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, 1999

                                       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                                 75-2692967
    (State or other jurisdiction of                  (I.R.S. Employer
    incorporation or organization)                  Identification No.)
       6300 Bridge Point Parkway

         Building 2, Suite 500                             78730
            Austin, Texas                               (Zip Code)
(Address of principal executive offices)

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

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

          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 23, 2000, the Registrant had 16,712,908  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 23, 2000, as reported on The Nasdaq Stock Market(sm),  was
approximately  $14  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 2000 Annual
Meeting  of  Stockholders  to be held  on May  18,  2000,  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, 1999.

<PAGE>

                                TABLE OF CONTENTS

                                     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.................................20

ITEM 6.       SELECTED FINANCIAL DATA.........................................21

ITEM 7.       MANAGEMENT'S DISCUSSION AND ANALYSIS
              OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................22

ITEM 7A.      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK......41

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.....................42

ITEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
              ON ACCOUNTING AND FINANCIAL DISCLOSURE..........................42

                                    PART III

ITEM 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..............42

ITEM 11.      EXECUTIVE COMPENSATION..........................................42

ITEM 12.      SECURITY OWNERSHIP OF CERTAIN
              BENEFICIAL OWNERS AND MANAGEMENT................................42

ITEM 13.      CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS............43

                                     PART IV

ITEM 14.      EXHIBITS, FINANCIAL STATEMENT SCHEDULES
              AND REPORTS ON FORM 8-K.........................................43

GLOSSARY OF OIL AND GAS TERMS.................................................52

SIGNATURES....................................................................54

INDEX TO FINANCIAL STATEMENTS...............................................F1-1

<PAGE>

                          BRIGHAM EXPLORATION COMPANY

                         1999 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.  The Company 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.

     The Company  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, 1999,
Brigham has acquired  5,122 square miles (3.3 million acres) of 3-D seismic data
and has identified  approximately 1,050 potential drilling  locations,  of which
the Company has drilled 469 through year-end 1999. The Company 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 1999, Brigham drilled 395 exploratory and 74
development  wells  on  its  3-D  generated  prospects  with  an  aggregate  64%
completion rate and an average working interest of 29%. As of December 31, 1999,
the  Company  has added 143 Bcfe of net proved  reserves  to its  reserve  base,
approximately  121 net Bcfe of which  were  discovered  by Brigham  through  its
systematic 3-D exploration  drilling  activities at an average net drilling cost
of $0.72 per Mcfe. In 1999,  the  Company's  average net drilling cost was $0.37
per Mcfe and its all-in net  finding  and  development  cost was $0.52 per Mcfe,
each of which  represent the lowest annual  finding costs achieved by Brigham to
date.

     The Company's estimated net proved reserves as of December 31, 1999 were 84
Bcfe having an aggregate  Present  Value of Future Net Revenues of $115 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.  The
Company's  net proved  reserve  volumes at December 31, 1999 are 78% natural gas
and 48% 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.
Since its  inception  in 1990,  the Company  has  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,  the Company's  current  activities are focused 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.

                                      1
<PAGE>

     Brigham  completed its initial public offering of common stock in May 1997,
raising  approximately $24 million to fund the Company's accelerated 3-D seismic
acquisition and exploration drilling  activities.  Key elements of the Company'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 that the Company discovers;

     o    identifying higher potential, higher impact prospects; and

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

     During  1997 and 1998,  the  Company  acquired  2,360  square  miles of 3-D
seismic data at an average  working  interest of 73%,  which nearly  doubled its
inventory of gross onshore 3-D seismic data to 5,122 square miles as compared to
year-end 1996 and  increased its net onshore 3-D seismic data in inventory  more
than  three-fold from 781 square miles at year-end 1996 to 2,507 square miles at
year-end 1998.  Brigham's overall level of 3-D seismic  acquisition  during 1997
and 1998 was the most active in the Company's history,  and the vast majority of
this newly  acquired  data was located in Brigham's  higher  potential  Anadarko
Basin and Gulf Coast provinces where it has achieved  historically lower average
finding costs for drilling than in its West Texas province. The majority of this
data was  processed  in 1998  and  1999,  and the  interpretation  and  prospect
generation is still underway.  As a result of these  significant  investments in
3-D seismic  acquisition  and  interpretation  in proven  natural gas  producing
trends,  the  Company  believes  it  has  assembled  a  significant  competitive
knowledge  base and  strategic  position  in each of its two 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 prospect
          inventory;

     o    maintain a balanced risk-reward profile in its planned exploration and
          development program;

     o    improve  cash flow  margins 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

     From 1990 to 1999,  the  Company  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  its  drilling  efforts to date.  During  1999,
Brigham began to focus 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.  As a result,  the
Company  achieved its lowest annual average drilling and finding and development
costs  in its  history  during  1999 at  $0.37  per Mcfe  and  $0.52  per  Mcfe,
respectively. In addition, Brigham generated approximately $4 in net PV10% value
of proved reserves for every dollar invested in drilling during 1999.

                                       2
<PAGE>

     Continuing  to  benefit  from its  existing  3-D  seismic  project  assets,
Brigham's  primary  objective  in 2000 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  80% of the  Company's
planned $25 million capital expenditure budget for 2000 is targeted for drilling
activities  within  its  Anadarko  Basin and Gulf  Coast 3-D  seismic  projects.
Through December 31, 1999, the Company has achieved  historical average drilling
costs of $0.56 and $0.62 per Mcfe in these two provinces, respectively. With the
significant   competitive   advantages   afforded  by  the  Company's   sizeable
investments in 3-D seismic data within its core provinces,  Brigham expects that
drilling capital  expenditures should represent at least 80% of its total annual
capital expenditures for the foreseeable future.

Execute Balanced Drilling Program

     The majority of the Company's  historical  drilling  expenditures have been
directed toward  exploration-oriented  projects.  Leveraging  numerous  drilling
discoveries during 1999,  including the Company's  potentially  significant Home
Run Field  discovery,  Brigham's  planned 2000  drilling  program  consists of a
balanced  blend of  exploration  and  development  projects in trends  where the
Company has achieved  historical  drilling success. Of the Company's $20 million
drilling budget planned for 2000, 54% of the expenditures  relate to exploration
projects and 46% are for development drilling projects that are either currently
planned or  contingent  upon  drilling  success  during the year.  In  addition,
approximately  20% of Brigham's planned 2000 drilling program is directed toward
continuing  drilling  activities in and adjacent to its Home Run Field discovery
in its Diablo  Project in South  Texas,  in which the  Company  maintains  a 34%
working interest. This planned activity consists of the drilling of three proved
undeveloped  locations  within the Home Run Field and two  exploratory  tests of
potentially  significant Lower Vicksburg structures located in fault blocks that
are adjacent to the Company's Home Run Field  discovery.  Drilling  success from
either  of these  two  exploratory  prospects  would  likely  establish  further
development drilling locations,  thereby further enhancing the overall economics
from this project area.

Improve Operating Margins

     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.  The Company has achieved  average drilling costs of $0.72 per
Mcfe during the past five years.  By focusing its drilling  program within areas
where the Company had previously experienced drilling success,  Brigham achieved
improved returns on its drilling  investments  during 1999 with average drilling
costs  of  $0.37  per  Mcfe.  Importantly,  the  Company's  all-in  finding  and
development  costs  during 1999 were $0.52 per Mcfe, a  substantial  improvement
from its most recent  five-year  average finding and development  costs of $1.37
per Mcfe 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;

     o    improved drilling returns achieved during 1999; and

     o    sales of  interests  in certain  3-D  seismic  projects  in 1999 which
          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  during the next few years as
the Company 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.

                                       3
<PAGE>

     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 the Company's producing wells;

     o    focused operations in three core provinces; and

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

     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 by greater  concentration  of its producing  assets
          within its project areas.

     Additionally, Brigham undertook numerous measures to reduce and control its
overhead expenses during 1999. These measures  contributed to a 33% reduction in
total general and administrative expenses (including amounts capitalized) in the
fourth  quarter of 1999 relative to the fourth quarter 1998, and a 43% reduction
in net general and  administrative  expenses  per Mcfe during the same  periods.
Through a  continuation  of overhead  cost  containment  efforts and  production
volume growth anticipated from its planned drilling program,  Brigham expects to
achieve  further  improvements in per unit general and  administrative  expenses
during 2000.

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, the Company raised  approximately $13 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.  Brigham expects
to market  interests  in certain 3-D seismic  projects or  individual  prospects
during 2000 to provide  incremental  sources of capital for  reinvestment in its
drilling program and to improve its project economics.

Exploration and Operating Approach

     The Company 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,  the Company 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  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 the Company can benefit  from the imaging of  producing
analogs.  These 3-D defined analogs,  combined with the Company's  experience in
drilling 469 wells,  provide the Company with a knowledge base to evaluate other
potential geologic trends, 3-D seismic projects within trends and 3-D delineated
potential  drilling   locations.   The  Company's   knowledge  base  assists  in
identifying  geologic  trends  where  Brigham  believes  it can find and develop
economic volumes of oil and natural gas.


                                    4
<PAGE>

     The Company 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).  The Company seeks to supplement its knowledge
base with the best local geologic expertise  available for a particular geologic
trend.  In  addition,  the Company  typically  acquires  digital  data bases for
integration on the Company's CAEX  workstations,  including  digital land grids,
well information, log curves, production information, geologic studies, geologic
top data bases and existing 2-D seismic data.

     The Company uses its knowledge base, local geological expertise and digital
data  bases  integrated  with  3-D  seismic  to  create  maps of  producing  and
potentially productive  reservoirs.  The Company 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 the Company
to more precisely evaluate  recoverable reserves and the economic feasibility of
projects and drilling locations.

     Brigham acquires 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,  the Company participates in non-proprietary group
shoots of 3-D data when it believes the expected  full cycle  project  economics
are justified.  In its proprietary  acquisitions and alliances,  Brigham selects
the sites of projects,  primarily  guided by its knowledge and experience in the
core provinces it explores;  establishes and monitors the seismic  parameters of
each project for which data is shot;  and typically  selects the equipment  that
will be used. Data is generally priced on the basis of square miles shot.

     Brigham's  operations staff includes four petroleum  engineers that have an
average  of  over  thirteen  years  of  reservoir  and  operations   engineering
experience, most of which was gained in the Company's primary areas of activity.
The Company's  engineers  work closely with  Brigham's  explorationists  and are
integrally  involved  in  all  phases  of  the  Company's  exploration  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,  operational  costs and  production  volumes,  Brigham has
significantly  increased the percentage of the wells that it operates during the
past several years.  Brigham  operated 44% of the gross and 73% of the net wells
it participated in during 1999, 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 61% of the PV10% value of
its proved developed  producing reserves at year-end 1999, as compared with only
8% at year-end 1996.

Technical Staff

     The Company's  experienced  technical  staff includes seven  geophysicists,
seven  geologists,   four  petroleum  engineers,   five  computer   applications
specialists, four geophysical/geological/engineering  technicians, three landmen
and three  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 the Company with valuable technical intellectual resources.
The  Company's  team of  explorationists  has  over  245  years  of  exploration
experience,  or an average of almost 18 years per person, and more than 80 years
of 3-D CAEX  workstation  experience,  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 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,  the Company complements and leverages 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.

                                       5
<PAGE>

3-D Seismic Technology

     The  Company's   strategy  is  to  use  3-D  seismic  and  other   advanced
technologies,  including 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.

     Brigham has  invested  extensively  in the advanced  computer  hardware and
software  necessary for 3-D seismic  exploration.  The Company has both Landmark
and  Schlumberger  Geoquest  CAEX  workstations.  This  workstation  flexibility
provides the Company the  opportunity  to interpret a project on the  particular
CAEX  workstation  that it believes is best suited for defining those particular
geologic  objectives.  Brigham's  explorationists  can access a diverse software
tool kit including SeisWorks, StratWorks,  EarthCube, OpenVision, Open Explorer,
ZAP, Zmap+, ARIES, SynTool,  Poststack, TDQ, AutoPix, Seis3DV, Seis2D, BaseMap+,
GeoViz,  Voxels,  SynView,  Seisan,  SeisTie, CSA (Computed Seismic Attributes),
Surface Slice,  Hampson Russell AVO Analysis and Modeling,  ZEH Graphics Plotex,
CGMage  Builder   (graphics   montage  tool),  and  Neuralog  Inc.  NDS/Log  and
NeuraSection.

Natural Gas and Oil Marketing and Major Customers

     Most of the  Company's  natural gas and oil  production is sold under price
sensitive  or spot market  contracts.  The revenues  generated by the  Company's
operations  are highly  dependent  upon the prices of and demand for natural gas
and  oil.  The  price  received  by the  Company  for  its  natural  gas and oil
production depends on numerous factors beyond the Company'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 natural gas and oil could have an adverse effect on the carrying value
of the Company's proved reserves and the Company's  revenues,  profitability and
cash flow.  Although the Company is not currently  experiencing  any significant
involuntary  curtailment of its natural gas or oil production,  market, economic
and regulatory factors may in the future materially affect the Company's ability
to sell its natural gas or oil 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, 1999,  sales to Highland  Energy Company,  Lantern  Petroleum
Corporation and Duke Energy Field Services,  Inc., were  approximately 26%, 16%,
and 11%, respectively, of the Company's natural gas and oil revenues. Due to the
availability  of other  markets and pipeline  connections,  the Company does not
believe  that the loss of any single  natural gas or oil  customer  would have a
material adverse effect on the Company's results of operations.

                                       6
<PAGE>

Competition

     The oil and gas industry is highly  competitive  in all of its phases.  The
Company 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.  The Company'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  the  Company's.  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 the Company's
financial or human resources permit. The Company'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 the Company will be productive or that the
Company 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.  The Company's
drilling  operations  may be  curtailed,  delayed  or  canceled  as a result  of
numerous  factors,  many of which are beyond the  Company's  control,  including
title problems,  weather conditions,  compliance with governmental  requirements
and shortages or delays in the delivery of equipment and services. The Company's
future  drilling  activities may not be successful  and, if  unsuccessful,  such
failure may have a material adverse effect on the Company's business,  financial
condition or results of  operations.  See "Item 7.  Management's  Discussion and
Analysis of Financial  Condition  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 the Company 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 the
Company's business, financial condition or results of operations.

     The  Company'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 the Company and others.  The Company  maintains
insurance  against some but not all of the risks described above. In particular,
the  insurance  maintained  by the  Company  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.  In certain  circumstances
in which  insurance is available the Company 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 the  Company's  business,  financial  condition and
results of operations.

Employees

     On  March  23,  2000,  the  Company  had 51  full-time  employees.  None is
represented  by any labor union.  The Company  believes its  relations  with its
employees  are good.  The  Company  also relies on several  regional  consulting
service  companies  to  provide  field  landmen  to  support  the  Company  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.

                                       7
<PAGE>
Facilities

     The Company'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.  As part of its
efforts to reduce corporate  overhead  expenses,  the Company agreed to sublease
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.  In addition to its  corporate  headquarters  location,  the Company  also
leases a 4,100 square foot office at 450 Gears Road, Suite 240,  Houston,  Texas
77067.

Title to Properties

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

Governmental Regulation

     The Company'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 the Company's  cost of
doing business and affects its  profitability.  Although the Company believes it
is in substantial  compliance  with all  applicable  laws and  regulations,  the
Company is unable to predict  the future cost or impact of  complying  with such
laws and  regulations  because  they are  frequently  amended,  interpreted  and
reinterpreted.

     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

     The Company'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 the Company's operations.  The permits required for
various of the Company'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,  the  Company  is in
substantial   compliance  with  current   applicable   environmental   laws  and
regulations,   and  the  Company  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 the Company,  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  the  Company'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.
                                       8
<PAGE>

     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
the Company.  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,  the Company is required to maintain  such  permits or meet  general
permit  requirements.  The  Environmental  Protection  Agency  ("EPA")  recently
adopted  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.  The Company 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 the Company.

     The Company has acquired  leasehold  interests in numerous  properties that
for many years have produced natural gas and oil.  Although the Company 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 or under the  properties.  In
addition,  some of the Company's  properties  are operated by third parties over
whom the Company 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 natural gas and oil
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  three  years,   Brigham  has
concentrated the majority of its 3-D seismic and drilling  activities on natural
gas projects in its 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.

     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,  the Company 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.  Based  upon  the  interpreted  portion  of its 3-D  seismic  data as of
December 31, 1999, the Company  estimates  that it has identified  approximately
580 potential undrilled  locations within its three core exploration  provinces.
From  inception in 1990 through  1999,  Brigham  achieved net drilling  costs of
$0.72 per Mcfe added through its 3-D seismic  exploration  efforts. In addition,
over  400  of  Brigham's  estimated  potential  drilling  locations  are  in its
currently  active  Anadarko Basin and Gulf Coast provinces where the Company has
achieved  inception-to-date  average net  drilling  costs of $0.56 and $0.62 per
Mcfe, respectively.

                                       9
<PAGE>

     Continuing its strategy  implemented  during 1999, Brigham intends to focus
substantially  all of its efforts and available capital resources in 2000 to the
drilling and  monetization of its highest grade prospects  within its over 5,000
square mile inventory of 3-D seismic data.  Employing this emphasis during 1999,
the  Company  achieved  its lowest  annual  average  drilling  and  finding  and
development  costs  of $0.37  per Mcfe and  $0.52  per  Mcfe,  respectively.  In
addition,  Brigham's  average net  drilling  cost for proved  developed  reserve
additions during 1999 was $0.63 per Mcfe.

     The Company's  current 2000 capital  expenditure  budget is estimated to be
$25 million,  which includes  approximately $20 million to drill an estimated 30
to 40 gross wells.  Brigham's  planned 2000  drilling  program is comprised of a
balanced  blend  of  exploration   and   development   drilling   projects  with
approximately  54% of budgeted  drilling  expenditures  targeted for exploratory
prospects,  28% for development  locations and the remaining 18% for development
locations  that are  contingent  upon  drilling  success  during  the  year.  In
addition,  the Company's 2000 budgeted drilling expenditures have been allocated
approximately  75% to its Gulf  Coast  province  and 25% to its  Anadarko  Basin
province,   concentrated   within  trends  where  the  Company  has  experienced
exploration  success  historically.  See "Item 7.  Management's  Discussion  and
Analysis of Financial  Condition  and Results of  Operations  --  Liquidity  and
Capital Resources."

     The  Company's  actual  capital  expenditures  in 2000 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 the Company  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;

     o    the  availability of sufficient  capital  resources by the Company 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    the  financial   resources  and  results  of  the  Company;   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 natural gas or oil.

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 the  Company's  established  3-D  seismic
exploration  approach  and its  staff's  extensive  Gulf Coast  experience  to a
prolific,   highly  complex  structural  province  with  potential  to  discover
significant  natural gas reserves and  production.  The Company has  assembled a
digital data base including geographical, production, geophysical and geological
information that the Company evaluates on its 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.

                                       10
<PAGE>

     A portion of Brigham's 3-D seismic data  acquisition  in the Gulf Coast has
been accomplished by the Company's participation in certain non-proprietary,  or
speculative,   seismic  programs.   By  converting   certain  of  the  Company's
proprietary  seismic projects in core exploration areas to speculative data, the
Company  was  able  to  leverage  these  proprietary   projects  for  access  to
substantially  larger  non-proprietary   speculative  data  for  minimal  or  no
additional  cost  to  the  Company.   The  Company  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,  1999,  the Company had  acquired  1,096  square  miles
(701,440  acres) of 3-D  seismic  data in its Gulf Coast  province.  Through its
drilling efforts in this region from 1996 through 1999, Brigham had completed 32
wells in 44  attempts  (73%  completion  rate) in the Gulf  Coast  and had found
cumulative  net proved  reserves  of  approximately  36 Bcfe at an  average  net
drilling cost of $0.62 per Mcfe. In its Gulf Coast drilling program in 1999, the
Company  completed 7 wells in 12 attempts (58% completion  rate) with an average
working interest of 22% that contributed to the addition of approximately 12 net
Bcfe of proved  reserves  (including  revisions  to  previous  estimates)  at an
average net drilling  cost of $0.66 per Mcfe during the year. As of December 31,
1999, Brigham had identified approximately 210 3-D delineated potential drilling
locations in the Gulf Coast  province,  of which the Company intends to drill 20
to 25  gross  wells  in 2000  with an  estimated  average  working  interest  of
approximately 45%.

     Brigham  intends  to  focus  its   exploration  and  development   drilling
activities in its Gulf Coast  province in the following key project areas during
2000:

     Diablo Project

     Brigham's  Diablo Project  covers 57 square miles in Brooks County,  Texas,
and targets shallow Frio and deep Vicksburg producing  horizons.  The Company is
involved in a joint  venture with a major  integrated  oil company that controls
adjoining  acreage to explore on the combined acreage for potential 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 Company and its
participant  currently  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. The Company initially acquired 25 square miles of proprietary 3-D seismic
in this project in 1997, and acquired an additional 33 square miles in 1998.

     In the fourth quarter of 1999,  Brigham  confirmed a major Lower  Vicksburg
field  discovery,  the Home Run Field, in its Diablo Project with the completion
of the Brigham-operated Palmer State #2 well (Brigham 34% working interest). 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  net daily
production  rates of 10.1 MMcf of  natural  gas and 650 Bbls of  condensate,  or
approximately  14.1 MMcfe in total.  Brigham's  net cost to drill,  complete and
fracture  stimulate  the  Palmer  State #2 was  approximately  $0.24 per  proved
developed  producing Mcfe discovered,  and the net PV10% of the proved producing
reserves  attributable  to the well were more than nine times the  Company's net
drilling  investment.  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),  approximately 19 net Bcfe of
which were booked as proved  reserves as of December 31,  1999.  The Company and
its project  participant  have  established  a multi-well  drilling plan for the
development  of the Home Run Field  that  includes  the  planned  drilling  of a
minimum of three field  delineation  wells and two exploratory wells in adjacent
fault blocks during 2000.

     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  structure in the fourth
quarter of 2000.  This 3-D delineated  Vicksburg  feature is located beneath the
shallower  Mariposa Field which has produced in excess of 187 Bcf of natural gas
from the Frio.  The  estimated  200 acre Floyd  feature is an apparent  four-way
Lower Vicksburg  closure that Brigham plans to test with an exploratory  well in
the  third  quarter  of 2000.  The  Company  believes  that  its Home Run  Field
discovery has significantly  enhanced the prospectiveness of each of these large
structural closures.

                                       11
<PAGE>

     Southwest Danbury Project

     Located in Brazoria County,  Texas,  Brigham's Southwest Danbury Project is
an  approximate 29 square mile 3-D project  targeting a series of  geo-pressured
Lower Frio sands at depths  ranging from 12,000 to 13,000 feet. The project area
was  well  suited  to 3-D  seismic  imaging  due to the  significant  structural
geologic  complexity  associated  with Danbury Salt Dome that provides  multiple
prospective pay intervals.  Since  commencement of drilling  operations in early
1998,  Brigham has completed three wells in three attempts in this project area.
The  Company's  two  1999  completions  in this  project,  the  Renn Gas Unit #1
(Brigham  working  interest  84%) and the Sebestia Gas Unit #1 (Brigham  working
interest 56%),  discovered gross proved reserves in the Frio interval  estimated
at 12.4 Bcfe as of December 31, 1999, or 6.6 net Bcfe to the  Company's  revenue
interests.    Brigham   has   identified    several   additional   3-D   seismic
amplitude-supported  prospects  in the  Upper  and Lower  Frio  sections  in its
Southwest Danbury Project,  three of which are expected to be tested in its 2000
drilling  program,  including  one that  may be an  offset  to its  most  recent
discovery well in this project.

     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 Miocene and Frio sands as well as
the deeper,  pressured  Frio sands.  Operators  have been  actively  leasing and
drilling  within  this  acreage  during the past two years.  This  activity  has
resulted  in the  completion  of nine wells in twelve  attempts,  including  the
discovery of a 3-D delineated  field that is estimated to contain gross reserves
of approximately 40 Bcfe in three wells that have produced at rates in excess of
30 MMcfe 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.  The Company's 2000 drilling program includes five 3-D seismic
amplitude-supported  prospects in its Hawkins Ranch and Millenium  Projects that
target  combined gross unrisked  reserve  potential of 112 Bcfe.  Three of these
five  planned  exploratory  wells are  expected to spud during the first half of
2000. Brigham expects to retain working interests ranging from 30% to 75% in its
wells planned for drilling in these project areas in 2000.

     El Sauz Project

     In May 1997,  Brigham  initiated its El Sauz Project with a seismic  option
covering  approximately 94,000 acres in Willacy and Kennedy Counties,  Texas. In
1998, the Company  acquired  approximately  200 square miles of 3-D seismic data
over this acreage and sold a 45% working interest in the project to two industry
participants  which  provided  the  Company  with  a  significant  carry  on the
pre-seismic  land and  seismic  acquisition  costs of the  project.  The El Sauz
Project is an underexplored  area that is bordered on three sides by Miocene and
Frio fields which have in aggregate  produced over 740 Bcf of natural gas and 94
MMBbls of oil.  Primary  targets in the El Sauz Project are the Miocene and Frio
sands at depths of 4,500 to 10,000 feet,  with  additional  potential as deep as
18,000 feet in the Lower Frio.  Reserve targets range from 5 to 20 Bcf per well.
Three  prospects are planned for drilling in 2000,  including a shallow  Miocene
3-D seismic amplitude-supported  four-way closure, an Upper Frio structural test
and a deep  multi-target  Miocene and  amplitude-supported  Middle Frio test. In
addition to these planned  wells,  the Company has  identified  nine  additional
potential  drilling  opportunities in its continuing  interpretation  of the 3-D
seismic data within this project area.  Brigham  currently retains a 55% working
interest in its El Sauz Project.

     Caliente Project

     Brigham's  Caliente  Project  consists  of 350 square  miles of  contiguous
non-proprietary  3-D seismic data in the prolific Wilcox and Queen City trend in
Duval and Webb  counties  of Texas.  Primary  targets  in this  project  include
shallow,  non-pressured  Queen City sands at depths  ranging from 6,000 to 7,000
feet,  and deeper,  geo-pressured  Expanded Upper Wilcox sands at depths ranging
from 10,000 to 18,000  feet.  Brigham has  identified  35  prospects  within its
Caliente  Project,  including four  prospects  planned for drilling in 2000. The
first of these  planned  wells is expected to spud during the second  quarter of
2000 and will test multiple pay objectives in a fault block located updip from a
well with pay on water. The Company  estimates gross unrisked reserve  potential
attributable  to this Wilcox  prospect of 25 Bcfe and it expects to retain a 50%
working interest in the well. During the second half of 2000,  Brigham currently
plans to test an additional  high potential  Wilcox prospect in which it expects
retain a working  interest of 37.5% to 50%. This  prospect  targets an analogous
fault block to a recent discovery that encountered over 300 feet of gross pay in
the target  Wilcox  objective.  The Company  estimates  gross  unrisked  reserve
potential of 37 Bcfe related to this prospect.

                                       12
<PAGE>

Anadarko Basin

     The  Anadarko  Basin is a prolific  natural gas  province  that the Company
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 30 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. The Company 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, 1999,  the Company 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 1999, Brigham had completed 83 wells in
109  attempts  (76%  completion  rate)  in the  Anadarko  Basin  and  had  found
cumulative  net proved  reserves of 63 Bcfe at an average net  drilling  cost of
$0.56 per Mcfe.  In its Anadarko  Basin  drilling  program in 1999,  the Company
completed 12 wells in 14 attempts (86% completion  rate) with an average working
interest  of 40% that  contributed  to the  addition  of 15 net  Bcfe of  proved
reserves (including  revisions to previous estimates) at an average net drilling
cost of $0.17 per Mcfe during the year. As of December 31, 1999, the Company had
identified  approximately 210 3-D delineated potential drilling locations in the
Anadarko  Basin,  of which the Company  intends to drill 10 to 15 gross wells in
2000 with an estimated average working interest of 45%.

     As part of its strategic  initiatives to improve its capital  resources and
liquidity during 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 in June 1999. The divested  properties were
located in two fields  operated by third  parties - the Chitwood  Field in Grady
County,  Oklahoma,  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 net daily  production  volumes from the divested
properties  to be  approximately  2.8 MMcfe per day at the time these sales were
consummated.  Net proceeds from these  transactions  were used by the Company to
reduce  borrowings  under its bank credit  facility and to fund working  capital
needs and capital  expenditures  during the second half of 1999.  The  effective
date of each transaction was June 30, 1999.

                                       13
<PAGE>

     Brigham  intends  to  focus  its   exploration  and  development   drilling
activities  in its Anadarko  Basin  province in the  following key project areas
during 2000:

     Arnett Project

     Brigham's Arnett Project covers approximately 81,920 acres in Ellis County,
Oklahoma,  and targets Morrow and Hunton producing  horizons at depths of 10,000
to 14,000 feet. In 1997 and 1998,  the Company  acquired 128 square miles of 3-D
seismic in the three phases of this project.  Following the sale of a portion of
its  interest in this  project in early 1999,  Brigham  retains a 70%  effective
working interest in its Arnett Project.  During 1999, Brigham completed all five
wells  drilled in its Arnett  Project,  resulting in the discovery of 11.3 gross
Bcfe of proved developed  reserves in Morrow sandstone  objectives,  or 5.4 Bcfe
net to the Company's interests.  Capitalizing on these discoveries,  the Company
plans to drill three offset Morrow locations during the first half of 2000. Each
of these Morrow  prospects  will test natural gas reserve  targets  estimated at
approximately  2 Bcf per well on a gross  unrisked  basis  with  dry hole  costs
estimated to be approximately $400,000 per well.

     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
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,  the Company  subsequently
acquired  data in its adjacent  Boilermaker  Project in 1998 where it retained a
100%  working  interest.  The Company  has  assembled  acreage  over a number of
potential  drilling  locations  in these  project  areas  and has at  least  one
exploratory  well  planned  for its Huskie  Project in 2000.  This well was spud
during the first  quarter 2000 and will test a prospect  with  approximately  20
Bcfe of gross  unrisked  reserve  potential  which is an extension to a prolific
Springer  channel  that has  produced  over 128 Bcfe.  Success from this initial
exploratory  well would likely  establish  several  development  locations.  The
Company retains a 71% working interest in this exploratory well.

     Wildcat and Panther Projects

     The  Company'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
21,000 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, the Company subsequently acquired data in its adjacent
Panther  Project  in 1998  where it  retained a 100%  working  interest.  In its
Wildcat Project, the Company has a deep 21,000 foot exploratory well planned for
the  first  half of 2000 to drill an updip  location  to a Hunton  well that has
produced over 15 Bcfe since 1981 and was still  producing in February  2000. The
Company believes  successful  completion of this exploratory test could prove up
an additional 55 Bcfe of remaining  gross  unrisked  reserves in this  producing
structure and set up several development locations.

     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 bar sands in
the Springer  section.  In early 2000, the Company drilled its first well in its
Bearcat Project,  which was a 13,000 foot test of a potentially  significant 3-D
delineated  Springer bar feature with gross  unrisked  reserve  potential of 100
Bcfe. The well encountered a significant  thickness of Springer-aged  sand which
confirmed  Brigham's 3-D seismic  interpretation  of this feature.  The well was
being tested in late March 2000,  and a successful  completion  would  establish
multiple offset development drilling opportunities.

                                       14
<PAGE>

West Texas

     The Company's drilling activity in its West Texas province has been focused
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,  the Company substantially reduced its 3-D seismic and
drilling  activities in its West Texas during 1998 and 1999. Based on the recent
recovery  in oil  prices,  the  Company  intends to  undertake  a  comprehensive
analysis of its proved and unproved West Texas assets to evaluate  opportunities
to generate value either  through the drilling of identified 3-D prospects,  the
sale of promoted  interests in drillable  3-D  prospects or the sale of all or a
portion of its proved reserves and 3-D prospect inventory.

     As of December  31,  1999,  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  1999,  Brigham had completed 185 wells in 299 attempts
(62%  completion  rate) in its  West  Texas  province  with an  average  working
interest of 23% and had found  cumulative  net proved  reserves of 21 Bcfe at an
average net drilling  cost of $1.31 per Mcfe.  The Company  participated  in the
drilling  of one well with a 35%  working  interest  in its West Texas  province
during 1999 which was  unsuccessful.  As of December 31,  1999,  the Company had
identified  approximately 165 3-D delineated potential drilling locations in its
West  Texas  projects.  While  the  Company's  2000  drilling  program  does not
currently include any wells in its West Texas province,  Brigham may participate
in the drilling of several of its highest quality West Texas prospects this year
to capitalize on high current oil prices.

Natural Gas and Oil Reserves

     The Company's estimated total net proved reserves of natural gas and oil as
of December 31, 1997, 1998 and 1999 and the present values attributable to these
reserves as of those dates were as follows:

                                                       As of December 31,
                                                -------------------------------
                                                    1997      1998       1999
                                                ----------  --------  ---------
 Estimated net proved reserves:
   Natural gas (MMcf) ........................    53,230     71,166     65,457
   Oil (MBbls) ...............................     3,181      4,433      3,027
   Natural gas equivalent (MMcfe) ............    72,316     97,764     83,618
 Proved developed reserves as a percentage
   of proved reserves ........................       65%        57%        48%
 Present Value of Future Net Revenues
   (in thousands).............................  $ 69,249   $ 81,741  $ 114,466
 Standardized Measure (in thousands)..........  $ 64,274   $ 81,649  $ 113,546

     The reserve estimates reflected above were prepared by Cawley,  Gillespie &
Associates, Inc. ("Cawley Gillespie"),  the Company's petroleum consultants, and
are part of reports on the Company's oil and natural gas properties  prepared by
Cawley  Gillespie.  The base sales prices for the Company's  reserves were $2.27
per Mcf for  natural  gas and $15.50 per Bbl for oil as of  December  31,  1997,
$2.12 per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998,
and $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December  31,
1999. 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.

     In accordance  with applicable  requirements  of the SEC,  estimates of the
Company'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 the control of the Company.  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 the Company, 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.  The Company'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."

                                       15
<PAGE>

     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.

Drilling Activities

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

<TABLE>
<CAPTION>
                                                     Year Ended December 31,
                                   ---------------------------------------------------------
                                         1997               1998                1999
                                   ----------------   -----------------   ------------------
                                    Gross      Net     Gross      Net       Gross      Net
                                   -------  -------   -------  --------   --------  --------
Exploratory Wells (1):

<S>                                   <C>     <C>       <C>     <C>          <C>      <C>
Natural gas.....................      15      6.5       30      15.6          8       3.4
Oil.............................      21      7.9        7       2.5          2       0.1
Non-productive .................      26      9.8       17       8.0          7       2.4
                                      --      ---       --       ---         --       ---
    Total.......................      62     24.2       54      26.1         17       5.9
                                      ==     ====       ==      ====         ==       ===

Development Wells (2):

Natural gas.....................       4      1.6       10       6.6          8       2.3
Oil.............................       5      1.6        3       1.5          1       0.5
Non-productive .................       2      0.9        5       3.4          1       0.6
                                      --      ---       --      ----         --       ---
    Total.......................      11      4.1       18      11.5         10       3.4
                                      ==      ===       ==      ====         ==       ===
</TABLE>
----------------

(1)  From  January 1, 2000  through  March 23,  2000,  the Company  drilled,  or
     participated in the drilling of, two gross (0.19 net) exploratory wells, of
     which one gross  (0.17  net) was  completed  as a natural  gas well and one
     gross (0.02 net) was completed as an oil well.

(2)  From  January 1, 2000  through  March 23,  2000,  the Company  drilled,  or
     participated in the drilling of, five gross (2.1 net) development wells, of
     which one gross (1.0 net) was  completed  as a natural gas well,  two gross
     (0.03  net) were  completed  as oil  wells  and two gross  (1.1 net) in the
     process of drilling at March 23, 2000.

     The  Company  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,  the  Company  has  continued  to  retain  operations  of an
increasing number of the wells it drills.  Brigham operated 44% of the gross and
73% of the net wells it participated in during 1999.

                                       16
<PAGE>

Productive Wells and Acreage

Productive Wells

     The  following  table sets forth the  Company's  ownership  interest  as of
December  31,  1999  in  productive  natural  gas  and oil  wells  in the  areas
indicated.

<TABLE>
<CAPTION>
                              Natural Gas             Oil               Total
                             --------------    ----------------   -----------------
                              Gross    Net       Gross     Net      Gross      Net
                             -------  -----    --------- ------   --------   ------

     Province:
<S>                             <C>    <C>        <C>     <C>         <C>     <C>
     Anadarko Basin......       88     32.1        12      3.7        100     35.8
     Gulf Coast..........       32     13.6        15      2.3         47     15.9
     West Texas .........        9      2.8        88     26.3         97     29.1
     Other...............       --       --         2      0.7          2      0.7
                               ---     ----       ---     ----        ---     ----
         Total...........      129     48.5       117     33.0        246     81.5
                               ===     ====       ===     ====        ===     ====
</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. A gross acre is an acre in which an interest is owned.
A net acre is deemed to exist when the sum of fractional  ownership interests in
gross  acres  equals one.  The number of net acres is the sum of the  fractional
interests owned in gross acres expressed as whole numbers and fractions thereof.
The following table sets forth the approximate developed and undeveloped acreage
in which the Company held a leasehold, mineral or other interest at December 31,
1999:

<TABLE>
<CAPTION>
                                                 Developed             Undeveloped                 Total
                                             ----------------      --------------------    -------------------
                                             Gross       Net        Gross        Net        Gross         Net
                                             -----      -----       -----       -----       -----        -----
<S>                                          <C>        <C>         <C>          <C>        <C>           <C>
     Province:
     Anadarko Basin...................       29,540     12,112       85,625      46,759     115,165       58,871
     Gulf Coast.......................        2,626      1,237       23,249      14,762      25,875       15,999
     West Texas ......................        6,861      2,013       15,370       5,331      22,231        7,344
     Other............................          480        148       16,646       5,412      17,126        5,560
                                             ------     ------      -------      ------     -------       ------
         Total........................       39,507     15,510      140,890      72,264     180,397       87,774
                                             ======     ======      =======      ======     =======       ======
</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, 2000...................          47,537        22,409
     December 31, 2001...................          64,153        33,711
     December 31, 2002...................           7,215         3,992
     Thereafter..........................          21,985        12,152
                                                  -------        ------
         Total...........................         140,890        72,264
                                                  =======        ======

                                       17
<PAGE>

     In  addition,  the  Company had lease  options as of  December  31, 1999 to
acquire an additional  109,374 gross  (67,119 net) acres,  substantially  all of
which expire before June 30, 2000.

Volumes, Prices and Production Costs

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

<TABLE>
<CAPTION>
                                                             Year Ended December 31,
                                                           --------------------------
                                                              1997    1998     1999
                                                           -------- -------- --------
<S>                                                        <C>      <C>      <C>
     Production:
        Natural gas (MMcf)..............................     1,382    4,269    4,197
        Oil (MBbls).....................................       291      396      346
        Natural gas equivalent (MMcfe)..................     3,126    6,644    6,270
     Average sales price:
        Natural gas (per Mcf)...........................   $  2.56  $  2.04  $  2.11
        Oil (per Bbl) ..................................     19.40    12.85    17.79
     Average production expenses and taxes (per Mcfe) ..   $  0.55  $  0.46  $  0.51
</TABLE>

Costs Incurred and Capitalized Costs

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

                                                   Year Ended December 31,
                                            ------------------------------------
                                               1997        1998        1999
                                            ----------  ----------  ------------

     Cost incurred for the year:
        Exploration.......................  $   29,516  $   68,214  $   19,224
        Property acquisition..............      26,956      16,245       3,462
        Development.......................       2,953      10,475       4,632
        Proceeds from participants........        (319)    (10,502)    (29,582)
                                            ----------- ----------- ----------
                                            $   59,106  $   84,432   $  (2,264)
                                            =========== ==========  ==========

     Costs incurred  represent  amounts incurred by the Company for exploration,
property acquisition and development activities.  Periodically, the Company 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

     The Company 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 the Company's  securityholders  during
the fourth quarter of 1999.

                                       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 the executive
officers of the Company as of March 23, 2000:

<TABLE>
<CAPTION>
         Name             Age                      Position
----------------------   -----  ---------------------------------------------------

<S>                       <C>   <C>
Ben M. Brigham            40    Chief Executive Officer, President and Chairman
Curtis F. Harrell         36    Chief Financial Officer and Director
David T. Brigham          39    Vice President - Land and Administration, Corporate
                                Secretary
A. Lance Langford         37    Vice President - Operations
Jeffery E. Larson         41    Vice President - Exploration
Karen E. Lynch            38    Vice President - Legal and General Counsel
Christopher A. Phelps     29    Vice President - Finance and Strategic Planning

</TABLE>

     Set  forth  below is a  description  of the  backgrounds  of the  executive
officers of the Company.

     Ben M. "Bud" Brigham has served as Chief Executive  Officer,  President and
Chairman of the Board of the Company  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 the
Company  since August  1999.  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 Vice
President-- Land and Administration and Corporate Secretary of the Company since
February 1998. Mr. Brigham served as Vice President--  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 the Company as Manager of Operations in 1995 and
has served as Vice President-- Operations since January 1997. 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  the  Company  in 1997 and has  served  as Vice
President -- Exploration since August 1999. Mr. Larson joined Brigham in October
1997 as Gulf Coast Exploration Manager in its Houston office where he co-managed
the Company's  successful 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  the  Company'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 the Company in October  1997 as General  Counsel and
has served as Vice  President--  Legal and General  Counsel of the Company since
February 1998. Prior to joining the Company,  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 the Company 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 the Company,  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.

                                     PART II

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

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

                                   1998                    1999
                            ------------------        ------------------
                             High         Low          High         Low
                            ------      ------        -----       ------

First Quarter...........    $14.00      $10.50        $6.00       $2.75
Second Quarter..........    $15.50       $8.75        $3.25       $0.88
Third Quarter...........    $10.25       $5.13        $3.31       $1.94
Fourth Quarter..........     $9.50       $4.75        $2.72       $1.00

     The closing  market price of the  Company's  common stock on March 23, 2000
was $2.13 per share. As of March 23, 2000, the Company estimates that there were
82 record owners of the Company's common stock.

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

                                       20
<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 the Company's  consolidated  financial
statements  and related  notes  included in "Item 8.  Financial  Statements  and
Supplementary Data."

<TABLE>
<CAPTION>
                                                                         Year Ended December 31,
                                                           ---------------------------------------------------
                                                             1995       1996       1997      1998       1999
                                                           ---------  --------   -------  ---------   --------
Statement of Operations Data:
Revenues:
<S>                                                        <C>        <C>       <C>        <C>        <C>
Natural gas and oil sales...............................   $  3,578   $ 6,141   $  9,184   $ 13,799  $ 14,992
Workstation revenue.....................................        635       627        637        390       285
                                                           --------   -------   --------   --------  --------
     Total revenues.....................................      4,213     6,768      9,821     14,189    15,277

Costs and expenses:
Lease operating.........................................        761       726      1,151      2,172     2,259
Production taxes........................................        165       362        549        850       968
General and administrative..............................      1,897     2,199      3,570      4,672     3,481
Depletion of natural gas and oil properties.............      1,626     2,323      2,743      8,483     7,792
Depreciation and amortization...........................        533       487        306        413       525
Capitalized ceiling impairment..........................          -         -          -     25,926         -
Amortization of stock compensation......................          -         -        388        372         1
                                                           --------   -------   --------   --------  --------
     Total costs and expenses...........................      4,982     6,097      8,707     42,888    15,026
                                                           --------   -------   --------   --------  --------

Operating income (loss).................................       (769)      671      1,114    (28,699)      251

Other income (expense):
Interest expense, net...................................       (936)   (1,173)    (1,190)    (5,968)   (9,697)
Interest income.........................................        128        52        145        136       176
Other expense...........................................          -         -          -          -      (163)
Loss on sale of natural gas and oil properties..........          -         -          -          -   (12,195)
                                                           --------   -------   --------   --------  --------
     Total other income (expense).......................       (808)   (1,121)    (1,045)    (5,832)  (21,879)
                                                           --------   -------   --------   --------  --------

Net income (loss) before income taxes...................     (1,577)     (450)        69    (34,531)  (21,628)
Income tax benefit (expense)............................          -         -     (1,186)     1,186         -
                                                           --------   -------   --------   --------  --------
Net loss................................................   $ (1,577)  $  (450)  $ (1,117)  $(33,345) $(21,628)
                                                           ========   =======   ========   ========  ========

Net loss per share - basic and diluted..................   $  (0.18)  $ (0.05)  $  (0.10)  $  (2.64) $  (1.53)
Weighted average shares outstanding - basic and diluted.      8,929     8,929     11,081     12,626    14,152

Statement of Cash Flows Data:

Net cash provided by operating activities...............   $  1,383   $ 3,710  $   9,806   $ 14,774  $  2,578
Net cash provided (used) by investing activities........     (8,005)  (11,796)   (57,300)   (86,227)    1,644
Net cash provided (used) by financing activities........      7,724     7,731     47,748     72,321    (4,049)

Other Financial Data:

Capital expenditures....................................   $  7,935   $13,612   $ 57,170   $ 85,207  $ 25,560

                                                                              As of December 31,
                                                           --------------------------------------------------
                                                             1995       1996       1997      1998       1999
                                                           ---------  --------   -------  ---------   --------
Balance Sheet Data:

Cash and cash equivalents...............................   $  1,802   $ 1,447  $  1,701   $   2,569 $  2,742
Oil and natural gas properties, net.....................     18,538    28,005     84,294    134,317   112,066
Total assets............................................     22,916    33,614     92,519    150,516   125,683
Long-term debt, net.....................................     16,000    24,000     32,000     94,786    97,341
Total stockholders' equity..............................      3,694     3,244     43,313     24,681     8,998
</TABLE>

                                       21
<PAGE>

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

Overview

     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.
From inception in 1990 through December 31, 1999,  Brigham acquired 5,122 square
miles of 3-D seismic data,  identified  approximately  1,050 potential  drilling
locations and drilled 469 wells delineated by 3-D seismic analysis.  Through its
3-D seismic-based  drilling efforts,  the Company had discovered an aggregate of
121 Bcfe of net proved  reserves as of December 31, 1999.  The Company  believes
this  performance  demonstrates  a  systematic  methodology  for finding oil and
natural gas in onshore domestic hydrocarbon producing provinces.

     Combining its geologic and geophysical  expertise with a sophisticated land
effort, the Company manages the majority of its projects from conception through
3-D acquisition,  processing and  interpretation and leasing.  In addition,  the
Company  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,  the Company can 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.  The  Company'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.  The
Company did not acquire  any new 3-D  seismic in 1999,  and its average  working
interest  in its wells  drilled  during  1999 was 34%.  Beginning  in 1995,  the
Company has managed  operations through the drilling and production phases on an
increasing  portion of its 3-D seismic  projects.  Brigham  operated  44% of its
gross wells and 73% of its net wells drilled in 1999 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 the Company.  Prior to 1997,
the Company'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 the Company 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,  the Company  acquired 2,762 gross (781 net)
square miles of 3-D seismic data. Initially,  the Company focused its efforts in
West Texas.  In 1995, the Company began to devote  substantial  attention to the
Anadarko  Basin,  and since 1996 the Company  has  devoted  the  majority of its
resources  to the  Anadarko  Basin and Gulf  Coast.  With this shift in regional
focus, the majority of the Company's  production volumes has shifted from oil to
natural gas. To finance these project  generation and drilling  activities,  the
Company  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 the Company'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, the Company 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,  the
Company  acquired 1,196 square miles (51%) of 3-D seismic in the Anadarko Basin,
making  this basin the most  active 3-D  seismic  acquisition  province  for the
Company. Brigham also significantly increased its Gulf Coast activity, acquiring
942 square miles (40%) of 3-D seismic during this period.  During 1997 and 1998,
the Company  drilled  145 gross  (65.9 net) wells based on its 3-D seismic  data
analysis. In addition to its drilling activities,  the Company 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,
the Company's net natural gas and oil production increased from 2.1 Bcfe in 1996
to 6.6 Bcfe in 1998.  The  Company'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. The Company 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.

                                       22
<PAGE>

     As a result of lower  commodity  prices and  reduced  access to the capital
markets in late 1998 and 1999,  the Company  implemented  a number of  strategic
initiatives  during 1999 to improve its capital liquidity to fund its continuing
exploration program in the difficult industry environment.  These objectives and
results accomplished for each include:

o    Focusing  All  Planned  Exploration  Efforts  in 1999  Toward  Drilling  of
     Highest-Grade  3-D Prospects in its Anadarko Basin and Gulf Coast Projects.
     Operating  under a reduced  drilling  budget in 1999 as compared with 1998,
     Brigham directed its resources toward the drilling of identified  prospects
     within  trends  where it had achieved  historical  drilling  success.  This
     focused drilling emphasis contributed to substantially  improved returns on
     the Company's drilling investments during 1999, with average drilling costs
     of $0.37 per Mcfe and average  all-in  finding  costs of $0.52 per Mcfe for
     the year.

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.  In addition to executing  the  Company's
     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.

o    Seeking to Divest Certain Producing Natural Gas and Oil Properties. In June
     1999,  Brigham sold  interests in certain  non-operated  properties  in two
     project areas 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 the
     Company'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
     subordinated notes due 2003 to provide the Company with increased borrowing
     availability  and financial  flexibility  to preserve cash flow to fund its
     exploration activities. 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 the  Company's  headquarters  space  effective  in
     November  1999,  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  the  Company's  per  unit  net  general  and
     administrative expenses decreased 43% from $0.92 per Mcfe to $0.52 per Mcfe
     during these same periods.

o    Raising  Equity  Capital.  During 1999,  Brigham raised  approximately  $13
     million in capital 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  February  2000 to fund its
     planned  exploration and development  program for 2000, Brigham raised $4.5
     million  through  the  issuance of common  stock and  warrants in a private
     equity placement. See "--Liquidity and Capital Resources."


                                       23
<PAGE>

     The Company uses the full-cost method of accounting for its natural gas and
oil properties. Under this method, all acquisition,  exploration and development
costs,  including  certain internal costs that are directly  attributable to the
Company's acquisition,  exploration and development activities,  are capitalized
in  the  amortizable  base  of  the  "full-cost  pool"  as  incurred.  Upon  the
interpretation  by the  Company  of the 3-D  seismic  associated  with  unproved
properties,  the  geological  and  geophysical  costs  of  acreage  that  is not
specifically  identified as prospective are transferred to the amortizable  base
of  the  full-cost  pool.  Geological  and  geophysical  costs  associated  with
prospective  acreage,  as  well  as  leasehold  costs,  are  transferred  to the
amortizable  base of the  full-cost  pool when the  prospects  are drilled.  The
Company  records  depletion of its  full-cost  pool using the unit of production
method.

     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 natural gas and
oil prices) of estimated future net after-tax cash flows from proved natural gas
and oil reserves plus the capitalized  cost of unproved  properties,  such costs
are charged to  operations  as a writedown of the carrying  value of natural gas
and oil properties,  or a "capitalized ceiling impairment" charge. The risk that
the Company 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
the  Company  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 natural  gas and oil  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 of the
Company's  high  working   interest  wells  in  1998,  the  Company  recorded  a
capitalized ceiling impairment charge at December 31, 1998 of $25.9 million (see
Note 4 of Notes to the Consolidated Financial  Statements).  No assurance can be
given that the Company 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."

     In connection  with the exchange of interests in the Company's  predecessor
partnership with shares of the Company's common stock (the "Exchange")  prior to
the Company's  initial  public  offering in 1997,  the Company issued options to
purchase  644,097  shares  of  common  stock  to  certain  of its  officers  and
employees.  The Company recorded an unearned stock compensation  balance of $2.5
million in the first quarter 1997, of which approximately one-half will be added
to the  amortizable  base of the full-cost  pool over the vesting  period of the
options and the balance will be recorded as a non-cash compensation expense over
the vesting  period of the options.  As a result,  the Company  expects to incur
unearned stock compensation  amortization  expenses of approximately  $64,000 in
2000, $33,000 in 2001 and an aggregate of $41,000 in the two years thereafter.

     The Company's  predecessor  was  classified  as a  partnership  for federal
income tax purposes. Therefore, no income taxes were paid or provided for by the
Company prior to the Exchange.  The Company is a taxable  entity.  In connection
with the Exchange on February 27, 1997, the Company incurred a $5 million charge
to record a deferred income tax liability to recognize the  differences  between
the  financial  statement  basis  and tax  basis  of the  Company's  predecessor
partnership's  natural gas and oil  properties at the Exchange  date,  given the
provisions  of enacted tax laws.  During the fourth  quarter  1997,  the Company
elected to record a step-up in the basis of its  assets  for tax  purposes  as a
result of the  Exchange.  Due to this  election,  the  Company  recorded  a $3.8
million  non-cash  deferred  income tax benefit  during the fourth quarter 1997,
which resulted in a net $1.2 million ($0.10 per diluted share) non-cash deferred
income tax charge for the year ended December 31, 1997.

                                       24
<PAGE>

Results of Operations

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

<TABLE>
<CAPTION>
                                                                               Year Ended December 31,
                                                                         ------------------------------------
                                                                            1997         998         1999
                                                                         ----------  ----------  ------------
<S>                                                                      <C>         <C>         <C>
Production:
     Natural gas (MMcf).............................................          1,382       4,269        4,197
     Oil (MBbls)....................................................            291         396          346
     Natural gas equivalent (MMcfe) ................................          3,126       6,644        6,270
     % Natural gas..................................................            44%         64%          67%
Average sales prices per unit (1):
     Natural gas (per Mcf)..........................................     $     2.56  $     2.04  $      2.11
     Oil (per Bbl)..................................................          19.40       12.85        17.79
     Natural gas equivalent (per Mcfe)..............................           2.94        2.08         2.39
Costs and expenses per Mcfe:
     Lease operating................................................     $     0.37  $     0.33  $      0.36
     Production taxes...............................................           0.18        0.13         0.15
     General and administrative.....................................           1.14        0.70         0.56
     Depletion of natural gas and oil properties....................           0.88        1.28         1.24
</TABLE>

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

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

     Natural  gas and oil sales.  Natural  gas and oil sales  increased  9% from
$13.8  million in 1998 to $15 million in 1999.  An increase in the average sales
price  received for natural gas and oil 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. Natural gas and oil sales in 1999 were increased by higher realized
natural gas and oil 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 --
Hedging Activities."

     Workstation  revenue.  Workstation  revenue  decreased 27% from $390,000 in
1998 to $285,000 in 1999.  Brigham  recognizes  workstation  revenue as industry
participants  in its  seismic  programs  are charged an hourly rate for the work
performed by the Company on its 3-D seismic  interpretation  workstations.  This
decrease in 1999 is primarily  attributable to the Company's  increased  working
interests in its 3-D seismic projects in 1997 and 1998, which reduces the amount
of  workstation   interpretation   costs  billable  to  the  Company's   project
participants. Brigham expects workstation revenue to continue to decline in 2000
due to the  Company's  increased  working  interests  in the square miles of 3-D
seismic it acquired in 1997 and 1998.

     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 the  Company  in its  mid-1999  property  divestitures.  See "--
Overview."


                                       25
<PAGE>

     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  natural gas and oil sales prices and revenues.  The  effective  average
production tax rate increased from 6.2% of natural gas and oil sales revenues in
1998 to 6.5% in 1999 resulting from changes in the  geographic  distribution  of
the Company's producing wells.

     General and administrative  expenses.  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 the Company's  headquarters  space  effective in November  1999,
certain  personnel  reductions and the elimination or reduction of various other
discretionary  expenses.  The Company  plans to  continue  certain of these cost
reduction   initiatives   in  an  effort  to  further  reduce  net  general  and
administrative expenses per unit in 2000.

     Depletion of natural gas and oil  properties.  Depletion of natural gas and
oil  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 natural gas and oil reserves at lower  average  capital costs due to improved
average  finding  costs  during  1999,  partially  offset by an  increase in the
percentage  of  the  Company's   total  full  cost  pool  subject  to  depletion
attributable  to an increase in the  estimate  of the  evaluated  portion of the
Company's natural gas and oil 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.  The Company'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 the Company's  increased capital
expenditures and working capital needs, net of operating cash flow,  during 1998
and 1999.  The  effective  annual  interest  rate on the  Company's  outstanding
indebtedness increased from 10.6% in 1998 to 12.6% in 1999, primarily due to the
Company's issuance of $40 million of senior subordinated  secured notes due 2003
(the "Subordinated Notes") 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 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.
Pursuant to the recently  amended terms of the Company's  senior credit facility
and the  Subordinated  Notes,  Brigham  expects to pay its interest  obligations
related  to  the   Subordinated   Notes   through  the  issuance  of  additional
Subordinated  Notes in lieu of cash during the first three quarters of 2000 (and
potentially during the fourth quarter 2000, if certain conditions are met) in an
effort to preserve cash flow to fund capital expenditures.  Borrowings under the
Company's  credit  facility had an  effective  annual  interest  rate of 9.5% at
December 31, 1999. See "-- Liquidity and Capital Resources."

     Loss on sale of natural gas and oil  properties.  In June 1999, the Company
sold all of its interests in certain producing and non-producing natural gas and
oil 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 the
Company's remaining net reserve volumes,  the Company 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.

Year Ended December 31, 1998 Compared to Year Ended December 31, 1997

     Natural  gas and oil sales.  Natural gas and oil sales  increased  50% from
$9.2  million in 1997 to $13.8  million  in 1998.  Production  volume  increases
accounted for $9.4 million of this increase and were offset by $4.8 million from
a decrease in the average  sales price  received  for natural gas and oil sales.
Production  volumes for natural  gas  increased  209% from 1,382 MMcf in 1997 to
4,269 MMcf in 1998.  The average  price  received for natural gas  decreased 20%
from $2.56 per Mcf in 1997 to $2.04 per Mcf in 1998.  Production volumes for oil
increased  36% from 291 MBbls in 1997 to 396 MBbls in 1998.  The  average  price
received for oil  decreased 34% from $19.40 per Bbl in 1997 to $12.85 per Bbl in
1998.  Natural gas and oil sales in 1998 were increased by production from wells
completed and flowing to sales since December 31, 1997,  offset partially by the
natural decline of existing  production,  and from certain wells acquired in the
Chitwood  Acquisition which were included in the Company's results of operations
effective  September  1,  1997.  See  "--  Overview."  As a  result  of  hedging
activities,  natural gas revenues increased by $555,000 ($0.13 per Mcf) in 1998,
compared to a decrease in oil  revenues of $6,200  ($0.02 per Bbl) in 1997.  See
"-- Other Matters -- Hedging Activities."


                                       26
<PAGE>

     Workstation  revenue.  Workstation  revenue  decreased 39% from $637,000 in
1997 to  $390,000  in 1998.  This  decrease  is  primarily  attributable  to the
Company's increased working interests in its recently acquired 3-D seismic data,
which reduced the amount of  workstation  interpretation  costs  billable to the
Company's project participants.

     Lease operating expenses.  Lease operating expenses increased 89% from $1.2
million ($0.37 per Mcfe) in 1997 to $2.2 million ($0.33 per Mcfe) in 1998.  This
increase  was  primarily  due to an  increase in the number of  producing  wells
during  1998  from  those in 1997.  The  decrease  in the per  unit  amount  was
primarily due to an increase in natural gas  production as a percentage of total
equivalent  production (44% in 1997 and 64% in 1998) since a typical natural gas
well produces with lower  average lease  operating  costs per unit of production
than a typical oil well.

     Production  taxes.  Production taxes increased 55% from $549,000 ($0.18 per
Mcfe)  in 1997 to  $850,000  ($0.13  per  Mcfe) in 1998 as a  direct  result  of
increased   production  volumes.  The  effective  average  production  tax  rate
increased  from 6% of natural gas and oil sales revenues in 1997 to 6.2% in 1998
due to  the  increase  in  natural  gas  production  as a  percentage  of  total
equivalent   production  as  natural  gas  is  typically  burdened  with  higher
production tax rates than oil. The decrease in the per unit amount was primarily
attributable  to the  decline  in  natural  gas and oil sales  prices in 1998 as
compared with 1997.

     General and administrative  expenses.  General and administrative  expenses
increased 31% from $3.6 million  ($1.14 per Mcfe) in 1997 to $4.7 million ($0.70
per Mcfe) in 1998.  This  increase was primarily  attributable  to the hiring of
additional  personnel  and related  expenses  necessary to manage the  Company's
growing operations.  The decrease in the per unit rate was a result of a greater
increase  in  natural  gas  and  oil   production   volumes   than  general  and
administrative expenses from 1997 to 1998 due to the aforementioned factors.

     Depletion of natural gas and oil  properties.  Depletion of natural gas and
oil properties increased 209% from $2.7 million ($0.88 per Mcfe) in 1997 to $8.5
million  ($1.28  per  Mcfe)  in  1998.  Of  this  increase,   $4.5  million  was
attributable  to the increase in production  volumes  during the period and $1.3
million was due to the increase in the  depletion  rate per unit of  production.
The increase in depletion  rate per unit of production  was primarily the result
of the addition of natural gas and oil reserves at higher average  capital costs
due to a reduction in drilling  performance  and downward  revisions to previous
reserve estimates.

     Interest  expense.  Interest expense increased from $1.2 million in 1997 to
$6 million in 1998 due to higher  outstanding  debt  balances  in 1998 at higher
effective  interest  rates.  The Company's  weighted  average  outstanding  debt
balance  increased  450% from $12 million in 1997 to $66  million in 1998.  This
increase in debt was incurred primarily to fund the Company's  increased capital
expenditures and working capital needs, net of operating cash flow, during 1998.
The effective  annual  interest rate on the Company's  outstanding  indebtedness
increased  from 9.4% in 1997 to 10.6% in 1998,  primarily  due to the  Company's
issuance of Subordinated Notes in August 1998. In addition,  interest expense in
1998 included (i)  approximately  $1 million of non-cash  charges related to the
amortization  of  deferred  loan fees and the  amortization  of  discount on the
Subordinated  Notes,  and (ii)  $507,000  of  interest  expenses  related to the
Subordinated  Notes that was paid in kind  through the  issuance  of  additional
Subordinated  Notes  in lieu of cash in  February  1999.  Borrowings  under  the
Company's  senior credit facility had an effective  annual interest rate of 7.2%
at December 31, 1998.

                                       27
<PAGE>

Liquidity and Capital Resources

     The  Company'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.  The
Company's primary capital requirements are 3-D seismic  acquisition,  processing
and interpretation costs, land acquisition costs and drilling  expenditures.  In
January 1998, the Company  entered into a new bank credit facility that provided
for  borrowing  availability  of $75  million  that was  used to repay  its then
outstanding  borrowings  under its previous  credit facility and to fund capital
expenditures.  This credit facility has been subsequently amended, including (i)
an amendment in July 1999 in  connection  with the Company's  mid-1999  sales of
natural gas and oil  properties  to provide for  borrowing  availability  of $56
million,  and (ii) an  amendment  in  February  2000 to  provide  for  borrowing
availability of $70 million that would be increased to $75 million under certain
circumstances. In August 1998, the Company issued $50 million of debt and equity
securities,  including the $40 million of  Subordinated  Notes,  that  generated
proceeds of approximately  $47.5 million,  net of offering costs, that were used
to repay a portion of then  outstanding  borrowings  under the Company's  credit
facility,  thereby  increasing the Company's  borrowing  availability  under its
credit facility to fund capital  expenditures.  During 1999, Brigham issued $4.2
million  of  common  stock  to  Veritas  DGC  Land,  Inc.,  to  satisfy  payment
obligations due to Veritas for seismic acquisition and processing  services.  In
June 1999, the Company  received $17.1 million ($16.7 million after  transaction
costs and post-closing  adjustments) from the sale of its interests in producing
and  non-producing  natural gas and oil properties  located in two  non-operated
fields in its Anadarko Basin  province.  In February  2000,  Brigham raised $4.5
million  through the issuance of common  stock and  warrants to purchase  common
stock in a private equity placement to three institutional investors.

Credit Facility

     In January 1998, the Company entered into a revolving credit agreement (the
"Credit Facility"),  which provided for an initial borrowing availability of $75
million.  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 incur certain capital expenditures, and
to increase the interest rate on outstanding borrowings.

     As a result of the  completion of the majority of the  Company's  strategic
initiatives to improve its capital  resources,  including the June 1999 property
divestitures and the application of the net sales proceeds to reduce  borrowings
outstanding  under the Credit  Facility,  the  Company  and its  senior  lenders
entered into an amendment to the Credit  Facility in July 1999.  This  amendment
provided the Company with borrowing  availability of $56 million  principally to
fund  its  planned   drilling   activities  and   anticipated   working  capital
requirements through the end of 1999. As consideration for this amendment to the
Credit  Facility,  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.  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 the Company and was recognized
as  additional  deferred  loan fees that will be  amortized  over the  remaining
period to maturity of the Credit Facility.

     In February  2000,  Brigham  entered  into an amended and  restated  Credit
Facility with its existing  lenders and a new lender.  This amended and restated
Credit Facility provides the Company with $70 million in borrowing  availability
for a three-year term, an increase from the $56 million previously available. If
Brigham exceeds certain asset value and interest coverage tests in the second or
third  quarters  of 2000,  the total  borrowing  availability  under the  Credit
Facility will increase to $75 million. The Company's lenders have indicated that
the borrowing  availability  provided under the amended Credit Facility exceeded
that which would  otherwise  have been made available  under a more  traditional
conforming  borrowing  base  calculation  based  on the  estimated  value of the
Company's  current net proved reserves and its cash flow.  Borrowings  under the
Credit Facility in excess of $45 million are convertible  into shares of Brigham
common stock in the following  amounts:  (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.  If the Credit  Facility  is repaid at  maturity  or is prepaid  prior to
maturity without payment of cash premiums, the warrants issued to the new lender
of the Credit Facility to purchase Brigham common stock become  exercisable.  In
addition,  certain financial  covenants of the Credit Facility have been amended
or added. In connection with this most recent  amendment,  the Company 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.

                                       28
<PAGE>

     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
under the Credit  Facility is either the lender's base rate or LIBOR plus 3.00%,
at the Company's option. The Company's obligations under the Credit Facility are
secured by  substantially  all of the natural gas and oil  properties  and other
tangible  assets of the Company.  At March 23, 2000, the Company had $58 million
in borrowings  outstanding under the Credit Facility,  which bear interest at an
annual  rate of  approximately  9.1%.  See Note 5 of  Notes to the  Consolidated
Financial Statements.

     The Credit Facility has certain financial covenants,  including current and
interest coverage ratios,  as defined.  The Company and its lenders effected the
amendments to the Credit Facility in March 1999, July 1999 and February 2000, in
part,  to enable the Company to comply with certain  financial  covenants of the
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 the Company 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, the Company's liquidity may be adversely affected, which could in turn
have an adverse impact on the Company's future financial position and results of
operations.

Subordinated Notes

     In  August  1998,  the  Company  issued  $50  million  of debt  and  equity
securities  to  affiliates  of Enron Corp.  Securities  issued by the Company in
connection  with  this  financing  transaction  included:  (i)  $40  million  of
Subordinated  Notes,  (ii)  warrants  to  purchase  one  million  shares  of the
Company's  common stock at a price of $10.45 per share (the  "Subordinated  Note
Warrants"),  and (iii) 1,052,632 shares of the Company's common stock at a price
of $9.50 per share.  The approximate  $47.5 million in net proceeds  received by
the  Company  from this  financing  transaction  were used to repay a portion of
outstanding  borrowings  under its  senior  credit  facility,  which at the time
increased the Company's borrowing availability under its credit facility to fund
capital expenditures.

     Principal  outstanding  under the Subordinated  Notes is due at maturity on
August 20,  2003.  Interest on the  Subordinated  Notes is payable  quarterly at
rates that vary depending upon whether  accrued  interest is paid in cash or "in
kind" through the issuance of additional Subordinated Notes. Interest is payable
in cash at interest rates of 12%, 13% and 14% per annum during years one through
three,  year four and year five,  respectively,  of the term of the Subordinated
Notes;  provided,  however,  that the  Company  may pay  interest  in kind for a
cumulative total of seven quarterly interest payments (potentially increasing to
eight if certain  conditions  are met) at interest rates of 13%, 14% and 15% per
annum during years one through three, year four and year five, respectively,  of
the term of the Subordinated Notes. As of March 23, 2000, the Company had made a
cumulative total of five quarterly interest payments in kind and expects to make
at least the next two quarterly interest payments (due May 2000 and August 2000)
in kind.

     The  Subordinated  Notes  rank  subordinate  in right of  payment to Senior
Indebtedness  (as  defined) and senior to all other  financings  (other than any
allowed  capital  leases and purchase  money  financings)  of the  Company.  The
Subordinated Notes are secured by a second lien against substantially all of the
natural gas and oil  properties and other  tangible  assets of the Company.  The
Subordinated  Notes may be  prepaid  at any time,  in whole or in part,  without
premium or penalty,  provided that all partial  prepayments  must be pro rata to
the various  holders of the  Subordinated  Notes.  The  Subordinated  Notes were
issued  pursuant  to  an  indenture  (the  "Indenture")  that  contains  certain
covenants  that,  among other  things,  limit the ability of the Company and its
subsidiaries   to   incur   additional   indebtedness,   pay   dividends,   make
distributions,  enter into certain sale and leaseback  transactions,  enter into
certain  transactions with affiliates,  dispose of certain assets,  incur liens,
reborrow  funds  utilized to prepay the Senior  Indebtedness  and engage in most
types of mergers and consolidations.

     In March 1999, the Company and Chase Bank of Texas,  National  Association,
as trustee (the "Trustee") for the holders of the  Subordinated  Notes,  entered
into an amendment to the Indenture. This amendment provided the Company with the
option to pay interest due on the  Subordinated  Notes in kind,  for any reason,
through the second  quarter of 2000.  In addition,  certain  financial and other
covenants  were  amended.  The  amendment  also  provided for a reduction in the
exercise price per share of the Subordinated Note Warrants from $10.45 per share
to $3.50 per share and extended the term of the Subordinated  Note Warrants from
seven to ten years.

                                       29
<PAGE>

     In February 2000,  Brigham  entered into another  amendment to the terms of
the Indenture.  In this amendment,  the holders of the Subordinated Notes agreed
to waive the minimum consolidated  interest coverage ratio covenant through June
30, 2000 and to adjust  subsequent  levels  under this test.  In  addition,  the
amendment provides the Company with an extension of its right to pay interest in
kind  through the  issuance  of  additional  Subordinated  Notes in lieu of cash
through the third quarter of 2000 and potentially  through the fourth quarter of
2000 if certain  conditions are met. In exchange for granting these  amendments,
the Company has (i) reset the price of the  Subordinated  Note  Warrants  from a
then  current  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  provides  for the limited  right to receive 4%, or 3% if certain
conditions  are met,  of the  Company's  net  production  revenue  to reduce any
outstanding Subordinated Notes issued as interest paid in-kind.

     The  Indenture  governing  the  Subordinated  Notes has  certain  financial
covenants,  including  current and interest  coverage  ratios,  as defined.  The
Company and the holders of the  Subordinated  Notes  effected the March 1999 and
February  2000  amendments to the Indenture to enable the Company to comply with
certain  financial  covenants of the  Indenture,  including the minimum  current
ratio and the minimum interest coverage ratio, as defined. Should the Company be
unable to comply with  certain of the  financial  covenants,  the holders of the
Subordinated  Notes may be unwilling to waive  compliance or amend the covenants
in the future.  In such  instance,  the  Company's  liquidity  may be  adversely
affected,  which could in turn have an adverse  impact on the  Company's  future
financial position and results of operations.

     At December 31, 1999 and March 23, 2000,  the Company had $45.5 million and
$46.9 million, respectively, principal amount of Subordinated Notes outstanding.

Sales of Interests in Projects and Natural Gas and Oil Properties

     Duke  Project  Financing.  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 Anadarko  Basin  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  (land  and
seismic) in these project areas to a newly formed limited liability company (the
"Duke LLC") for 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,  Brigham
pays 100% of the drilling and completion costs for all wells drilled by the 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 Duke LLC,  subject  in each
instance  to  proportionate  reduction  by any  ownership  rights  held by third
parties.  Upon 100% project payout, the Company has the right to back-in for 80%
of the 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 Duke LLC agreement,  thereby increasing
the Company's  effective working interest in the Duke LLC wells from 70% to 94%.
The Company believes this project  financing  arrangement to be beneficial as it
enabled Brigham to recoup  substantially all of its pre-seismic land and seismic
data  acquisition  costs incurred in these project areas and provided capital to
fund the drilling of the first six wells within these projects.

     Mid-1999  Property Sales. In June 1999,  Brigham sold certain producing and
non-producing  natural  gas and oil  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 the Company 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. The Company  estimated
that net production volumes from the divested  properties were 2.8 MMcfe per day
at the time of the sales. The Company used the proceeds from these  transactions
to reduce borrowings under its credit facility, which contributed to provide the
Company with $8 million in borrowing availability under its 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.

                                       30
<PAGE>

Equity Placements

     Veritas Equity  Issuances.  On March 30, 1999, the Company  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 the Company
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
September  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 Equity  Placement.  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 the  Company'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 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 will be used
to fund a portion of the Company's planned 2000 capital expenditures and working
capital obligations.

Cash Flow Analysis

     Cash Flows from  Operating  Activities.  Cash flows  provided by  operating
activities were $2.6 million in 1999,  $14.8 million in 1998 and $9.8 million in
1997.  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).  The increase in cash flows for 1998
compared  to 1997  was due  primarily  to an  increase  in  natural  gas and oil
revenues,  net of lease  operating  expenses,  production  taxes and general and
administrative expenses, and net changes in working capital items.

     Cash Flows from  Investing  Activities.  Cash flows  provided by  investing
activities in 1999 were $1.6 million as compared to cash flows used by investing
activities of $86.2  million in 1998 and $57.3 million in 1997.  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 natural gas and oil  properties,  which
consisted  principally of the Company'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 Gulf Coast  regions.  The decrease in cash
flow from investing  activities in 1998 were the direct result of an increase in
capital  expenditures  related  to the  Company's  exploration  and  development
activities.  Capital  expenditures  (before  the  application  of  net  proceeds
received  from the sales of interests in projects)  were $25.6  million in 1999,
$85.2 million in 1998 and $57.2 million in 1997.

     After  acquiring  1,227 gross (807 net) square miles of 3-D seismic in 1997
and 1,134 gross (920 net) square  miles of 3-D seismic in 1998,  the Company did
not acquire any new 3-D seismic data during 1999. The Company's drilling efforts
during the past three years  resulted in the completion of 19 (6.3 net) wells in
1999,  50 (26.3  net)  wells in 1998,  and 45 (17.6  net)  wells in 1997,  which
contributed  to  aggregate  net  increases  in proved  reserve  volumes  (net of
revisions  to previous  estimates)  of 28.7 Bcfe in 1999,  31.2 Bcfe in 1998 and
32.4 Bcfe in 1997. In addition,  the Company sold interests in certain producing
and  non-producing  properties  in 1999  for a total of  $27.1  million,  and it
acquired certain  producing  properties and related  interests for $1 million in
1998 and $13.5 million in 1997.


                                       31
<PAGE>

     Cash  Flows  from  Financing  Activities.  Cash  flows  used  by  financing
activities  in 1999 were $4.1 million,  principally  due to the net repayment of
borrowings  outstanding  under the Company's  credit facility and the payment of
deferred  loan fees.  Cash flows  provided by financing  activities in 1998 were
$72.3 million,  primarily as a result of borrowings  under the Company's  credit
facility,  the issuance of the Subordinated Notes and the sale of $10 million of
common stock. Cash flows from financing  activities for 1997 were $47.7 million,
primarily as a result of  borrowings  under the  Company's  credit  facility and
proceeds from the common stock sold in the Company's initial public offering.

Capital Expenditures

     Continuing its strategy  implemented  during 1999, Brigham intends to focus
substantially  all of its efforts and available capital resources in 2000 to the
drilling and  monetization of its highest grade prospects  within its over 5,000
square mile  inventory of 3-D seismic data.  The Company's  current 2000 capital
expenditure budget is estimated to be $25 million,  which includes approximately
$20 million for  drilling  projects and $5 million for  non-drilling  activities
(primarily  acreage  acquisition  and  capitalized  overhead  costs).  Brigham's
planned 2000 drilling  program  consists of a balanced blend of exploration  and
development  drilling  projects  with  approximately  54% of  budgeted  drilling
expenditures targeted for exploratory  prospects,  28% for development locations
and the  remaining  18% for  development  locations  that  are  contingent  upon
drilling  success  during the year.  In addition,  the  Company's  2000 budgeted
drilling  expenditures  have been allocated  approximately 75% to its Gulf Coast
province and 25% to its Anadarko  Basin  province,  concentrated  within  trends
where the  Company  has  experienced  exploration  success to date.  The Company
intends to fund these  budgeted  capital  expenditures  through a combination of
cash flow from operations, available borrowings under its senior credit facility
and the proceeds from its February 2000 private equity placement.  Additionally,
the Company  intends 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 the Company's active exploration and development activities, Brigham
has  experienced  and  expects to  continue to  experience  substantial  working
capital requirements.  While the Company believes that cash flow from operations
and  borrowings  under its senior  credit  facility  should allow the Company to
finance its planned  operations  through  2000 based on current  conditions  and
expectations,  additional  financing  will be required in the future to fund the
Company's  exploration  and  development  activities.  In the  event  additional
financing is not available,  the Company may be required to curtail or delay its
planned activities.

Other Matters

Hedging Activities

     The Company  believes that hedging,  although not free of risk,  allows the
Company to reduce its  exposure to natural gas and oil sales price  fluctuations
and  thereby  to  achieve  more   predictable  cash  flows.   However,   hedging
arrangements,  when  utilized,  limit the benefit to the Company of increases in
the prices of the hedged commodity. Moreover, the Company's hedging arrangements
apply  only to a portion  of its  production  and  provide  only  partial  price
protection  against declines in commodity  prices.  The Company 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
the  Company  exchanges  a floating  market  price for a fixed  contract  price.
Payments are made by the Company when the floating price exceeds the fixed price
for a contract  month and  payments  are  received by the Company 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 the Company was 2,750,000 MMBtu in 1998 and 5,025,000 MMBtu in 1999. The
Company  accounted  for  substantially  all of  these  transactions  as  hedging
activities and, accordingly, adjusted the price received for natural gas and oil
production during the period the 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 a decrease in natural
gas revenues of $486,000 in 1999.

                                       32
<PAGE>

     In September 1999, Brigham sold call options on a portion of its future oil
and natural gas  production.  The Company  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 the Company's fixed natural gas swap price  attributable to these
transactions is not reflected in reported  revenues.  Rather, it is 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 the Company's  outstanding  natural gas and
oil hedging arrangements as of March 23, 2000:

Natural Gas Hedges
<TABLE>
<CAPTION>
                                                           2000                   2001                  2002
                                                 ------------------------ --------------------- ---------------------
                                                               Average                 Average              Average
                                                 Volumes       Contract    Volumes    Contract   Volumes   Contract
                                     Monthly     Hedged         Price       Hedged      Price    Hedged      Price
                   Pricing Basis  Contract Term   (MMBtu)     ($/MMBtu)    (MMBtu)    ($/MMBtu)  (MMBtu)   ($/MMBtu)
                   -------------  -------------   -------     ---------    -------    ---------  -------   ---------

Fixed Price Swaps:
<S>               <C>            <C>              <C>           <C>        <C>         <C>      <C>          <C>
   Contract #1          ANR      November 1999 -  2,740,000     $2.1690    600,000     $2.0650         --         --
                     Oklahoma      April 2001
   Contract #2        Houston     April 2000 -    1,375,000     $2.1500    600,000     $2.1500         --         --
                   Ship Channel    April 2001
   Contract #3         TETCO      April 2000 -    1,375,000     $2.0575    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
</TABLE>

Crude Oil Hedges

<TABLE>
<CAPTION>
                                                           2000                   2001                  2002
                                                  ----------------------  ----------------------  --------------------
                                                                Average                Average               Average
                                                   Volumes      Contract   Volumes     Contract   Volumes    Contract
                                     Monthly        Hedged       Price     Hedged        Price    Hedged      Price
                   Pricing Basis  Contract Term     (Bbls)      ($/Bbl)    (Bbls)       ($/Bbl)   (Bbls)      ($/Bbl)
                   -------------  -------------     ------      -------    ------       -------   ------      -------

<S>                    <C>               <C>        <C>          <C>       <C>          <C>         <C>        <C>
Fixed Price Cap        NYMEX     October 1999 -     219,600      $27.40    109,200      $26.15         --         --
                                  December 2001

Fixed Price Floor      NYMEX      March 2000 -      183,600      $18.00    109,200      $17.36         --         --
                                  December 2001
</TABLE>

                                       33
<PAGE>

Effects of Inflation and Changes in Prices

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

Environmental and Other Regulatory Matters

     The Company'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  natural  gas and oil,  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  the  Company  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
the  Company 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 the Company's  financial condition and operations.  Although  significant
expenditures  may be required to comply with  governmental  laws and regulations
applicable to the Company,  compliance has not had a material  adverse effect on
the earnings or competitive position of the Company.  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."

Year 2000 Issue

     The Company has initially  incurred no significant  problems related to the
Year 2000 issue.  However,  the Company has not yet fully utilized all functions
and processes of its systems and accordingly cannot be sure that all its systems
will be free of Year 2000 issues.  Also,  the Company has no assurance  that its
critical  business  partners,  governmental  agencies or other key third parties
have not incurred Year 2000 issues that may affect the Company.

Recent Accounting Pronouncements

     In June 1998,  the FASB  issued SFAS No. 133,  "Accounting  for  Derivative
Instruments  and Hedging  Activities."  The Company  must adopt SFAS No. 133, as
amended by SFAS No. 137,  effective  January 1, 2001.  The Company is  currently
assessing  the  impact  adoption  of this  standard  will have on its  financial
statement presentation.

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  the  Company  anticipates  drilling  through  2000  and the  Company's
financial position,  business strategy and other plans and objectives for future
operations.  Although the Company  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 the Company will be realized
or, even if substantially  realized, that they will have the expected effects on
its business or operations. Among the factors that could cause actual results to
differ   materially  from  the  Company'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 the  Company  and its  project  participants,
government  regulations and other factors set forth among the risk factors noted
below or in the description of the Company's  business in Item 1 of this report.
All subsequent oral and written forward looking  statements  attributable to the
Company  or  persons  acting on its  behalf  are  expressly  qualified  in their
entirety by these  factors.  The Company  assumes no obligation to update any of
these statements.

                                       34
<PAGE>

Risk Factors

We Are Substantially Leveraged

     Our outstanding  long-term debt was $101.5 million (principal amount) as of
December 31, 1999. The indenture governing our senior subordinated secured notes
limits the amounts of additional debt borrowings, including borrowings under our
senior  credit  facility or other senior  indebtedness.  However,  the indenture
permits us to borrow  under our senior  credit  facility up to the lesser of $75
million or the loan commitments  under the facility ($70 million as of March 23,
2000).  We had $58 million of  borrowings  outstanding  under our senior  credit
facility as of March 23, 2000.

     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 will not
          have these cash flows available for other purposes.

     o    The  covenants in our senior credit  facility and the indenture  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 credit  facility should allow us to finance
our  planned   operations   through  2000  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."

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;

                                       35
<PAGE>

     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 1999, the high and low prices for oil on the NYMEX were $27.07
per Bbl and $11.37 per Bbl,  and the high and low prices for  natural gas on the
NYMEX were $3.09 per MMBtu and $1.63 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.  Because the
terms of our  hedging  contracts  are  based on  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  --  Hedging
Activities" and "Item 7A. Quantitative and Qualitative  Disclosures About Market
Risk."

                                       36
<PAGE>

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;

     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."

                                       37
<PAGE>

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, 1999, we had an accumulated  deficit of $55 million and total  stockholders'
equity of $9 million.  We have recognized the following  annual net losses 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
natural gas and oil  properties) in 1998,  and $21.6 million  (including a $12.2
million  non-cash loss on the sale of natural gas and oil  properties)  in 1999.
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;

     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.

                                       38
<PAGE>

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 -- Natural Gas and Oil 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.

     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.

                                       39
<PAGE>

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."

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 23, 2000,  our  directors,  executive  officers  and  principal
stockholders, and certain of their affiliates,  beneficially owned approximately
53% 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.

                                       40
<PAGE>

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

     The  Company  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.  As a result,  management
believes that its use of derivative  instruments  does not expose the Company to
material  risk.  The  Company's  use  of  derivative   instruments  for  hedging
activities  could  materially  affect the  Company's  results of  operations  in
particular  quarterly or annual  periods  since such  instruments  can limit the
Company's ability to benefit from favorable oil and natural gas price movements.
However,  management  believes  that  use of these  instruments  will not have a
material adverse effect on the Company's financial position or liquidity.

Commodity Price Risk

     The Company'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, the Company 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 -- Hedging Activities."

     The Company  believes that hedging,  although not free of risk,  allows the
Company 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,  limit the benefit to the Company of increases in
the prices of the hedged commodity. Moreover, the Company's hedging arrangements
apply  only to a portion  of its  production  and  provide  only  partial  price
protection  against declines in commodity  prices.  The Company expects that the
amount of its hedges will vary from time to time.

     Based on the Company's oil and natural gas hedging arrangements outstanding
at March 23, 2000,  an adverse  change  (defined as a  hypothetical  10% and 25%
increase in underlying  commodity  prices for open positions)  would reduce cash
flow  by  approximately  $3.3  million  and  $8.8  million,  respectively,  from
currently  projected  levels.  Additionally,  as the Company  utilizes  swap and
collar  arrangements to hedge anticipated and firmly committed  transactions,  a
loss in fair value for those instruments is generally offset by price changes in
the underlying commodity.  The impact of these price changes is not reflected in
this sensitivity analysis.

                                       41
<PAGE>

Interest Rate Risk

     The Company is subject to interest rate risk as borrowings under its senior
credit  facility ($58 million  outstanding as of March 23, 2000) accrue interest
at floating rates based on the lender's base rate or LIBOR. The Company does not
utilize  derivative  instruments to protect against changes in interest rates on
debt borrowings.  See Note 9 of Notes to Consolidated Financial Statements for a
description of the Company's financial instruments at December 31, 1999.

ITEM 8.      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The  Company's   Consolidated   Financial   Statements  and  the  Financial
Statements  of Certain of the Company's  Subsidiaries  required by this item are
included on the pages  immediately  following the Index to Financial  Statements
appearing on page F1-1.

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

     None.


                                    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 1 - Election of Directors"  and to the
information  under the caption  "Compliance with Section 16(a) of the Securities
Exchange Act of 1934" in the Company's  definitive  Proxy  Statement  (the "2000
Proxy  Statement")  for its annual meeting of stockholders to be held on May 18,
2000.  The 2000 Proxy  Statement  will be filed with the Securities and Exchange
Commission (the "Commission") not later than 120 days subsequent to December 31,
1999.

     Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company 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 2000 Proxy  Statement,  which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information  required by this item is incorporated  herein by reference
to the 2000 Proxy  Statement,  which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     The information  required by this item is incorporated  herein by reference
to the 2000 Proxy  Statement,  which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.

                                       42
<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 F1-1.

     2.      Financial Statement Schedules:

             See Index to Financial Statements on page F1-1.

   3. 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).

3.2     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     Indenture  dated as of  August  20,  1998  between  Brigham  Exploration
        Company and Chase Bank of Texas, National Association, as Trustee (filed
        as Exhibit 4.2 to the Company's  Annual Report on Form 10-K for the year
        ended December 31, 1998, and incorporated herein by reference).

4.2.1   Supplemental  Indenture  dated  as of March  26,  1999  between  Brigham
        Exploration Company and Chase Bank of Texas,  National  Association,  as
        Trustee  (filed as Exhibit 4.2.1 to the Company's  Annual Report on Form
        10-K for the year ended  December 31, 1998, and  incorporated  herein by
        reference).

4.3     Form of  Warrant  Certificate  (filed as  Exhibit  4.3 to the  Company's
        Annual  Report on Form 10-K for the year ended  December 31,  1998,  and
        incorporated herein by reference).

4.4     Form of Senior Subordinated  Secured Note due 2003 (filed as Exhibit 4.4
        to the Company's  Registration  Statement on Form S-1  (Registration No.
        333-53873), and incorporated herein by reference).

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).

                                       43
<PAGE>

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).

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.

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 (filed as Exhibit
        10.9 to the Company's  Registration  Statement on Form S-1 (Registration
        No. 333-22491), 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* Option  Agreement  dated as of March 4,  1997,  by and  between  Brigham
        Exploration  Company  and Jon L. Glass  (filed as Exhibit  10.9.2 to the
        Company's   Registration   Statement  on  Form  S-1   (Registration  No.
        333-22491), and incorporated herein by reference).

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).

                                       44
<PAGE>

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.

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 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).

                                       45
<PAGE>

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., 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).

                                       46
<PAGE>

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   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).

                                       47
<PAGE>

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   Securities  Purchase Agreement dated as of August 20, 1998 among Brigham
        Exploration  Company,  Enron Capital & Trade  Resources  Corp. and Joint
        Energy Development  Investments II Limited Partnership (filed as Exhibit
        10.38 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 August 20, 1998, by and among
        Brigham Exploration  Company,  Enron Capital & Trade Resources Corp. and
        Joint Energy  Development  Investments II Limited  Partnership (filed as
        Exhibit 10.39 to the  Company's  Annual Report on Form 10-K for the year
        ended December 31, 1998, and incorporated herein by reference).

10.39.1 Amendment to Registration  Rights  Agreement dated as of March 26, 1999,
        by  and  among  Brigham  Exploration  Company,  Enron  Capital  &  Trade
        Resources  Corp.,  ECT  Merchant  Investments  Corp.  and  Joint  Energy
        Development Investments II Limited Partnership (filed as Exhibit 10.39.1
        to the Company's  Annual Report on Form 10-K for the year ended December
        31, 1998, and incorporated herein by reference).

10.40   Form of  Guaranty  for  subsidiaries  (filed  as  Exhibit  10.40  to the
        Company's  Annual  Report on Form 10-K for the year ended  December  31,
        1998, and incorporated herein by reference).

10.41   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).

10.42   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).

10.43   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).

                                       48
<PAGE>

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

10.45*  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).

10.46*  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).

10.47   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).

10.48   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).

10.49   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).

10.50   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).

10.51   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).

10.52   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).

10.53   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).

10.54   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).

10.55   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).

10.56   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).

                                       49
<PAGE>

10.57   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).

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

10.59   Second Amendment to Intercreditor and  Subordination  Agreement dated as
        of February 17, 2000 by and among ECT Merchant  Investments Corp., Joint
        Energy  Development  Investments  II  Limited  Partnership  and  Bank of
        Montreal,  as agent for each of the lenders  that is a signatory  to, or
        which  becomes a signatory  to, the Senior  Credit  Agreement  (filed as
        Exhibit 10.10 to the Company's Current Report on Form 8-K filed February
        29, 2000 and incorporated herein by reference).

10.60   Second  Amendment  to  Indenture  dated as of  February  17,  2000 among
        Brigham   Exploration   Company  and  Chase  Bank  of  Texas,   National
        Association  (filed as Exhibit 10.11 to the Company's  Current Report on
        Form 8-K filed February 29, 2000 and incorporated herein by reference).

10.61   Conveyance of Adjustable  Term Overriding  Royalty  Interest dated as of
        February  17,  2000 by and  between  Brigham  Oil & Gas,  L.P.,  and ECT
        Merchant  Investments Corp. and Joint Energy Development  Investments II
        Limited  Partnership  (filed as Exhibit 10.12 to the  Company's  Current
        Report on Form 8-K filed  February 29, 2000 and  incorporated  herein by
        reference).

10.62   Warrant Certificate dated as of February 17, 2000 by and between Brigham
        Exploration Company and Joint Energy Development  Investments II Limited
        Partnership  (filed as Exhibit 10.13 to the Company's  Current Report on
        Form 8-K filed February 29, 2000 and incorporated herein by reference).

10.63   Warrant Certificate dated as of February 17, 2000 by and between Brigham
        Exploration Company and ECT Merchant Investments Corp. (filed as Exhibit
        10.14 to the  Company's  Current  Report on Form 8-K filed  February 29,
        2000 and incorporated herein by reference).

10.64   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).

10.65+  Joint Development  Agreement,  dated as of  February  10,  1999,  by and
        between Brigham Oil & Gas, L.P. and Aspect Resources LLC.

10.65.1+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.

10.65.2+Acquisition and Participation Agreement,  dated October 21, 1999, by and
        between Brigham Oil & Gas, L.P. and Aspect Resources LLC.

10.65.3+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.

10.66+  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.

                                       50
<PAGE>

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.

27+     Financial Data Schedule.

*       Management contract or compensatory plan.
+       Filed herewith.


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

     None.


                                       51
<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 gas 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  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.

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%.

                                       52
<PAGE>

Proved Developed 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.

                                       53
<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 24, 2000.

                                        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 24, 2000, 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


                                       54
<PAGE>

                          INDEX TO FINANCIAL STATEMENTS

                                                                           Page
                                                                           ----

Financial Statements of Brigham Exploration Company
     Report of Independent Accountants.................................... F1-2
     Consolidated Balance Sheets as of December 31, 1999 and 1998......... F1-3
     Consolidated Statements of Operations for the Years Ended
        December 31, 1999, 1998, and 1997................................. F1-4
     Consolidated Statements of Stockholders' Equity for the Years Ended
        December 31, 1999, 1998, and 1997................................. F1-5
     Consolidated Statements of Cash Flows for the Years Ended
        December 31, 1999, 1998, and 1997................................. F1-6
     Notes to the Consolidated Financial Statements....................... F1-7
Financial Statements of Certain Brigham Exploration Company Subsidiaries
     Report of Independent Accountants.................................... F2-1
     Balance Sheets as of December 31, 1999............................... F2-2
     Balance Sheets as of December 31, 1998............................... F2-3
     Statements of Operations for the Year Ended December 31, 1999........ F2-4
     Statements of Operations for the Year Ended December 31, 1998........ F2-5
     Statements of Operations for the Year Ended December 31, 1997........ F2-6
     Statements of Equity for the Year Ended December 31, 1999............ F2-7
     Statements of Equity for the Year Ended December 31, 1998............ F2-8
     Statements of Equity for the Year Ended December 31, 1997............ F2-9
     Statements of Cash Flows for the Year Ended December 31, 1999........ F2-10
     Statements of Cash Flows for the Year Ended December 31, 1998........ F2-11
     Statements of Cash Flows for the Year Ended December 31, 1997........ F2-12
     Notes to the Financial Statements.................................... F2-13


As  all  Brigham  Exploration   Company   significant   subsidiaries  fully  and
unconditionally  guarantee the Senior Subordinated Secured Notes and the Company
has no significant  assets other than its investments in its  subsidiaries,  the
consolidated  financial  statements are  substantially the same as the financial
statements of the subsidiary  guarantors and separate financial  statements have
been omitted as they would not be meaningful to investors.

Financial  statements  for the wholly owned  subsidiaries  whose  securities are
pledged as  collateral  for the Senior  Subordinated  Notes are  included in the
separate financial statements.



                                      F1-1
<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 stockholders' equity and of cash flows
present  fairly,  in all material  respects,  the financial  position of Brigham
Exploration  Company  at  December  31,  1999 and 1998,  and the  results of its
operations  and its cash flows for each of the three  years in the period  ended
December 31, 1999, in conformity with accounting  principles  generally accepted
in the United States.  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,  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 the opinion expressed above.

PricewaterhouseCoopers LLP

Dallas, Texas
March 7, 2000

                                      F1-2
<PAGE>


                           BRIGHAM EXPLORATION COMPANY

                           CONSOLIDATED BALANCE SHEETS
                                 (in thousands)
<TABLE>
<CAPTION>

                                                                                            December 31,
                                                                               ---------------------------------------
                                                                                     1999                   1998
                                                                               ------------------      ---------------
<S>                                                                                  <C>                     <C>

                                                       ASSETS
Current assets:
     Cash and cash equivalents                                                 $           2,742       $        2,569
     Accounts receivable                                                                   4,945                7,938
     Other current assets                                                                    577                  290
                                                                               ------------------      ---------------
        Total current assets                                                               8,264               10,797
                                                                               ------------------      ---------------

Natural gas and oil properties, at cost, net                                             112,066              134,317
Other property and equipment, at cost, net                                                 1,686                2,014
Drilling advances paid                                                                        23                  230
Deferred loan fees                                                                         3,481                3,146
Other noncurrent assets                                                                      163                   12
                                                                               ------------------      ---------------
                                                                               $         125,683       $      150,516
                                                                               ==================      ===============


                                        LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
     Accounts payable                                                          $          14,851       $       19,883
     Accrued drilling costs                                                                  541                1,219
     Participant advances received                                                           850                  764
     Other current liabilities                                                             1,502                1,647
                                                                               ------------------      ---------------
        Total current liabilities                                                         17,744               23,513
                                                                               ------------------      ---------------

Notes payable                                                                             56,000               59,000
Senior subordinated notes, net                                                            41,341               35,786
Other noncurrent liabilities                                                               1,600                7,536

Commitments and contingencies

Stockholders' equity:
     Preferred stock, $.01 par value, 10 million shares
        authorized, none issued and outstanding                                                -                    -
     Common stock, $.01 par value, 30 million shares
        authorized, 14,517,786 and 13,306,206 issued and
        outstanding at December 31, 1999 and 1998, respectively                              145                  133
     Additional paid-in capital                                                           64,171               58,838
     Unearned stock compensation                                                            (290)                (890)
     Accumulated deficit                                                                 (55,028)             (33,400)
                                                                               ------------------      ---------------
        Total stockholders' equity                                                         8,998               24,681
                                                                               ------------------      ---------------
                                                                               $         125,683       $      150,516
                                                                               ==================      ===============

</TABLE>

  Natural gas and oil properties are accounted for using the full cost method.



        See accompanying notes to the consolidated financial statements.

                                      F1-3
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

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


<TABLE>
<CAPTION>

                                                                              Year Ended December 31,
                                                        ---------------------------------------------------------------
                                                              1999                   1998                  1997
                                                        ------------------     -----------------     ------------------
<S>                                                             <C>                   <C>                   <C>
Revenues:

     Natural gas and oil sales                          $          14,992      $         13,799      $           9,184
     Workstation revenue                                              285                   390                    637
                                                        ------------------     -----------------     ------------------
                                                                   15,277                14,189                  9,821
                                                        ------------------     -----------------     ------------------
Costs and expenses:

     Lease operating                                                2,259                 2,172                  1,151
     Production taxes                                                 968                   850                    549
     General and administrative                                     3,481                 4,672                  3,570
     Depletion of natural gas and oil properties                    7,792                 8,483                  2,743
     Depreciation and amortization                                    525                   413                    306
     Capitalized ceiling impairment                                     -                25,926                      -
     Amortization of stock compensation                                 1                   372                    388
                                                        ------------------     -----------------     ------------------
                                                                   15,026                42,888                  8,707
                                                        ------------------     -----------------     ------------------
        Operating income (loss)                                       251               (28,699)                 1,114
                                                        ------------------     -----------------     ------------------

Other income (expense):

     Interest income                                                  176                   136                    145
     Interest expense, net                                         (9,697)               (5,968)                (1,017)
     Interest expense - related party                                   -                     -                   (173)
     Loss on sale of natural gas and oil propertieS               (12,195)                    -                      -
     Other expense                                                   (163)                    -                      -
                                                        ------------------     -----------------     ------------------
                                                                  (21,879)               (5,832)                (1,045)
                                                        ------------------     -----------------     ------------------

Net income (loss) before income taxes                             (21,628)              (34,531)                    69

Income tax benefit (expense)                                            -                 1,186                 (1,186)
                                                        ------------------     -----------------     ------------------
     Net loss                                           $         (21,628)     $        (33,345)     $          (1,117)
                                                        ==================     =================     ==================

Net loss per share:

     Basic/Diluted                                      $           (1.53)     $          (2.64)     $           (0.10)

Weighted average common shares outstanding:

     Basic/Diluted                                                 14,152                12,626                 11,081
</TABLE>



        See accompanying notes to the consolidated financial statements.

                                      F1-4

<PAGE>
                           BRIGHAM EXPLORATION COMPANY

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

<TABLE>
<CAPTION>
                                                            Additional        Unearned
                                  Common Stock                Paid-in           Stock       Accumulated     Predecessor
                          ------------------------------
                               Shares           Amounts       Capital        Compensation     Deficit         Capital         Total
                          --------------    ------------   -----------     --------------  ------------   ---------------    -------

<S>                        <C>              <C>            <C>             <C>             <C>            <C>               <C>
Balance,
    December 31, 1996                    -   $    -        $        -      $      -       $       -   $       3,244   $       3,244
Consummation of
    the Exchange                 8,928,574       90            19,580             -               -          (3,244)         16,426
Issuance of stock
    options                              -        -             2,576        (2,576)              -               -               -
Forfeiture of stock
    options                              -        -               (69)           69               -               -               -
Issuance of common
    stock                        3,325,000       33            23,894             -               -               -          23,927
Net loss for
    period ended
    February 27, 1997                    -        -            (4,869)            -               -               -          (4,869)
Net income for
    period from
    February 27, 1997
    to Dec. 31, 1997                     -        -             3,807             -             (55)              -           3,752
Amortization of
    unearned stock
    compensation                         -        -                 -           833               -               -             833
                          -----------------  ----------  ----------------  ------------  --------------  --------------  -----------
Balance,
    December 31, 1997           12,253,574      123            44,919        (1,674)            (55)              -          43,313

Net loss                                 -        -                 -             -         (33,345)              -         (33,345)
Issuance of
    common stock                 1,052,632       10             9,419             -               -               -           9,429
Issuance of warrants                     -        -             4,500             -               -               -           4,500
Amortization of
    unearned stock
    compensation                         -        -                 -           784               -               -             784
                          -----------------  ----------  ----------------  ------------  --------------  --------------  ----------
Balance,
    December 31, 1998           13,306,206      133            58,838          (890)        (33,400)              -          24,681
Net loss                                 -        -                 -             -         (21,628)              -         (21,628)
Issuance of
    common stock                 1,211,580       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           14,517,786   $     145   $        64,171   $      (290)  $     (55,028)  $           -   $    8,998
                          =================  ==========  ================  ============  ==============  ==============  ==========
</TABLE>

               See accompanying notes to the financial statements.


                                      F1-5
<PAGE>
                           BRIGHAM EXPLORATION COMPANY

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (in thousands)
<TABLE>
<CAPTION>
                                                                                         Year ended December 31,
                                                                                ------------------------------------------
                                                                                   1999           1998           1997
                                                                                -----------    ------------   ------------
<S>                                                                                 <C>             <C>           <C>
Cash flows from operating activities:

     Net loss                                                                   $  (21,628)    $   (33,345)   $    (1,117)
     Adjustments to reconcile net loss to cash
       provided by operating activities:

        Depletion of natural gas and oil properties                                  7,792           8,483          2,743
        Depreciation and amortization                                                  525             413            306
        Capitalized ceiling impairment                                                   -          25,926              -
        Amortization of stock compensation                                               1             372            388
        Interest paid through issuance of additional senior subordinated notes       5,459               -              -
        Amortization of deferred loan fees and debt issuance costs                   1,739             726              -
        Amortization of discount on senior subordinated notes                          575             286              -
        Amortization of deferred loss on derivatives instruments                       759               -              -
        Market value adjustment for derivatives instruments                            115               -              -
        Loss on sale of natural gas and oil properties                              12,195               -              -
        Changes in working capital and other items:

            (Increase) decrease in accounts receivable                               2,993          (3,029)        (2,213)
            Increase in other current assets                                        (1,046)            (10)          (128)
            Increase (decrease) in accounts payable                                 (1,136)          7,991          8,955
            Increase (decrease) in participant advances received                        86             275           (648)
            Increase (decrease) in other current liabilities                          (115)            862             50
            Increase in deferred interest payable - related party                        -               -             53
            Increase (decrease) in deferred income tax liability                         -          (1,186)         1,186
            Other noncurrent assets                                                   (151)              6            281
            Other noncurrent liabilities                                            (5,585)          7,004            (50)
                                                                                -----------    ------------   ------------
            Net cash provided by operating activities                                2,578          14,774          9,806
                                                                                -----------    ------------   ------------

Cash flows from investing activities:

     Additions to natural gas and oil properties                                   (25,560)        (85,207)       (57,170)
     Proceeds from sale of natural gas and oil properties                           27,143               -             74
     Additions to other property and equipment                                        (146)           (868)          (545)
     (Increase) decrease in drilling advances paid                                     207            (152)           341
                                                                                -----------    ------------   ------------
            Net cash provided (used) by investing activities                         1,644         (86,227)       (57,300)
                                                                                -----------    ------------   ------------
Cash flows from financing activities:

     Proceeds from issuance of common stock                                              -           9,429         23,927
     Proceeds from issuance of sr. subordinated notes payable and warrants               -          40,000              -
     Increase in notes payable                                                      13,750         105,800         37,250
     Repayment of notes payable                                                    (16,750)        (78,800)       (13,250)
     Principal payments on capital lease obligations                                  (253)           (236)          (179)
     Deferred loan fees paid                                                          (796)         (3,872)             -
                                                                                -----------    ------------   ------------
            Net cash provided (used) by financing activities                        (4,049)         72,321         47,748
                                                                                -----------    ------------   ------------

Net increase in cash and cash equivalents                                              173             868            254
Cash and cash equivalents, beginning of period                                       2,569           1,701          1,447
                                                                                -----------    ------------   ------------
Cash and cash equivalents, end of period                                        $    2,742     $     2,569    $     1,701
                                                                                ===========    ============   ============
Supplemental disclosure of cash flow information:

     Cash paid during the period for interest                                   $    1,960     $     5,490    $     1,679
                                                                                ===========    ============   ============
Supplemental disclosure of noncash investing and financing activities:

     Capital lease asset additions                                              $       51     $       320    $       403
                                                                                ===========    ============   ============
     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 periods                                                       $       50
                                                                                ===========
     Increase in deferred loan fees for issuance of warrants                    $    1,228
                                                                                ===========
</TABLE>

        See accompanying notes to the consolidated financial statements.

                                      F1-6
<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  natural gas and
oil properties using 3-D seismic imaging and other advanced technologies.  Since
its inception,  the  Partnership  has focused its exploration and development of
natural gas and oil 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.

Property and Equipment

     The Company uses the full cost method of accounting  for its  investment in
natural gas and oil properties. Under this method, all acquisition,  exploration
and development costs, including certain payroll and other internal costs,
incurred  for  the  purpose  of  finding   natural  gas  and  oil  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.

                                      F1-7
<PAGE>

     The capitalized  costs of the Company's natural gas and oil properties plus
future  development,  dismantlement,  restoration  and  abandonment  costs  (the
"Amortizable  Base"),  net of estimated salvage values,  are amortized using the
unit-of-production   method  based  upon   estimates  of  total  proved  reserve
quantities.  The  Company's  capitalized  costs  of  its  natural  gas  and  oil
properties,  net of  accumulated  amortization,  are  limited  to the  total  of
estimated  future net cash  flows  from  proved  natural  gas and oil  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 natural gas and oil. A reduction in the
valuation of natural gas and oil properties  resulting from declining  prices or
production   could  adversely   impact  depletion  rates  and  capitalized  cost
limitations.

     All costs  directly  associated  with the  acquisition  and  evaluation  of
unproved  properties are initially  excluded from the Amortizable Base. Upon the
interpretation  by the Company of the 3-D seismic data  associated with unproved
properties,  the geological and geophysical costs related to acreage that is not
specifically  identified  as  prospective  are  added to the  Amortizable  Base.
Geological and geophysical costs associated with prospective acreage, as well as
leasehold  costs,  are  added to the  Amortizable  Base when the  prospects  are
drilled.  Costs of prospective acreage are reviewed annually for impairment on a
property-by-property basis.

     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  natural gas and oil 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 natural gas or oil 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,  1999,  1998  and  1997  were  not  significant.  Interest  is
capitalized on significant  unevaluated  natural gas and oil properties that are
not subject to amortization.

     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.

Derivative Instruments

     The Company  periodically enters into commodity hedge 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  derivative   financial
instruments are based on expected  production  from existing wells.  The Company
uses these  derivative  financial  instruments to manage market risks  resulting
from fluctuations in commodity prices.

                                      F1-8
<PAGE>

     Correlation  of the hedge  contracts is determined  by  evaluating  whether
hedge 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 hedge contracts and the underlying  natural
gas and crude oil sales volumes, realized gains or losses and related cash flows
arising from the hedge  contracts  are  recognized as a component of natural gas
and oil sales in the same period as the sale of the underlying  volumes.  To the
extent  that  correlation  does not exist  between the hedge  contracts  and the
underlying natural gas and crude oil sales volumes, realized gains or losses and
related cash flows arising from the hedge contracts are recognized in the period
incurred  as a component  of other  income.  The fair market  value of any hedge
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 hedge  contract,
generally accepted  accounting  principles require that any gains or losses upon
termination be carried  forward and recognized as a component of natural gas and
oil sales in the period in which the underlying volumes are sold.

Stock Based Compensation

     The Company  measures  compensation  expense for its stock based  incentive
plan using the intrinsic  value method and has provided in Note 11 the pro forma
disclosure  of the  effect on net loss and net loss per  common  share as if the
fair  value  based  method  prescribed  by  Statement  of  Financial  Accounting
Standards ("SFAS") No. 123,  "Accounting for Stock Based Compensation," had been
applied in measuring compensation expense.

Federal and State Income Taxes

     Prior  to the  consummation  of the  Exchange,  there  was  no  income  tax
provision  included in the  financial  statements as the  Partnership  was not a
taxpaying  entity.  Income and losses were passed through to its partners on the
basis of the allocation  provisions  established by the  partnership  agreement.
Upon  consummation of the Exchange,  the  Partnership  became subject to federal
income taxes through its ownership by the Company.

     In conjunction  with the Exchange,  the Company  recorded a deferred income
tax liability of $5 million to recognize the temporary  differences  between the
financial  statement  and  tax  bases  of  the  assets  and  liabilities  of the
Partnership  at the Exchange  date,  February 27, 1997,  given the provisions of
enacted  tax laws.  Subsequent  to this date,  the  Company  elected to record a
step-up  in basis of its assets for tax  purposes  as a result of the  Exchange.
Related to this election,  the Company  recorded a $3.8 million  deferred income
tax benefit,  resulting in a net $1.2 million deferred income tax charge for the
year ended December 31, 1997.

Segment Information

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


                                      F1-9
<PAGE>

New Pronouncements

     In June 1998, the Financial  Accounting Standards Board (the "FASB") issued
SFAS No. 133,  "Accounting for Derivative  Instruments and Hedging  Activities."
SFAS No. 133 requires that all derivative instruments be recorded on the balance
sheet at fair value.  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. For fair value hedge transactions in which the
Company is hedging changes in an asset's, liability's, or firm commitment's fair
value, changes in the fair value of the derivative  instrument will generally be
offset in the income  statement by changes in the hedged item's fair value.  For
cash flow hedge  transactions in which the Company is hedging the variability of
cash  flows  related  to a  variable-rate  asset,  liability,  or  a  forecasted
transaction,  changes in the fair  value of the  derivative  instrument  will be
reported in other  comprehensive  income. The gains and losses on the derivative
instrument that are reported in other comprehensive  income 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.  The Company must adopt SFAS No. 133, as
amended  by SFAS No.  137,  effective  January 1,  2001.  The  Company is in the
process of analyzing  the  potential  impact of this  standard on its  financial
statement presentations.

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.

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

                                     F1-10
<PAGE>

4.       Property and Equipment

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

<TABLE>
<CAPTION>
                                                                December 31,
                                                        ------------------------------
                                                            1999            1998
                                                        -------------   --------------
<S>                                                     <C>             <C>
Natural gas and oil properties.......................   $    178,755          181,019
Accumulated depletion................................        (66,689)         (46,702)
                                                        -------------   --------------
                                                             112,066          134,317
                                                        -------------   --------------
Other property and equipment:
   3-D seismic interpretation workstations
     and software....................................          2,248            2,186
   Office furniture and equipment....................          1,909            1,774
   Accumulated depreciation..........................        (2,471)          (1,946)
                                                        -------------   --------------
                                                               1,686            2,014
                                                        -------------   --------------
                                                        $    113,752    $     136,331
                                                        =============   ==============
</TABLE>

     At December 31, 1998, a capitalized ceiling impairment of $25.9 million was
recognized  and is included  above in the  accumulated  depletion  balances  for
natural  gas and oil  properties.  The write  down was  calculated  based on the
estimated  discounted present value of future net cash flows from proved natural
gas and oil reserves using prices in effect at December 31, 1998.

     The Company  capitalizes  certain payroll and other internal costs directly
attributable to acquisition,  exploration and development  activities as part of
its investment in natural gas and oil properties  over the periods  benefited by
these activities. During the years ended December 31, 1999, 1998 and 1997, these
capitalized  costs  amounted to $3.3  million,  $4.6  million and $3.5  million,
respectively.  Capitalized costs do not include any costs related to production,
general  corporate  overhead,  or  similar  activities.  Interest  costs of $3.0
million and $1.2 million were capitalized in 1999 and 1998, respectively.

5.   Notes Payable and Senior Subordinated 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 is
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.   The  Credit  Facility  contains  covenants
restricting  the Company's  ability to declare or pay dividends on its stock. 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.

     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 natural gas
and oil properties and other tangible assets of the Company.

                                     F1-11
<PAGE>

     In August 1998,  upon the filing of a registration  statement with the SEC,
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  "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 Notes and  common  stock of the  Company
generated  proceeds,  net of offering costs, of approximately $47.5 million that
was used to  repay a  portion  of the  then  outstanding  borrowings  under  the
Company's Credit Facility.

     Principal  outstanding  under the Notes is due at  maturity  on August  20,
2003.  Interest on the Notes is payable  quarterly at rates that vary  depending
upon whether accrued  interest is paid in cash or "in kind" through the issuance
of additional Notes.  Interest is 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 Notes; provided, however, that the Company may
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 Notes.  The Company may repay the Notes in full without  premium at any time
prior to maturity.  The indenture governing the Notes contains certain covenants
including,  but not limited to,  limitations or  restrictions  on  indebtedness,
distributions,   affiliate   transactions,   liens   and  sale   and   leaseback
transactions.  The indenture  prohibits  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 Notes.

     The Notes are fully and unconditionally  guaranteed, on a joint and several
basis, by each of the Company's subsidiaries (the "Subsidiary Guarantors"),  all
of which are directly or indirectly  wholly-owned by the Company.  Additionally,
the stock of certain  subsidiaries  has also been pledged as collateral  for the
Notes.  The  obligations  of the  Subsidiary  Guarantors  under  the  subsidiary
guaranty   agreements  are  subordinated  to  the  senior  indebtedness  of  the
Subsidiary  Guarantors.  The assets of the parent,  Brigham Exploration Company,
consist solely of investments in its subsidiaries.

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

     In March 1999, the indenture governing the Notes was amended to provide the
Company  with the  option  to pay  interest  due on the  Notes in kind,  for any
reason,  through the second quarter of 2000. In addition,  certain financial and
other covenants were amended. The amendment also provides 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 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.

                                     F1-12
<PAGE>



6.    Capital Lease Obligations

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

<TABLE>
<CAPTION>
                                                                                             December 31,
                                                                                     ------------------------------
                                                                                         1999            1998
                                                                                     -------------   --------------
<S>  <C>                                                                             <C>             <C>
     3-D seismic interpretation workstations and software.......................     $        607    $         620
     Office furniture and equipment.............................................              167              167
                                                                                     -------------   --------------
                                                                                              774              787
     Accumulated depreciation and amortization..................................            (410)            (276)
                                                                                     -------------   --------------
                                                                                     $        364    $         511
                                                                                     =============   ==============
</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,  1999  are as  follows  (in
thousands):

     2000......................................................  $         258
     2001......................................................            115
     2002......................................................             27
                                                                 -------------
     Total minimum lease payments..............................            400
        Estimated executory costs included in capital leases...            (25)
                                                                 -------------
     Net minimum lease payments................................            375
        Amounts representing interest..........................            (38)
                                                                 -------------
     Present value of net minimum lease payments...............            337
     Less:  current portion....................................           (210)
                                                                 -------------
     Noncurrent portion........................................  $         127
                                                                 =============

7.   Income Taxes

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

                                                         Year ended
                                                        December 31,
                                                ------------------------------
                                                    1999            1998
                                                -------------   --------------
     Current income taxes:
        Federal...............................        $    -           $    -
        State.................................             -                -
     Deferred income taxes:
        Federal...............................             -           (1,186)
        State.................................             -                -
                                                -------------   --------------
                                                      $    -    $      (1,186)
                                                =============   ==============

                                     F1-13
<PAGE>

         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,
                                               ------------------------------
                                                   1999            1998
                                               -------------   --------------
     Tax at statutory rate...................  $    (7,570)    $     (11,740)
     Add the effect of:
        Nondeductible expenses...............             8               10
        Valuation reserve....................         7,562           10,544
                                               -------------   --------------
                                               $          -    $      (1,186)
                                               =============   ==============

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

                                                           December 31,
                                                   -----------------------------
                                                      1999            1998
                                                   ------------   --------------
     Deferred tax assets:
        Net operating loss carryforwards........   $    18,796    $      11,219
        Amortization of stock compensation......           266              258
        Other...................................            27                3
                                                   ------------   --------------
                                                        19,089           11,480
     Deferred tax liability:
        Depreciable and depletable property.....         (484)             (936)
        Valuation reserve.......................      (18,605)          (10,544)
                                                   ------------   --------------
                                                   $        -     $           -
                                                   ============   ==============

     At December 31, 1999, the Company had regular and  alternative  minimum tax
net  operating  loss  carryforwards  of  approximately  $53.7  million and $45.2
million, respectively, which expire by December 31, 2019.

8.   Net Income (Loss) Per Share

     Net loss per share is presented in the  consolidated  financial  statements
based on a basic loss per share  calculation as well as a diluted loss per share
calculation. Basic loss per share is computed by dividing net loss applicable to
common  shareholders by the weighted average number of common shares outstanding
during each  period.  Diluted  loss per share is  computed by dividing  net loss
applicable  to common  shareholders  by the  weighted  average  number of common
shares and common  share  equivalents  outstanding  (if  dilutive)  during  each
period. The number of common share equivalents outstanding is computed using the
treasury stock method.

     Net loss per share for 1997 is presented giving effect to the shares issued
pursuant  to the  Exchange  as well  as  shares  issued  in the  initial  public
offering.  At  December  31,  1999 and 1998,  options  and  warrants to purchase
3,519,726 and 2,194,654 shares of common stock,  respectively,  were outstanding
but were not included in the  computation of diluted loss per share because they
were anti-dilutive.

9.   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.

                                     F1-14
<PAGE>

     As of  December  31,  1999,  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.

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, 1999, are
as follows (in thousands):

     2000.......................................................   $         795
     2001.......................................................             790
     2002.......................................................             395
                                                                   -------------
                                                                   $       1,980
                                                                   =============

     Rental  expense for the years ended  December 31,  1999,  1998 and 1997 was
$937,669, $875,150 and $606,173, respectively.

Major Customers

     During 1999,  approximately  26%, 16% and 11% of the Company's  natural gas
and  oil  production  was  sold  to  three  separate  customers.   During  1998,
approximately  25%,  15%,  11%  and  11% of the  Company's  natural  gas and oil
production was sold to four separate customers.  During 1997,  approximately 14%
and 12% of the Company's natural gas and oil production was sold to two separate
customers. However, due to the availability of other customers, the Company does
not  believe  that  the  loss of any one of  these  individual  customers  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  natural  gas and oil  could  have a  significant  impact on the
Company's results of operations for any particular year.

10.  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 1997, the Company was a party to a crude oil swap arrangement  resulting
in a fixed price over a period of time for a  specified  volume of crude oil. In
February 1998, the Company entered into a hedging  contract whereby 10,000 MMBtu
per day of natural  gas is  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 exchanges a floating market price for a contract
month and payments are received when the fixed price exceeds the floating price.
Total  natural gas subject to this hedging  contract is 2,750,000  MMBtu in 1998
and 3,040,000 MMBtu in 1999.

                                     F1-15
<PAGE>

     In August 1998, the Company entered into a hedging  contract  whereby 5,000
MMBtu per day of natural gas is 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  exchanges a floating  market price for a fixed
contract  price of $2.015 per MMBtu.  Payments  are made by the Company when the
floating  price  exceeds the fixed price for a contract  month and  payments are
received  when the fixed price  exceeds the floating  price.  Total  natural gas
subject to this hedging contract is 1,070,000 MMBtu in 1999.

     In January  1999,  the Company  entered  into a swap  agreement  with terms
similar to existing  agreements  which relates to production for monthly periods
from November 1999 through April 2001.  Pursuant to these  arrangements,  15,000
MMBtu per day of natural gas is purchased and sold subject to a fixed price swap
agreement,  and the  Company  exchanges  a  floating  market  price  for a fixed
contract  price of $2.065 per MMBtu.  Total natural gas volumes  subject to this
agreement are 915,000 MMBtu,  5,490,000  MMBtu and 1,800,000 MMBtu in 1999, 2000
and 2001, respectively.

     As a  result  of these  arrangements,  the  Company  realized  an  increase
(decrease) in natural gas and oil revenues of approximately $(486,000), $555,000
and  $(6,200)  during  1999,  1998 and 1997,  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  $291,000 as of December  31,
1999.  Additionally,  the  mark-to-market  adjustments  and  related  cash flows
associated with this portion of these contracts of approximately $(429,000) have
been recorded as a component of other income  (expense) on the 1999 statement of
operations.

     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
natural gas and oil revenues over the original  contract  period of October 1999
through  January  2000.  During 1999,  approximately  $645,000 was  amortized to
natural gas and oil revenues.

     Concurrently,  in September  1999 the Company  entered into natural gas and
crude oil cap contracts.  The natural gas cap contract 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, 1999, the fair value of
the remaining  contracts  approximated  $875,000 million with the  corresponding
mark-to-market  adjustments  and related  cash flows  recorded as a component of
other income (expense) on the statement of operations.

     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 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 natural gas and oil sales 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,  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.

                                     F1-16
<PAGE>

11.  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 15%
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
which vest 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  will  determine 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.

                                     F1-17
<PAGE>

         The following  table  summarizes  activity under the incentive plan for
each of the three years ended December 31, 1999:

                                                                      Weighted
                                                                      Average
                                                                      Exercise
                                                       Shares          Price
                                                    -------------   ------------

     Options outstanding December 31, 1996.......              -     $        -
          Options granted........................        646,097           5.03
          Options forfeited or cancelled.........       (17,360)           5.00
          Options exercised......................              -              -
                                                    -------------   ------------
     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.........       (324,928)         (4.68)
          Options exercised......................              -               -
                                                    -------------   ------------
     Options outstanding December 31, 1999.......      1,519,726    $      4.47
                                                    =============   ============

     On December 14, 1998, the Board of Directors  approved a proposal to cancel
and reissue  outstanding  employee  stock  options which 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, 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  years 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 years to 6 years. Options
exercisable at December 31, 1999, 1998 and 1997 were 291,242,  145,740 and zero,
respectively.

     The  weighted  average  fair value per share of stock  compensation  issued
during 1999, 1998 and 1997 was $1.42,  $5.40 and $6.24,  respectively.  The fair
value for these options was  estimated  using the  Black-Scholes  model with the
following  weighted average  assumptions for grants made in 1999, 1998 and 1997:
risk free  interest  rate of 6.0%,  4.7% and 6.2%;  volatility  of the  expected
market  prices  of the  Company's  common  stock of 57%,  77% and 38%;  expected
dividend yield of zero and weighted  average  expected  option lives of 5.6, 5.0
and 7.3 years, respectively.

     The  Black-Scholes  valuation model was developed for use in estimating the
fair  value  of  traded  options  which  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 SFAS No. 123 the Company's net loss and net loss per
share for 1999,  1998 and 1997 would have been the pro forma  amounts  indicated
below:

                                     F1-18
<PAGE>

                                           1999         1998        1997
                                        ------------ ------------ ----------
     Net loss (in thousands):
        As reported..................   $  (21,628)  $  (33,345)  $ (1,117)
        Pro forma....................      (21,605)     (33,591)    (1,314)
     Net loss per share:
        As reported..................        (1.53)       (2.64)     (0.10)
        Pro forma....................        (1.53)       (2.66)     (0.12)

     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  which 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.

12.  Related Party Transactions

     During the years  ended  December  31,  1999,  1998 and 1997,  the  Company
incurred costs of approximately  $180,000,  $851,000 and $837,000  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.

     In 1997, the Company paid $18,000 for working  interests in natural gas and
oil  properties  owned by  affiliates  of a  member  of the  Company's  board of
directors/management committee.

     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  $62,874,  $100,539 and $86,580 for the years ended
December  31,  1999,  1998  and  1997,  respectively.  Additional  disbursements
totaling approximately $12,000,  $12,000 and $13,000 were made during 1999, 1998
and 1997, respectively, for the reimbursement of certain expenses.

13.  Subsequent Event

     In February 2000, the Company  entered into an amended and restated  Credit
Facility with its existing  lenders and a new lender.  This amended and restated
Credit  Facility  provides  the  Company  with an  increase  to $70  million  in
borrowing  availability  for a three-year  term. If the Company  exceeds certain
asset value and interest coverage tests in the second or third quarters of 2000,
the total borrowing  availability under the Credit Facility will increase to $75
million.  Borrowings  under the Credit  Facility  in excess of $45  million  are
convertible into shares of the Company's common stock in the following  amounts:
(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.  If the Credit Facility is repaid
at maturity or is prepaid prior to maturity  without  payment of cash  premiums,
the  Company  must  issue to a new  lender of the Credit  Facility  warrants  to
purchase shares of the Company's  common stock. In addition,  certain  financial
covenants of the Credit  Facility have been amended or added. In connection with
this  most  recent  amendment,  the  Company  reset  the  price of the  warrants
previously  issued to its existing 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.

     In February  2000,  the  indenture  governing  the Notes was  amended.  The
holders of the Notes waived the minimum  consolidated  interest  coverage  ratio
covenant through June 30, 2000 and adjusted  subsequent  levels under this test.
In addition, an amendment to the Notes provides the Company with an extension of
its right to pay interest  through the issuance of  additional  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  are met.  In  exchange  for
granting these  amendments,  the Company has (i) reset the price of the warrants
previously  issued to the holders of the 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 Notes a term overriding royalty
interest  that  provides  for the limited  right to receive 4%, or 3% if certain
conditions  are met,  of the  Company's  net  production  revenue  to reduce any
outstanding Notes issued as interest paid in kind.



                                     F1-19

<PAGE>

14.  Natural Gas and Oil Exploration and Production Activities

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

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

<TABLE>
<CAPTION>
                                                                Year ended December 31,
                                                          -------------------------------------
                                                              1999         1998         1997
                                                          -----------  ------------  ----------
<S>                                                       <C>          <C>           <C>
     Natural gas and oil sales.........................   $   14,992   $    13,799   $   9,184
     Costs and expenses:
        Lease operating................................        2,259         2,172       1,151
        Production taxes...............................          968           850         549
        Depletion of natural gas and oil properties....        7,792         8,483       2,743
        Capitalized ceiling impairment.................            -        25,926           -
        Income tax expense (benefit) (a)...............        1,391        (8,271)       1,318
                                                          -----------  ------------  ----------
     Total costs and expenses..........................       12,410        29,160       5,761
                                                          -----------  ------------  ----------
                                                          $    2,582   $   (15,361)  $   3,423
                                                          ===========  ============  ==========
     Depletion per physical unit of production
        (equivalent Mcf of gas)........................   $     1.24   $      1.27   $    0.88
                                                          ===========  ============  ==========
</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.

     Natural gas and oil 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 natural gas and oil properties relates to capitalized costs
incurred in  acquisition,  exploration and  development  activities.  Results of
operations do not include interest expense and general corporate amounts.


                                     F1-20
<PAGE>

Costs Incurred and Capitalized Costs

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

                                                     December 31,
                                       ----------------------------------------
                                          1999          1998          1997
                                       ------------  ------------  ------------

     Costs incurred for the year:
        Exploration.................   $    19,224   $    68,214   $    29,516
        Property acquisition........         3,462        16,245        26,956
        Development.................         4,632        10,475         2,953
        Proceeds from participants..        (2,439)      (10,502)         (319)
                                       ------------  ------------  ------------
                                       $    24,879   $    84,432   $    59,106
                                       ============  ============  ============

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

                                                     December 31,
                                            ------------------------------
                                                1999            1998
                                            -------------   --------------
Cost of natural gas and oil properties
at year-end:

   Proved.................................  $   140,757     $    128,643
   Unproved...............................       37,998           52,376
                                            -------------   --------------
   Total capitalized costs................      178,755          181,019
   Accumulated depletion..................      (66,689)         (46,702)
                                            -------------   --------------
                                            $   112,066     $    134,317
                                            =============   ==============

     Following is a summary of costs (in  thousands)  excluded from depletion at
December  31, 1999,  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
                          ------------------------------------
                             1999         1998        1997        Years        Total
                          -----------  -----------  ----------  ----------   ----------
<S>                       <C>          <C>          <C>         <C>          <C>
 Property acquisition...  $    1,079   $    6,414   $   5,558   $   1,921    $  14,972
 Exploration............       1,174       12,876       7,404       1,572       23,026
                          -----------  -----------  ----------  ----------   ----------
 Total..................  $    2,253   $   19,290   $  12,962   $   3,493    $  37,998
                          ===========  ===========  ==========  ==========   ==========
</TABLE>

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

     Information  with respect to the  Company's  natural gas and oil  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.



                                     F1-21
<PAGE>

Natural Gas and Oil Reserve Data

     The following tables present the Company's  estimates of its proved natural
gas  and oil  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 natural gas and oil 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 were  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, 1996.............           10,257            1,940
        Revisions to previous estimates...............           (3,044)            (447)
        Extensions, discoveries and other additions...           33,721              735
        Purchase of minerals-in-place.................           13,718            1,244
        Sales of minerals-in-place....................              (40)               -
        Production....................................           (1,382)            (291)
                                                           -------------   --------------
     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 of 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
                                                           =============   ==============
     Proved developed reserves at December 31:

        1997..........................................           30,677            2,665
        1998..........................................           38,571            2,935
        1999..........................................           28,594            1,873
</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 which can be
expected to be recovered  through  existing  wells with  existing  equipment and
operating methods.

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 natural gas and oil reserves.
Future cash flows were  computed by applying  year end prices of natural gas and
oil  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  natural gas and oil
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 natural gas and oil reserves.


                                     F1-22
<PAGE>

<TABLE>
<CAPTION>
                                                                                       December 31,
                                                                         ----------------------------------------
                                                                              1999          1998         1997
                                                                         ------------  ------------  ------------

<S>                                                                      <C>           <C>           <C>
     Future cash inflows..........................................       $   228,429   $   198,082   $   165,156
     Future development and production costs......................          (61,878)      (61,064)      (40,923)
     Future income taxes..........................................          (12,406)       (6,972)      (22,919)
                                                                         ------------  ------------  ------------
     Future net cash inflows......................................       $   154,145   $   130,046   $   101,314
                                                                         ============  ============  ============

     Future net cash inflow before income taxes, discounted
        at 10% per annum..........................................       $   114,466   $    81,741   $    69,249
                                                                         ============  ============  ============

     Standardized measure of future net cash inflows discounted
        at 10% per annum..........................................       $   113,546   $    81,649   $    44,506
                                                                         ============  ============  ============
</TABLE>


     The base sales  prices for the  Company's  reserves  were $2.35 per Mcf for
natural gas and $22.75 per Bbl for oil as of December  31,  1999,  $2.12 per Mcf
for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.27 per
Mcf for natural gas and $15.50 per Bbl for oil as of December  31,  1997.  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.

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

<TABLE>
<CAPTION>
                                                                                       December 31,
                                                                         ----------------------------------------
                                                                            1999          1998          1997
                                                                         ------------  ------------  ------------

<S>                                                                      <C>               <C>           <C>
     Beginning of period.............................................    $   81,649    $   64,274    $   44,506
        Sales of natural gas and oil produced, net of production
             costs...................................................       (11,765)      (10,776)       (7,484)
        Development costs incurred...................................         4,413         5,423         1,955
        Extensions and discoveries...................................        43,346        52,389        38,016
        Purchases of minerals-in-place...............................             -           687        16,965
        Sales of minerals-in-place...................................       (32,783)            -           (94)
        Net change of prices and production costs....................        33,226       (11,921)      (20,466)
        Change in future development costs...........................          (555)         (656)           319
        Changes in production rates and other........................           637        (6,109)        (1,954)
        Revisions of quantity estimates..............................       (11,969)      (23,470)        (6,964)
        Accretion of discount........................................         8,174         6,925          4,450
        Change in income taxes.......................................          (827)        4,883         (4,975)
                                                                         ------------  ------------  ------------
     End of period...................................................    $  113,546    $   81,649    $    64,274
                                                                         ============  ============  ============
</TABLE>


                                     F1-23
<PAGE>

16.  Quarterly Financial Data (Unaudited)

     The Company has restated  previously  reported quarterly  financial results
for the nine months  ended  September  30, 1999 and the year ended  December 31,
1998  to  give  effect  to  the   capitalization  of  interest  for  significant
acquisition,  exploration and development  activities in progress.  There was no
effect on the year ended  December  31,  1998 net loss or on the 1997  financial
results.  The effect of this  restatement  on the  statement of operations is as
follows (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                                 Year Ended December 31, 1999
                                    ------------------------------------------------------------------------------------
                                             Quarter 1              Quarter 2              Quarter 3          Quarter 4
                                    ------------------------ ---------------------- ------------------------ -----------
                                       Previously     As      Previously      As     Previously      As
                                        Reported   Restated    Reported    Restated   Reported    Restated
                                    ------------- ----------- ----------- ---------- ----------- -----------

<S>                                    <C>         <C>          <C>        <C>         <C>        <C>           <C>
Revenue...........................     $   3,281   $   3,281    $  3,626   $  3,624    $ 4,195    $ 4,238     $ 4,134
Operating income (loss)...........           124         113         245        190       (379)      (432)        380
Net loss..........................        (2,669)     (1,944)    (15,034)   (14,839)    (3,589)    (2,651)     (2,194)
Net loss per share:
     Basic/Diluted................         (0.20)      (0.15)      (1.05)     (1.04)     (0.25)     (0.18)      (0.15)
</TABLE>



<TABLE>
<CAPTION>
                                                          Year Ended December 31, 1998
                        -----------------------------------------------------------------------------------------------
                                 Quarter 1              Quarter 2              Quarter 3              Quarter 4
                        -----------------------------------------------------------------------------------------------
                          Previously      As      Previously     As      Previously     As      Previously      As
                           Reported    Restated    Reported   Restated    Reported   Restated    Reported    Restated
                        ------------- ---------- ----------- ----------- ----------- ---------- ----------- -----------

<S>                       <C>            <C>        <C>         <C>        <C>         <C>      <C>         <C>
Revenue.................. $  3,257    $  3,257    $ 4,120     $ 4,120    $ 4,237     $ 4,237   $   2,575   $  2,575
Operating income (loss)..       31          27        427         413        481         466     (28,486)   (29,605)
Net loss.................     (632)       (460)      (627)       (461)      (964)       (777)    (31,122)   (31,647)
Net loss per share:
     Basic/Diluted.......    (0.05)      (0.04)     (0.05)      (0.04)     (0.08)      (0.06)      (2.34)     (2.34)
</TABLE>


                                     F1-24
<PAGE>

                        REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors
and Stockholders of Brigham Exploration Company

In our opinion,  the accompanying  balance sheets and the related  statements of
operations,  of  changes  in equity  and of cash  flows,  present  fairly in all
material  respects,  the  financial  position  of Brigham Oil & Gas,  L.P.,  and
Brigham, Inc. at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three  years in the period  ended  December
31, 1999, in conformity with  accounting  principles  generally  accepted in the
United States. Additionally, in our opinion, the accompanying balance sheets and
the related  statements  of  operations,  of changes in equity and of cash flows
present  fairly,  in all material  respects,  the financial  position of Brigham
Holdings I, LLC and Brigham  Holdings  II, LLC at December 31, 1999 and 1998 and
for the two years then ended, in conformity with accounting principles generally
accepted in the United States. 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,  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 the opinion expressed above.

PricewaterhouseCoopers LLP

Dallas, Texas
March 7, 2000

                                      F2-1
<PAGE>
                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                                 BALANCE SHEETS
                             As of December 31, 1999
                                 (in thousands)

<TABLE>
<CAPTION>
                                                          Brigham                               Brigham           Brigham
                                                           Oil &            Brigham,            Holdings         Holdings
                                                         Gas, L.P.            Inc.               I, LLC           II, LLC

                                                                  ASSETS

Current assets:
<S>                                                  <C>                 <C>                <C>              <C>
     Cash and cash equivalents                       $         2,718     $         2,736    $           6    $            6
     Accounts receivable                                       4,945               4,945                -                 -
     Other current assets                                        577                 577                -                 -
                                                     ----------------    ----------------   --------------   ---------------
        Total current assets                                   8,240               8,258                6                 6
                                                     ----------------    ----------------   --------------   ---------------

Natural gas and oil properties, at cost, net                 112,066             112,066                -                 -
Other property and equipment, at cost, net                     1,686               1,686                -                 -
Investment in subsidiaries
     and intercompany advances                                   130                  26            1,299            47,802
Drilling advances paid                                            23                  23                -                 -
Deferred loan fees                                             2,108               2,108                -                 -
Other noncurrent assets                                          164                 164                -                 -
                                                     ----------------    ----------------   --------------   ---------------
                                                     $       124,417     $       124,331    $       1,305    $       47,808
                                                     ================    ================   ==============   ===============

                                                     LIABILITIES AND EQUITY

Current liabilities:
     Accounts payable                                $        14,851     $        14,851    $           -    $            -
     Accrued drilling costs                                      541                 541                -                 -
     Participant advances received                               850                 850                -                 -
     Other current liabilities                                 1,429               1,429                -                 -
                                                     ----------------    ----------------   --------------   ---------------
        Total current liabilities                             17,671              17,671                -                 -
                                                     ----------------    ----------------   --------------   ---------------

Notes payable                                                 56,000              56,000                -                 -
Other noncurrent liabilities                                   1,600               1,600                -                 -
Intercompany accounts payable                                  1,752               1,687                -             1,779
Intercompany notes payable                                    45,459              45,459                -            45,459

Commitments and contingencies

Minority interest                                                  -               1,325                -                 -

Equity

     Partners' capital                                         1,935                   -            1,305               570
     Common stock, $1.00 par value, 1,000
        shares authorized, issued and
        outstanding                                                -                   1                -                 -
     Additional paid-in capital                                    -              17,832                -                 -
     Accumulated deficit                                           -             (17,244)               -                 -
                                                     ----------------    ----------------   --------------   ---------------
        Total equity                                           1,935                 589            1,305               570
                                                     ----------------    ----------------   --------------   ---------------
                                                     $       124,417     $       124,331    $       1,305    $       47,808
                                                     ================    ================   ==============   ===============
</TABLE>


  Natural gas and oil properties are accounted for using the full cost method.

               See accompanying notes to the financial statements.

                                      F2-2
<PAGE>

                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
                                 BALANCE SHEETS
                             As of December 31, 1998
                                 (in thousands)

<TABLE>
<CAPTION>
                                                          Brigham                               Brigham           Brigham
                                                           Oil &            Brigham,            Holdings         Holdings
                                                         Gas, L.P.            Inc.               I, LLC           II, LLC

                                                                  ASSETS

Current assets:
<S>                                                  <C>                 <C>                <C>             <C>
     Cash and cash equivalents                       $         2,549     $         2,563    $          5    $            6
     Accounts receivable                                       7,938               7,938               -                 -
     Other current assets                                        290                 290               -                 -
                                                     ----------------    ----------------   -------------   ---------------
        Total current assets                                  10,777              10,791               5                 6
                                                     ----------------    ----------------   -------------   ---------------

Natural gas and oil properties, at cost, net                 134,317             134,317               -                 -
Other property and equipment, at cost, net                     2,014               2,014               -                 -
Investment in subsidiaries
     and intercompany advances                                   115                  16          11,714            46,913
Drilling advances paid                                           231                 231               -                 -
Deferred loan fees                                             1,397               1,397               -                 -
Other noncurrent assets                                           12                  12               -                 -
                                                     ----------------    ----------------   -------------   ---------------
                                                     $       148,863     $       148,778    $     11,719    $       46,919
                                                     ================    ================   =============   ===============

                                                     LIABILITIES AND EQUITY

Current liabilities:
     Accounts payable                                $        19,883     $        19,883    $          -    $            -
     Accrued drilling costs                                    1,219               1,219               -                 -
     Participant advances received                               764                 764               -                 -
     Other current liabilities                                 1,647               1,647               -                 -
                                                     ----------------    ----------------   -------------   ---------------
        Total current liabilities                             23,513              23,513               -                 -
                                                     ----------------    ----------------   -------------   ---------------

Notes payable                                                 59,000              59,000                -                 -
Other noncurrent liabilities                                   7,536               7,536                -                 -
Intercompany accounts payable                                  1,690               1,616                -             1,707
Intercompany notes payable                                    40,000              40,000                -            40,000

Commitments and contingencies

Minority interest                                                  -              11,730                -                 -

Equity

     Partners' capital                                        17,124                   -           11,719             5,212
     Common stock, $1.00 par value, 1,000
        shares authorized, issued and
        outstanding                                                -                   1                -                 -
     Additional paid-in capital                                    -              16,109                -                 -
     Accumulated deficit                                           -             (10,727)               -                 -
                                                     ----------------    ----------------   --------------   ---------------
        Total equity                                          17,124               5,383           11,719             5,212
                                                     ----------------    ----------------   --------------   ---------------
                                                     $       148,863     $       148,778    $      11,719    $       46,919
                                                     ================    ================   ==============   ===============
</TABLE>


  Natural gas and oil properties are accounted for using the full cost method.

               See accompanying notes to the financial statements.

                                      F2-3

<PAGE>


                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                            STATEMENTS OF OPERATIONS
                      For the Year Ended December 31, 1999
                                 (in thousands)

<TABLE>
<CAPTION>
                                                              Brigham                           Brigham             Brigham
                                                               Oil &          Brigham,          Holdings           Holdings
                                                             Gas, L.P.          Inc.             I, LLC             II, LLC
Revenues:
<S>                                                        <C>              <C>             <C>               <C>
     Natural gas and oil sales                             $     14,992     $     14,992    $           -     $           -
     Workstation revenue                                            285              285                -                 -
                                                           -------------    -------------   --------------    --------------
                                                                 15,277           15,277                -                 -
                                                           -------------    -------------   --------------    --------------
Costs and expenses:
     Lease operating                                              2,259            2,259                -                 -
     Production taxes                                               968              968                -                 -
     General and administrative                                   3,462            3,472                9                 9
     Depletion of natural gas and oil properties                  7,792            7,792                -                 -
     Depreciation and amortization                                  525              525                -                 -
     Amortization of stock compensation                               1                1                -                 -
                                                           -------------    -------------   --------------    --------------
                                                                 15,007           15,017                9                 9
                                                           -------------    -------------   --------------    --------------
        Operating income (loss)                                     270              260               (9)               (9)
                                                           -------------    -------------   --------------    --------------

Other income (expense):
     Interest income                                                176              176                -                 -
     Interest expense, net                                       (3,214)          (3,214)               -                 -
     Interest expense - intercompany                             (5,532)          (5,532)               -            (5,532)
     Loss on sale of natural gas and
        oil properties                                          (12,195)         (12,195)               -                 -
     Other expense                                                 (163)            (163)               -                 -
                                                           -------------    -------------   --------------    --------------
                                                                (20,928)         (20,928)               -            (5,532)
                                                           -------------    -------------   --------------    --------------

Minority interest in net loss                                         -          (14,151)               -                 -

                                                           -------------    -------------   --------------    --------------
Net loss before income taxes                                    (20,658)          (6,517)              (9)           (5,541)

Income tax benefit                                                    -                -                -                 -
Equity in net loss of investee                                        -                -          (14,151)             (769)
                                                           -------------    -------------   --------------    --------------
     Net loss                                              $    (20,658)    $     (6,517)   $     (14,160)    $      (6,310)
                                                           =============    =============   ==============    ==============
</TABLE>





               See accompanying notes to the financial statements.

                                      F2-4

<PAGE>


                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                            STATEMENTS OF OPERATIONS
                      For the Year Ended December 31, 1998
                                 (in thousands)

<TABLE>
<CAPTION>
                                                              Brigham                           Brigham           Brigham
                                                               Oil &          Brigham,          Holdings         Holdings
                                                             Gas, L.P.          Inc.             I, LLC           II, LLC
Revenues:
<S>                                                        <C>              <C>             <C>               <C>
     Natural gas and oil sales                             $     13,799     $     13,799    $           -     $           -
     Workstation revenue                                            390              390                -                 -
                                                           -------------    -------------   --------------    --------------
                                                                 14,189           14,189                -                 -
                                                           -------------    -------------   --------------    --------------
Costs and expenses:
     Lease operating                                              2,172            2,172                -                 -
     Production taxes                                               850              850                -                 -
     General and administrative                                   4,650            4,661               11                11
     Depletion of natural gas and oil properties                  8,483            8,483                -                 -
     Depreciation and amortization                                  413              413                -                 -
     Capitalized ceiling impairment                              25,926           25,926                -                 -
     Amortization of stock compensation                             372              372                -                 -
                                                           -------------    -------------   --------------    --------------
                                                                 42,866           42,877               11                11
                                                           -------------    -------------   --------------    --------------
        Operating loss                                          (28,677)         (28,688)             (11)              (11)
                                                           -------------    -------------   --------------    --------------

Other income (expense):
     Interest income                                                136              136                -                 -
     Interest expense, net                                       (3,841)          (3,841)               -                 -
     Interest expense - intercompany                             (1,707)          (1,707)               -            (1,707)
                                                           -------------    -------------   --------------    --------------
                                                                 (5,412)          (5,412)               -            (1,707)
                                                           -------------    -------------   --------------    --------------

Minority interest in net loss                                         -          (23,351)               -                 -

                                                           -------------    -------------   --------------    --------------
Net loss before income taxes                                    (34,089)         (10,749)             (11)           (1,718)

Income tax benefit                                                    -            5,088                -                 -
Equity in net loss of investee                                        -                -          (23,351)           (8,690)
                                                           -------------    -------------   --------------    --------------
     Net loss                                              $    (34,089)    $     (5,661)   $     (23,362)    $     (10,408)
                                                           =============    =============   ==============    ==============
</TABLE>







               See accompanying notes to the financial statements.


                                      F2-5
<PAGE>


                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                            STATEMENTS OF OPERATIONS
                      For the Year Ended December 31, 1997
                                 (in thousands)

<TABLE>
<CAPTION>
                                                                                                Brigham
                                                                                                 Oil &            Brigham,
                                                                                               Gas, L.P.            Inc.
Revenues:
<S>                                                                                         <C>               <C>
     Natural gas and oil sales                                                              $       9,184     $        9,184
     Workstation revenue                                                                              637                637
                                                                                            --------------    ---------------
                                                                                                    9,821              9,821
                                                                                            --------------    ---------------
Costs and expenses:
     Lease operating                                                                                1,151              1,151
     Production taxes                                                                                 549                549
     General and administrative                                                                     3,570              3,570
     Depletion of natural gas and oil properties                                                    2,743              2,743
     Depreciation and amortization                                                                    306                306
     Amortization of stock compensation                                                               388                388
                                                                                            --------------    ---------------
                                                                                                    8,707              8,707
                                                                                            --------------    ---------------
        Operating income                                                                            1,114              1,114
                                                                                            --------------    ---------------

Other income (expense):
     Interest income                                                                                  145                145
     Interest expense, net                                                                         (1,017)            (1,017)
     Interest expense - related party                                                                (173)              (173)
                                                                                            --------------    ---------------
                                                                                                   (1,045)            (1,045)
                                                                                            --------------    ---------------

Minority interest in net income                                                                         -                 47
                                                                                            --------------    ---------------
Net income before income taxes                                                                         69                 22

Income tax expense                                                                                      -             (5,088)
                                                                                            --------------    ---------------
     Net income (loss)                                                                      $          69     $       (5,066)
                                                                                            ==============    ==============
</TABLE>









               See accompanying notes to the financial statements.

                                      F2-6

<PAGE>
                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                         STATEMENTS OF CHANGES IN EQUITY
                          (in thousands, except shares)

<TABLE>
<CAPTION>
                                                                 Retained
                                                Additional       Earnings/
                             Common Stock         Paid-in       Accumulated      Partners'
                         ---------------------
                          Shares       Amounts    Capital         Deficit         Capital          Total
                         ---------    ----------------------   --------------  --------------  --------------

Brigham Oil & Gas, L.P.
     Balance,
<S>                      <C>        <C>         <C>            <C>             <C>             <C>
       December 31, 1998        -   $       -   $         -    $           -   $      17,124   $      17,124
     Capital contribution       -           -             -                -           5,469           5,469
     Net loss                   -           -             -                          (20,658)        (20,658)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1999        -   $       -   $         -    $           -   $       1,935   $       1,935
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Inc.
     Balance,
       December 31, 1998    1,000   $       1   $    16,109    $     (10,727)  $           -   $       5,383
     Capital contribution       -           -         1,723                -               -           1,723
     Net loss                   -           -             -           (6,517)              -          (6,517)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1999    1,000   $       1   $    17,832    $     (17,244)  $           -   $         589
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Holding I, LLC
     Balance,
       December 31, 1998        -   $       -   $         -    $           -   $      11,719   $      11,719
     Capital contribution       -           -             -                -           3,746           3,746
     Net loss                   -           -             -                -         (14,160)        (14,160)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1999        -   $       -   $         -    $           -   $       1,305   $       1,305
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Holdings II, LLC
     Balance,
       December 31, 1998        -   $       -   $         -    $           -   $       5,212   $       5,212
     Capital contribution       -           -             -                -           1,668           1,668
     Net loss                   -           -             -                -          (6,310)         (6,310)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1999        -   $       -   $         -    $           -   $         570   $         570
                         =========  ==========  ============   ==============  ==============  ==============
</TABLE>

               See accompanying notes to the financial statements.

                                      F2-7

<PAGE>

                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                         STATEMENTS OF CHANGES IN EQUITY
                          (in thousands, except shares)

<TABLE>
<CAPTION>
                                                                 Retained
                                                Additional       Earnings/
                             Common Stock         Paid-in       Accumulated      Partners'
                         ---------------------
                          Shares       Amounts    Capital         Deficit         Capital          Total
                         ---------    ----------------------   --------------  --------------  --------------

Brigham Oil & Gas, L.P.
     Balance,
<S>                       <C>       <C>         <C>            <C>             <C>             <C>
       December 31, 1997        -   $       -   $         -    $           -   $      43,665   $      43,665
     Capital contribution       -           -             -                -           7,548           7,548
     Net loss                   -           -             -                          (34,089)        (34,089)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1998        -   $       -   $         -    $           -   $      17,124   $      17,124
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Inc.
     Balance,
       December 31, 1997    1,000   $       1   $    13,732    $      (5,066)  $           -   $       8,667
     Capital contribution       -           -         2,377                -               -           2,377
     Net loss                   -           -             -           (5,661)              -          (5,661)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1998    1,000   $       1   $    16,109    $     (10,727)  $           -   $       5,383
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Holding I, LLC
     Balance,
       December 31, 1997        -   $       -   $         -    $           -   $           -   $           -
     Partnership interest
       contributed              -           -             -                -          29,911          29,911
     Capital contribution       -           -             -                -           5,170           5,170
     Net loss                   -           -             -                -         (23,362)        (23,362)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1998        -   $       -   $         -    $           -   $      11,719   $      11,719
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Holdings II, LLC
     Balance,
       December 31, 1997        -   $       -   $         -    $           -   $           -   $           -
     Partnership interest
       contributed              -           -             -                -          13,318          13,318
     Capital contribution       -           -             -                -           2,302           2,302
     Net loss                   -           -             -                -         (10,408)        (10,408)
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1998        -   $       -   $         -    $           -   $       5,212   $       5,212
                         =========  ==========  ============   ==============  ==============  ==============
</TABLE>


               See accompanying notes to the financial statements.

                                      F2-8


<PAGE>

                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                         STATEMENTS OF CHANGES IN EQUITY
                                 (in thousands)

<TABLE>
<CAPTION>
                                                                 Retained
                                                Additional       Earnings/
                             Common Stock         Paid-in       Accumulated      Partners'
                         ---------------------
                          Shares       Amounts    Capital         Deficit         Capital          Total
                         ---------    ----------------------   --------------  --------------  --------------

Brigham Oil & Gas, L.P.
  Balance,
<S>                         <C>      <C>         <C>            <C>             <C>             <C>
   December 31, 1996             -   $       -   $         -    $           -   $       3,244   $       3,244
 Capital contribution from
   Brigham Exploration
   Company at consummation
     of Exchange                 -           -             -                -          16,425          16,425
 Capital contribution from
   Brigham Exploration
   Company of proceeds
     from Offering               -           -             -                -          23,927          23,927
   Net income                    -           -             -                -              69              69
                         ---------  ----------  ------------   --------------  --------------  --------------
     Balance,
       December 31, 1997        -   $       -   $         -    $           -   $      43,665   $      43,665
                         =========  ==========  ============   ==============  ==============  ==============

Brigham Inc.
  Balance,
    December 31, 1996       1,000   $       1   $        29    $           -   $           -   $          30
  Increase in equity due to
    change in ownership in
    the Partnership resulting
    from the Exchange and
       the Offering             -           -        13,703                -               -          13,703
  Net loss                      -           -             -           (5,066)              -          (5,066)
                         ---------  ----------  ------------   --------------  --------------  --------------
  Balance,
    December 31, 1997       1,000   $       1   $    13,732    $      (5,066)  $           -   $       8,667
                         =========  ==========  ============   ==============  ==============  ==============
</TABLE>


               See accompanying notes to the financial statements.

                                      F2-9

<PAGE>
                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                            STATEMENTS OF CASH FLOWS
                      For the Year Ended December 31, 1999
                                 (in thousands)
<TABLE>
<CAPTION>

                                                                        Brigham                            Brigham         Brigham
                                                                         Oil &           Brigham,          Holdings        Holdings
                                                                       Gas, L.P.           Inc.            I, LLC          II, LLC
<S>                                                                      <C>               <C>                <C>            <C>

Cash flows from operating activities:

 Net loss                                                           $   (20,658)     $     (6,517)  $    (14,160)  $       (6,310)
 Adjustments to reconcile net loss to cash
  provided by operating activities:

   Depletion of natural gas and oil properties                            7,792             7,792              -                -
   Depreciation and amortization                                            525               525              -                -
   Amortization of stock compensation                                         1                 1              -                -
   Amortization of deferred loan fees and debt issuance costs             1,363             1,363              -                -
   Amortization of deferred loss on derivatives instruments                 759               759              -                -
   Market value adjustment for derivatives instruments                      115               115              -                -
   Loss on sale of natural gas and oil properties                        12,195            12,195              -                -
   Minority interest in net loss                                              -           (14,151)             -                -
   Equity in net loss of investee                                             -                 -         14,151              769
   Changes in working capital and other items:

     Decrease in accounts receivable                                      2,993             2,993              -                -
     Increase in other current assets                                    (1,046)           (1,046)             -                -
     Decrease in accounts payable                                        (1,136)           (1,136)             -                -
     Increase in participant advances received                               86                86              -                -
     Decrease in other current liabilities                                 (188)             (188)             -                -
     Increase in intercompany accounts payable                               65                74              -               72
     Other noncurrent assets                                               (151)             (151)             -                -
     Other noncurrent liabilities                                        (5,585)           (5,585)             -                -
                                                                    ------------     -------------  -------------  ---------------
                                                                         (2,870)           (2,871)            (9)          (5,469)
                                                                    ------------     -------------  -------------  ---------------
Cash flows from investing activities:

 Natural gas and oil properties                                         (25,560)          (25,560)             -                -
 Proceeds from sale of natural gas and oil properties                    27,143            27,143              -                -
 Other property and equipment                                              (146)             (146)             -                -
 Investment in subsidiaries and intercompany advances                       (15)              (10)            10               10
 Change in drilling advances paid                                           207               207              -                -
                                                                    ------------     -------------  -------------  ---------------
                                                                          1,629             1,634             10               10
                                                                    ------------     -------------  -------------  ---------------
Cash flows from financing activities:

 Increase in notes payable                                               13,750            13,750              -                -
 Repayment of notes payable                                             (16,750)          (16,750)             -                -
 Increase in intercompany notes payable                                   5,459             5,459              -            5,459
 Principal payments on capital lease obligations                           (253)             (253)             -                -
 Deferred loan fees paid                                                   (796)             (796)             -                -
                                                                    ------------     -------------  -------------  ---------------
                                                                          1,410             1,410              -            5,459
                                                                    ------------     -------------  -------------  ---------------

Net increase in cash and cash equivalents                                   169               173              1                -
Cash and cash equivalents, beginning of year                              2,549             2,563              5                6
                                                                    ------------     -------------  -------------  ---------------
Cash and cash equivalents, end of year                              $     2,718      $      2,736   $          6   $            6
                                                                    ============     =============  =============  ===============

Supplemental disclosure of cash flow information:

     Cash paid during the year for interest                         $     1,960      $      1,960   $          -   $            -
Supplemental disclosure of noncash investing and
    financing activities:

     Capital lease asset additions                                  $        51      $         51   $          -   $            -
     Increase in accounts payable for deferred loan fees to be
       paid on future periods                                       $        50      $         50   $          -   $            -
     Capital contributions received in exchange for accounts
       payable and other noncurrent liabilities                     $     5,469      $          -   $          -   $            -
     Intercompany capital contributions                             $         -      $      1,723   $      3,746   $        1,668

               See accompanying notes to the financial statements.
</TABLE>


                                      F2-10
<PAGE>

                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                            STATEMENTS OF CASH FLOWS
                      For the Year Ended December 31, 1998
                                 (in thousands)
<TABLE>
<CAPTION>

                                                                  Brigham                               Brigham        Brigham
                                                                   Oil &                  Brigham,      Holdings      Holdings
                                                                 Gas, L.P.                  Inc.         I, LLC        II, LLC
<S>                                                                 <C>                      <C>           <C>            <C>

Cash flows from operating activities:

 Net loss                                                      $    (34,089)        $     (5,661)  $      (23,362)  $   (10,408)
 Adjustments to reconcile net loss to cash
  provided by operating activities:

   Depletion of natural gas and oil properties                        8,483                8,483                -             -
   Depreciation and amortization                                        413                  413                -             -
   Capitalized ceiling impairment                                    25,926               25,926                -             -
   Amortization of stock compensation                                   372                  372                -             -
   Amortization of deferred loan fees and debt issuance costs           593                  593                -             -
   Minority interest in net loss                                          -              (23,351)               -             -
   Equity in net loss of investee                                         -                    -           23,351         8,690
   Changes in working capital and other items:

     Increase in accounts receivable                                 (3,029)              (3,029)               -             -
     Increase in prepaid expenses                                       (10)                 (10)               -             -
     Increase in accounts payable                                     7,991                7,991                -             -
     Increase in participant advances received                          275                  275                -             -
     Increase in other current liabilities                              862                  862                -             -
     Decrease in deferred income tax liability                            -               (5,088)               -             -
     Increase in intercompany accounts payable                            -                    -                -         1,707
     Other noncurrent assets                                              6                    6                -             -
     Other noncurrent liabilities                                     7,004                7,004                -             -
                                                               -------------        -------------  ---------------  ------------
                                                                     14,797               14,786              (11)          (11)
                                                               -------------        -------------  ---------------  ------------
Cash flows from investing activities:

 Natural gas and oil properties                                     (85,208)             (85,208)               -             -
 Other property and equipment                                          (868)                (868)               -             -
 Investment in subsidiaries and intercompany advances                   (42)                 (17)          (5,154)      (42,285)
 Change in drilling advances paid                                      (153)                (153)               -             -
                                                               -------------        -------------  ---------------  ------------
                                                                    (86,271)             (86,246)          (5,154)      (42,285)
                                                               -------------        -------------  ---------------  ------------
Cash flows from financing activities:

 Capital contribution received                                        7,548                7,548            5,170         2,302
 Increase in intercompany notes payable                              40,000               40,000                -        40,000
 Increase in notes payable                                          105,800              105,800                -             -
 Repayment of notes payable                                         (78,800)             (78,800)               -             -
 Principal payments on capital lease obligations                       (236)                (236)               -             -
 Deferred loan fees                                                  (1,990)              (1,990)               -             -
                                                               -------------        -------------  ---------------  ------------
                                                                     72,322               72,322            5,170        42,302
                                                               -------------        -------------  ---------------  ------------

Net increase in cash and cash equivalents                               848                  862                5             6

Cash and cash equivalents, beginning of year                          1,701                1,701                -             -
                                                               -------------        -------------  ---------------  ------------
Cash and cash equivalents, end of year                         $      2,549         $      2,563   $            5   $         6
                                                               =============        =============  ===============  ============

Supplemental disclosure of cash flow information:

  Cash paid during the year for interest                       $      4,878         $      4,878   $            -   $         -

Supplemental disclosure of noncash investing
  and financing activities:

     Capital lease asset additions                             $        320         $        320   $            -   $         -
     Intercompany capital contributions                        $          -         $          -   $       29,911   $    13,318

</TABLE>


               See accompanying notes to the financial statements.

                                      F2-11
<PAGE>


                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                            STATEMENTS OF CASH FLOWS
                      For the Year Ended December 31, 1997
                                 (in thousands)
<TABLE>
<CAPTION>

                                                                       Brigham
                                                                        Oil &          Brigham,
                                                                      Gas, L.P.          Inc.
<S>                                                                       <C>             <C>

Cash flows from operating activities:

     Net income (loss)                                              $       69   $      (5,066)
     Adjustments to reconcile net income (loss) to cash
      provided by operating activities:

       Depletion of natural gas and oil properties                       2,743           2,743
       Depreciation and amortization                                       306             306
       Amortization of stock compensation                                  388             388
       Minority interest in net income                                       -              47
       Changes in working capital and other items:

         Increase in accounts receivable                                (2,213)         (2,213)
         Increase in prepaid expenses                                     (128)           (128)
         Increase in accounts payable                                    8,955           8,955
         Decrease in participant advances received                        (648)           (648)
         Increase in other current liabilities                              50              50
         Increase in deferred interest payable - related party              53              53
         Increase in deferred income tax liability                           -           5,088
         Other noncurrent assets                                           281             281
         Other noncurrent liabilities                                      (50)            (50)
                                                                    -----------  --------------
                                                                         9,806           9,806
                                                                    -----------  --------------
Cash flows from investing activities:

     Natural gas and oil properties                                    (57,170)        (57,170)
     Proceeds from the sale of natural gas and oil properties               74              74
     Other property and equipment                                         (545)           (545)
     Change in drilling advances paid                                      341             341
                                                                    -----------  --------------
                                                                       (57,300)        (57,300)
                                                                    -----------  --------------
Cash flows from financing activities:

     Capital contribution received                                      23,927          23,927
     Increase in notes payable                                          37,250          37,250
     Repayment of notes payable                                        (13,250)        (13,250)
     Principal payments on capital lease obligations                      (179)           (179)
                                                                    -----------  --------------
                                                                        47,748          47,748
                                                                    -----------  --------------

Net increase in cash and cash equivalents                                  254             254

Cash and cash equivalents, beginning of year                             1,447           1,447
                                                                    -----------  --------------
Cash and cash equivalents, end of year                              $    1,701   $       1,701
                                                                    ===========  ==============

Supplemental disclosure of cash flow information:

     Cash paid during the year for interest                         $    1,679   $       1,679

Supplemental disclosure of noncash investing and
  financing activities:

     Capital lease asset additions                                  $      403   $         403
     Intercompany capital contributions                             $   16,425   $           -
     Increase resulting from the Exchange and the Offering
       in ownership interest in the Partnership                     $        -   $      13,703
</TABLE>



               See accompanying notes to the financial statements.

                                      F2-12

<PAGE>

                    BRIGHAM EXPLORATION COMPANY SUBSIDIARIES

                       NOTES TO THE FINANCIAL STATEMENTS

1.   Organization and Background

     In August 1998,  upon the filing of a registration  statement with the SEC,
Brigham Exploration Company, a Delaware corporation,  (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   "Notes").   The   Notes  are  fully  and
unconditionally  guaranteed,  on a  joint  and  several  basis,  by  each of the
Company's directly or indirectly wholly-owned subsidiaries which are Brigham Oil
& Gas, L.P. (the "Partnership"), Brigham Inc., Brigham Holdings I LLC ("Holdings
I"),  and  Brigham   Holdings  II  LLC  ("Holdings  II").   Furthermore,   these
subsidiaries  have pledged their respective  stock and partnership  interests as
collateral  for the Notes.  These  financial  statements  include the  financial
statements for the wholly owned  subsidiaries  whose  securities and partnership
interests comprise substantially all of the collateral pledged for the Notes.

     The  Partnership  was formed in May 1992 to  explore  and  develop  onshore
domestic  natural gas and oil  properties  using 3-D  seismic  imaging and other
advanced  technologies.  Since its inception,  the  Partnership  has focused its
exploration and development of natural gas and oil properties  primarily in West
Texas, the Anadarko Basin and the onshore Gulf Coast.  Brigham, Inc. is a Nevada
corporation  whose  only  asset  prior  to the  Exchange  was its  less  than 1%
ownership  interest in the  Partnership.  Brigham,  Inc. is the managing general
partner of the Partnership.

     On February 25, 1997,  the Company was formed for the purpose of exchanging
its common  stock for the common  stock of  Brigham,  Inc.  and the  partnership
interests of the Partnership.

     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.  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.  As a result of
the Exchange and the Offering,  the Company owns a 68.5% partnership interest in
the Partnership and all of the outstanding shares of Brigham, Inc. Brigham, Inc.
owns the remainder of the Partnership interest in the Partnership.  The proceeds
of the Offering were contributed to the Partnership by the Company.

     Subsequent  to the Exchange  and the  Offering,  the Company  owned a 68.5%
interest in the  Partnership  and Brigham,  Inc. owned a 31.50%  interest in the
Partnership.  Effective January 1, 1998, Brigham,  Inc. contributed 30.5% of its
31.5% interest in the  Partnership to Holdings II, a newly formed Nevada LLC and
wholly owned subsidiary of Brigham,  Inc., whose only asset is its investment in
the  Partnership.  Also effective  January 1, 1998 the Company  contributed  its
68.5% interest in the  Partnership to Brigham  Holdings I, a newly formed Nevada
LLC  and  wholly  owned  subsidiary  of the  Company  whose  only  asset  is its
investment in the Partnership.

                                     F2-13
<PAGE>

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
Partnership, Brigham, Inc., Holdings I and Holdings II (collectively referred to
as the "Subsidiaries"). Holdings II accounts for its interest in the Partnership
under the  equity  method.  Brigham,  Inc.  consolidates  its  interests  in the
Partnership and Holdings II as a result of its general  partner  interest in the
Partnership  and its 100% ownership of Holdings II.  Holdings I accounts for its
68.5% investment in the Partnership under the equity method and its ownership in
the  Partnership  is  reflected  as the  minority  interest in the  consolidated
results of  Brigham,  Inc.  All  entities  are  either  directly  or  indirectly
wholly-owned  subsidiaries of the Company. All significant intercompany accounts
and transactions have been eliminated.

     Substantially  all  of  the  Subsidiaries'  assets  are  held  by  and  all
operations   conducted  through  the  Partnership  and  its  subsidiaries.   All
references in these  financial  statements to assets held by the Partnership and
transactions  entered into by the  Partnership  are applicable to Brigham,  Inc.
through its consolidation of the Partnership.

Cash and Cash Equivalents

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

Property and Equipment

     All natural gas and oil properties are held by the  Partnership  which uses
the full cost method of  accounting  for its  investment  in natural gas and oil
properties.  Under this method,  all  acquisition,  exploration  and development
costs,  including  certain  payroll and other internal  costs,  incurred for the
purpose of finding natural gas and oil 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 and administrative activities are expensed in the period incurred.

     The capitalized costs of the  Partnership's  natural gas and oil properties
plus future development,  dismantlement,  restoration and abandonment costs (the
"Amortizable Base"), net of estimated of salvage values, are amortized using the
unit-of-production   method  based  upon   estimates  of  total  proved  reserve
quantities.  The  Partnership's  capitalized  costs of its  natural  gas and oil
properties,  net of  accumulated  amortization,  are  limited  to the  total  of
estimated  future net cash  flows  from  proved  natural  gas and oil  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 natural gas and oil. A reduction in the
valuation of natural gas and oil properties  resulting from declining  prices or
production   could  adversely   impact  depletion  rates  and  capitalized  cost
limitations.

     All costs  directly  associated  with the  acquisition  and  evaluation  of
unproved  properties are initially  excluded from the Amortizable Base. Upon the
interpretation  by the  Partnership  of the 3-D  seismic  data  associated  with
unproved  properties,  the geological and  geophysical  costs related to acreage
that is not specifically  identified as prospective are added to the Amortizable
Base.  Geological and geophysical costs associated with prospective  acreage, as
well as leasehold  costs,  are added to the Amortizable  Base when the prospects
are drilled.  Costs of prospective  acreage are reviewed annually for impairment
on a property-by-property basis.

                                     F2-14
<PAGE>

     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 Partnership  recognizes natural gas and oil sales from its interests in
producing  wells under the sales method of  accounting.  Under the sales method,
the  Partnership  recognizes  revenues based on the amount of natural gas or oil
sold to purchasers,  which may differ from the amounts to which the  Partnership
is entitled based on its interest in the properties.  Gas balancing  obligations
as of  December  31,  1999,  1998 and 1997  were not  significant.  Interest  is
capitalized on significant  unevaluated  natural gas and oil properties that are
not subject to amortization.

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

Derivative Instruments

     The  Partnership   periodically  enters  into  commodity  hedge  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  derivative
financial  instruments are based on expected production from existing wells. The
Partnership uses these derivative  financial  instruments to manage market risks
resulting from fluctuations in commodity prices.

     Correlation  of the hedge  contracts is determined  by  evaluating  whether
hedge 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 hedge contracts and the underlying  natural
gas and crude oil sales volumes, realized gains or losses and related cash flows
arising from the hedge  contracts  are  recognized as a component of natural gas
and oil sales in the same period as the sale of the underlying  volumes.  To the
extent  that  correlation  does not exist  between the hedge  contracts  and the
underlying natural gas and crude oil sales volumes, realized gains or losses and
related cash flows arising from the hedge contracts are recognized in the period
incurred  as a component  of other  income.  The fair market  value of any hedge
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.

                                     F2-15
<PAGE>

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

Federal and State Income Taxes

     The Subsidiaries other than Brigham, Inc. are not taxable entities and as a
result, no income tax provision has been recorded.  However,  the taxable income
or loss  resulting  from their  operations  will  ultimately  be included in the
federal and state  income tax returns of the Company and may vary  substantially
from the income or loss reported for financial reporting purposes.

     Brigham,  Inc., which is included in the Company's  consolidated income tax
return,  is subject to federal  corporate  income taxation and utilizes an asset
and  liability  approach  for  accounting  for income  taxes that  requires  the
recognition of deferred tax assets and  liabilities  for the expected future tax
consequences of temporary differences between the carrying amounts and tax bases
of assets and liabilities.  Resulting tax liabilities,  if any, are borne by the
Company.

Segment Information

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

Recent Pronouncements

     In June 1998,  the FASB  issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging  Activities."  SFAS No. 133 requires that all derivative
instruments be recorded on the balance sheet at fair value.  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.
For fair value hedge transactions in which the Partnership is hedging changes in
an asset's,  liability's,  or firm commitment's fair value,  changes in the fair
value of the  derivative  instrument  will  generally  be offset  in the  income
statement  by changes  in the  hedged  item's  fair  value.  For cash flow hedge
transactions  in which the  Partnership is hedging the variability of cash flows
related  to a  variable-rate  asset,  liability,  or a  forecasted  transaction,
changes in the fair value of the derivative instrument will be reported in other
comprehensive income. The gains and losses on the derivative instrument that are
reported in other  comprehensive  income 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.  The  Partnership  must adopt SFAS No. 133  effective
January 1, 2000.  The  Partnership  is in the process of analyzing the potential
impact of this standard on its financial statement presentation.

                                     F2-16
<PAGE>

3.       Asset Dispositions

     In  February  1999,  the  Partnership  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  Partnership
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 Partnership 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 Partnership 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 Partnership has certain rights to back-in for up to a 94% effective  working
interest in the Duke LLC properties.

     In June 1999, the Partnership sold its entire interest in certain producing
and non-producing  natural gas and oil properties  located in its Anadarko Basin
province  to two  parties for a combined  sales  price of $17.1  million.  Total
proceeds,  net of transaction costs, were $16.7 million and were used to repay a
portion of the Partnership's notes payable.  Due to the magnitude of the reserve
volumes that were attributable to these properties relative to the Partnership's
remaining  net  reserve  volumes,  the  Partnership  recognized  a loss of $12.2
million, which was 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.

4.   Property and Equipment

     Property and equipment (held by the  Partnership),  at cost, are summarized
as follows (in thousands):

<TABLE>
<CAPTION>
                                                                  December 31,
                                                          ------------------------------
                                                              1999            1998
                                                          -------------   --------------
<S>                                                       <C>             <C>

Natural gas and oil properties..........................  $    178,755    $     181,019
Accumulated depletion...................................       (66,689)         (46,702)
                                                          -------------   --------------
                                                               112,066          134,317
                                                          -------------   --------------
Other property and equipment:
   3-D seismic interpretation workstations and software.         2,248            2,186
   Office furniture and equipment.......................         1,909            1,774
   Accumulated depreciation.............................       (2,471)          (1,946)
                                                          -------------   --------------
                                                                 1,686            2,014
                                                          -------------   --------------
                                                          $    113,752    $     136,331
                                                          =============   ==============
</TABLE>

     At December 31, 1998, a capitalized ceiling impairment of $25.9 million was
recognized by the Partnership and is included above in the accumulated depletion
balances for natural gas and oil properties. The write down was calculated based
on the estimated  discounted  present value of future net cash flows from proved
natural gas and oil reserves using prices in effect at December 31, 1998.

     The  Partnership  capitalizes  certain  payroll  and other  internal  costs
directly attributable to acquisition,  exploration and development activities as
part of its  investment  in  natural  gas and oil  properties  over the  periods
benefited by these  activities.  During the years ended December 31, 1999,  1998
and 1997,  these  capitalized  costs amounted to $3.3 million,  $4.6 million and
$3.5 million,  respectively.  Capitalized costs do not include any costs related
to production, general corporate overhead, or similar activities. Interest costs
of  $3.0  million  and  $1.2  million  were   capitalized   in  1999  and  1998,
respectively.

                                     F2-17
<PAGE>

5.   Notes Payable and Senior Subordinated Notes Payable

     In January 1998, the  Partnership  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 is 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  Partnership's  option.  The Credit  Facility  contains
covenants  restricting the Company's  ability to declare or pay dividends on its
stock. 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 Partnership'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  Partnership's  option.  The  Partnership
incurred a $500,000 transaction fee due to the lender over a ten month period.

     In July 1999,  the Credit  Facility was amended to provide the  Partnership
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
Partnership and was recognized as additional  deferred loan fees to be amortized
over the remaining period to maturity of the Credit Facility.  The Partnership's
obligations  under the Credit Facility are secured by  substantially  all of the
natural gas and oil properties and other tangible assets of the Partnership.

     In August 1998,  upon the filing of a registration  statement with the SEC,
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  "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 Notes and  common  stock of the  Company
generated  proceeds,  net of offering costs, of approximately $47.5 million that
was used to  repay a  portion  of the  then  outstanding  borrowings  under  the
Company's Credit Facility.

     Principal  outstanding  under the Notes is due at  maturity  on August  20,
2003.  Interest on the Notes is payable  quarterly at rates that vary  depending
upon whether accrued  interest is paid in cash or "in kind" through the issuance
of additional Notes.  Interest is 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 Notes; provided, however, that the Company may
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 Notes.  The Company may repay the Notes in full without  premium at any time
prior to maturity.  The indenture governing the Notes contains certain covenants
including,  but not limited to,  limitations or  restrictions  on  indebtedness,
distributions,   affiliate   transactions,   liens   and  sale   and   leaseback
transactions.  The indenture  prohibits  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 Notes.

     The Notes are fully and unconditionally  guaranteed, on a joint and several
basis,  by each of the  Subsidiaries,  all of which are  directly or  indirectly
wholly-owned  by the Company.  The  obligations  of the  Subsidiaries  under the
subsidiary  guaranty  agreements are subordinated to the senior  indebtedness of
the Partnership.  Furthermore,  all  Subsidiaries  have pledged their respective
stock and Partnership interests as collateral for the Notes.

                                     F2-18
<PAGE>

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

     The $40 million in proceeds  from the Notes and  Warrants,  and  subsequent
changes  to the Note  balance  due to  interest  paid in kind  were  transferred
through a series of  intercompany  notes from the Company to Brigham Inc.;  from
Brigham, Inc. to Holdings II; and from Holdings II to the Partnership. Principal
on the  intercompany  notes is due at the maturity of the Notes and intercompany
interest  accrues at rates  corresponding  to those  applicable to the Notes. In
1998,  approximately  $7.6  million of the  proceeds  from the common  stock was
transferred  through a series of  intercompany  capital  contributions  from the
Company to Holdings I ($5.2  million) and Brigham,  Inc.  ($2.4  million);  from
Holdings I to the Partnership ($5.2 million);  from Brigham, Inc. to Holdings II
($2.3  million)  and the  Partnership  ($75,000);  and from  Holdings  II to the
Partnership ($2.3 million).

     In March 1999, the indenture governing the Notes was amended to provide the
Company  with the  option  to pay  interest  due on the  Notes in kind,  for any
reason,  through the second quarter of 2000. In addition,  certain financial and
other covenants were amended. The amendment also provides 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 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.

6.   Capital Lease Obligations

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

<TABLE>
<CAPTION>
                                                                       December 31,
                                                               ------------------------------
                                                                   1999            1998
                                                               -------------   --------------
<S>  <C>                                                       <C>             <C>
     3-D seismic interpretation workstations and software...   $        607    $         620
     Office furniture and equipment.........................            167              167
                                                               -------------   --------------
                                                                        774              787
     Accumulated depreciation and amortization..............           (410)            (276)
                                                               -------------   --------------
                                                               $        364    $         511
                                                               =============   ==============
</TABLE>

                                     F2-19
<PAGE>

         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, 1999 are as
follows (in thousands):

     2000.....................................................  $         258
     2001.....................................................            115
     2002.....................................................             27
                                                                --------------
     Total minimum lease payments.............................            400
        Estimated executory costs included in capital leases..            (25)
                                                                --------------
     Net minimum lease payments...............................            375
        Amounts representing interest.........................            (38)
                                                                --------------
     Present value of net minimum lease payments..............            337
     Less:  current portion...................................           (210)
                                                                --------------
     Noncurrent portion.......................................  $         127
                                                                ==============

7.   Income Taxes

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

                                              Year ended
                                             December 31,
                                      ----------------------------
                                          1999            1998
                                      ------------    ------------
     Current income taxes:
         Federal....................        $   -           $   -
         State......................            -               -
     Deferred income taxes:
         Federal....................            -          (5,088)
         State......................            -               -
                                      ------------    ------------
                                            $   -     $    (5,088)
                                      ============    ============

     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,
                                       ----------------------------
                                          1999            1998
                                       ------------    ------------
     Tax at statutory rate...........  $   (2,281)     $   (3,655)
     Add (deduct) the effect of:
         Tax effect of Exchange......            -         (1,433)
         Valuation reserve...........        2,281               -
                                       ------------    ------------
                                        $        -     $   (5,088)
                                       ============    ============

                                     F2-20
<PAGE>

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

                                                        December 31,
                                                -----------------------------
                                                    1999            1998
                                                -------------   -------------
     Deferred tax assets:
         Net operating loss carryforwards.....  $     8,119     $     4,767
     Deferred tax liability:
         Depreciable and depletable property..       (7,158)         (4,767)
         Valuation reserve....................         (961)              -
                                                -------------   -------------
                                                $         -     $         -
                                                =============   =============

     At December 31, 1999, Brigham, Inc. had regular and alternative minimum tax
net  operating  loss  carryforwards  of  approximately  $23.2  million and $20.4
million, respectively, which expire by December 31, 2019.

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

Litigation

     The  Subsidiaries  are,  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 Subsidiaries.

     As of  December  31,  1999,  there  were no  known  environmental  or other
regulatory matters related to the Subsidiaries'  operations which are reasonably
expected to result in a material liability to the Subsidiaries.  Compliance with
environmental  laws and  regulations has not had, and is not expected to have, a
material adverse effect on their capital  expenditures,  earnings or competitive
position.

Lease Commitments

     The Partnership  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, 1999, are
as follows (in thousands):

     2000......................................................   $        795
     2001......................................................            790
     2002......................................................            395
                                                                  -------------
                                                                  $      1,980
                                                                  =============

     Rental  expense for the years ended  December 31,  1999,  1998 and 1997 was
$937,669, $875,150 and $606,173, respectively.

Major Customers

     During 1999,  approximately  26%, 16% and 11% of the Partnership's  natural
gas and oil  production  was  sold to three  separate  customers.  During  1998,
approximately  25%,  15%, 11% and 11% of the  Partnership's  natural gas and oil
production was sold to four separate customers.  During 1997,  approximately 14%
and 12% of the  Partnership's  natural  gas and oil  production  was sold to two
separate  customers.  However,  due to the availability of other customers,  the
Partnership  does not  believe  that  the  loss of any one of  these  individual
customers would adversely affect the Partnership's result of operations.

                                     F2-21
<PAGE>

Factors Which May Affect Future Operations

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

9.   Financial Instruments

     The  Partnership  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 Partnership 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  1997,  the  Partnership  was a party to a crude  oil  swap  arrangement
resulting in a fixed price over a period of time for a specified volume of crude
oil. In February 1998, the Partnership  entered into a hedging  contract whereby
10,000  MMBtu per day of natural gas is  purchased  and sold  subject to a fixed
price swap agreement for monthly  periods from April 1998 through  October 1999.
Pursuant to these arrangements the Partnership exchanges a floating market price
for a contract  month and payments are received when the fixed price exceeds the
floating price.  Total natural gas subject to this hedging contract is 2,750,000
MMBtu in 1998 and 3,040,000 MMBtu in 1999.

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

     In January 1999, the  Partnership  entered into a swap agreement with terms
similar to existing  agreements  which relates to production for monthly periods
from November 1999 through April 2001.  Pursuant to these  arrangements,  15,000
MMBtu per day of natural gas is purchased and sold subject to a fixed price swap
agreement,  and the  Partnership  exchanges a floating  market price for a fixed
contract  price of $2.065 per MMBtu.  Total natural gas volumes  subject to this
agreement are 915,000 MMBtu,  5,490,000  MMBtu and 1,800,000 MMBtu in 1999, 2000
and 2001, respectively.

     As a result of these  arrangements,  the  Partnership  realized an increase
(decrease) in natural gas and oil revenues of approximately $(486,000), $555,000
and  $(6,200)  during  1999,  1998 and 1997,  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  $291,000 as of December  31,
1999.  Additionally,  the  mark-to-market  adjustments  and  related  cash flows
associated  with this portion of the contract of  approximately  $(429,000) have
been recorded as a component of other income  (expense) on the 1999 statement of
operations.

                                     F2-22
<PAGE>

     In September  1999, the  Partnership  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 natural gas and oil revenues over the original  contract  period
of October 1999 through January 2000.  During 1999,  approximately  $645,000 was
amortized to natural gas and oil revenues.

     Concurrently,  in September 1999 the  Partnership  entered into natural gas
and  crude  oil cap  contracts.  The  natural  gas  cap  contract  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 Partnership 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, 1999, the fair value of
the remaining  contracts  approximated  $875,000 million with the  corresponding
mark-to-market  adjustments  and related  cash flows  recorded as a component of
other income (expense) on the statement of operations.

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

     The Partnership's  accounts  receivable relate to natural gas and oil sales
to various  industry  companies,  amounts  due from  industry  participants  for
expenditures  made by the Partnership on their behalf and workstation  revenues.
Credit terms, typical of industry standards,  are of a short-term nature and the
Partnership does not require collateral.  The Partnership's  accounts receivable
at  December  31, 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.

10. Employee Benefit Plans

Retirement Savings Plan

     The  Partnership  has  adopted  a  defined  contribution  401(k)  plan  for
substantially  all of its  employees.  In 1997  Brigham,  Inc.  succeeded to the
401(k) plan when the employees of the Partnership  became  employees of Brigham,
Inc. Eligible  employees may contribute up to 15% of their  compensation to this
plan. The 401(k) plan provides that the employer may, at its  discretion,  match
employee  contributions.  The employer has not matched employee contributions in
any plan year.

                                     F2-23
<PAGE>

Stock Compensation

     In  1994  three  employees  were  granted   restricted   interests  in  the
Partnership  which vest 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  will  result 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.
Non-cash compensation expense related to certain stock options granted under the
incentive plan by the Company on behalf of the Partnership has been allocated to
the Partnerships's results of operations.  Compensation expense allocated to the
Partnership  totaled  $600,506,  $782,544 and  $833,710 in 1999,  1998 and 1997,
respectively.

11.  Subsequent Event

     In February  2000,  the  Partnership  entered  into an amended and restated
Credit  Facility  with its existing  lenders and a new lender.  This amended and
restated  Credit  Facility  provides  the  Partnership  with an  increase to $70
million in borrowing  availability  for a three-year  term.  If the  Partnership
exceeds  certain asset value and interest  coverage tests in the second or third
quarters of 2000, the total  borrowing  availability  under the Credit  Facility
will increase to $75 million.  Borrowings under the Credit Facility in excess of
$45 million are  convertible  into shares of the  Company's  common stock in the
following  amounts:  (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. If the Credit
Facility is repaid at maturity or is prepaid prior to maturity  without  payment
of cash premiums,  the Company must issue to a new lender of the Credit Facility
warrants to purchase shares of the Company's common stock. In addition,  certain
financial  covenants  of the Credit  Facility  have been  amended  or added.  In
connection with this most recent  amendment,  the Company reset the price of the
warrants  previously  issued to its  existing  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.

     In February  2000,  the  indenture  governing  the Notes was  amended.  The
holders of the Notes waived the minimum  consolidated  interest  coverage  ratio
covenant through June 30, 2000 and adjusted  subsequent  levels under this test.
In addition, an amendment to the Notes provides the Company with an extension of
its right to pay interest  through the issuance of  additional  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  are met.  In  exchange  for
granting these  amendments,  the Company has (i) reset the price of the warrants
previously  issued to the holders of the 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 Notes a term overriding royalty
interest  that  provides  for the limited  right to receive 4%, or 3% if certain
conditions  are met,  of the  Company's  net  production  revenue  to reduce any
outstanding Notes issued as interest paid in kind.

                                     F2-24
<PAGE>

12.      Natural Gas and Oil Exploration and Production Activities

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

     The  Partnership's  natural  gas and oil  properties  are  included  in the
consolidated results of Brigham, Inc., subject to the minority interest of 68.5%
held by the Company in 1997 and by Holdings I in 1999 and 1998.

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

<TABLE>
<CAPTION>
                                                                                   Year ended December 31,
                                                                             -------------------------------------
                                                                                1999(a)       1998(a)      1997(a)
                                                                             -----------  ------------  ----------
<S>                                                                          <C>          <C>            <C>

    Natural gas and oil sales...........................................    $   14,992   $    13,799   $   9,184
     Costs and expenses:
        Lease operating.................................................          2,259         2,172       1,151
        Production taxes................................................            968           850         549
        Depletion of natural gas and oil properties.....................          7,792         8,483       2,743
        Capitalized ceiling impairment..................................              -        25,926           -
                                                                             -----------  ------------  ----------
     Total costs and expenses...........................................         11,019        37,431       4,443
                                                                             -----------  ------------  ----------
                                                                             $    3,973   $   (23,632)  $   4,741
                                                                             ===========  ============  ==========
     Depletion per physical unit of production (equivalent Mcf of gas)..     $     1.24   $       1.27  $    0.88
                                                                             ===========  ============  ==========
</TABLE>
-----------------

     (a)   The income tax expense (benefit)  related to Brigham,  Inc. for 1998,
           1998 and 1997 is  calculated  at the  statutory  rate and  determined
           without regard to deduction for general and administrative  expenses,
           interest  costs and other income tax  deductions  and  credits.  Upon
           consolidation  of the  Partnership  interest into  Brigham,  Inc. for
           1999,  1998 and 1997,  the income tax  expense  (benefit)  related to
           results of operations  for natural gas and oil  producing  activities
           for Brigham, Inc. would be $438, $(2,605) and $523, respectively.

     Natural gas and oil 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 natural gas and oil properties relates to capitalized costs
incurred in  acquisition,  exploration and  development  activities.  Results of
operations do not include interest expense and general corporate amounts.

                                     F2-25
<PAGE>



Costs Incurred and Capitalized Costs

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

                                                    December 31,
                                      ----------------------------------------
                                         1999          1998          1997
                                      ------------  ------------  ------------

     Costs incurred for the year:
        Exploration.................  $    19,224   $    68,214   $    29,516
        Property acquisition........        3,462        16,245        26,956
        Development.................        4,632        10,475         2,953
        Proceeds from participants..       (2,439)      (10,502)         (319)
                                      ------------  ------------  ------------
                                      $    24,879   $    84,432   $    59,106
                                      ============  ============  ============

     Costs  incurred   represent   amounts   incurred  by  the  Partnership  for
exploration, property acquisition and development activities.  Periodically, the
Partnership  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 natural gas and oil acquisition,  exploration
and development activities follow (in thousands):

<TABLE>
<CAPTION>
                                                                      December 31,
                                                              ------------------------------
                                                                  1999            1998
                                                              -------------   --------------
<S>                                                           <C>             <C>

    Cost of natural gas and oil properties at year-end:

        Proved.............................................   $    140,757    $     128,643
        Unproved...........................................         37,998           52,376
                                                              -------------   --------------
        Total capitalized costs............................        178,755          181,019
        Accumulated depletion..............................        (66,689)         (46,702)
                                                              -------------   --------------
                                                              $    112,066    $     134,317
                                                              =============   ==============
</TABLE>

     Following is a summary of costs (in  thousands)  excluded from depletion at
December 31, 1999, by year incurred.  At this time, the Partnership 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
                                                    ------------------------------------
                                                       1999         1998         1997        Years        Total
                                                   -----------  -----------  ----------  ----------   ----------
<S>                                                <C>           <C>         <C>        <C>           <C>

     Property acquisition........................   $    1,079   $    6,414   $   5,558   $   1,921    $  14,972
     Exploration.................................        1,174       12,876       7,404       1,572       23,026
                                                    -----------  -----------  ----------  ----------   ----------
     Total.......................................   $    2,253   $   19,290   $  12,962   $   3,493    $  37,998
                                                    ===========  ===========  ==========  ==========   ==========
</TABLE>

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

     Information with respect to the Partnership's natural gas and oil 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 Partnership's  independent  petroleum consultants and internal
petroleum reservoir engineer.

                                     F2-26
<PAGE>

Natural Gas and Oil Reserve Data

     The  following  tables  present the  Partnership's  estimates of its proved
natural gas and oil reserves.  The Partnership 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 natural gas and oil 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 were  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, 1996..................       10,257            1,940
        Revisions to previous estimates....................       (3,044)            (447)
        Extensions, discoveries and other additions........       33,721              735
        Purchase of minerals-in-place......................       13,718            1,244
        Sales of minerals-in-place.........................          (40)               -
        Production.........................................       (1,382)            (291)
                                                            -------------   --------------
     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 of 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
                                                            =============   ==============

     Proved developed reserves at December 31:

        1997...............................................       30,677            2,665
        1998...............................................       38,571            2,935
        1999...............................................       28,594            1,873
</TABLE>

     Proved reserves are estimated quantities of crude natural gas and 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 which can be
expected to be recovered  through  existing  wells with  existing  equipment and
operating methods.

                                     F2-27
<PAGE>

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 natural gas and oil reserves.
Future cash flows were  computed by applying  year end prices of natural gas and
oil relating to the  Partnership'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  natural gas and oil
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 Partnership's natural gas and oil reserves.

<TABLE>
<CAPTION>
                                                                                       December 31,
                                                                         ----------------------------------------
                                                                            1999          1998          1997
                                                                         ------------  ------------  ------------

<S>                                                                      <C>           <C>           <C>
     Future cash inflows.............................................    $   228,429   $   198,082   $   165,156
     Future development and production costs.........................        (61,878)      (61,064)      (40,923)
                                                                         ------------  ------------  ------------
     Future net cash inflows.........................................    $   166,551   $   137,018   $   124,233
                                                                         ============  ============  ============

     Standardized measure of future net cash inflows discounted
        at 10% per annum.............................................    $   114,466   $    81,741   $    69,249
                                                                         ============  ============  ============
</TABLE>

     Estimated  future income tax expense as of December 31, 1999, 1998 and 1997
attributable  to Brigham,  Inc.'s  interest in the Partnership was $3.9 million,
$2.2 million and $7.2 million,  respectively. The standardized measure of future
net cash inflows  discounted at 10% per annum as of December 31, 1999,  1998 and
1997 after estimated  income taxes  attributable to Brigham,  Inc.'s interest in
the  Partnership   was  $114.2   million,   $81.7  million  and  $67.7  million,
respectively.

     The base sales prices for the Partnership's reserves were $2.35 per Mcf for
natural gas and $22.75 per Bbl for oil as of December  31,  1999,  $2.12 per Mcf
for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.27 per
Mcf for natural gas and $15.50 per Bbl for oil as of December  31,  1997.  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 Partnership's reserves at these dates.

                                     F2-28
<PAGE>

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

<TABLE>
<CAPTION>
                                                                           December 31,
                                                              ----------------------------------------
                                                                  1999          1998        1997
                                                              ------------ ------------ ------------

<S>                                                           <C>          <C>          <C>
Beginning of period .......................................   $  81,741    $  69,249    $  44,506
   Sales of natural gas and oil produced, net of production
        costs .............................................     (11,765)     (10,776)      (7,484)
   Development costs incurred .............................       4,413        5,423        1,955
   Extensions and discoveries .............................      43,346       52,389       38,016
   Purchases of minerals-in-place .........................        --            687       16,965
   Sales of minerals-in-place .............................     (32,783)        --            (94)
   Net change of prices and production costs ..............      33,226      (11,921)     (20,466)
   Change in future development costs .....................        (555)        (656)         319
   Changes in production rates and other ..................         637       (6,109)      (1,954)
   Revisions of quantity estimates ........................     (11,969)     (23,470)      (6,964)
   Accretion of discount ..................................       8,174        6,925        4,450
                                                              ---------    ---------    ---------
End of period .............................................   $ 114,465    $  81,741    $  69,249
                                                              =========    =========    =========
</TABLE>

     The estimated change in future net cash inflows discounted at 10% per annum
attributable  to income taxes for the years ended  December  31, 1999,  1998 and
1997 attributable to Brigham, Inc.'s interest in the Partnership was $(261,000),
$1.5 million and $(1.6) million, respectively.

14.  Quarterly Financial Data (Unaudited)

     The Subsidiaries  have restated  previously  reported  quarterly  financial
results for the nine months ended September 30, 1999 and the year ended December
31,  1998 to give  effect to the  capitalization  of  interest  for  significant
acquisition,  exploration and development  activities in progress.  There was no
effect on the year ended  December  31,  1998 net loss or on the 1997  financial
results.  The effect of this  restatement  on the  statement of operations is as
follows (in thousands):

<TABLE>
<CAPTION>
                                                                 Year Ended December 31, 1999
                                    ------------------------------------------------------------------------------------
                                             Quarter 1              Quarter 2              Quarter 3         Quarter 4
                                    ------------------------ ---------------------- ----------------------- ------------
                                       Previously     As      Previously      As     Previously      As
                                        Reported   Restated    Reported    Restated   Reported    Restated
                                    ------------- ---------- ------------ --------- ------------ ----------
<S>                                   <C>         <C>         <C>         <C>         <C>        <C>          <C>
Brigham Oil and Gas, L.P.
  Revenue...........................    $   3,281   $   3,281   $   3,626  $   3,624   $  4,195   $  4,238    $  4,134
  Operating income (loss)...........          124         113         255        200       (379)      (432)        389
  Net loss..........................       (2,484)     (1,759)    (14,794)   (14,599)    (3,329)    (2,391)     (1,909)

Brigham, Inc.
  Revenue...........................    $   3,281   $   3,281   $   3,626  $   3,624   $  4,195   $  4,238    $  4,134
  Operating income (loss)...........          124         113         250        195       (379)      (432)        384
  Net loss..........................         (783)       (554)     (4,664)    (4,604)    (1,049)      (753)       (606)

Brigham Holdings I, LLC
  Revenue...........................    $       -   $       -   $       -  $       -   $      -   $      -    $      -
  Operating income (loss)...........            -           -          (5)        (5)         -          -          (4)
  Net loss..........................       (1,701)     (1,205)    (10,140)   (10,005)    (2,280)    (1,638)     (1,312)

Brigham Holdings II, LLC
  Revenue...........................    $       -   $       -   $       -  $       -   $      -   $      -    $      -
  Operating income (loss)...........            -           -          (5)        (5)         -          -          (4)
  Net loss..........................         (758)       (537)     (4,517)    (4,457)    (1,015)      (729)       (587)
</TABLE>

                                     F2-29
<PAGE>

<TABLE>
<CAPTION>
                                                          Year Ended December 31, 1998
                        -----------------------------------------------------------------------------------------------
                                 Quarter 1              Quarter 2              Quarter 3              Quarter 4
                        ------------------------ ---------------------- ---------------------- ------------------------
                          Previously      As      Previously     As      Previously     As      Previously      As
                           Reported    Restated    Reported   Restated    Reported   Restated    Reported    Restated
                        ------------- ---------- ----------- ---------- ----------- --------- ---------- --------------

Brigham Oil & Gas, L.P.
<S>                       <C>         <C>        <C>         <C>        <C>         <C>       <C>        <C>
  Revenue.................$ 3,257     $ 3,257    $ 4,120     $ 4,120    $ 4,237     $ 4,237   $   2,575  $   2,575
  Operating income (loss).     31          27        438         424        481         466     (28,475)   (29,594)
  Net loss................   (954)       (692)      (932)       (682)    (1,348)     (1,064)    (30,855)   (31,651)

Brigham, Inc.
  Revenue.................$ 3,257     $ 3,257    $ 4,120     $ 4,120    $ 4,237     $ 4,237   $   2,575  $   2,575
  Operating income (loss).     31          27        432         418        481         466     (28,480)   (29,599)
  Net loss................   (207)       (152)      (201)       (150)      (280)       (221)     (4,973)    (5,138)

Brigham Holdings I, LLC
  Revenue.................$     -     $     -    $     -     $     -    $     -     $     -   $       -  $       -
  Operating income (loss).      -           -         (6)         (6)         -           -          (5)        (5)
  Net loss................   (653)       (474)      (645)       (473)      (923)       (729)    (21,141)   (21,686)

Brigham Holdings II, LLC
  Revenue.................$     -     $     -    $     -     $     -    $      -    $     -   $       -  $       -
  Operating income (loss).      -           -         (6)         (6)          -          -          (5)        (5)
  Net loss................   (291)       (211)      (290)       (214)      (411)       (325)     (9,416)    (9,658)
</TABLE>

                                     F2-30