortized to other income.

      In March 2000, the Company redesignated or replaced the 15,000 MMBtu per
day swap of natural gas production with three swap agreements of 5,000 MMBtu per
day for the period from April 1, 2000 through April 30, 2001 at fixed prices of
$2.065 per MMBtu, $2.0575 per MMBtu, and $2.15 per MMBtu. The floating prices in
the replacement swap agreements represent the principal geographic markets in
which the Company produces and sells the natural gas which provides a better
hedge of commodity price risks. Total natural gas subject to these agreements in
2000 and 2001 are 4,125,000 MMBtu and 1,800,000 MMBtu, respectively. The Company
realized a decrease in oil and natural gas revenues of $9.4 million for the year
ended December 31, 2000.

      In September 1999, the Company entered into a natural gas cap contract
that provides the counterparty with a call option on 10,000 MMBtu per day of
natural gas production for the monthly periods from May 2001 through June 2002.
Payments are made by the Company to the counterparty when the floating price
exceeds the fixed price of $2.50 per MMBtu for the periods May 2001 through
October 2001 and May 2002 through June 2002, and $2.70 per MMBtu for the period
November 2001 through April 2002. These instruments do not qualify for hedge
accounting and, accordingly, were recorded on the date of the transaction at
their fair value of $1.1 million as a deferred credit on the balance sheet. As
of December 31, 2000 and 1999, the fair value of the remaining contracts
approximated $10.1 million and $875,000, respectively, with the corresponding
mark-to-market adjustments and related cash flows recorded as a component of
other income (expense) on the statement of operations.

      In March 2000, the Company entered into a combination of crude oil floor
and cap options on the sale of 400 barrels per day of production for the period
January 1, 2001 through June 30, 2001. Under this collar arrangement, the
Company will receive a minimum price of $18.00 per barrel and a maximum of
$26.60 per barrel. The Company concurrently established a collar on 200 barrels
per day of oil production for the period July 1, 2001 through December 31, 2001.
The minimum and maximum prices for this collar are $16.10 and $25.25 per barrel,
respectively.

      The Company's non-derivative financial instruments include cash and cash
equivalents, accounts receivable, accounts payable and long-term debt. The
carrying amount of cash and cash equivalents, accounts receivable and accounts
payable approximate fair value because of their immediate or short maturities.
The carrying value of the


                                      F-19
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Company's revolving credit facility approximates its fair market value since it
bears interest at floating market interest rates.

      The Company's accounts receivable relate to oil and natural gas to various
industry companies, amounts due from industry participants for expenditures made
by the Company on their behalf and workstation revenues. Credit terms, typical
of industry standards, are of a short-term nature and the Company does not
require collateral. The Company's accounts receivable at December 31, 2000 and
1999 do not represent significant credit risks as they are dispersed across many
counterparties. Counterparties to the natural gas and crude oil price swaps are
investment grade financial institutions.

13. Employee Benefit Plans

Retirement Savings Plan

      The Company has adopted a defined contribution 401(k) plan for
substantially all of its employees. Eligible employees may contribute up to 25%
of their compensation to this plan. The 401(k) plan provides that the Company
may, at its discretion, match employee contributions. The Company has not
matched employee contributions in any plan year.

Stock Compensation

      In 1994, three employees were granted restricted interests in the Company
that vested in increments through July 1999. At the date of grant, the value of
these interests was immaterial. On February 26, 1997, in connection with the
Exchange (see Note 1), the three employees transferred these interests to the
Company in exchange for 156,250 shares of restricted common stock of the
Company. The terms of the restricted stock and the restricted Company interests
are substantially the same. No compensation expense resulted from this exchange.

      The Company adopted an incentive plan, effective upon completion of the
Exchange (see Note 1), which provides for the issuance of stock options, stock
appreciation rights, stock, restricted stock, cash or any combination of the
foregoing. The objective of this plan is to reward key employees whose
performance may have a significant effect on the success of the Company. An
aggregate of 1,588,170 shares of the Company's common stock was reserved for
issuance pursuant to this plan. The Compensation Committee of the Board of
Directors determines the type of awards made to each participant and the terms,
conditions and limitations applicable to each award. Options granted subsequent
to March 4, 1997 have an exercise price equal to the fair market value of the
Company's common stock on the date of grant and generally vest over three to
five years.

      The Company also maintains a plan under which it offers stock compensation
to non-employee directors. Pursuant to the terms of the plan, non-employee
directors are entitled to annual grants. Options granted under this plan have an
exercise price equal to the fair market value of the Company's common stock on
the date of grant and generally vest over five years.


                                      F-20
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

      The following table summarizes activity under the incentive plan for each
of the three years ended December 31, 2000:

                                                                       Weighted
                                                                       Average
                                                                       Exercise
                                                           Shares       Price
                                                         ---------     --------
      Options outstanding December 31, 1997 .........      628,737     $   5.03
            Options granted .........................      873,500         8.62
            Options forfeited or cancelled ..........     (307,583)      (12.88)
            Options exercised .......................           --           --
                                                         ---------     --------
      Options outstanding December 31, 1998 .........    1,194,654         5.63
            Options granted .........................      650,000         2.43
            Options forfeited or cancelled ..........     (324,761)       (4.68)
            Options exercised .......................         (167)       (7.46)
                                                         ---------     --------
      Options outstanding December 31, 1999 .........    1,519,726         4.47
            Options granted .........................      793,500         2.83
            Options forfeited or cancelled ..........     (898,112)       (5.57)
            Options exercised .......................       (8,000)       (5.11)
                                                         ---------     --------
      Options outstanding December 31, 2000 .........    1,407,114     $   2.89
                                                         =========     ========

      The Company is required to use variable accounting for 252,500 of the
stock options granted during 2000. This method of accounting requires
recognition of noncash compensation expense for the difference between the
option exercise price and the market price of the Company's stock at the end of
the accounting period of vested options. Since the market price for the
Company's stock is a component of the variable cost accounting calculation, it
is not possible to determine the total noncash compensation expense that will be
recognized during the vesting period of these options.

      On December 14, 1998, the Board of Directors approved a proposal to cancel
and reissue outstanding employee stock options that were granted in January 1998
with an exercise price of $12.88. A total of 305,250 options with an exercise
price of $12.88 per share were cancelled and reissued with an exercise price of
$6.31 per share, the fair market value of the Company's stock at the date of
reissuance. Vesting schedules remained unchanged by the reissuance.

      Exercise prices for options outstanding at December 31, 2000 range from
$1.5545 to $14.375 and have remaining contract lives of 1 to 7 years. Exercise
prices for options outstanding at December 31, 1999 range from $1.5545 to
$14.375 and remaining contractual lives range from 4.5 to 7 years. Exercise
prices for options outstanding at December 31, 1998 range from $5.00 to $14.375
and remaining contractual lives range from 5.5 to 7 years. Exercise prices for
options outstanding at December 31, 1997 range from $5.00 to $14.375 and
remaining contractual lives range from 5.5 to 6 years. Options exercisable at
December 31, 2000, 1999 and 1998 were 247,450, 291,242 and 145,740,
respectively.

      The weighted average fair value per share of stock compensation issued
during 2000, 1999 and 1998 was $1.92, $1.42 and $5.40, respectively. The fair
value for these options was estimated using the Black-Scholes model with the
following weighted average assumptions for grants made in 2000, 1999 and 1998:
risk free interest rate of 6.2%, 6.0% and 4.7%; volatility of the expected
market prices of the Company's common stock of 67%, 57% and 77%; expected
dividend yield of zero and weighted average expected option lives of 6.6, 5.6
and 5.0 years, respectively.


                                      F-21
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

      The Black-Scholes valuation model was developed for use in estimating the
fair value of traded options that have no vesting restrictions and are
transferable. Additionally, the assumptions required by the valuation model are
highly subjective. Because the Company's stock options have significantly
different characteristics from those of traded options, and because changes in
the subjective input assumptions can materially affect the fair value estimate,
in management's opinion the model does not necessarily provide a reliable single
measure of the fair value of the Company's stock options.

      Had compensation cost for the Company's stock options been determined
based on the fair market value at the grant dates of the awards consistent with
the methodology prescribed by FAS No. 123, the Company's net income (loss) and
net income (loss) per share for 2000, 1999 and 1998 would have been the pro
forma amounts indicated below:

<TABLE>
<CAPTION>
                                                                           2000          1999          1998
                                                                        ----------    ----------   ----------
      <S>                                                               <C>           <C>          <C>
      Net income (loss) (in thousands):
          As reported .......................................           $   16,612    $  (21,628)  $  (33,345)
          Pro forma .........................................               17,744       (21,605)     (33,591)
      Net income (loss) per share:
          As reported .......................................                 1.01         (1.53)       (2.64)
          Pro forma .........................................                 1.09         (1.53)       (2.66)
</TABLE>

      The Company granted 644,097 stock options as of March 4, 1997. These
options have an exercise price of $5.00 compared to an originally determined
estimated fair market value of the Company's common stock at date of grant of
$8.00. This grant resulted in noncash compensation expense that is being
recognized over the related vesting period of the options. In January 1998, the
Company revised the fair market value of its common stock at the date these
options were granted from $8.00 to $9.00. The result of this revision was an
increase in the 1997 net loss of approximately $81,000, or $0.01 per share.

Exchange of Certain Options for Shares of Restricted Stock

      On October 25, 2000, the compensation committee of the Board of Directors
approved a proposal to give its employees a one-time right to elect to cancel
all or half of their outstanding employee stock options which were previously
granted with exercise prices of $5.00 per share (the "$5 Options") or $6.31 per
share (the "$6.31 Options") and to receive in exchange shares of restricted
stock under the Company's 1997 Incentive Plan. The exchange ratios were .643
shares of restricted stock for each share of common stock underlying a $5 Option
and .4 shares of restricted stock for each share of common stock underlying a
$6.31 Option.

      Pursuant to the option exchange offer, on October 27, 2000, a total of
244,794 of the $5 Options were canceled in exchange for 157,401 shares of
restricted stock, and a total of 379,665 of the $6.31 Options were canceled in
exchange for 151,866 shares of restricted stock. Regardless of whether the
canceled options were vested or unvested, the shares of restricted stock vest
25% per year beginning October 27, 2000. The restricted stock agreements contain
provisions for accelerated vesting in some circumstances, which provisions are
similar to those in the agreements covering the canceled options. This exchange
resulted in noncash compensation expense of approximately $1.1 million that is
being recognized over the vesting period of the restricted stock.


                                      F-22
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

14. Related Party Transactions

      During the years ended December 31, 2000, 1999 and 1998, the Company
incurred costs of approximately $138,000, $180,000 and $851,000, respectively,
for fees for land acquisition services performed by a company owned by a brother
of the Company's President and Chief Executive Officer. Other participants in
the Company's 3-D seismic projects reimbursed the Company for a portion of these
amounts.

      A director of the Company served as a consultant to the Company on various
aspects of the Company's business and strategic issues. Fees paid for these
services by the Company were $32,709, $62,874 and $100,539 for the years ended
December 31, 2000, 1999 and 1998, respectively. Additional disbursements
totaling approximately $12,000, $12,000 and $12,000 were made during 2000, 1999
and 1998, respectively, for the reimbursement of certain expenses.

15. Supplemental Cash Flow Information

<TABLE>
<CAPTION>
                                                                                                2000        1999       1998
                                                                                              --------    --------   --------
      <S>                                                                                     <C>         <C>        <C>
      Cash paid for interest ..........................................................       $  3,894    $  1,960   $  5,490
      Noncash investing and financing activities:
        Capital lease asset additions .................................................       $     --    $     51   $    320
        Decrease in accounts payable and other noncurrent liabilities in
           exchange for issuance of common stock ......................................             --       4,240         --
        Increase in accounts payable for deferred loan fees to be paid in future ......             --          50         --
        Increase in deferred loan fees for issuance of warrants .......................          2,400       1,228         --
        Dividends and accretion on mandatorily redeemable preferred stock .............            275          --         --
</TABLE>

16. Subsequent Events

Duke Project

      In February 2001, Duke, as majority member of the Duke LLC (as described
in Note 3) elected to dissolve the Duke LLC. As a result, the remaining
undeveloped land and seismic data in the Duke LLC project areas will be
unconditionally owned by Duke following the dissolution of the Duke LLC.

Preferred Stock Placement

      In March 2001, the Company issued 500,000 shares of Series A Preferred
Stock and 2,105,263 warrants to purchase the Company's common stock (the
"Additional Series A Warrants") for $10 million. The Series A Preferred Stock,
which is mandatorily redeemable, is described in Note 6.

      The Additional Series A Warrants have terms similar to the Series A
Warrants described in Note 6 except the Additional Series A Warrants have an
exercise price of $4.75 per share and must be exercised, if the Company so
requires, in the event that the Company's common stock trades at an average of
at least 150% of the exercise price (currently $7.125 per share) for 60
consecutive trading days. The Additional Series A Warrants are valued at
approximately $4.5 million using the Black-Scholes valuation model and were
recorded as additional paid-in capital in March 2001.


                                      F-23
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

17. Oil and Natural Gas Exploration and Production Activities

      The tables presented below provide supplemental information about oil and
natural gas exploration and production activities as defined by SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities".

Results of Operations for Oil and Natural Gas Producing Activities (in
thousands)

<TABLE>
<CAPTION>

                                                                                       Year ended December 31,
                                                                                ------------------------------------
                                                                                   2000         1999          1998
                                                                                ---------    ---------    ----------
     <S>                                                                        <C>          <C>          <C>
     Oil and natural gas sales...............................................   $  19,143    $  14,992    $   13,799
     Costs and expenses:
         Lease operating.....................................................       2,139        2,259         2,172
         Production taxes....................................................       1,786          968           850
         Depletion of oil and natural gas properties.........................       7,920        7,792         8,483
         Capitalized ceiling impairment......................................           -            -        25,926
         Income tax expense (benefit) (a)....................................       2,554        1,391        (8,271)
                                                                                ---------    ---------    ----------
     Total costs and expenses................................................      14,399       12,410        29,160
                                                                                ---------    ---------    ----------
                                                                                $   4,744    $   2,582    $  (15,361)
                                                                                =========    =========    ==========
     Depletion per physical unit of production (equivalent Mcf of gas).......   $    1.20    $    1.24    $     1.27
                                                                                =========    =========    ==========
</TABLE>

      ------------
      (a)   The income tax expense (benefit) is calculated at the statutory rate
            and determined without regard to the Company's deduction for general
            and administrative expenses, interest costs and other income tax
            deductions and credits.

      Oil and natural gas sales reflect the market prices of net production sold
or transferred with appropriate adjustments for royalties, net profits interest
and other contractual provisions. Lease operating expenses include lifting costs
incurred to operate and maintain productive wells and related equipment
including such costs as operating labor, repairs and maintenance, materials,
supplies and fuel consumed. Production taxes include production and severance
taxes. Depletion of oil and natural gas properties relates to capitalized costs
incurred in acquisition, exploration and development activities. Results of
operations do not include interest expense and general corporate amounts.

Costs Incurred and Capitalized Costs

      The costs incurred in oil and natural gas acquisition, exploration and
development activities follow (in thousands):

<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                              --------------------------------------
                                                                                  2000         1999          1998
                                                                              ----------    ----------    ----------
     <S>                                                                      <C>           <C>           <C>
     Costs incurred for the year:
         Exploration.....................................................     $   14,238    $   19,224    $   68,214
         Property acquisition............................................          2,540         3,462        16,245
         Development.....................................................         12,555         4,632        10,475
         Proceeds from participants......................................            (40)       (2,439)      (10,502)
                                                                              ----------    ----------    ----------
                                                                              $   29,293    $   24,879    $   84,432
                                                                              ==========    ==========    ==========
</TABLE>


                                      F-24
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

      Costs incurred represent amounts incurred by the Company for exploration,
property acquisition and development activities. Periodically, the Company will
receive proceeds from participants subsequent to project initiation for an
assignment of an interest in the project. These payments are represented by
"Proceeds from participants" in the table above.

      Capitalized costs related to oil and natural gas acquisition, exploration
and development activities follow (in thousands):

<TABLE>
<CAPTION>
                                                                             December 31,
                                                                      ---------------------------
                                                                          2000             1999
                                                                      -----------     -----------
     <S>                                                              <C>             <C>
     Cost of oil and natural gas properties at year-end:
         Proved...................................................    $   162,482     $   138,237
         Unproved.................................................         41,617          40,518
                                                                      -----------     -----------
         Total capitalized costs..................................        204,099         178,755
         Accumulated depletion....................................        (74,609)        (66,689)
                                                                      -----------     -----------
                                                                      $   129,490     $   112,066
                                                                      ===========     ===========
</TABLE>

      Following is a summary of costs (in thousands) excluded from depletion at
December 31, 2000 by year incurred. At this time, the Company is unable to
predict either the timing of the inclusion of these costs and the related
natural gas and oil reserves in its depletion computation or their potential
future impact on depletion rates.

<TABLE>
<CAPTION>
                                                                    December 31,
                                                        -----------------------------------      Prior
                                                           2000         1999         1998        Years         Total
                                                        ---------    ---------    ---------     --------     ---------
     <S>                                                <C>          <C>          <C>           <C>          <C>
     Property acquisition..........................     $   1,126    $     933    $   4,000     $  7,396     $  13,455
     Exploration...................................           595        1,015       13,107        8,480        23,197
     Capitalized interest..........................         2,772        1,951          242           --         4,965
                                                        ---------    ---------    ---------     --------     ---------
          Total                                         $   4,493    $   3,899    $  17,349     $ 15,876     $  41,617
                                                        =========    =========    =========     ========     =========
</TABLE>


                                      F-25
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

18. Oil and Natural Gas Reserves and Related Financial Data (Unaudited)

      Information with respect to the Company's oil and natural gas producing
activities is presented in the following tables. Reserve quantities as well as
certain information regarding future production and discounted cash flows were
determined by the Company's independent petroleum consultants and internal
petroleum reservoir engineer.

Oil and Natural Gas Reserve Data

      The following tables present the Company's estimates of its proved oil and
natural gas reserves. The Company emphasizes that reserve estimates are
approximates and are expected to change as additional information becomes
available. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact way, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Accordingly, there can be no assurance that the reserves set forth herein will
ultimately be produced nor can there be assurance that the proved undeveloped
reserves will be developed within the periods anticipated. A substantial portion
of the reserve balances was estimated utilizing the volumetric method, as
opposed to the production performance method.

<TABLE>
<CAPTION>
                                                                                          Natural
                                                                                            Gas              Oil
                                                                                           (MMcf)          (MBbls)
                                                                                          -------          ------
     <S>                                                                                  <C>              <C>
     Proved reserves at December 31, 1997...........................................       53,230           3,181
         Revisions to previous estimates.............................................     (26,696)           (115)
         Extensions, discoveries and other additions.................................      48,050           1,752
         Purchase of minerals-in-place...............................................         851              11
         Production..................................................................      (4,269)           (396)
                                                                                          -------          ------
     Proved reserves at December 31, 1998...........................................       71,166           4,433
         Revisions to previous estimates.............................................      (9,938)            214
         Extensions, discoveries and other additions.................................      30,428           1,156
         Sales of minerals-in-place..................................................     (22,002)         (2,430)
         Production..................................................................      (4,197)           (346)
                                                                                          -------          ------
     Proved reserves at December 31, 1999...........................................       65,457           3,027
         Revisions of previous estimates.............................................          83            (554)
         Extensions, discoveries and other additions.................................      17,058             758
         Production..................................................................      (4,431)           (361)
                                                                                          -------          ------
     Proved reserves at December 31, 2000...........................................       78,167           2,870
                                                                                          =======          ======
     Proved developed reserves at December 31:
         1998........................................................................      38,571           2,935
         1999........................................................................      28,594           1,873
         2000........................................................................      30,754           1,620
</TABLE>

      Proved reserves are estimated quantities of natural gas and crude oil
which geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.


                                      F-26
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein

      The following table presents a standardized measure of discounted future
net cash inflows (in thousands) relating to proved oil and natural gas reserves.
Future cash flows were computed by applying year-end prices of oil and natural
gas relating to the Company's proved reserves to the estimated year-end
quantities of those reserves. Future price changes were considered only to the
extent provided by contractual agreements in existence at year-end. Future
production and development costs were computed by estimating those expenditures
expected to occur in developing and producing the proved oil and natural gas
reserves at the end of the year, based on year-end costs. Actual future cash
inflows may vary considerably and the standardized measure does not necessarily
represent the fair value of the Company's oil and natural gas reserves.

<TABLE>
<CAPTION>
                                                                                            December 31,
                                                                               --------------------------------------
                                                                                  2000          1999          1998
                                                                               ----------    ----------    ----------
     <S>                                                                       <C>           <C>           <C>
     Future cash inflows................................................       $  899,819    $  228,429    $  198,082
     Future development and production costs............................         (154,295)      (61,878)      (61,064)
     Future income taxes................................................         (216,342)      (12,406)       (6,972)
                                                                               ----------    ----------    ----------
     Future net cash inflows............................................       $  529,182    $  154,145    $  130,046
     Future net cash inflow before income taxes, discounted
         at 10% per annum...............................................       $  497,666    $  114,466    $   81,741
     Standardized measure of future net cash inflows discounted
         at 10% per annum...............................................       $  359,228    $  113,546    $   81,649
                                                                               ==========    ==========    ==========
</TABLE>

      The base sales prices for the Company's reserves were $10.42 per Mcf for
natural gas and $26.83 per Bbl for oil as of December 31, 2000, $2.35 per Mcf
for natural gas and $22.75 per Bbl for oil as of December 31, 1999, and $2.12
per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998. These
base prices were adjusted to reflect applicable transportation and quality
differentials on a well-by-well basis to arrive at realized sales prices used to
estimate the Company's reserves at these dates.


                                      F-27
<PAGE>

                           BRIGHAM EXPLORATION COMPANY

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                                   (continued)

      Changes in the future net cash inflows discounted at 10% per annum follow
(in thousands):

<TABLE>
<CAPTION>
                                                                                           December 31,
                                                                             --------------------------------------
                                                                                2000          1999          1998
                                                                             ----------    ----------    ----------
     <S>                                                                     <C>           <C>           <C>
     Beginning of period.................................................    $  113,546    $   81,649    $   64,274
         Sales of oil and natural gas produced, net of production
              costs......................................................       (15,218)      (11,765)      (10,776)
         Development costs incurred......................................         5,308         4,413         5,423
         Extensions and discoveries......................................       295,239        43,346        52,389
         Purchases of minerals-in-place..................................             -             -           687
         Sales of minerals-in-place......................................             -       (32,783)            -
         Net change of prices and production costs.......................       175,018        33,226       (11,921)
         Change in future development costs..............................         6,990          (555)         (656)
         Changes in production rates and other...........................       (83,322)          637        (6,109)
         Revisions of quantity estimates.................................       (12,262)      (11,969)      (23,470)
         Accretion of discount...........................................        11,447         8,174         6,925
         Change in income taxes .........................................      (137,518)         (827)        4,883
                                                                             ----------    ----------    ----------
     End of period                                                           $  359,228    $  113,546    $   81,649
                                                                             ==========    ==========    ==========
</TABLE>

19. Quarterly Financial Data (Unaudited)

<TABLE>
<CAPTION>
                                                                                   Year Ended December 31, 2000
                                                                    ---------------------------------------------------------
                                                                    Quarter 1       Quarter 2       Quarter 3       Quarter 4
                                                                    ---------       ---------       ---------       ---------
      <S>                                                            <C>             <C>             <C>             <C>
      Revenue ...............................................        $ 4,538         $ 4,651         $ 5,365         $  4,642
      Operating income ......................................          1,136           1,078           1,198              219
      Net loss before extraordinary gain ....................         (2,198)         (4,328)         (5,345)          (3,784)
      Extraordinary gain ....................................             --              --              --           32,267
      Net income (loss) .....................................         (2,198)         (4,328)         (5,345)          28,208
      Net loss per share:
           Basic/Diluted
              Net loss before extraordinary gain ............          (0.14)          (0.26)          (0.32)           (0.25)
              Extraordinary gain ............................             --              --              --             1.99

<CAPTION>
                                                                                   Year Ended December 31, 1999
                                                                    ---------------------------------------------------------
                                                                    Quarter 1       Quarter 2       Quarter 3       Quarter 4
                                                                    ---------       ---------       ---------       ---------
      <S>                                                            <C>             <C>             <C>             <C>
      Revenue ...............................................        $ 3,281         $ 3,624         $ 4,238         $  4,134
      Operating income (loss) ...............................            113             190            (432)             380
      Net loss ..............................................         (1,944)        (14,839)         (2,651)          (2,194)
      Net loss per share:
           Basic/Diluted ....................................          (0.15)          (1.04)          (0.18)           (0.15)
</TABLE>


                                      F-28
<PAGE>

                                INDEX TO EXHIBITS

The following documents are filed as exhibits to this report:

Number                                 Description

2.1      --    Exchange Agreement (filed as Exhibit 2.1 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

3.1      --    Certificate of Incorporation (filed as Exhibit 3.1 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

3.1.1    --    Certificates of Amendmnt to Certificate of Incorporation (filed
               as Exhibit 3.1.1 to the Company's Registration Statement on Form
               S-3 (Registration No. 333-37558), and incorporated herein by
               reference).

3.2      --    Bylaws (filed as Exhibit 3.2 to the Company's Registration
               Statement on Form S-1 (Registration No. 333-22491), and
               incorporated herein by reference).

4.1      --    Form of Common Stock Certificate (filed as Exhibit 4.1 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

4.2      --    Certificate of Designations of Series A Preferred Stock (Par
               Value $.01 Per Share) of Brigham Exploration Company filed
               October 31, 2000 (filed as Exhibit 4.1 to the Company's Current
               Report on Form 8-K, as amended (filed November 8, 2000), and
               incorporated herein by reference).

4.2.1+   --    Certificate of Amendment of Certificate of Designations of Series
               A Preferred Stock (Par Value $.01 Per Share) of Brigham
               Exploration Company, filed March 2, 2001.

10.1     --    Agreement of Limited Partnership, dated May 1, 1992, between
               Brigham Exploration Company and General Atlantic Partners III,
               L.P. as general partners, and Harold D. Carter and GAP-Brigham
               Partners, L.P. as limited partners (filed as Exhibit 10.1 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.1.1   --    Amendment No. 1 to Agreement of Limited Partnership of Brigham
               Oil & Gas, L.P., dated May 1, 1992, by and among Brigham
               Exploration Company, General Atlantic Partners III, L.P.,
               GAP-Brigham Partners, L.P. and Harold D. Carter (filed as Exhibit
               10.1.1 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.1.2   --    Amendment No. 2 to Agreement of Limited Partnership of Brigham
               Oil & Gas, L.P., dated September 30, 1994, by and among Brigham
               Exploration Company, General Atlantic Partners III, L.P.,
               GAP-Brigham Partners, L.P., Harold D. Carter and the additional
               signatories thereto (filed as Exhibit 10.1.2 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.1.3   --    Amendment No. 3 to Agreement of Limited Partnership of Brigham
               Oil & Gas, L.P., dated August 24, 1995, by and among Brigham
               Exploration Company, General Atlantic Partners III, L.P.,
               GAP-Brigham Partners, L.P., Harold D. Carter, Craig M. Fleming,
               David T. Brigham and Jon L. Glass (filed as Exhibit 10.1.3 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.1.4   --    Amended and Restated Agreement of Limited Partnership of Brigham
               Oil & Gas, L.P., dated December 30, 1997 by and among Brigham,
               Inc., Brigham Holdings I, L.L.C. and Brigham Holdings II, L.L.C.
               (filed as Exhibit 10.1.4 to the Company's Annual Report on Form
               10-K for the year ended December 31, 1998, and incorporated
               herein by reference)

10.2     --    Agreement of Limited Partnership of Venture Acquisitions, L.P.,
               dated September 23, 1994, by and between Quest Resources, L.L.C.
               and RIMCO Energy, Inc. as general partners, and RIMCO Production
               Company, Inc., RIMCO Exploration Partners, L.P. I and RIMCO
               Exploration Partners, L.P. II, as limited partners (filed as
               Exhibit 10.2 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.3     --    Regulations of Quest Resources, L.L.C. (filed as Exhibit 10.3 to
               the Company's Registration Statement on Form S-1 (Registration
               No. 333-22491), and incorporated herein by reference).
<PAGE>

10.4     --    Management and Ownership Agreement, dated September 23, 1994, by
               and among Brigham Oil & Gas, L.P., Brigham Exploration Company,
               General Atlantic Partners III, L.P., Harold D. Carter, Ben M.
               Brigham and GAP-Brigham Partners, L.P. (filed as Exhibit 10.4 to
               the Company's Registration Statement on Form S-1 (Registration
               No. 333-22491), and incorporated herein by reference).

10.5*    --    Consulting Agreement, dated May 1, 1997, by and between Brigham
               Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit 10.4 to
               the Company's Registration Statement on Form S-1 (Registration
               No. 33-53873), and incorporated herein by reference).

10.5.1*  --    Letter agreement, dated as of March 20, 2000, setting forth
               amendments effective January 1, 2000, to the Consulting
               Agreement, dated May 1, 1997, by and between Brigham Oil & Gas,
               L.P. and Harold D. Carter (filed as Exhibit 10.5.1 to the
               Company's Annual Report on Form 10-K for the year ended December
               31, 1999, and incorporated herein by reference).

10.6*    --    Employment Agreement, by and between Brigham Exploration Company
               and Ben M. Brigham (filed as Exhibit 10.7 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.7*    --    Form of Confidentiality and Noncompete Agreement between the
               Registrant and each of its executive officers (filed as Exhibit
               10.8 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.8*    --    1997 Incentive Plan of Brigham Exploration Company as amended on
               February 1, 2000 (filed as an amendment to the Company's
               definitive proxy statement filed on Schedule 14A on April 20,
               2000, and incorporated herein by reference).

10.8.1*  --    Form of Option Agreement for certain executive officers (filed as
               Exhibit 10.9.1 to the Company's Registration Statement on Form
               S-1 (Registration No. 333-22491), and incorporated herein by
               reference).

10.8.2*+ --    Form of Restricted Stock Agreement for certain executive officers
               dated as of October 27, 2000.

10.9*    --    Incentive Bonus Plan dated as of February 28, 1997 of Brigham,
               Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.10 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.10    --    Two Bridgepoint Lease Agreement, dated September 30, 1996, by and
               between Investors Life Insurance Company of North America and
               Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.10.1  --    First Amendment to Two Bridge Point Lease Agreement dated April
               11, 1997 between Investors Life Insurance Company of North
               America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.1 to
               the Company's Registration Statement on Form S-1 (Registration
               No. 333-53873), and incorporated herein by reference).

10.10.2  --    Second Amendment to Two Bridge Point Lease Agreement dated
               October 13, 1997 between Investors Life Insurance Company of
               North America and Brigham Oil & Gas, L.P. (filed as Exhibit
               10.9.2 to the Company's Registration Statement on Form S-1
               (Registration No. 333-53873), and incorporated herein by
               reference).

10.10.3  --    Letter dated April 17, 1998 exercising Right of First Refusal to
               Lease "3rd Option Space" (filed as Exhibit 10.9.3 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-53873), and incorporated herein by reference).

10.10.4  --    Sublease agreement dated as of November 16, 1999, by and between
               Brigham Oil & Gas, L.P., and ShowSupport.com, Inc. (filed as
               Exhibit 10.10.4 to the Company's Annual Report on Form 10-K for
               the year ended December 31, 1999, and incorporated herein by
               reference).

10.11    --    Anadarko Basin Seismic Operations Agreement, dated February 15,
               1996, by and between Brigham Oil & Gas, L.P. and Veritas
               Geophysical, Ltd. (filed as Exhibit 10.15 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.11.1  --    Letter Amendment to Anadarko Basin Seismic Operations Agreement,
               dated June 10, 1996, between Brigham Oil & Gas, L.P. and Veritas
               Geophysical, Ltd. (filed as Exhibit 10.15.1 to the
<PAGE>

               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.12    --    Expense Allocation and Participation Agreement, dated April 1,
               1996, between Brigham Oil & Gas, L.P. and Gasco Limited
               Partnership. (filed as Exhibit 10.16 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.12.1  --    Amendment to Expense Allocation and Participation Agreement,
               dated October 21, 1996, between Brigham Oil & Gas, L.P. and Gasco
               Limited Partnership (filed as Exhibit 10.16.1 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.13    --    Expense Allocation and Participation Agreement, dated April 1,
               1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company,
               Inc. (filed as Exhibit 10.17 to the Company's Registration
               Statement on Form S-1 (Registration No. 333-22491), and
               incorporated herein by reference).

10.13.1  --    Amendment to Expense Allocation and Participation Agreement,
               dated September 26, 1996, between Brigham Oil & Gas, L.P. and
               Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.1 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.13.2  --    Letter Amendment to Expense Allocation and Participation
               Agreement, dated May 20, 1996, between Brigham Oil & Gas, L.P.
               and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.2 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.14    --    Anadarko Basin Joint Participation Agreement, dated May 1, 1996,
               by and among Stephens Production Company and Brigham Oil & Gas,
               L.P. (filed as Exhibit 10.18 to the Company's Registration
               Statement on Form S-1 (Registration No. 333-22491), and
               incorporated herein by reference).

10.15    --    Anadarko Basin Joint Participation Agreement, dated May 1, 1996,
               by and between Vintage Petroleum, Inc. and Brigham Oil & Gas,
               L.P. (filed as Exhibit 10.19 to the Company's Registration
               Statement on Form S-1 (Registration No. 333-22491), and
               incorporated herein by reference).

10.16    --    Processing Alliance Agreement, dated July 20, 1993, between
               Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as
               Exhibit 10.20 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.16.1  --    Letter Amendment to Processing Alliance Agreement, dated November
               3, 1994, between Veritas Seismic Ltd. and Brigham Oil & Gas, L.P.
               (filed as Exhibit 10.20.1 to the Company's Registration Statement
               on Form S-1 (Registration No. 333-22491), and incorporated herein
               by reference).

10.17    --    Agreement and Assignment of Interest, West Bradley Project, dated
               September 1, 1995, by and between Aspect Resources Limited
               Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit
               10.21 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.18    --    Agreement and Assignment of Interests in lands located in Grady
               County, Oklahoma, West Bradley Project, dated December 1, 1995,
               by and between Aspect Resources Limited Liability Company,
               Brigham Oil & Gas, L.P. and Venture Acquisitions, L.P. (filed as
               Exhibit 10.22 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.19    --    Agreement and Assignment of Interests, West Bradley Project,
               dated December 1, 1995, by and between Aspect Resources Limited
               Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit
               10.23 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.20    --    Geophysical Exploration Agreement, Hardeman Project, Hardeman and
               Wilbarger Counties, Texas and Jackson County, Oklahoma, dated
               March 15, 1993 by and among General Atlantic Resources, Inc.,
               Maynard Oil Company, Ruja Muta Corporation, Tucker Scully
               Interests Ltd.,
<PAGE>

               JHJ Exploration, Ltd., Cheyenne Petroleum Company, Antrim
               Resources, Inc., and Brigham Oil & Gas, L.P. (filed as Exhibit
               10.24 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.21    --    Agreement and Partial Assignment of Interests in OK13-P Prospect
               Area, Jackson County, Oklahoma (Hardeman Project), dated August
               1, 1995, by and between Brigham Oil & Gas, L.P. and Aspect
               Resources Limited Liability Company (filed as Exhibit 10.25 to
               the Company's Registration Statement on Form S-1 (Registration
               No. 333-22491), and incorporated herein by reference).

10.22    --    Agreement and Partial Assignment of Interests in Q140-E Prospect
               Area, Hardeman County, Texas (Hardeman Project), dated August 1,
               1995, by and between Brigham Oil & Gas, L.P. and Aspect Resources
               Limited Liability Company (filed as Exhibit 10.26 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.23    --    Agreement and Partial Assignment of Interests in Hankins #1
               Chappel Prospect Agreement, Jackson County, Oklahoma (Hardeman
               Project), dated March 21, 1996, by and between Brigham Oil & Gas,
               L.P., NGR, Ltd. and Aspect Resources Limited Liability Company
               (filed as Exhibit 10.27 to the Company's Registration Statement
               on Form S-1 (Registration No. 333-22491), and incorporated herein
               by reference).

10.24    --    Form of Indemnity Agreement between the Registrant and each of
               its executive officers (filed as Exhibit 10.28 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.25    --    Registration Rights Agreement dated February 26, 1997 by and
               among Brigham Exploration Company, General Atlantic Partners III
               L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II, RIMCO
               Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M. Brigham,
               Anne L. Brigham, Harold D. Carter, Craig M. Fleming, David T.
               Brigham and Jon L. Glass (filed as Exhibit 10.29 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.26    --    1997 Director Stock Option Plan (filed as Exhibit 10.30 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.27    --    Form of Employee Stock Ownership Agreement (filed as Exhibit
               10.31 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.28    --    Agreement and Assignment of Interest in Geophysical Exploration
               Agreement, Esperson Dome Project, dated November 1, 1994, by and
               between Brigham Oil & Gas, L.P. and Vaquero Gas Company (filed as
               Exhibit 10.33 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.29    --    Geophysical Exploration Agreement, Southwest Danbury Project,
               Brazoria County, Texas, dated as of July 1, 1996, by and among
               UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.34
               to the Company's Registration Statement on Form S-1 (Registration
               No. 333-22491), and incorporated herein by reference).

10.30    --    Geophysical Exploration Agreement, Welder Project, Duval County,
               Texas, dated as of October 1, 1996, by and among UNEXCO, Inc. and
               Brigham Oil & Gas, L.P. (filed as Exhibit 10.35 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.31    --    Proposed Trade Structure, RIMCO/Tigre Project, Vermillion Parish,
               Louisiana, among Brigham Oil & Gas, L.P., Tigre Energy
               Corporation and Resource Investors Management Company (filed as
               Exhibit 10.36 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.31.1  --    Letter relating to Proposed Trade Structure, RIMCO/Tigre Project,
               dated January 31, 1997, from Resource Investors Management
               Company to Brigham Oil & Gas, L.P. (filed as Exhibit 10.36 to the
               Company's Registration Statement on Form S-1 (Registration No.
               333-22491), and incorporated herein by reference).

10.31.2  --    Agreement dated March 6, 2000 by and between RIMCO Production
               Co., Tigre Energy
<PAGE>

               Corporation and Brigham Oil & Gas, L.P. regarding modifications
               to the Proposed Trade Structure, RIMCO/Tigre Project, dated
               January 31, 1997.

10.32    --    Anadarko Basin Seismic Operations Agreement II, dated as of April
               1, 1997, by and between Brigham Oil & Gas, L.P. (filed as Exhibit
               10.37 to the Company's Registration Statement on Form S-1
               (Registration No. 333-22491), and incorporated herein by
               reference).

10.32.1  --    Letter Amendment to Anadarko Basin Seismic Operations Agreement
               II, dated March 20, 1997, between Brigham Oil & Gas, L.P. and
               Veritas DGC Land, Inc. (filed as Exhibit 10.37 to the Company's
               Registration Statement on Form S-1 (Registration No. 333-22491),
               and incorporated herein by reference).

10.33    --    Expense Allocation and Participation Agreement II, dated April 1,
               1997, between Brigham Oil & Gas, L.P., and Gasco Limited
               Partnership (filed as Exhibit 10.31 to the Company's Quarterly
               Report on Form 10-Q for the quarter ended June 30, 1997, and
               incorporated herein by reference).

10.36    --    Credit Agreement dated as of January 26, 1998 among Brigham Oil &
               Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory
               thereto (filed as Exhibit 10.36 to the Company's Annual Report on
               Form 10-K for the year ended December 31, 1997, and incorporated
               herein by reference).

10.36.1  --    First Amendment to Credit Agreement dated as of August 20, 1998
               among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and
               the lenders signatory thereto (filed as Exhibit 10.36.1 to the
               Company's Annual Report on Form 10-K for the year ended December
               31, 1998, and incorporated herein by reference).

10.36.2  --    Second Amendment to Credit Agreement dated as of March 26, 1999
               among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and
               the lenders signatory thereto (filed as Exhibit 10.36.2 to the
               Company's Annual Report on Form 10-K for the year ended December
               31, 1998, and incorporated herein by reference).

10.37    --    Guaranty Agreement dated January 26, 1998 by Brigham Exploration
               Company in favor of Bank of Montreal, as Agent, and each of the
               Lenders party to the Credit Agreement (filed as Exhibit 10.33.1
               to the Company's Registration Statement on Form S-1 (Registration
               No. 333-53873), and incorporated herein by reference).

10.37.1  --    First Amendment to Guaranty Agreement dated as of March 30, 1998
               between Brigham Exploration Company and Bank of Montreal, as
               Agent for the Lenders party to the Credit Agreement (filed as
               Exhibit 10.33.2 to the Company's Registration Statement on Form
               S-1 (Registration No. 333-53873), and incorporated herein by
               reference).

10.37.2  --    Second Amendment to Guaranty Agreement dated as of August 20,
               1998 between Brigham Exploration Company and Bank of Montreal, as
               Agent for the Lenders party to the Credit Agreement (filed as
               Exhibit 10.37.2 to the Company's Annual Report on Form 10-K for
               the year ended December 31, 1998, and incorporated herein by
               reference).

10.37.3  --    Third Amendment to Guaranty Agreement dated as of March 26, 1999
               between Brigham Exploration Company and Bank of Montreal, as
               Agent for the Lenders party to the Credit Agreement (filed as
               Exhibit 10.37.3 to the Company's Annual Report on Form 10-K for
               the year ended December 31, 1998, and incorporated herein by
               reference).

10.38    --    Exchange Agreement dated as of March 30, 1999 by and between
               Brigham Exploration Company and Veritas DGC Land, Inc. (filed as
               Exhibit 10.41 to the Company's Annual Report on Form 10-K for the
               year ended December 31, 1998, and incorporated herein by
               reference).

10.39    --    Registration Rights Agreement dated as of March 30, 1999 by and
               between Brigham Exploration Company and Veritas DGC Land, Inc.
               (filed as Exhibit 10.42 to the Company's Annual Report on Form
               10-K for the year ended December 31, 1998, and incorporated
               herein by reference).

10.40    --    Third Amendment to Credit Agreement dated as of July 19, 1999
               among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and
               the lenders signatory thereto (filed as Exhibit 10.1 to the
               Company's Quarterly Report on Form 10-Q for the fiscal quarter
               ended July 31, 1999 and incorporated by reference herein).

10.41    --    Fourth Amendment to Guaranty Agreement dated as of July 19, 1999
               between Brigham Exploration Company and Bank of Montreal, as
               Agent for the lenders party to the Credit Agreement (filed as
               Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for
               the fiscal
<PAGE>

               quarter ended July 31, 1999 and incorporated by reference
               herein).

10.42*   --    Agreement dated as of August 16, 1999 between Brigham Exploration
               Company and Jon L. Glass for the amendment of an Employee Stock
               Ownership Agreement and Option Agreements (filed as Exhibit 10.1
               to the Company's Quarterly Report on Form 10-Q for the fiscal
               quarter ended September 30, 1999 and incorporated by reference
               herein).

10.43*   --    Agreement dated as of August 16, 1999 between Brigham Exploration
               Company and Craig M. Fleming for the amendment of an Employee
               Stock Ownership Agreement and Option Agreement (filed as Exhibit
               10.2 to the Company's Quarterly Report on Form 10-Q for the
               fiscal quarter ended September 30, 1999 and incorporated by
               reference herein).

10.44    --    Form Change of Control Agreement dated as of September 20, 1999
               between Brigham Exploration Company and certain Officers (filed
               as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q
               for the fiscal quarter ended September 30, 1999 and incorporated
               by reference herein).

10.45    --    Warrant Agreement for the Purchase of Common Stock dated as of
               July 19, 1999 by and between Brigham Exploration Company and Bank
               of Montreal (filed as Exhibit 10.4 to the Company's Quarterly
               Report on Form 10-Q for the fiscal quarter ended September 30,
               1999 and incorporated by reference herein).

10.46    --    Warrant Agreement for the Purchase of Common Stock dated as of
               July 19, 1999 by and between Brigham Exploration Company and
               Societe Generale, Southwest Agency (filed as Exhibit 10.5 to the
               Company's Quarterly Report on Form 10-Q for the fiscal quarter
               ended September 30, 1999 and incorporated by reference herein).

10.47    --    Amended and Restated Credit Agreement dated as of February 17,
               2000 among Brigham Oil & Gas, L.P., as Borrower, Bank of
               Montreal, as Agent, and the Lenders signatory thereto (filed as
               Exhibit 10.1 to the Company's Current Report on Form 8-K filed
               February 29, 2000, and incorporated herein by reference).

10.48    --    Amended and Restated Guaranty Agreement dated as of February 17,
               2000 by Brigham Exploration Company in favor of Bank of Montreal,
               as Agent, and each of the Lenders party to the Amended and
               Restated Credit Agreement (filed as Exhibit 10.2 to the Company's
               Current Report on Form 8-K filed February 29, 2000 and
               incorporated herein by reference).

10.49    --    Partial Assignment of Notes dated as of February 17, 2000 by and
               among (i) Bank of Montreal, (ii) Societe Generale, Southwest
               Agency, (iii) Shell Capital Inc,, and (iv) Brigham Oil & Gas,
               L.P. (filed as Exhibit 10.3 to the Company's Current Report on
               Form 8-K filed February 29, 2000 and incorporated herein by
               reference).

10.50    --    First Amendment to Warrant Agreement dated as of February 17,
               2000 between Brigham Exploration Company and Bank of Montreal
               (filed as Exhibit 10.4 to the Company's Current Report on Form
               8-K filed February 29, 2000 and incorporated herein by
               reference).

10.51    --    First Amendment to Warrant Agreement dated as of February 17,
               2000 between Brigham Exploration Company and Societe Generale,
               Southwest Agency (filed as Exhibit 10.5 to the Company's Current
               Report on Form 8-K filed February 29, 2000 and incorporated
               herein by reference).

10.52    --    Equity Conversion Agreement dated as of February 17, 2000 by and
               among Brigham Oil & Gas, L.P., Brigham Exploration Company and
               Shell Capital Inc. and its successors and assigns (filed as
               Exhibit 10.6 to the Company's Current Report on Form 8-K filed
               February 29, 2000 and incorporated herein by reference).

10.53    --    Warrant Agreement dated as of February 17, 2000 by and between
               Brigham Exploration Company and Shell Capital Inc. (filed as
               Exhibit 10.7 to the Company's Current Report on Form 8-K filed
               February 29, 2000 and incorporated herein by reference).

10.54    --    Registration Rights Agreement dated as of February 17, 2000 by
               and between Brigham Exploration Company and Shell Capital Inc.
               (filed as Exhibit 10.8 to the Company's Current Report on Form
               8-K filed February 29, 2000 and incorporated herein by
               reference).

10.55    --    Letter dated as of February 17, 2000 regarding certain fees
               pursuant to Credit Agreement dated as of February 17, 2000, among
               Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, Shell
               Capital Inc. and the lenders signatory thereto (filed as Exhibit
               10.9 to the Company's Current
<PAGE>

               Report on Form 8-K filed February 29, 2000 and incorporated
               herein by reference).

10.56    --    Securities Purchase and Registration Rights Agreement dated as of
               February 22, 2000 by and among Brigham Exploration Company and
               GAP Coinvestment Partners II, L.P., Special Situations Private
               Equity Fund, L.P., and Aspect Resources, L.L.C. (filed as Exhibit
               10.15 to the Company's Current Report on Form 8-K filed February
               29, 2000 and incorporated herein by reference).

10.57    --    Joint Development Agreement, dated as of February 10, 1999, by
               and between Brigham Oil & Gas, L.P. and Aspect Resources LLC.
               (filed as Exhibit 10.65 to the Company's Annual Report on Form
               10-K for the year ended December 31, 1999, and incorporated
               herein by reference).

10.57.1  --    First Amendment, dated as of May 10, 1999, to that certain Joint
               Development Agreement entered into effective as of February 10,
               1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources
               LLC. (filed as Exhibit 10.65.1 to the Company's Annual Report on
               Form 10-K for the year ended December 31, 1999, and incorporated
               herein by reference).

10.57.2  --    Acquisition and Participation Agreement, dated October 21, 1999,
               by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC.
               (filed as Exhibit 10.65.2 to the Company's Annual Report on Form
               10-K for the year ended December 31, 1999, and incorporated
               herein by reference).

10.57.3  --    Letter agreement, dated as of December 30, 1999, regarding
               amendments to Joint Development Agreement, dated as of February
               10, 1999, as amended, by and between Brigham Oil & Gas, L.P. and
               Aspect Resources LLC. (filed as Exhibit 10.65.3 to the Company's
               Annual Report on Form 10-K for the year ended December 31, 1999,
               and incorporated herein by reference).

10.58    --    Letter agreement dated as of September 6, 1999 between Brigham
               Oil & Gas, L.P. and Brigham Land Management Company, Inc.
               regarding work to be performed within Brigham's Angelton Project.
               (filed as Exhibit 10.66 to the Company's Annual Report on Form
               10-K for the year ended December 31, 1999, and incorporated
               herein by reference).

10.59    --    Securities and Note Acquisition Agreement dated as of October 31,
               2000 by and among Brigham Oil & Gas, L.P., Brigham, Inc., Brigham
               Exploration Company, Brigham Holdings I, LLC, Brigham Holdings
               II, LLC, ECT Merchant Investment Corp., and Joint Energy
               Development Investments II Limited Partnership (filed as Exhibit
               10.1 to the Company's Current Report on Form 8-K, as amended
               (filed November 8, 2000), and incorporated herein by reference).

10.60    --    Subordinated Credit Agreement dated as of October 31, 2000 among
               Brigham Oil & Gas, L.P., as Borrower, Shell Capital Inc., as
               Agent, and the Lenders signatory hereto (filed as Exhibit 10.2 to
               the Company's Current Report on Form 8-K, as amended (filed
               November 8, 2000), and incorporated herein by reference).

10.60.1  --    First Amendment to Amended and Restated Guaranty Agreement dated
               as of October 31, 2000 between Brigham Exploration Company and
               Bank of Montreal (filed as Exhibit 10.8 to the Company's Current
               Report on Form 8-K, as amended (filed November 8, 2000) and
               incorporated herein by reference).

10.61    --    Subordinated Guaranty Agreement dated as of October 31, 2000 by
               Brigham Exploration Company in favor of Shell Capital Inc., as
               Agent, and each of the Lenders party to the Credit Agreement
               (filed as Exhibit 10.3 to the Company's Current Report on Form
               8-K, as amended (filed November 8, 2000), and incorporated herein
               by reference).

10.61.1  --    First Amendment to Amended and Restated Credit Agreement dated as
               of October 31, 2000 by and among Brigham Oil & Gas, L.P., Bank of
               Montreal, Societe Generale, Southwest Agency, and Shell Capital
               Inc.(filed as Exhibit 10.7 to the Company's Current Report on
               Form 8-K, as amended (filed November 8, 2000) and incorporated
               herein by reference).

10.62    --    Ancillary Agreement dated as of October 31, 2000 by and among
               Brigham Oil & Gas, L.P. and Shell Capital Inc. (filed as Exhibit
               10.4 to the Company's Current Report on Form 8-K, as amended
               (filed November 8, 2000), and incorporated herein by reference).

10.63    --    Intercreditor and Subordination Agreement dated as of October 31,
               2000 by and among Bank of Montreal, as Senior Agent and a Senior
               Lender, Societe Generale, Southwest Agency, as a Senior Lender,
               Shell Capital Inc., as a Senior Lender, Shell Capital Inc., both
               as a Subordinated Agent
<PAGE>

               and a Subordinated Lender, Brigham Exploration Company, Brigham
               Oil & Gas, L.P., Brigham, Inc., Brigham Holdings I, LLC, and
               Brigham Holdings II, LLC. (filed as Exhibit 10.5 to the Company's
               Current Report on Form 8-K, as amended (filed November 8, 2000),
               and incorporated herein by reference).

10.64    --    Warrant Agreement dated as of October 31, 2000 by and between
               Brigham Exploration Company and Shell Capital Inc.(filed as
               Exhibit 10.6 to the Company's Current Report on Form 8-K, as
               amended (filed November 8, 2000), and incorporated herein by
               reference).

10.65    --    Securities Purchase Agreement dated as of November 1, 2000
               between Brigham Exploration Company, DLJ MB Funding III, Inc.,
               and DLJ ESC II, LP., (filed as Exhibit 10.9 to the Company's
               Current Report on Form 8-K, as amended (filed November 8, 2000),
               and incorporated herein by reference).

10.66    --    Registration Rights Agreement dated November 1, 2000 by and
               between Brigham Exploration Company, DLJ MB Funding III, Inc.,
               and DLJ ESC II, LP. (filed as Exhibit 10.10 to the Company's
               Current Report on Form 8-K, as amended (filed November 8, 2000),
               and incorporated herein by reference).

10.67    --    Warrant Certificate dated as of November 1, 2000 by and between
               Brigham Exploration Company and DLJ MB Funding III, Inc. (filed
               as Exhibit 10.11 to the Company's Current Report on Form 8-K, as
               amended (filed November 8, 2000), and incorporated herein by
               reference).

10.68    --    Warrant Certificate dated as of November 1, 2000 by and between
               Brigham Exploration Company and DLJ ESC II, LP. (filed as Exhibit
               10.12 to the Company's Current Report on Form 8-K, as amended
               (filed November 8, 2000), and incorporated herein by reference).

10.69    --    Stockholders Voting Agreement dated as of October 31, 2000 by and
               among Brigham Exploration Company, DLJ ESC II, L.P., DLJ MB
               Funding III, Inc., and certain shareholders of Brigham
               Exploration Company (filed as Exhibit 10.13 to the Company's
               Current Report on Form 8-K, as amended (filed November 8, 2000),
               and incorporated herein by reference).

10.70+   --    Securities Purchase Agreement dated as of March 5, 2001 among
               Brigham Exploration Company, DLJ MB Funding III, Inc., DLJ
               Merchant Banking Partners III, LP, DLJ ESC II, LP and DLJ
               Offshore Partners III, CV.

10.71+   --    First Amendment to Registration Rights Agreement, dated March 5,
               2001, by and among Brigham Exploration Company, DLJMB Funding
               III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP
               and DLJ Offshore Partners III, CV.

10.72+   --    Warrant Certificate dated as of March 5, 2001 by and between
               Brigham Exploration Company and DLJMB Funding III, Inc.

10.73+   --    Warrant Certificate dated as of March 5, 2001 by and between
               Brigham Exploration Company and DLJ ESC II, LP. 10.74+ -- Warrant
               Certificate dated as of March 5, 2001 by and between Brigham
               Exploration Company and DLJ Merchant Banking Partners III, LP.

10.75+   --    Warrant Certificate dated as of March 5, 2001 by and between
               Brigham Exploration Company and DLJ Offshore Partners III, CV.

10.76+   --    Stockholders Voting Agreement dated as of March 5, 2001 by and
               among Brigham Exploration Company, DLJMB Funding III, Inc., DLJ
               Merchant Banking Partners III, LP, DLJ ESC II, LP, DLJ Offshore
               Partners III, CV and certain shareholders of Brigham Exploration
               Company.

21+      --    Subsidiaries of the Registrant.

23.1+    --    Consent of PricewaterhouseCoopers LLP, independent public
               accountants.

23.2+    --    Consent of Cawley, Gillespie & Associates, Inc., independent
               petroleum engineers.

    *          Management contract or compensatory plan.

    +          Filed herewith.