BRIGHAM EXPLORATION CO - 10-K Annual Report

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

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FORM 10-K
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(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, 2001

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
AUSTIN, TEXAS 78730
(Address of principal executive offices) (Zip Code)

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

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

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 22, 2002, the Registrant had 16,016,113 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 22, 2002, as reported on The Nasdaq Stock Market(SM), was
$25.3 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 2002 Annual
Meeting of Stockholders to be held on May 17, 2002, 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, 2001.

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TABLE OF CONTENTS

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BRIGHAM EXPLORATION COMPANY

2001 ANNUAL REPORT ON FORM 10-K

ITEM 1. BUSINESS

OVERVIEW

Brigham Exploration Company ("Brigham" or the "Company") is an independent
exploration and production company that applies 3-D seismic imaging and other
advanced technologies to systematically explore and develop onshore oil and
natural gas provinces in the United States. Brigham focuses its activity in
provinces where it believes 3-D seismic technology may be effectively applied to
discover relatively large potential reserve volumes (on both a per well and per
field basis) with 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.

Brigham pioneered the acquisition of large-scale onshore 3-D seismic surveys
for exploration, obtaining extensive 3-D seismic data and experience in
capturing undiscovered oil and natural gas reserves. As of December 31, 2001,
Brigham had accumulated approximately 6,633 square miles (4.2 million acres) of
3-D seismic data and had drilled 530 wells in its 3-D project areas. Brigham
generates most of its exploratory projects and as a result, can retain a
sizeable working interest in these projects.

Since its inception in 1990 through 2001, Brigham has drilled 420
exploratory and 110 development wells on its 3-D generated prospects with an
aggregate completion rate of 67% and an average working interest of 30%. Also
during this period, Brigham has added an estimated 191 Bcfe (including revisions
to previous estimates) of net proved reserves, 168 Bcfe of which were discovered
by Brigham through its systematic 3-D exploration drilling activities at an
average drilling finding cost of $0.79 per Mcfe.

Since 1999, Brigham has focused the majority of its capital expenditures on
drilling its 3-D delineated prospect inventory. Drilling activity has been
concentrated in the five focus plays where the Company believes it benefits from
a superior knowledge base and an optimal seismic and leasehold position. For the
three-year period ended December 31, 2001, the Company's average drilling
finding cost was $0.74 per Mcfe and its average all-sources finding cost was
$1.00 per Mcfe. During this same three-year period, Brigham's equivalent
production volumes have grown by 44% to average 26.6 MMcfe per day in 2001 and
EBITDA (net income (loss) plus interest expense, depletion, depreciation and
amortization expenses, deferred income tax and other non-cash items) has grown
244% to $22.7 million in 2001.

Brigham's estimated net proved reserves as of December 31, 2001 were
111 Bcfe with a present value of future net revenues of $147 million, compared
to estimated net proved reserves as of December 31, 1996 of 22 Bcfe with a
present value of future net revenues of $45 million. Brigham's net proved
reserve volumes as of December 31, 2001 were 80% natural gas and 49% 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

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use of 3-D seismic imaging and other advanced technologies to reduce drilling
risks and finding costs. Key elements of Brigham's long-term growth strategy
include:

- delineate the geologic plays that provide higher potential reserve impact
and superior 3-D driven drilling economics;

- acquire large scale 3-D seismic surveys in such geologic plays to expand
the Company's competitive knowledge base and to identify and capture high
quality potential drilling locations;

- retain significant working interests to capture a greater share of the
reserve potential;

- leverage capital investments by selling promoted working interests in
selected prospects and projects;

- generate high rates of growth in reserves, production volumes and cash
flow; and

- efficiently grow net asset value per share.

Brigham's corporate history can be described in three distinct phases:

From 1990 to 1996, Brigham acquired approximately 2,760 square miles of 3-D
seismic in over 28 different geologic plays, seven basins and seven states with
an average working interest of approximately 28%. During this period, to reduce
its capital exposure, Brigham typically retained carried interests in its 3-D
projects by selling promoted working interest to industry participants. Brigham
also identified geologic objectives and trends that it believed would provide
optimal 3-D drilling economics.

In 1997, Brigham completed its initial public offering and accelerated its
acquisition of 3-D seismic data in the plays that it believed were most likely
to provide attractive 3-D delineated drilling economics. Brigham acquired an
additional 2,475 square miles of 3-D seismic data and retained substantially
higher working interests (averaging approximately 73%) in its newly acquired
projects and prospects. These acquisitions were the largest in Brigham's history
and nearly doubled its inventory of onshore 3-D seismic data, as compared to
year-end 1996, to approximately 5,235 square miles. With these significant
investments, Brigham believes it has assembled a superior knowledge base and the
premier seismic and leasehold position in each of its current focus plays.
Brigham further believes it has captured a high quality, multi-year inventory of
3-D delineated potential drilling locations and the quality and depth of this
inventory is evidenced by its recent drilling results.

Starting in 1999, the Company entered the third phase of its corporate
history by focusing the majority of its capital on the drilling of its inventory
of potential drilling locations to grow reserves, production volumes and cash
flow. For the three-year period ended December 31, 2001, Brigham achieved a net
completion rate of 81%, an average all-sources finding cost of $1.00 per Mcfe
and an average drilling finding cost of $0.74 per Mcfe. Drilling in this
inventory has generated several field discoveries, including the Home Run Field
in 1999, the Mills Ranch Field in 2000, and the Triple Crown Field and the
Providence Field in 2001.

Also during this period, Brigham has focused on improving its cash flow
margin and its return on invested capital by controlling costs while growing
production volumes and revenue. From 1998 to 2001, Brigham reduced its
discretionary unit operating costs (general and administrative expense plus
lease operating expense) from $1.03 per Mcfe to $0.74 per Mcfe. This lower cost
structure, combined with higher oil and gas revenue per unit of equivalent
production, resulted in an increase in gross profit per unit of equivalent
production from $0.98 per Mcfe in 1998 to $2.50 per Mcfe in 2001. Furthermore,
Brigham's reduced debt levels have led to a decline in net interest expense (net
of interest income) on a per unit of equivalent production basis, from
$1.52 per Mcfe in 1999 and $1.48 per Mcfe in 2000 to $0.67 per Mcfe in 2001. As
a result, unit cash flow improved from ($0.15) per Mcfe in 1999 and $0.37 per
Mcfe in 2000 to $1.83 per Mcfe in 2001, and cash flow margins improved from (6%)
in 1999

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and 13% in 2000 to 54% in 2001. Brigham believes that by focusing its capital on
its large prospect inventory, while controlling its costs, the inherent value of
its prospect inventory will become apparent through its operating and financial
results. In 2001, relative to 2000, Brigham grew its oil and natural gas
reserves by 17%, its equivalent production volumes by 45%, and its operating
cash flow before changes in working capital by 111%.

In 2002, Brigham's strategy is composed of the following key elements:

- focus the majority of its resources on the drilling of its established 3-D
delineated project inventory in its five focus plays, targeting primarily
natural gas prospects in established producing trends;

- development of the Home Run Field, Mills Ranch Field, Triple Crown Field
and Providence Field discoveries;

- continue its active and high potential exploration program;

- leverage its prior investments in 3-D seismic and land by selectively
selling interests in prospects and projects to mitigate risk and enhance
its corporate rate of return; and

- continue to focus upon improving its cash flow margin and return on
invested capital by controlling costs while growing reserves, production
volumes and cash flow.

FOCUS ON DRILLING

During the first six years of its history, Brigham acquired 3-D seismic in
over 28 different geologic plays, seven basins and seven states. The Company
also identified geologic objectives and trends that it believed would provide
optimal 3-D drilling economics. During the second phase of Brigham's corporate
history, from 1997 to 1998, the Company accumulated a multi-year inventory of
3-D delineated exploration drilling locations in the plays that it believed were
most likely to provide attractive 3-D delineated drilling economics.

Beginning in 1999, Brigham began to focus the majority of its resources
toward drilling activities within its five focus plays to generate growth in
proved reserves, production volumes and cash flow. Since 1999, the Company has
achieved a net completion rate of 81%, an average all-sources finding cost of
$1.00 per Mcfe, an average drilling finding cost of $0.74 per Mcfe and has
discovered four potentially substantial fields.

For 2002, approximately 80% of Brigham's exploration and development budget
of $17.9 million has been allocated to drilling expenditures in its three core
provinces, over 90% of which is dedicated to drilling in its five focus plays.

DEVELOP HOME RUN, MILLS RANCH, TRIPLE CROWN AND PROVIDENCE FIELD DISCOVERIES

From 1990 to 1999, a majority of Brigham's drilling expenditures were
directed toward exploration-oriented projects. Due to the success of Brigham's
past exploration drilling programs and the discovery of the Home Run Field and
Mills Ranch Field, over 50% of the Company's drilling expenditures in 2001 were
developmental. Capitalizing on the discovery of the Triple Crown Field and
Providence Field in 2001, approximately 80% of Brigham's 2002 drilling
expenditures have been allocated to development drilling. Given that Brigham is
early in the development of these fields, the Company anticipates an ongoing,
multi-year drilling program to fully develop these fields.

CONTINUE AN ACTIVE EXPLORATION PROGRAM

Beginning in 1999, Brigham began to focus its drilling investments in the
five focus plays it believed would provide excellent 3-D delineated drilling
economics. These plays include the Vicksburg

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and Frio trends in the onshore Texas Gulf Coast, the Springer and Hunton trends
in the Anadarko Basin and the Horseshoe Atoll trend of West Texas. In these
trends Brigham has completed 25 wells in its 28 most recent attempts and in the
process discovered the Home Run Field in 1999, the Mills Ranch Field in 2000,
and the Triple Crown Field and the Providence Field in 2001. Approximately 20%
of Brigham's 2002 budgeted drilling capital expenditures will be dedicated to
exploration.

In 2001, to supplement its exploration drilling prospect inventory, Brigham
exchanged licensing rights in certain non-core 3-D data volumes for licenses in
additional 3-D seismic data programs located within its focus trends. For 2002,
Brigham expects to continue looking for opportunities to acquire additional 3-D
seismic data within its focus trends with very little capital investment.

LEVERAGE PRIOR INVESTMENTS TO MITIGATE RISK AND ENHANCE CORPORATE RATE OF RETURN

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 advantage in attracting participants to invest in its
projects. Often times, Brigham can recoup a portion of its initial capital
investment on a promoted basis. Historically, Brigham has been effective at
raising capital and attaining promoted working interests in its 3-D seismic
projects and prospects, thereby utilizing leverage extensively to manage its
risk and enhance its corporate rate of return. Given the depth of Brigham's land
and 3-D seismic inventory, and in particular the Company's inventory of 3-D
delineated drilling prospects, Brigham plans to again leverage its investments
in 2002.

MAXIMIZE RETURN ON INVESTED CAPITAL AND OPERATING MARGINS

Brigham seeks to maximize its return on invested capital by achieving low
finding and development costs and by reducing and controlling its per unit
operating costs. From inception through 1998, Brigham's average drilling finding
cost was $0.82 per Mcfe. Since 1999, Brigham has achieved improved returns on
its drilling investments with an average drilling finding cost of $0.74 per
Mcfe. Additionally, Brigham's average all-sources finding cost from 1999-2001
was $1.00 per Mcfe, a substantial improvement from its average all-sources
finding cost of $1.59 per Mcfe from inception through 1998. Brigham believes
these improvements are due to the following:

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

- significantly lower non-drilling capital expenditures in 1999, 2000 and
2001;

- improved drilling returns achieved during 1999, 2000 and 2001; and

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

Brigham expects this convergence of its all-sources finding cost and its
drilling finding cost to continue in 2002. Brigham will continue to capitalize
on its extensive inventory of 3-D delineated drilling prospects by allocating
the majority of its capital expenditures to drilling within its existing 3-D
seismic project areas.

Brigham's low per unit lease operating expenses over the past few years can
be attributed to the relatively new nature of many of its producing wells, its
focused operations in three core provinces and the operation of a greater
percentage of the wells that it drills. Brigham intends to continue to maintain
low operating expenses per unit by monitoring and controlling production
efficiency from its existing producing wells, adding new producing wells that
typically cost less to operate than more mature wells and by seeking to achieve
operating cost efficiencies through increased economies of scale resulting from
a greater concentration of producing assets within its core project areas.

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3-D SEISMIC TECHNOLOGY

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

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

EXPLORATION AND OPERATING APPROACH

Brigham has acquired 3-D seismic data covering approximately 6,633 square
miles (4.2 million acres) in over 28 geologic plays in seven basins and seven
states. Through this activity, Brigham has developed expertise in the selection
of geologic trends that are best suited 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, to lower
finding and development costs, to compress project cycle times and to increase
its project rate of return.

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

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

Brigham uses its knowledge base, local geological expertise and digital data
bases integrated with 3-D seismic data to create maps of producing and
potentially productive reservoirs. As such, Brigham believes its 3-D generated
maps are more accurate than previous reservoir maps (which generally were

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based on subsurface geological information and 2-D seismic surveys), enabling it
to more precisely evaluate recoverable reserves and the economic feasibility of
projects and drilling locations.

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

Combining its geologic and geophysical expertise with a sophisticated land
effort, Brigham manages the majority of its projects from conception through 3-D
acquisition, processing and interpretation and leasing. In addition, Brigham
manages the negotiation and drafting of most of its geophysical exploration
agreements, resulting in reduced contract risk and more consistent deal terms.
Because it generates most of its projects, Brigham can often control the size of
the working interest that it retains as well as the selection of the operator
and the non-operating participants. Consistent with its business strategy,
Brigham has increased the working interest it retains in its projects, based
upon capital availability and perceived risk. Brigham's average working interest
in its 3-D seismic projects acquired during 1996, 1997 and 1998 was 37%, 67% and
80%, respectively. Brigham did not shoot any new 3-D seismic during the
three-year period ended December 31, 2001. However, in 2001, Brigham exchanged
licensing rights in certain non-core 3-D data volumes for licenses to additional
3-D seismic data programs, many of which were located in Brigham's focus plays
in the Texas Gulf Coast. As a result, Brigham added approximately 1,400 square
miles of 3-D seismic data in 2001, with very little capital investment. The
Company believes that by applying its knowledge base and expertise to this newly
acquired 3-D seismic data it should generate additional drilling inventory in
its current focus plays, thereby further capitalizing on its recent drilling
successes. One of Brigham's 2001 Gulf Coast Frio discoveries was drilled on this
recently acquired data. Brigham anticipates that in 2002, it will enter into
transactions similar to those entered into in 2001 to acquire additional 3-D
seismic data.

Brigham's operations personnel (including management) includes six engineers
that have drilling, reservoir, environmental and operations engineering
experience primarily within Brigham's three core areas of operations. These
engineers work closely with Brigham's explorationists and are integrally
involved in all phases of the exploration and development process, including
preparation of pre- and post-drill reserve estimates, analysis of full cycle
risked drilling economics, well design and production management. Brigham
conducts field operations for its operated oil and natural gas properties
through a Company employed field superintendent and third party contract
personnel. In an effort to retain better control of its project timing, drilling
and operational costs and production volumes, over the past several years
Brigham has significantly increased the percentage of the wells that it
operates. Brigham operated 45% of the gross and 67% of the net wells that it
participated in during 2001, as compared with 10% and 17%, respectively, of the
wells it drilled during 1996. As a result of its increased operational control
in recent years, Brigham-operated wells constituted 72% of the PV10% value of
its proved developed producing reserves at year-end 2001, as compared with only
8% at year-end 1996.

TECHNICAL STAFF

Brigham's experienced technical staff (excluding management) includes five
geophysicists, seven geologists, five engineers, three computer applications
specialists, two 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

6

software and seismic data processing), provide Brigham with valuable technical
intellectual resources. Brigham's team of explorationists has over 253 years of
exploration experience, or an average of more than 21 years per person, most of
which was acquired at Brigham and various major and large independent oil
companies. Brigham's team of technical specialists was assembled according to
the expertise that these individuals have within producing basins where Brigham
focuses its exploration and development activities. By integrating both geologic
and geophysical expertise within its project teams, Brigham believes it
possesses a competitive advantage in its exploration approach. Occasionally,
Brigham will complement and leverage its exploration staff by seeking out
alliances or retainer relationships with geologists and other technical
professionals who have extensive experience in a particular area of interest.

OIL AND NATURAL GAS MARKETING AND MAJOR CUSTOMERS

Most of Brigham's oil and natural gas production is sold under price
sensitive or spot market contracts. The revenues generated by Brigham's
operations are highly dependent upon the prices of and demand for oil and
natural gas. The price received by Brigham for its oil and natural gas
production depends upon numerous factors beyond Brigham's control, including
seasonality, competition, the condition of the United States economy, foreign
imports, political conditions in other oil-producing and natural gas-producing
countries, the actions of the Organization of Petroleum Exporting Countries, and
domestic government regulation, legislation and policies. Decreases in the
prices of oil and natural gas could have an adverse effect on the carrying value
of Brigham's proved reserves and its revenues, profitability and cash flow.
Although Brigham is not currently experiencing any significant involuntary
curtailment of its oil or natural gas production, market, economic and
regulatory factors may in the future materially affect Brigham's ability to sell
its oil or natural gas production. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations", "--Risk
Factors--Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas
Prices Are Volatile" and "--Risk Factors--The Marketability Of Our Production Is
Dependent On Facilities That We Typically Do Not Own Or Control" For the year
ended December 31, 2001, sales to Highland Energy Company and Lantern Petroleum
Corporation represented approximately 60% of Brigham's oil revenue and 58% of
its natural gas revenue. On March 1, 2002 the Company ended its oil purchase
agreement with Lantern Petroleum and began selling oil to a broader range of
purchasers. Effective July 1, 2002, Brigham is ending a similar gas sales and
purchase arrangement with Highland Energy Company. Due to the availability of
other markets and pipeline connections, Brigham does not believe that the loss
of any single oil or natural gas customer would have a material adverse effect
on its results of operations.

COMPETITION

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

7

OPERATING HAZARDS AND UNINSURED RISKS

Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by Brigham will be productive or that Brigham
will recover all or any portion of its investment. Drilling for oil and natural
gas may involve unprofitable efforts, not only from dry wells, but also from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost and timing of
drilling, completing and operating wells is often uncertain. Brigham's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond Brigham's control, including title problems,
weather conditions, delays by project participants, compliance with governmental
requirements and shortages or delays in the delivery of equipment and services.
Brigham's future drilling activities may not be successful and, if unsuccessful,
such failure may have a material adverse effect on its business, financial
condition or results of operations. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations--Risk
Factors--Exploratory Drilling Is A Speculative Activity Involving Numerous Risks
And Uncertain Costs; We Are Dependent On Exploratory Drilling Activities" In
addition, use of 3-D seismic technology requires greater pre-drilling
expenditures than traditional drilling strategies. Although Brigham believes
that its use of 3-D seismic technology will increase the probability of drilling
success, some unsuccessful wells are likely, and there can be no assurance that
unsuccessful drilling efforts will not have a material adverse effect on
Brigham's business, financial condition or results of operations.

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

EMPLOYEES

On March 22, 2002, Brigham had 52 full-time employees. None is represented
by any labor union and Brigham believes its relations with its employees are
good. In addition, Brigham relies on several regional consulting service
companies to provide field landmen to support Brigham on a project-by-project
basis. One of these companies, Brigham Land Management, is owned by Vincent M.
Brigham, who is the brother of Ben M. Brigham, Brigham's Chief Executive
Officer, President and Chairman of the Board and David T. Brigham, Brigham's
Senior Vice President of Land and Administration.

FACILITIES

Brigham's principal executive offices are located in Austin, Texas, where it
leases approximately 34,330 square feet of office space at 6300 Bridge Point
Parkway, Building 2, Suite 500, Austin, Texas 78730. In an effort to reduce
corporate overhead expenses, Brigham subleased approximately 5,400 square feet
of excess office space at its principal executive offices to a third party for a
two-year term beginning in November 1999 and extended that sublease by an
additional six months in October 2001.

8

TITLE TO PROPERTIES

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

GOVERNMENTAL REGULATION

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

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

ENVIRONMENTAL MATTERS

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

9

into the environment. The Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes govern the disposal of "solid waste" and "hazardous
waste" and authorize imposition of substantial fines and penalties for
noncompliance. Although CERCLA currently excludes petroleum from its definition
of "hazardous substance," state laws affecting Brigham's operations impose
clean-up liability relating to petroleum and petroleum related products. In
addition, although RCRA classifies certain oil field wastes as "non-hazardous,"
such exploration and production wastes could be reclassified as hazardous wastes
thereby making such wastes subject to more stringent handling and disposal
requirements.

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

Brigham has acquired leasehold interests in numerous properties that for
many years have produced oil and natural gas. Although Brigham believes that the
previous owners of these interests have used operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties. In addition, some
of Brigham's properties are operated by third parties over whom it has little
control. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations--Other Matters" and "--Risk Factors--We Are
Subject To Various Governmental Regulations And Environmental Risks"

10

ITEM 2. PROPERTIES

PRIMARY EXPLORATION PROVINCES

Brigham focuses its 3-D seismic exploration efforts in oil and natural gas
producing provinces where it believes 3-D technology may be effectively applied
to discover relatively large potential reserve volumes (on both a per well basis
and per field basis) with 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.

Since inception in 1990 through 2001, Brigham has drilled 420 exploratory
and 110 development wells on its 3-D generated prospects with an aggregate
completion rate of 67% and an average working interest of 30%. During this
period, Brigham has added an estimated 191 Bcfe of net proved reserves, 168 net
Bcfe of which were discovered by Brigham through its systematic 3-D exploration
drilling activities at an average drilling finding cost of $0.79 per Mcfe.

Brigham was a pioneer in 3-D exploration in domestic onshore provinces. From
1990 to 1996 Brigham acquired approximately 2,760 square miles of 3-D seismic
data in over 28 different geologic plays, seven basins and seven states, and in
the process identified the geologic objectives that it believed would provide
optimal 3-D drilling economics.

During 1997 and 1998, Brigham aggressively capitalized on its 3-D
exploration experience by accumulating a multi-year inventory of 3-D delineated
drilling locations in the plays that it believed were most likely to provide
attractive 3-D delineated drilling economics. During this period, Brigham
acquired an additional 2,475 square miles of 3-D seismic data and retained a
substantially higher than historical project working interests of 73%. These
acquisitions were the largest in Brigham's history and nearly doubled Brigham's
inventory of onshore 3-D seismic data, as compared to year-end 1996, to 5,235
square miles. With these significant investments, Brigham believes it has
assembled a superior knowledge base and the premier seismic and leasehold
position in each of its current focus plays. Brigham further believes it has
captured a high quality, multi-year inventory of 3-D delineated potential
drilling locations and the quality and depth of this inventory is evidenced by
its recent drilling results.

Beginning in 1999, Brigham began to focus the majority of its capital
expenditures on drilling in its 3-D delineated prospect inventory in the five
plays where it has assembled a superior knowledge base and an optimal seismic
and leasehold position. As a result of this focus, for the three-year period
ending December 31, 2001, Brigham achieved an average drilling finding cost and
all-sources finding cost of $0.74 and $1.00 per Mcfe, respectively. Also, during
this same three-year period Brigham's production volumes grew by 44% to average
26.6 MMcfe per day in 2001, while EBITDA grew by 244% to $22.7 million in 2001.

Brigham's exploration success achieved through the drilling of its 3-D
delineated prospect inventory has resulted in four substantial field discoveries
since 1999 and has added a substantial number of developmental locations to
Brigham's large inventory of 3-D delineated exploration prospects. As a result,
the Company's annual drilling investments have evolved from pure 3-D delineated
exploration to a blended exploration and development portfolio. For example,
while Brigham's drilling capital expenditures in 1999 were almost 100%
exploration, capital expenditures in 2001 were approximately 50% developmental.
Growth in the proportion of the drilling expenditures allocated to development
drilling should continue in 2002, particularly given the discovery of the Triple
Crown Field and the Providence Field in 2001. Although these new field
discoveries did not materially impact production volumes and cash flow in 2001,
management believes they will have a material impact on production volumes in
2002.

Continuing its strategic focus implemented during 1999, Brigham intends to
direct substantially all of its efforts and available capital resources in 2002
to the drilling and monetization of the prospective

11

drilling locations within its over 6,600 square mile inventory of 3-D seismic
data. Brigham's planned 2002 capital budget is estimated to be approximately
$23.7 million. The spending will be funded out of Brigham's discretionary cash
flow and availability under its Subordinated Notes Facility. Depressed commodity
prices have led to a budgeted decrease in capital spending of $12.3 million
(34%) for 2002 when compared to 2001. Brigham's budget is based upon anticipated
commodity prices and is subject to change if market conditions shift.

For 2002, Brigham plans to spend approximately 80% of its $17.9 million
exploration and development budget to drill 26 planned wells with an average
working interest of 32%. Brigham's planned 2002 drilling program represents a
blend of capital investments consisting of both, development projects to recent
discoveries and high potential exploration prospects. Approximately 80% of
budgeted drilling expenditures are allocated to development activities with the
remaining 20% targeted for exploratory drilling. In addition, over 90% of
Brigham's budgeted drilling expenditures are focused in the Company's five focus
plays, which include the Frio and Vicksburg trends in the Texas Gulf Coast, the
Springer and Hunton trends in the Anadarko Basin, and the Horseshoe Atoll trend
in West Texas. In these focus plays Brigham has completed 25 wells in 28 recent
attempts, generated four significant field discoveries and achieved an average
proved developed drilling finding cost of $0.75 per Mcfe.

Brigham's actual capital expenditures in 2002 may differ from the estimates
discussed herein based upon cash flow and capital availability during the year.
See "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources" There can be no
assurance that any potential drilling locations identified by Brigham will be
drilled at all or within the expected time frame. The final determination with
respect to the drilling of any well, including those currently budgeted, will
depend upon a number of factors, including:

- the availability of leases on reasonable terms and permitting for the
potential drilling location;

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

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

- the availability of sufficient capital resources by Brigham and other
participants to fund drilling and completion expenditures.

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

ANADARKO BASIN

The Anadarko Basin is a prolific natural gas province that Brigham believes
offers a combination of lower risk exploration and development opportunities in
shallower horizons and deeper, higher potential objectives that have been
relatively under explored. This province has produced approximately 100 Tcfe to
date from numerous, historically elusive stratigraphic targets, such as the Red
Fork, Upper Morrow and Springer channel sands, as well as from deeper, higher
potential structural objectives, such the Lower Morrow sandstones and the Hunton
and Arbuckle carbonates. In some cases, these objectives have produced in excess
of 50 Bcf of natural gas from a single well at rates of up to 30 MMcf of natural
gas per day. In addition, drilling economics in the Anadarko Basin are enhanced
by the multi-pay nature of many of the prospects, with secondary or tertiary
targets serving as either incremental value or as a bailout alternative in the
event the primary target zone is not productive.

Each of the stratigraphic and structural objectives in the Anadarko Basin
can provide excellent targets for 3-D seismic imaging. Brigham has assembled an
extensive digital database in this province,

12

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 delineated drilling prospects.

As of December 31, 2001, Brigham had accumulated 2,259 square miles
(1.4 million acres) of 3-D seismic data in the Anadarko Basin. Since 1994,
Brigham has completed 104 (37.8 net) wells in 133 (48.8 net) attempts for a net
completion rate of 77% and has found cumulative net proved reserves of 81 Bcfe
at an average drilling finding cost of $0.60 per Mcfe. For the three-year period
ended December 31, 2001, Brigham completed 33 (11.8 net) wells in 38 (13.0 net)
attempts in the Anadarko Basin for a net completion rate of 91%. The Company
retained an average working interest of 34% in these wells and added 33
net Bcfe of proved reserves at an average drilling finding cost of $0.47 per
Mcfe.

For 2002, Brigham intends to focus the majority of its Anadarko Basin
drilling activities in the following key focus trends:

SPRINGER TREND

Brigham's inventory of 3-D projects in the Springer trend consists of
approximately 630 square miles of 3-D seismic data covering approximately
400,000 acres in Dewey, Blaine, Canadian and Caddo Counties, Oklahoma. These
projects target stratigraphic fluvial sand channels in the Springer-aged Old
Woman and Britt intervals, as well as secondary objectives including the Morrow.

Brigham initiated the acquisition of 3-D seismic data in the area in 1991 by
acquiring a 13 square mile program, and subsequently acquired 14 square miles in
1994, and 219 square miles in 1996. To capitalize on its prior experiences and
successes in the play, the Company accelerated its 3-D acquisitions in the trend
in 1997 and 1998, when it acquired 383 square miles of 3-D seismic data with an
average working interest of 72%. The processing of the majority of this data was
completed in 1998 and 1999, and Brigham's interpretation and prospect generation
efforts are still underway.

In May 2000, Brigham completed the Price #2, a 3-D delineated Springer
channel test in Blaine County, Oklahoma. The Company retained a 71% working
interest and 56% net revenue interest in the discovery, which began producing to
sales at a curtailed rate of approximately 3.5 MMcf of natural gas and 350
barrels of condensate per day. Due to increased pipeline capacity, production
rates were increased in December 2000 to approximately 6.5 MMcf of natural gas
and 250 barrels of condensate per day. At year-end 2001, the Price #2 had
produced 2.7 Bcfe and was producing approximately 2.4 MMcfe per day. During
2001, Brigham drilled the Price #3, a successful offset to its earlier Price #2
discovery. Brigham operated the Price #3 and retained a 41% net revenue interest
in the well, which began producing to sales in May 2001 at 2.8 MMcf of natural
gas and 70 barrels of condensate per day. At year-end 2001, the Price #3 had
produced 0.5 Bcfe and was producing approximately 1.3 MMcfe per day.

In February 2001, Brigham completed the Zachary #1, another Springer channel
discovery, which was drilled to a total depth of approximately 9,750 feet. The
Company began producing the well to sales in March 2001 at a pipeline-curtailed
rate of approximately 2.2 MMcf of natural gas and 75 barrels of condensate per
day. In April 2001, the production rate was increased to approximately 6.0 MMcf
of natural gas and 200 barrels of condensate per day, or approximately
1.4 MMcfe per day to Brigham's 20% net revenue interest. At year-end, 2001 the
Zachary #1 had produced 2.0 Bcfe and was producing approximately 8.4 MMcfe per
day. In July 2001, Brigham completed two offset wells to this discovery. The
Company retained a 24% working interest and 20% net revenue interest in the
first offset, which began producing to sales in September 2001 at
3.3 MMcfe per day. Brigham retained a 47% working interest and 38% net revenue
interest in the second offset, which also began producing to sales in
September 2001 at 2.1 MMcfe per day. The Company plans to stimulate both of
these wells in early 2002.

13

Since 2000, Brigham has completed six Springer channel tests in eight
attempts at an estimated proved developed drilling finding cost of $0.58 per
Mcfe. Based on this recent drilling success, Brigham plans to drill four to six
Springer channel tests in 2002. These wells target similar objectives as its
previous producers, and the Company expects to retain an average working
interest of approximately 35% in these planned wells.

HUNTON TREND

Brigham's 3-D seismic inventory in the deep Hunton play of the southwestern
portion of the Anadarko Basin consists of approximately 763 square miles of 3-D
seismic data covering approximately 488,000 acres in the southern portion of the
Texas Panhandle in Wheeler, Hemphill and Roberts Counties, Texas and Beckham
County, Oklahoma. The primary exploration targets within these projects are high
potential, structural features at depths ranging from 7,500 to 25,000 feet.

Brigham initiated acquisition of data in the Hunton trend in 1994 when it
retained a 25% working interest in 67 square miles of 3-D seismic. Following
Brigham's 3-D seismic acquisition in 1994, it acquired an additional 85 square
miles of 3-D seismic (average working interest of 15%) in 1995, 254 square miles
(average working interest of 30%) in 1996, and 123 square miles (average working
interest of 38%) in 1997. Based upon the interpretation of these data sets
Brigham acquired an additional 99 square miles of 3-D data in 1998 where it
retained a 100% working interest. In 2001, Brigham traded ownership interest in
a less active 3-D project to obtain an additional 135 square miles of 3-D
seismic data in the Hunton trend.

MILLS RANCH FIELD

In July 2000, Brigham spud the Mills Ranch #1, which targeted a large high
potential Hunton structure adjacent to a currently producing Hunton well that
has produced over 15 Bcfe. The Company operated and retained a 64% working
interest in the well, which was drilled directionally to a total depth of over
25,000 feet. Brigham completed the discovery in the targeted Hunton formation in
December 2000. The well encountered approximately 1,200 feet of gross pay and
340 feet of measured depth net pay (240 feet of calculated true vertical net
pay) in three Hunton intervals. The well began producing to sales from one
Hunton interval in January 2001 at approximately 9.5 MMcf of natural gas and 90
barrels of condensate per day, or 5.1 MMcfe per day to Brigham's 51% net revenue
interest. As of December 31, 2001 the Mills Ranch #1 had produced 1.9 Bcfe and
was producing approximately 4.0 MMcfe per day.

The Company estimates its proved developed drilling finding cost for the
Mills Ranch discovery well was $0.31 per Mcfe, and currently plans to drill an
offset well during 2002 or early in 2003.

TEXAS GULF COAST

The onshore Texas Gulf Coast region is a high potential, multi-pay province
that lends itself to 3-D seismic exploration due to its substantial structural
and stratigraphic complexity. Brigham was attracted to the Gulf Coast province
because of the opportunity to apply its established 3-D seismic exploration
approach and its exploration staff's extensive Gulf Coast experience to a
prolific, structurally complex province with the potential to discover
significant natural gas reserves with associated high production rates. Brigham
has assembled a digital database including geographical, production, geophysical
and geological information that it evaluates on CAEX workstations.

A portion of Brigham's 3-D seismic data acquisition in the Texas Gulf Coast
has been accomplished through participation in certain non-proprietary, or
speculative, seismic programs. By converting certain of Brigham's proprietary
seismic projects in core exploration areas to speculative data, Brigham was able
to leverage these proprietary projects for access to substantially larger
non-proprietary speculative data for minimal or no additional cost. While
increasing its exposure to

14

competition in speculative seismic programs, Brigham believes this 3-D seismic
acquisition strategy in the Gulf Coast, in certain circumstances, can accelerate
the addition of attractive potential drilling locations in targeted trends at
costs that are considerably less than those associated with proprietary 3-D
seismic programs, thereby enhancing the expected project rate of return.

As of December 31, 2001, Brigham had accumulated 2,233 square miles
(1.4 million acres) of 3-D seismic data in its Texas Gulf Coast province. The
Company began to acquire 3-D seismic in the Texas Gulf Coast in 1995 when it
acquired 39 square miles of 3-D seismic data. Brigham subsequently acquired 115
square miles in 1996, and in 1997 and 1998 accelerated its acquisition of 3-D
seismic data by acquiring approximately 990 square miles in the plays it
believed would provide optimal 3-D drilling economics. The Company further
capitalized on its experience by retaining an average working interest of 78% in
this newly acquired data. In 2001, Brigham exchanged licensing rights in certain
non-core 3-D data volumes for licenses to additional 3-D seismic data programs
located in Brigham's focus plays in the Texas Gulf Coast. As a result, Brigham
added approximately 1,100 square miles of 3-D seismic data in the Texas Gulf
Coast in 2001, with very little capital investment. The Company believes that by
applying its knowledge base and expertise to this newly acquired 3-D seismic
data it should generate additional drilling inventory in its current focus
plays. One of Brigham's 2001 Frio discoveries was drilled on this recently
acquired data.

Since 1996 Brigham has completed 59 (21.7 net) wells in 75 (27.3 net)
attempts in the Texas Gulf Coast for a net completion rate of 79%. Brigham has
discovered cumulative net proved reserves of 60 Bcfe at an average net drilling
finding cost of $0.85 per Mcfe. For the three-year period ended December 31,
2001, Brigham completed 34 (10.8 net) wells in 43 (14.5 net) attempts in the
Texas Gulf Coast for a net completion rate of 74%. Brigham retained an average
working interest in these wells of 34% and added approximately 36 net Bcfe of
proved reserves at an average drilling finding cost of $1.02 per Mcfe.

For 2002, Brigham intends to focus the majority of its Texas Gulf Coast
drilling activities in the following key focus plays:

VICKSBURG TREND

Brigham has made two significant field discoveries (Home Run Field and
Triple Crown Field) in the Vicksburg trend since 1999. Brigham and its
participant, a major integrated oil company, acquired a 54 square mile program
in 1997 and 1998, and jointly control 10,000 gross and net acres of leasehold.
Brigham retained a 34% working interest in the project to explore and develop
the Vicksburg formation below 10,000 feet, but increased its pre-payout working
interest to 50% in select acreage that was subsequently drilled as its Triple
Crown Field discovery. Also in the project, in the prospective zones above
10,000 feet, the Company retained a 100% working interest in its original 4,000
acre lease block. Since 1999, excluding the Palmer #5 well (which experienced a
casing failure) Brigham has completed eight Vicksburg wells in eight attempts at
an estimated proved developed drilling finding cost of $1.47 per Mcfe.

HOME RUN FIELD

Brigham discovered the Home Run Field in late 1999 with its Palmer State #2
discovery well. The Brigham operated Palmer State #2 began producing in
February 2000 at an initial rate of 10.1 MMcf of natural gas and 650 barrels of
condensate per day, or 4.1 MMcfe to Brigham's 29% net revenue interest. At
year-end 2001, the Palmer #2 had produced 3.2 Bcfe and was producing
2.0 MMcfe per day.

In 2001, Brigham completed four wells in its Home Run Field. Two of these
wells, the Palmer #4 and the D.J. Sullivan #C-25, were spud in the fourth
quarter of 2000 and completed during the first quarter of 2001. Brigham retained
a 34% working interest in both wells. The Palmer #4, an offset to

15

the previously drilled Palmer #2 and Palmer #3 wells, was drilled to a total
depth of approximately 13,550 feet and encountered prospective pay intervals in
several of the targeted Lower Vicksburg objectives. The Palmer #4 was fracture
stimulated in four Vicksburg pay intervals and began producing to sales in
March 2001 at 6.8 MMcf of natural gas and 280 barrels of condensate per day, or
2.5 MMcfe net to Brigham's 29% net revenue interest. The D.J. Sullivan #C-25
began producing to sales in March at 9.8 MMcf of natural gas and 390 barrels of
condensate per day, or 3.0 MMcfe net to Brigham's 25% net revenue interest. At
year-end 2001, the D.J. Sullivan #C-25 had produced 1.5 Bcfe and was producing
3.1 MMcfe per day.

During August 2001, Brigham drilled the Palmer #5, its fourth successive
development well in the Home Run Field and encountered pay intervals comparable
to the previously completed D.J. Sullivan #C-25 well. Subsequent to fracture
stimulation, Brigham's initial completion of one of several potential pay
intervals in the Palmer #5 tested at an estimated 1.6 MMcf of natural gas per
day. However, surface production facilities subsequently plugged with large
pieces of formation and steel casing fragments, and repeated attempts to restore
the well to production were unsuccessful. The Company believes that the well's
problems were created by a poor cement job caused by a casing failure during
cementing operations. As a result, Brigham is currently pursuing compensation
for losses, and anticipates drilling a replacement well late in 2002. See "Item
3. Legal Proceedings"

In November 2001, Brigham completed and began producing to sales the D.J.
Sullivan #C-27 at 11.3 MMcf of natural gas and 506 barrels of condensate per
day, or 3.6 MMcfe per day to Brigham's 25% net revenue interest. Brigham
completed the D.J. Sullivan #C-28 in January 2002, which began producing to
sales in February at 9.3 MMcfe per day, or 2.3 MMcfe per day to Brigham's 25%
net revenue interest.

Excluding the Palmer #5, which experienced a casing failure, Brigham has
completed six consecutive wells in its Home Run Field. The Company believes the
field could require ten to twenty additional wells for full development.
Excluding the undeveloped reserves in this field, and excluding the Palmer #5
(which the Company anticipates will be redrilled) Brigham estimates it has
achieved an average proved developed drilling finding cost of $1.36 per Mcfe.
The Company plans to drill two to three development wells in the Home Run Field
during 2002 and expects to retain an average working interest of approximately
34% in these planned wells.

TRIPLE CROWN FIELD

In October 2001, Brigham completed the Dawson #1, which was drilled as an
exploratory test of one of several downthrown fault blocks adjacent to the
Company's Home Field in Brooks County, Texas. The Dawson #1 was drilled to a
depth of 14,256 feet and encountered approximately 179 feet of net pay in seven
Vickburg sand intervals. Approximately 149 feet of the net pay was located in
the Upper Vicksburg and 25 feet of apparent pay in the Lower Vicksburg. Brigham
retained a 50% working interest and 37.5% net revenue interest in the well,
which is subject to a back in working interest that ultimately reduces Brigham's
working interest in the well to 42% at 200% payout.

Given the volume of apparent pay in the well, Brigham's completion plans
were similar to the procedures utilized in completing Lower Vicksburg sand
intervals in the Company's Home Run Field, including the sequential perforation
and fracture stimulation of each of seven pay intervals, all of which were to be
subsequently commingled. Individual production tests from three Lower Vicksburg
intervals ranged from 300 Mcf of natural gas per day with flowing tubing
pressure of 1,000 psi to 3.6 MMcf of natural gas and 54 barrels of
condensate per day with flowing tubing pressure of 5,800 psi. The Company
subsequently tested the "Loma Blanca" interval in the Upper Vicksburg at
2.3 MMcf of natural gas per day with flowing tubing pressure of 7,320 psi.

Brigham's interpretation of wireline logs and drilling shows indicated that
the highest production rates in the Dawson #1 well should have been achieved by
producing three Upper Vicksburg "9800"

16

sand lobes (the "A", "B" and "C"). However, subsequent to fracture stimulation
of both the "B" and "C" zones, the well tested both natural gas and significant
quantities of formation sand. Brigham subsequently stimulated the 9800 "A" zone
utilizing a fracture stimulation and completion technique designed to limit
production of formation sand (a "fracpack"). As a result the Dawson #1 began
producing to sales in November 2001, from only the shallowest of several pay
intervals at 3.4 MMcf of natural gas and 24 barrels of condensate per day with
flowing tubing pressure of 6,000 psi. At year-end 2001, the Dawson #1 was
producing approximately 2.5 MMcfe per day.

Brigham completed its first development well in the Triple Crown Field in
November 2001. The Company retained a 50% working interest and 37.5% net revenue
interest in the Sullivan #1, which encountered the objective Upper and Lower
Vicksburg sands approximately 200 feet structurally low to the Dawson #1
discovery well with diminished reservoir quality sands. As a result, the
production performance of the Sullivan #1 has been disappointing.

In late December 2001, Brigham spud the Sullivan F-31, its second
development well in the Triple Crown Field. Brigham retained a 42% working
interest and 31% net revenue interest in the Sullivan F-31, which encountered
approximately 65 feet of apparent Upper Vicksburg net pay with porosity greater
than 15%, including several intervals with porosity as high as 26%. Given the
quality of the pay, and the risk associated with drilling deeper for Lower
Vicksburg sands that the Company found to be productive in the Dawson #1
discovery well, Brigham decided to set casing and complete the well in the Upper
Vicksburg. The Company plans to fracture stimulate the various productive
intervals in the well beginning in March and to subsequently commingle and
produce all zones to sales by May 2002.

Brigham plans to drill between two and four development wells in the Triple
Crown Field in 2002 and expects to retain an average working interests of 42%
and 34% in these wells.

FRIO TREND

In the Frio trend of the Upper Texas Gulf Coast, Brigham has accumulated an
inventory of over 1,088 square miles of predominantly non-proprietary 3-D
seismic data. The Company added over 500 square miles of this data in 2001 by
exchanging licensing rights in non-core 3-D data volumes. This trade was
intended to capitalize on Brigham's recent success in the Frio play and
supplement its inventory of 3-D delineated drilling prospects. In this trend
Brigham is targeting both the shallow, non-pressured and the deeper, pressured
Frio sands.

Several high production rate 3-D delineated drilling discoveries ignited the
Frio play in the mid to late 1990's. In Matagorda County, Texas, in 1998 a 3-D
discovery and two offset wells were each completed at initial rates of over
40 MMcfe per day. These three wells averaged over 10 Bcfe of production in their
first year, and produced a total of approximately 40 Bcfe in less than eighteen
months, thus illustrating the play's potential for generating extraordinary
production rates.

Late in 2000, Brigham completed a high rate Frio bright spot discovery in
Matagorda County, Texas. This discovery began producing to sales in
December 2000 at 10.0 MMcf of natural gas and 200 barrels of condensate per day,
or 2.1 MMcfe net to Brigham's 18.75% revenue interest. In February 2001, Brigham
drilled and completed a subsequent Frio bright spot discovery that began
producing to sales in March 2001 at 17.5 MMcf of natural gas and 290 barrels of
condensate per day, or 4.4 MMcfe net to Brigham's 23% net revenue interest.

In April 2001, Brigham completed its third consecutive Frio bright spot
discovery, the Pitchfork Ranch #1, which began producing to sales in early
May 2001 at 12.1 MMcfe, or 2.8 MMcfe per day to the Company's 23% net revenue
interest. Brigham completed its fourth consecutive Frio bright spot discovery in
August 2001. The Heckendorn #1 began producing to sales at 6.5 MMcfe per day, or
1.0 MMcfe per day to Brigham's 15% net revenue interest. After drilling a dry
hole in the third quarter 2001, the Company completed its fifth Frio test in six
recent attempts, in Brazoria County, Texas. The

17

Sebesta Cloud #1 began producing to sales at 2.4 MMcfe per day, or
0.6 MMcfe per day to Brigham's 24% net revenue interest.

Brigham has developed particular expertise in the Frio play that it believes
is contributing to its recent drilling success. As a result, since late 2000,
Brigham has completed six Frio tests in seven attempts and has achieved an
estimated drilling finding cost for proved developed reserves of $0.73 per Mcfe.

PROVIDENCE FIELD

During the fourth quarter of 2001, Brigham drilled and completed a
significant Frio test targeting a large structure with multiple pay sands.
Brigham operated and retained a 41% working interest and 31% net revenue
interest in the Staubach #1, which reached total depth in December and
encountered approximately 36 feet of net pay in the over pressured Frio
formation. In February 2002, Brigham began producing this well to sales at
approximately 2,000 barrels of oil and 5.0 MMcf of natural gas per day, or
approximately 5.3 MMcfe per day to Brigham's 31% net revenue interest. The
Company believes that the field could require four to six wells to fully
develop. Brigham spud the first offset to this discovery, the Burkhart #1, in
March 2002. The Company operates and retained a 41% working interest in the
well.

In 2002, Brigham plans to drill between five and seven wells in the Frio and
expects to maintain an average working interest of 41% in these wells.

WEST TEXAS

Brigham's drilling activity in its West Texas province has been focused
primarily in the Horseshoe Atoll trend, the Midland Basin and the Eastern Shelf
of the Permian Basin and in the Hardeman Basin. In response to reduced market
prices for oil and comparatively higher potential natural gas projects in its
Anadarko Basin and Gulf Coast provinces, Brigham substantially reduced its 3-D
seismic acquisition and drilling activities in West Texas during 1998 and 1999.
In response to improved oil prices during 2000 and the first half of 2001,
Brigham began reprocessing and reinterpreting certain 3-D seismic projects in
its West Texas 3-D seismic projects.

As of December 31, 2001, Brigham had accumulated 2,141 square miles
(1.4 million acres) in its West Texas province. Since 1990, Brigham has
completed 189 (46.4 net) wells in 305 (77.7 net) attempts for a net completion
rate of 60% and an average working interest of 25%. During this period, Brigham
has added cumulative net proved reserves of 27 Bcfe at an average net drilling
finding cost of $1.15 per Mcfe. For the three-year period ended December 31,
2001, Brigham completed four (3.4 net) wells in seven (4.5 net) attempts for a
net completion rate of 76% and an average working interest of 64%. During this
same three-year period, Brigham has added 7.5 net Bcfe of proved reserves at an
average net drilling finding cost of $0.52 per Mcfe.

HORSESHOE ATOLL TREND

Brigham has completed four consecutive oil discoveries in the Horseshoe
Atoll trend in West Texas that have positively impacted the Company's net oil
production. The first of these was completed in February 2001, when Brigham
successfully drilled a 9,400 foot Canyon Reef test that logged over 90 feet of
reef pay. This discovery began producing to sales in March 2001 at 200 barrels
of oil per day, or 140 barrels per day to Brigham's 71% net revenue interest. At
year-end 2001, this well had produced a cumulative 58,000 barrels of oil and was
producing approximately 180 barrels of oil per day.

18

In April 2001, Brigham retained a 100% working interest in its second
consecutive Horseshoe Atoll trend discovery, which encountered approximately 100
feet of pay in the Canyon Reef at a depth of 9,100 feet. This discovery began
producing to sales at 250 barrels of oil per day, or 200 barrels of oil per day
to the Company's 80% net revenue interest. At December 31, 2001, this well had
produced a cumulative 57,000 barrels of oil and was producing approximately 230
barrels of oil per day.

Also in April 2001, Brigham retained a 55% working interest in its third
consecutive Horseshoe Atoll trend discovery. This well was completed in the
targeted Fusselman formation, and began producing to sales at 170 barrels of oil
per day, or 80 barrels per day to Brigham's net revenue interest. At
December 31, 2001, this well had produced a cumulative 21,000 barrels of oil,
and was producing approximately 47 barrels of oil per day.

In May 2001, Brigham retained a 100% working interest in its fourth
consecutive Horseshoe Atoll trend discovery, which encountered approximately
179 feet of Canyon Reef pay at a depth of approximately 9,400 feet. This
discovery began producing to sales in May at 250 barrels of oil per day, or 193
barrels per day to Brigham's 77% net revenue interest. At December 31, 2001 this
well had produced a cumulative 55,000 barrels of oil and was producing
approximately 200 barrels of oil per day.

In the Horseshoe Atoll trend of West Texas, Brigham has completed four wells
in four recent attempts at an estimated average drilling finding cost for proved
developed reserves of $0.48 per Mcfe. In 2002, Brigham plans to drill up to six
wells in the Horseshoe Atoll trend. The Company has sold a portion of its
working interest to industry participants on a promoted basis, thus the majority
of its drilling costs will be carried to casing point. Brigham expects to retain
an average 35% working interest after casing point in these wells.

19

OIL AND NATURAL GAS RESERVES

Brigham's estimated total net proved reserves of oil and natural gas as of
December 31, 1999, 2000 and 2001 and the present values attributable to these
reserves as of those dates were as follows:

The reserve estimates reflected above were prepared by Cawley, Gillespie &
Associates, Inc. ("Cawley Gillespie"), Brigham's independent petroleum
consultants, and are part of reports on Brigham's oil and natural gas properties
prepared by Cawley Gillespie. The base sales prices for Brigham's reserves were
$2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31,
1999, $10.42 per Mcf for natural gas and $26.83 per Bbl for oil as of
December 31, 2000, and $2.57 per Mcf for natural gas and $19.84 per Bbl for oil
as of December 31, 2001. These base prices were adjusted to reflect applicable
transportation and quality differentials on a well-by-well basis to arrive at
realized sales prices used to estimate Brigham's reserves at these dates.

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

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

20

DRILLING ACTIVITIES

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

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

(1) Excludes one gross (1.0 net) exploratory well that was temporarily abandoned
during drilling due to operational difficulties encountered prior to
reaching total depth. Brigham re-entered and completed this temporarily
abandoned well during 2001.

(2) From January 1, 2002 through March 22, 2002, Brigham drilled, or
participated in the drilling of one gross (0.4 net) exploratory well, which
was non-productive. In addition, Brigham is carried for a 25% working
interest in the drilling and completion of a second exploratory well that
was drilling at March 22, 2002.

(3) From January 1, 2002 through March 22, 2002, Brigham drilled, or
participated in the drilling of, one gross (0.4 net) development well which
was in the process of drilling at March 22, 2002.

Brigham does not own any drilling rigs and the majority of its drilling
activities have been conducted by independent contractors or industry
participant operators under standard drilling contracts. Brigham operated 45% of
the gross and 67% of the net wells it participated in during 2001.

PRODUCTIVE WELLS AND ACREAGE

PRODUCTIVE WELLS

The following table sets forth Brigham's ownership interest as of
December 31, 2001 in productive oil and natural gas wells in the areas
indicated.

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, two had multiple completions.

21

ACREAGE

Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves. The following table sets forth the approximate
developed and undeveloped acreage in which Brigham held a leasehold, mineral or
other interest at December 31, 2001:

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:

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

(1) Total undeveloped leasehold includes 1,904 gross and 1,229 net mineral
acres, which are not included in total undeveloped acres expiring.

In addition, Brigham had lease options as of December 31, 2001 to acquire an
additional 1,759 gross and 1,426 net acres, all of which expire in 2002.

VOLUMES, PRICES AND PRODUCTION COSTS

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

22

COSTS INCURRED

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

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

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

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

(3) Excludes $262,000 of proceeds from the sale of interests in properties,
projects and prospects in 2001.

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

23

ITEM 3. LEGAL PROCEEDINGS

On November 20, 2001, the Company filed a lawsuit in the District Court of
Travis County, Texas, against Steve Massey Company, Inc. ("Massey") for breach
of contract. The Petition claims Massey furnished defective casing to the
Company, which ultimately led to the casing failure of the Palmer "347" No. 5
Well (the "Palmer #5") and the loss of the Palmer #5 as a producing well. The
Company believes the amount of damages incurred by it due to loss of the
Palmer #5 may exceed $5 million. Massey joined as additional defendants to the
lawsuit other parties that had responsibility for the manufacture, importation
or fabrication of the casing for its use in the Palmer #5. The case is currently
in discovery. A trial has not been set, but the Company believes a trial will
not take place before the first quarter of 2003.

On February 20, 2002, Massey filed an Original Petition to Foreclose Lien in
Brooks County, Texas. Massey's Petition claims the Company breached its contract
for failure to pay for the casing it furnished the Company for the Palmer #5
(and that the Company's claim is defective, forming the basis of the lawsuit
described in the paragraph above). Massey's Petition claims the Company owes
Massey a total of $445,819. The Company recently filed a Motion to Transfer
Venue to Travis County, Texas, to join this case with the Company's suit against
Massey pending in Travis County. In the addition, the Company has asked for a
Plea in Abatement to place the case on hold until after the Travis County suit
has been resolved. If Massey is successful in its Brooks County case, Massey
would have the right to foreclose its lien against the well, associated
equipment and the Company's leasehold interest. At this point in time, the
Company cannot predict the outcome of either the Travis County case or the
Brooks County case.

On June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed
suit against the Company, claiming the Company transported natural gas under his
property through an existing pipeline, without his consent. The Company is now
using an alternate pipeline. Mr. Garcia is claiming $1.2 million in actual
damages and $3 million in exemplary damages. The Company is strenuously
defending this lawsuit, believing there is no basis for the damages being
claimed. The case has been set for mediation on May 2, 2002. At this point in
time, the Company cannot predict the outcome of this case.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

No matter was submitted to a vote of Brigham's securityholders during the
fourth quarter of 2001.

24

EXECUTIVE OFFICERS OF THE REGISTRANT

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

The following table sets forth certain information concerning Brigham's
executive officers as of March 20, 2002:

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

BEN M. "BUD" BRIGHAM has served as Chief Executive Officer, President and
Chairman of the Board since founding Brigham 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, Senior Vice
President--Land and Administration and Corporate Secretary.

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

DAVID T. BRIGHAM joined Brigham in 1992 and has served as Senior Vice
President--Land and Administration and Corporate Secretary since March 2001.
Mr. Brigham served as Vice President--Land and Administration and Corporate
Secretary from February 1998 to March 2001, and as Vice President--Land and
Legal of Brigham 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 worked as a landman for a short period of time
for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration
and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management
from the University of Texas and a J.D. from Texas Tech School of Law.
Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President
and Chairman of the Board.

A. LANCE LANGFORD joined Brigham as Manager of Operations in 1995 and served
as Vice President--Operations from January 1997 to March 2001, and as Senior
Vice President--Operations

25

since March 2001. From 1987 to 1995, Mr. Langford served in various engineering
capacities with Meridian Oil Inc., handling a variety of reservoir, production
and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum
Engineering from Texas Tech University.

JEFFERY E. LARSON joined Brigham in 1997 and served as Vice
President--Exploration from August 1999 to March 2001, and as Senior Vice
President--Exploration since March 2001. Mr. Larson joined Brigham in
October 1997 as Gulf Coast Exploration Manager in its Houston office where he
co-managed Brigham's expansion into the onshore Gulf Coast province through the
initiation and assemblage of 3-D seismic projects and drilling opportunities. In
November 1998, Mr. Larson relocated to Brigham's corporate office in Austin
where he assumed an expanded role in directing Brigham's exploration activities
in the Anadarko Basin, in addition to the further advancement of its Gulf Coast
activities. Prior to joining Brigham, Mr. Larson was an explorationist in the
Offshore Department of Burlington Resources, a large independent exploration
company, where he was responsible for generating exploration and development
drilling opportunities. Mr. Larson worked at Burlington for seven years in
various roles of increasing responsibility within its exploration and production
departments. 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.

26

PART II

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

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

The closing market price of Brigham's common stock on March 22, 2002 was
$3.55 per share. As of March 22, 2002, there were an estimated 112 record owners
of Brigham's common stock.

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

Brigham is obligated to pay dividends on its Series A Preferred Stock which
may be paid, at Brigham's option, in cash at a rate of 6% per annum or in
additional shares of Series A Preferred Stock at a rate of 8% per annum for a
period of five years. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital
Resources--Equity Placements Stock--Series A Preferred Stock" and "--Liquidity
and Capital Resources--Equity Placements Stock--Additional Series A Preferred
Stock")

27

ITEM 6. SELECTED FINANCIAL DATA

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

28

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

OVERVIEW

In 1999, Brigham outlined a business strategy that would enable the
recognition of the inherent value of its 3-D delineated prospect inventory and
would provide significant improvement in its financial and operating results.
This business strategy includes the following elements:

- FOCUS THE MAJORITY OF CAPITAL RESOURCES TOWARD DRILLING ACTIVITIES WITHIN
ITS FIVE FOCUS PLAYS TO GENERATE GROWTH IN PROVED RESERVES, PRODUCTION
VOLUMES AND CASH FLOW. In 2001, relative to 2000, Brigham grew its oil and
natural gas reserves by 17%, its equivalent production volumes by 45%, and
its operating cash flow before changes in working capital by 111%. The
Company's net completion rate was 89% for 2001 and was 81% for the
three-year period ended 2001. All-sources finding cost for 2001 were
$1.23 per Mcfe and were $1.00 per Mcfe for the three-year period ended
2001. Average drilling finding cost for 2001 were $0.93 per Mcfe and,
since 1999, have been $0.74 per Mcfe. This focus has also resulted in the
discovery of four potentially substantial fields.

- IMPROVE CASH FLOW MARGINS AND RETURN ON INVESTED CAPITAL BY CONTROLLING
COSTS. For 2001, discretionary unit operating costs were $0.74 per Mcfe,
down 28% from $1.03 per Mcfe in 1998. This lower cost structure, combined
with higher oil and gas revenue per unit of equivalent production, has
resulted in an increase in gross profit per unit of equivalent production
from $0.98 per Mcfe in 1998 to $2.50 per Mcfe in 2001. In addition,
Brigham's reduced debt levels have led to a decline in net interest
expense (net of interest income) per unit of production, from $1.52 per
Mcfe in 1999 and $1.48 per Mcfe in 2000 to $0.67 per Mcfe in 2001. As a
result, unit cash flow improved from ($0.15) per Mcfe in 1999 and
$0.37 per Mcfe in 2000 to $1.83 per Mcfe in 2001, and cash flow margins
improved from (6%) in 1999 and 13% in 2000 to 54% in 2001.

- ALLOCATE A HIGHER PERCENTAGE OF DRILLING CAPITAL TOWARD THE DEVELOPMENT OF
ITS PRIOR DISCOVERIES. Prior to 2000, a majority of Brigham's drilling
capital expenditures were allocated to exploration-oriented projects. Due
to the success of Brigham's past exploration drilling programs and the
discovery of the Home Run Field and Mills Ranch Field, over 50% of the
Company's 2001 drilling capital expenditures were developmental.

- EXECUTE AN ACTIVE, HIGH POTENTIAL EXPLORATION DRILLING PROGRAM WITHIN ITS
LARGE INVENTORY OF EXPLORATION PROSPECTS. In 1999, Brigham began focusing
its drilling investments in the five plays in its three core provinces
that the Company believed provided excellent 3-D delineated drilling
economics. These focus plays include the Vicksburg and Frio trends in the
onshore Texas Gulf Coast, the Springer and Hunton trends in the Anadarko
Basin and the Horseshoe Atoll trend of West Texas. In these trends,
Brigham has completed 25 wells in its 28 most recent attempts, and in the
process discovered the Home Run Field in 1999, the Mills Ranch Field in
2000 and the Triple Crown Field and Providence Field in 2001. For 2001,
approximately 44% of Brigham's drilling capital was spent on exploration
drilling and approximately 85% was allocated to Brigham's five focus plays
where the Company has achieved significant recent drilling success.

- LEVERAGE PRIOR INVESTMENTS TO MITIGATE RISK AND ENHANCE ITS CORPORATE RATE
OF RETURN. 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 advantage in attracting
participants to invest in its projects. Often times, Brigham can recoup a
portion of its initial capital investment on a promoted basis.
Historically, Brigham has been effective at raising capital and attaining
promoted working interests in its 3-D seismic projects and prospects,
thereby utilizing leverage extensively to manage its risk and enhance its
corporate rate of return. Given the depth

29

of Brigham's land and 3-D seismic inventory, and in particular the
Company's inventory of 3-D delineated drilling prospects, Brigham plans to
again leverage its investments in 2002.

2001 RESULTS

The year ended December 31, 2001, was a highly successful year for Brigham.
Driven by the Company's active drilling program, total production for 2001
increased 45% over total production for 2000, to average 26.6 MMcfe per day.
Compared to 2000, revenue from the sale of natural gas and oil increased 69% to
$32.3 million, EBITDA increased 90% to $22.7 million, net interest expense
decreased 33% to $6.7 million, and operating cash flow before working capital
items increased 111% to $18.1 million.

At year-end 2001, Brigham's proved reserves totaled 3.7 MMbbls of oil and 89
Bcf of natural gas. Proved reserves were 80% natural gas, 49% proved developed
and distributed 46% in its Texas Gulf Coast province, 43% in the Anadarko Basin
and the remaining 11% in its West Texas province. For 2001, the Company
completed 27 (10.4 net) wells in 33 (11.7 net) attempts for a completion rate of
82% (89% net). The Company spent $27.0 million on drilling and added 29 Bcfe in
proved reserves, replacing 306% of its 2001 production of 9.6 Bcfe.

2002 OUTLOOK

The Company's capital spending budget for 2002 is $23.7 million. The
majority of Brigham's planned 2002 expenditures will be directed toward the
drilling of its prospect inventory in a continued effort to focus resources on
its primary objective of growing production volumes and cash flow. For 2002,
Brigham expects to drill 26 wells with an average working interest of 32%.
Capitalizing on the prior discovery of the Home Run Field, Mills Ranch Field,
Triple Crown Field and Providence Field, approximately 80% of Brigham's 2002
drilling expenditures are allocated to development drilling. Spending will be
funded by Brigham's 2002 discretionary cash flow, availability under its
Subordinated Notes Facility and by its beginning cash balance. As a result,
capital expenditures for 2002 are expected to be down approximately 34% from
2001. This decline is primarily attributable to lower forecasted oil and natural
gas prices and is subject to change if market conditions shift. In the event
that commodity prices decrease, Brigham may be required to curtail or delay some
of its planned activities.

30

RESULTS OF OPERATIONS

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

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

(1) Reflects the effects of Brigham's hedging activities. See "--Other
Matters--Derivative Instruments"

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

PRODUCTION. Net equivalent production volumes for 2001 were 9.6 Bcfe
compared to 6.6 Bcfe in 2000. Average net daily equivalent production volumes
for 2001 increased 45% to 26.6 MMcfe per day from 18.3 MMcfe per day in 2000.
This increase is the result of additional production related to wells completed
during 2001 and is offset partly by the natural decline of existing production.
Natural gas production represented 71% of total equivalent production volumes in
2001 compared to 67% in 2000. Natural gas production increased 53% from
4,431 MMcf in 2000 to 6,766 MMcf in 2001 and average net daily production
volumes for natural gas increased from 12.3 MMcf per day in 2000 to 18.8
MMcf per day in 2001. Oil production increased by 29% from 362 MBbls in 2000 to
468 MBbls in 2001. Average net daily production volumes for oil during 2001 were
1,300 barrels per day compared to 1,006 barrels per day in 2000.

REVENUE FROM THE SALE OF NATURAL GAS AND OIL. Natural gas and oil sales
increased 69% from $19.1 million in 2000 to $32.3 million in 2001. Higher net
equivalent production volumes accounted for $7.7 million of this increase while
a 16% increase in the average equivalent sales price received for natural gas
and oil sales accounted for $5.5 million of the increase.

The average realized price for natural gas increased 60% from $1.94 per Mcf
in 2000 to $3.11 per Mcf in 2001. Revenues from the sale of natural gas
increased 61% from $18.0 million in 2000 to $29.0 million in 2001. Cash
settlements on natural gas hedging contracts of $8.0 million ($1.18 per Mcf)
negatively impacted Brigham's average realized natural gas sales price and
revenues in 2001 compared to $9.4 million ($2.12 per Mcf) in cash settlements on
natural gas hedging contracts in 2000. See "--Other Matters--Derivative
Instruments"

The average realized price for oil decreased 18% from $29.17 per barrel in
2000 to $24.05 per barrel in 2001. Revenue from the sale of oil increased 7%
from $10.7 million in 2000 to $11.4 million in 2001. Revenues from the sale of
oil and Brigham's average realized oil price were negatively affected

31

by hedging losses of $153,000 ($0.33 per barrel) in 2001 compared to hedging
loses of $107,000 ($0.30 per barrel) in 2000. See "--Other Matters--Derivative
Instruments"

OTHER REVENUE. Other revenue increased 270% from $69,000 in 2000 to
$255,000 in 2001. This increase is related to an increase in transportation
revenue that Brigham receives from other parties for using its pipelines.

LEASE OPERATING EXPENSES. Lease operating expenses increased 67% from
$2.1 million in 2000 to $3.5 million in 2001. On a per unit of production basis,
lease operating expense increased 13% from $0.32 per Mcfe in 2000 to $0.36 per
Mcfe in 2001. The increase in lease operating expense was related to higher than
expected charges for well repair and maintenance, increased production volumes
from a greater total well count, and higher overall service costs.

PRODUCTION TAXES. Production taxes decreased 17% from $1.8 million ($0.27
per Mcfe) in 2000 to $1.5 million ($0.16 per Mcfe) in 2001. This decrease is
primarily related to production tax refunds on wells that qualify for reduced
severance tax rates and resulted in a decrease in Brigham's effective production
tax rate from 6.2% of pre-hedge oil and natural gas sales in 2000 to 3.7% in
2001.

GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
increased 16% from $3.1 million in 2000 to $3.6 million in 2001. This increase
was primarily due to an increase in employee payroll and benefit expenses,
office expenses, public company expenses and contract and professional expenses.
On a per unit of equivalent production basis, general and administrative
expenses decreased by 19% from $0.47 per Mcfe in 2000 to $0.38 per Mcfe in 2001.
This decrease is primarily due to increased production volumes for 2001.

DEPLETION OF OIL AND NATURAL GAS PROPERTIES. Depletion of oil and natural
gas properties increased 67% from $7.9 million in 2000 to $13.2 million in 2001.
Of this increase, $4.1 million was attributable to higher production volumes and
$1.2 million was due to an increase in the depletion rate per unit of
production. On a per unit of equivalent production basis, depletion expense
increased 15% from $1.20 per Mcfe in 2000 to $1.38 per Mcfe in 2001. The
increase in the depletion rate per unit is primarily due to an increase in the
estimated cost required to fully develop Brigham's Home Run Field.

INTEREST EXPENSE. Interest expense decreased from $9.9 million in 2000 to
$6.7 million in 2001 due to a lower weighted average outstanding debt balance
and a lower effective interest rate for 2001. Brigham's weighted average
outstanding debt balance decreased 7% from $97.4 million in 2000 to
$90.6 million in 2001. The reduction in debt was primarily attributable to the
November 2000 refinancing of its senior subordinated notes due 2003. See
"--Liquidity and Capital Resources--Refinancing Transactions" The effective
annual interest rate on Brigham's total outstanding indebtedness decreased from
12.7% in 2000 to 9.3% in 2001. In addition, interest expense for 2001 included
(i) $721,000 in interest expense that was paid in kind through the issuance of
additional debt in lieu of cash, and (ii) $1.4 million of non-cash charges
related to the amortization of deferred loan fees. Borrowings under Brigham's
Senior Credit Facility had an interest rate of 4.9% at December 31, 2001.

OTHER INCOME (EXPENSE). Other income (expense) increased from a
$9.5 million expense in 2000 to $8.1 million in income for 2001. Brigham
recognizes other income or expense primarily related to the change in the fair
market value and the related cash flows of certain oil and natural gas
derivative contracts that do not qualify for hedge accounting treatment. Other
income (expense) in 2001 included (i) $9.7 million of non-cash income related to
the change in the fair market value of derivative contracts during the period,
and (ii) $1.5 million of expenses related to cash settlements incurred during
the period pursuant to derivative contracts. Other expense in 2000 included
(i) $8.9 million of non-cash expenses related to the change in the fair market
value of derivative contracts during the

32

period, and (ii) $620,000 of expenses related to cash settlements incurred
during the period pursuant to derivative contracts.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

PRODUCTION. Net equivalent production volumes for 2000 were 6.6 Bcfe
compared to 6.3 Bcfe in 1999. Brigham's average net daily production volumes for
2000 increased 5% to 18.3 MMcfe per day compared to 17.4 MMcfe per day for 1999.
Natural gas production represented 67% of total equivalent production during
1999 and 2000. Natural gas production volumes for 2000 increased 6% from
4,197 MMcf in 1999 to 4,431 MMcf. Average net daily production volume for
natural gas was 12.3 MMcf per day in 2000 compared to 11.7 MMcf per day for
1999. Natural gas production volumes for 1999 include 442 MMcf attributable to
properties sold by Brigham in June 1999. Excluding production attributable to
these divested properties, natural gas production volumes increased 18% in 2000
as compared with adjusted production volumes in 1999. Oil production volumes for
2000 increased 5% from 346 MBbls in 1999 to 362 MBbls. Average net daily
production volume for oil during 2000 were 1,006 barrels per day compared to 961
barrels per day for 1999. Oil production volumes for 1999 include 22 MBbls
attributable to properties sold by Brigham in June 1999. Excluding production
attributable to these divested properties, oil production volumes increased 12%
in 2000 as compared with adjusted production volumes in 1999.

REVENUE FROM THE SALE OF NATURAL GAS AND OIL. Revenue from the sale of
natural gas and oil increased 27% from $15.0 million in 1999 to $19.1 million in
2000. A 21% increase in the average equivalent sales price received for natural
gas and oil sales accounted for $3.4 million and an increase in net equivalent
production volumes accounted for $780,000. The average price received for
natural gas decreased 8% from $2.11 per Mcf in 1999 to $1.94 per Mcf in 2000.
Revenues from the sale of natural gas increased 98% from $9.1 million in 1999 to
$18.0 million in 2000. Cash settlements on natural gas hedging contracts of
$9.4 million ($2.12 per Mcf) negatively impacted Brigham's average realized
natural gas sales price and revenues for 2000 versus a $486,000 ($0.12 per Mcf)
reduction in the realized natural gas sales price and revenues in 1999. See
"--Other Matters--Derivative Instruments"

The average realized price for oil increased 64% from $17.79 per Bbl in 1999
to $29.17 per Bbl in 2000. Revenue from the sale of oil increased 75% from
$6.1 million in 1999 to $10.7 million in 2000. Revenues from the sale of oil
were negatively affected by hedging losses of $107,000 ($0.30 per barrel) in
2000. There were no gains or losses on crude oil hedges during 1999. See
"--Other Matters--Derivative Instruments"

OTHER REVENUE. Other revenue decreased 76% from $285,000 in 1999 to $69,000
in 2000. Brigham recognizes workstation revenue as industry participants in its
seismic programs are charged an hourly rate for the work Brigham performs on its
3-D seismic interpretation workstations. This decrease in 2000 is primarily
attributable a reduction in the volume of 3-D seismic interpretation activity
billable to industry participants as compared with 1999.

LEASE OPERATING EXPENSES. Lease operating expenses decreased 9% from
$2.3 million ($0.36 per Mcfe) in 1999 to $2.1 million ($0.32 per Mcfe) in 2000.
This decrease was primarily due to a decrease in the number of producing wells
in 2000 as compared with 1999 that was attributable to Brigham's June 1999
property divestitures and the plugging and abandonment of certain uneconomic
wells.

PRODUCTION TAXES. Production taxes increased 86% from $968,000 ($0.15 per
Mcfe) in 1999 to $1.8 million ($0.27 per Mcfe) in 2000 primarily due to higher
average oil and natural gas sales prices and revenues before the effects of
hedging gains or losses. The effective average production tax rate decreased
from 6.3% of pre-hedge oil and natural gas sales in 1999 to 6.2% in 2000
resulting primarily from changes in the geographic distribution of Brigham's
producing wells.

33

GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses
decreased 11% from $3.5 million in 1999 to $3.1 million in 2000. This decrease
was primarily attributable to the reduction of various administrative costs,
including lower office rent due to the subleasing of a portion of Brigham's
headquarters space, reduced equipment rental and maintenance expenses, and lower
employee payroll and benefits expenses.

DEPLETION OF OIL AND NATURAL GAS PROPERTIES. Depletion of oil and natural
gas properties increased 2% from $7.8 million in 1999 to $7.9 million in 2000.
Of this increase, $396,000 was attributable to higher production volumes,
partially offset by $268,000 due to the reduction in the depletion rate per unit
of production. On a per unit of equivalent production basis, depletion expense
decreased 3% from $1.24 per Mcfe in 1999 to $1.20 per Mcfe in 2000. The decrease
in depletion rate per unit of production was primarily the result of the
addition of oil and natural gas reserves at lower average capital costs due to
improved average finding costs during 2000.

INTEREST EXPENSE. Interest expense increased from $9.7 million in 1999 to
$9.9 million in 2000 due to a higher effective interest rate that was partly
offset by a lower weighted average outstanding debt balance. The effective
annual interest rate on Brigham's total outstanding indebtedness increased
slightly from 12.6% in 1999 to 12.7% in 2000. Brigham's weighted average
outstanding debt balance decreased 2% from $99.5 million in 1999 to
$97.4 million in 2000. This reduction in debt was primarily attributable to
Brigham's refinancing of its senior subordinated notes due 2003 in
November 2000. In addition, interest expense in 2000 included (i) $4.6 million
of interest expense that was paid in kind through the issuance of additional
debt in lieu of cash, and (ii) $2.0 million of non-cash charges related to the
amortization of deferred loan fees and the amortization of discount on senior
subordinated notes. Borrowings under Brigham's Senior Credit Facility had an
effective annual interest rate of 9.7% for year-end December 31, 2000. In
November 2000, Brigham refinanced its senior subordinated notes due 2003 at a
substantial discount to the principal amount then outstanding.

OTHER INCOME (EXPENSE). Other expense increased from $163,000 in 1999 to
$9.5 million in 2000. Brigham recognizes other income or expense primarily
related to the change in the fair market value and the related cash flows of
certain oil and natural gas derivative contracts that do not qualify for hedge
accounting treatment. Other income (expense) in 2000 included (i) $8.9 million
of non-cash expense related to the change in the fair market value of these
derivative contracts during the period, and (ii) $620,000 of expenses related to
cash settlements incurred during the period pursuant to these derivative
contracts. Other income (expense) in 1999 included (i) $115,000 of non-cash
expenses related to the change in the fair market value of these derivative
contracts during the period, and (ii) $48,000 of expenses related to cash
settlements incurred during the period pursuant to these derivative contracts.

EXTRAORDINARY GAIN ON REFINANCING OF SENIOR SUBORDINATED NOTES. In
November 2000, Brigham repurchased all of the debt and equity securities in
Brigham held by affiliates of Enron North America (the "Enron Affiliates") at a
substantial discount. With a portion of the proceeds from two new financing
transactions, Brigham repurchased all of the Enron Affiliates' interests in
Brigham, which included (i) $51.2 million of senior subordinated notes due 2003
(which bore interest at annual rates of 12% to 14%) and associated accrued
interest obligations, (ii) warrants to purchase an aggregate of one million
shares of common stock at $2.43 per share, and (iii) 1,052,632 shares of common
stock (collectively, the "Enron Securities"), for total cash consideration of
$20 million. As a result of the repurchase of the senior subordinated notes due
2003 at a discount to the principal amount outstanding, Brigham recorded an
extraordinary gain of $32.3 million in the fourth quarter of 2000.

34

LIQUIDITY AND CAPITAL RESOURCES

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

The following table summarizes the Company's contractual cash obligations at
December 31, 2001 and the effect such obligations are expected to have on its
liquidity and cash flow in future periods:

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

(1) The $75 million shown as scheduled for payment in 2003 represents the
December 31, 2001 balance outstanding on the Senior Credit Facility. The
Company expects to renew as this Senior Credit Facility comes due. See
"--Liquidity and Capital Resources--Senior Credit Facility" and Note 5 of
Consolidated Financial Statements

(2) Through November 2002, up to 50% of Brigham's interest payment obligation on
its Subordinated Notes Facility can be satisfied by payment-in-kind ("PIK")
through the issuance of additional SCI Notes to Shell Capital Inc. in lieu
of cash. See "--Liquidity and Capital Resources Refinancing
Transactions--Subordinated Notes Facility" and Note 5 of Consolidated
Financial Statements

(3) See discussion in Note 8 of Consolidated Financial Statements

(4) See discussion in Note 11 of Consolidated Financial Statements

SENIOR CREDIT FACILITY

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

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

35

In February 2000, Brigham entered into an amended and restated Senior Credit
Facility with its existing senior lenders and a new senior lender. The Senior
Credit Facility was further amended in October 2000. The amended and restated
Senior Credit Facility provides Brigham with $75 million in borrowing
availability for a three-year term. In December 2001, Brigham extended the
maturity of the amended and restated Senior Credit Facility by one year to
December 31, 2003.

As a result of the February 2000 amendments, $30 million of the Senior
Credit Facility held by one of the lenders is convertible into shares of Brigham
common stock (the "Convertible Notes") in the following amounts and prices:
(i) $10 million is convertible at $3.90 per share, (ii) $10 million is
convertible at $6.00 per share and (iii) $10 million is convertible at $8.00 per
share. As of December 31, 2001, Brigham had $75 million in borrowings
outstanding under the Senior Credit Facility, of which the Convertible Notes
were $30 million.

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

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

Principal outstanding under the Senior Credit Facility is due at maturity on
December 31, 2003, with interest due monthly for base rate tranches or
periodically as LIBOR tranches mature. The annual interest rate for borrowings
under the Senior Credit Facility is either the lender's base rate or LIBOR plus
3.00%, at Brigham's option. The interest rate on the Senior Credit facility at
December 31, 2001 was 4.9%. Obligations under the Senior Credit Facility are
secured by substantially all of Brigham's oil and natural gas properties and
other tangible assets. At March 22, 2002, Brigham had $75 million in borrowings
outstanding under the Senior Credit Facility, which bear an interest rate of
approximately 4.9%.

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

36

which could in turn have an adverse impact on its future financial position and
results of operations. At December 31, 2001 and for the year then ended, Brigham
was in compliance with the covenants.

SUBORDINATED NOTES

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

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

REFINANCING TRANSACTIONS

On October 31, 2000 and November 1, 2000, Brigham entered into a series of
financing agreements to provide funding (i) to repurchase all the debt and
equity securities in Brigham held by affiliates of Enron North America at a
substantial discount, and (ii) to continue and expand Brigham's planned drilling
program.

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

SUBORDINATED NOTES FACILITY. The $20 million of new subordinated notes
issued to Shell Capital Inc. (the "SCI Notes") bear interest at 10.75% per annum
and have no principal repayment obligations until maturity in 2005. The SCI
Notes will be issued pursuant to a multi-draw facility (the "Subordinated Notes
Facility") at borrowing increments of at least $1 million, and such funds cannot
be redrawn once they have been repaid. At Brigham's option, up to 50% of the
interest payments on the SCI Notes during the first two years can be satisfied
by payment-in-kind ("PIK") through the issuance of additional SCI Notes in lieu
of cash. The SCI Notes are secured obligations ranking junior to Brigham's
existing $75 million Senior Credit Facility. The SCI Notes have a five-year
maturity, are redeemable at Brigham's option for face value at anytime, and have
certain financial and other covenants. The warrants to purchase an aggregate of
1,250,000 shares of Brigham common stock issued to Shell Capital Inc. (the "SCI
Warrants") have a term of seven years, an exercise price of $3.00 per share and
a cashless exercise feature. For financial reporting purposes, the SCI Warrants
were valued using the Black-Scholes valuation model and the estimated value of
$2.9 million was recorded as deferred loan costs that will be amortized over the
five-year term of the SCI Notes. During 2001 Brigham exercised its option to PIK
50% of the interest payments on the SCI Notes resulting in the issuance of an
additional $721,000 in SCI Notes. As of December 31, 2001 and March 22, 2002,
Brigham had $16.7 million and $20.7 million, respectively, of borrowings
outstanding under the

37

Subordinated Notes Facility and $4.0 million and $0.0 million, respectively, in
additional borrowing capacity.

The SCI Notes contain various restrictive covenants and compliance
requirements, which include minimum current ratio, interest coverage ratio,
limitations on capital expenditures related to seismic and land activities, and
various other financial covenants. At December 31, 2001 and for the year then
ended, Brigham was in compliance with the covenants.

SERIES A PREFERRED STOCK. See "--Liquidity and Capital Resources--Equity
Placements--Series A Preferred Stock"

SALES OF INTERESTS IN PROJECTS AND OIL AND NATURAL GAS PROPERTIES

DUKE PROJECT FINANCING. In February 1999, Brigham entered into a project
financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund
the continued exploration of five Anadarko Basin projects covered by
approximately 200 square miles of 3-D seismic data acquired in 1998. In this
transaction, Brigham conveyed 100% of its working interest (land and seismic) in
these project areas to a newly formed limited liability company (the
"Brigham-Duke LLC") for total consideration of $10 million. Brigham entered into
this project financing arrangement to enable it to recoup substantially all of
its pre-seismic land and seismic data acquisition costs incurred in these
project areas and to provide the capital to fund the drilling of the first six
wells within these projects. Brigham served as the managing member of the
Brigham-Duke LLC with a 1% interest, and Duke was the sole remaining member with
a 99% interest. Pursuant to the terms of the Brigham-Duke LLC agreement, Brigham
paid 100% of the drilling and completion costs for all wells drilled by the
Brigham-Duke LLC within the designated project areas in exchange for a 70%
working interest in the wells (and their allocable drilling and spacing units),
with the remaining 30% working interest remaining in the Brigham-Duke LLC,
subject in each instance to proportionate reduction by any ownership rights held
by third parties. Upon 100% project payout, Brigham had the right to back-in for
80% of the Brigham-Duke LLC's working interest in all of the then producing
wells (and their allocable drilling and spacing units) and a 94% working
interest in any wells (and their allocable drilling and spacing units) drilled
after payout within the designated project areas governed by the Brigham-Duke
LLC agreement, thereby increasing Brigham's effective working interest in the
Brigham-Duke LLC wells from 70% to 94%. In February 2001, Duke, as majority
member of the Brigham-Duke LLC, elected to dissolve the Brigham-Duke LLC. As a
result of the dissolution of the Brigham-Duke LLC, the remaining undeveloped
land and seismic data in the Brigham-Duke LLC project areas was unconditionally
owned by Duke. In December 2001, Brigham recorded a loss of $94,000 on its
investment in the Brigham-Duke LLC.

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

38

EQUITY PLACEMENTS

VERITAS EQUITY ISSUANCES. On March 30, 1999, Brigham entered into an
agreement with Veritas DGC Land, Inc. to exchange 1,002,865 shares of newly
issued Brigham common stock valued at $3.50 per share for approximately
$3.5 million of payment obligations due to Veritas in 1999 for certain seismic
acquisition and processing services previously performed. In addition, this
agreement provided for the payment by Brigham of up to $1 million in future
seismic processing services to be performed by Veritas in newly issued shares of
Brigham common stock valued at $3.50 per share, in the event that Brigham did
not elect to pay for such services in cash. The settlement of these future
seismic processing services was determined on a quarterly basis through
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 PLACEMENT OF COMMON STOCK. On February 22, 2000, Brigham entered
into an agreement to issue 2,195,122 shares of common stock and 731,707 warrants
to purchase common stock for total consideration of $4.5 million in a private
placement to a group of institutional investors led by affiliates of two members
of Brigham's board of directors. The equity sale consisted of units that include
one share of common stock priced at $2.0525 per share and one-third of a warrant
to purchase Brigham common stock at an exercise price of $2.5625 per share with
a three-year term. Pricing of this private equity placement was based on the
average market price of Brigham common stock during a twenty trading day period
prior to issuance. Net proceeds from this equity placement were used to fund a
portion of Brigham's capital expenditures and working capital obligations during
2000. Warrants associated with this transaction will expire February 22, 2003.

SERIES A PREFERRED STOCK. On November 1, 2000, $20 million of mandatorily
redeemable preferred stock (the "Series A Preferred Stock") was issued to
affiliates of Credit Suisse First Boston (USA), Inc., which bear dividends at a
rate of 6% per annum if paid in cash and 8% per annum if paid-in-kind through
the issuance of additional Series A Preferred Stock in lieu of cash. At
Brigham's option, up to 100% of the dividend payments on the Series A Preferred
Stock during the first five years (expiring November 2005) can be satisfied
through the issuance of PIK dividends. The Series A Preferred Stock has a
ten-year maturity and is redeemable at Brigham's option at 100% or 101% of par
value (depending upon certain conditions) at anytime prior to maturity.
Warrants, to purchase an aggregate of 6,666,667 shares of Brigham common stock
were also issued to the CSFB Affiliates (the "Series A Warrants"), which have a
term of ten years, an exercise price of $3.00 per share and must be exercised,
if Brigham so requires, in the event that Brigham common stock trades at or
above $5.00 per share for 60 consecutive trading days. The exercise price of the
Series A Warrants is payable either in cash or in shares of Series A Preferred
Stock, valued at liquidation value plus accrued dividends. If Brigham requires
exercise of the Series A Warrants, proceeds from the exercise of the Series A
Warrants will be used to fund the redemption of a similar value of then
outstanding Series A Preferred Stock.

For financial reporting purposes, the Series A Warrants were valued at
$11.5 million using the Black-Scholes valuation model and were recorded as
additional paid-in capital in the year ended December 31, 2000. Pursuant to the
terms of the securities purchase agreement related to the Series A Preferred
Stock, Brigham agreed to nominate one representative of one of the CSFB
Affiliates to serve as a member of Brigham's board of directors so long as the
CSFB Affiliates or their affiliates own at least 10% of the Series A Preferred
Stock issued in November 2000, or at least 5% of the outstanding shares of
Brigham common stock.

ADDITIONAL SERIES A PREFERRED STOCK. On March 5, 2001, Brigham sold
$10 million of additional Series A Preferred Stock and warrants (the "New CSFB
Warrants") to the CSFB affiliates in a private placement transaction. The
conditions to Brigham's receipt of the proceeds from this transaction were

39

fulfilled on March 22, 2001. The New CSFB Warrants to purchase an aggregate of
2,105,263 shares of Brigham common stock have a term of ten years, an exercise
price of $4.75 per share and must be exercised, if Brigham so requires, in the
event that Brigham common stock trades at an average of at least 150% of the
exercise price (currently, $7.125 per share) for 60 consecutive trading days.
The exercise price of the New CSFB Warrants is payable either in cash or in
shares of Series A Preferred Stock, valued at liquidation value plus accrued
dividends. If Brigham requires exercise of the New CSFB Warrants, proceeds from
the exercise of the New CSFB Warrants will be used to fund the redemption of a
similar value of then outstanding Series A Preferred Stock. For financial
reporting purposes, the New CSFB Warrants were valued at approximately
$4.5 million using the Black-Scholes valuation model and were recorded as
additional paid-in capital in March 2001. As of December 31, 2001 and March 22,
2002, Brigham had $32.6 million (in Liquidation Value) of Series A Preferred
stock outstanding.

CASH FLOW ANALYSIS

CASH FLOWS FROM OPERATING ACTIVITIES. Cash flows provided (used) by
operating activities were $18.9 million in 2001, ($4.6) million in 2000, and
$2.6 million in 1999. The increase in cash flows from operating activities for
2001 as compared to 2000 is due to a 45% increase in total production volumes, a
16% increase in Brigham's average realized natural gas equivalent sales price
and a reduction in overhead cost per unit of equivalent production. The decrease
in cash flows for 2000 as compared to 1999 is due to changes in working capital
(a $13.2 million reduction in cash flow from working capital items in 2000
compared to a $5 million reduction in cash flow from working capital items in
1999), offset in part by a $1.1 million increase in cash flow from operations
before working capital. Cash flow from operations before working capital changes
were $8.6 million in 2000 as compared to $7.5 million in 1999.

CASH FLOWS FROM INVESTING ACTIVITIES. Cash flows provided (used) by
investing activities were ($33.6) million in 2001, ($26.1) million in 2000 and
$1.6 million in 1999. The increase in cash flows used by investing activities in
2001 were primarily the result of an increase in capital expenditures for
exploration and development activities and a reduction in proceeds from the sale
of assets, as compared with those in 2000. The decrease in cash flow from
investing activities in 2000 compared to 1999 were primarily attributable to an
increase in Brigham's capital expenditures related to exploration and
development activities and a reduction in proceeds received from the sale of oil
and natural gas properties, as compared with those in 1999. Capital expenditures
(before the application of net proceeds received from the sales of interests in
projects) were $34.5 million in 2001, $28.9 million in 2000 and $25.6 million in
1999.

After acquiring 2,475 square miles of 3-D seismic data in 1997 and 1998,
Brigham did not acquire any new 3-D seismic data during the three-year period
ended 2001. However, in 2001, Brigham exchanged licensing rights in certain
non-core 3-D data volumes for licenses to additional 3-D seismic data programs,
many of which were located in Brigham's focus plays in the Texas Gulf Coast. As
a result, Brigham added approximately 1,400 square miles of 3-D seismic data in
2001. Brigham's drilling efforts during the past three years resulted in the
completion of 27(10.4 net) wells in 2001, 25 (9.3 net) wells in 2000 and 19 (6.3
net) wells in 1999, which contributed to an aggregate net increase in proved
reserve volumes (net of revisions to previous estimates) of 29 Bcfe in 2001,
18 Bcfe in 2000 and 29 Bcfe in 1999. In addition, Brigham sold interests in
certain 3-D seismic data for $3.9 million in 2000 and sold interests in certain
producing and non-producing properties in 1999 for a total of $27.1 million.

CASH FLOWS FROM FINANCING ACTIVITIES. Cash flows from financing activities
in 2001 were $18.9 million, principally due to the issuance of $10 million in
additional Series A Preferred Stock and New CSFB Warrants in March 2001 and
increased borrowings of $9.0 million under its Subordinated Notes Facility. Cash
flows from financing activities in 2000 were $28.8 million, principally due to
the

40

combined effects of increased borrowings under its Senior Credit Facility and
Subordinated Notes Facility, the repurchase of its senior subordinated notes due
2003, the issuance of $20 million of Series A Preferred Stock and Series A
Warrants, and the placement of common stock that provided $4.2 million. Cash
flows used by financing activities in 1999 were $4.1 million, principally due to
the net repayment of borrowings outstanding under Brigham's Senior Credit
Facility and the payment of deferred loan fees.

CAPITAL EXPENDITURES

The Company's capital spending budget for 2002 is $23.7 million. The
majority of Brigham's planned 2002 expenditures will be directed towards
drilling in its prospect inventory in a continued effort to focus resources on
its primary objective of growing production volumes and cash flow. For 2002,
Brigham expects to drill 26 wells with an average working interest of 32%.
Capitalizing on the prior discovery of Home Run, Mills Ranch, Triple Crown and
Providence Fields, approximately 80% of Brigham's 2002 drilling expenditures are
allocated to development drilling. Spending will be funded by Brigham's 2002
discretionary cash flow, availability under its Subordinated Notes Facility and
its 2002 beginning cash balance. As a result, capital expenditures for 2002 are
expected to be down approximately 34% from 2001. This decline is primarily
attributable to lower forecasted oil and natural gas prices and is subject to
change if market conditions shift. In the event that commodity prices decrease,
Brigham may be required to curtail or delay some of its planned activities.

OTHER MATTERS

DERIVATIVE INSTRUMENTS

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

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

Total natural gas purchased and sold subject to swap arrangements entered
into by Brigham was 5,025,000 MMBtu in 1999, 5,490,000 MMBtu in 2000 and
1,800,000 MMBtu in 2001. Brigham accounted for these transactions as hedging
activities and, accordingly, adjusted the price received for natural gas
production during the period the hedged transactions occurred. Adjustments to
the price received for natural gas under these swap arrangements resulted in
decreases in natural gas revenues of $486,000 in 1999, $9.4 million in 2000 and
$8.0 million in 2001. In addition, Brigham's oil revenues were reduced by
$107,000 in 2000 and $153,000 in 2001 as a result of its crude oil collar
hedging arrangements outstanding during the year. Brigham did not have any
outstanding crude oil hedging contracts during 1999.

In September 1999, Brigham sold call options on a portion of its future oil
and natural gas production. Brigham applied the proceeds from the sale of these
call options to increase the effective

41

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

In March 2000, Brigham purchased put options on a portion of its future oil
and natural gas production. These transactions effectively converted a portion
of its existing call options into collars, thus providing a hedge to future
changes in oil and natural gas prices. Brigham also entered into costless
collars on additional future oil and natural gas production thus providing
further protection to Brigham's exposure to potential oil and natural gas price
declines.

As of December 31, 2001, Brigham has three fixed price swap derivative
contracts that are designated as hedges and one fixed price cap derivative
contract that is not designated as a hedge. The following table sets forth
Brigham's outstanding natural gas derivative contracts as of December 31, 2001:

NATURAL GAS DERIVATIVE CONTRACTS

There were no outstanding oil derivative contracts as of December 31, 2001.
However, in February 2002, Brigham entered into a combination of crude oil cap
and floor option contracts. Under these option contracts, which together form
collars, Brigham will receive a maximum of $21.95 per Bbl and a minimum of
$18.00 per Bbl for 250 Bbls per day for the period from February 2002 to
June 2002, a maximum of $22.35 per Bbl and minimum of $18.00 per Bbl for 250
Bbls per day for the period from February 2002 to December 2002, and a maximum
of $22.56 per Bbl and minimum of $18.00 per Bbl for 250 Bbls per day for the
period from February 2002 to June 2003. These contracts settle based on the
NYMEX price for West Texas Intermediate and are designated as cash flow hedges.

In March 2002, Brigham entered into six crude oil fixed price swap
agreements whereby Brigham exchanged a floating market price for a fixed
contract price of $25.06 per Bbl for 500 Bbls per day for the period from
July 2002 to September 2002, $24.50 per Bbl for 250 Bbls per day for the period
from October 2002 to December 2002, $23.92 per Bbl for 250 Bbls per day for the
period from January 2003 to March 2003, $23.50 per Bbl for 250 Bbls per day for
the period from April 2003 to June 2003, $23.15 per Bbl for 250 Bbls per day for
the period from July 2003 to September 2003, and $22.90 per Bbl for 250
Bbls per day for the period from October 2003 to December 2003. These contracts
settle based on the NYMEX price for West Texas Intermediate and are designated
as cash flow hedges.

42

Also in March 2002, Brigham entered into six natural gas fixed price swap
agreements whereby Brigham exchanged a floating market price for a fixed
contract price of $3.20 per MMBtu for 2,500 MMBtu per day for the period from
July 2002 to September 2002, $3.46 per MMBtu for 1,000 MMBtu per day for the
period from October 2002 to December 2002, $3.70 per MMBtu for 2,500 MMBtu per
day for the period from January 2003 to March 2003, $3.40 per MMBtu for 1,000
MMBtu per day for the period from April 2003 to June 2003, $3.45 per MMBtu for
2,500 MMBtu per day for the period from July 2003 to September 2003, and
$3.67 per MMBtu for 1,000 MMBtu per day for the period from October 2003 to
December 2003. These contracts settle based on the NYMEX price for natural gas
and are designated as cash flow hedges.

At December 31, 2001, the fair value of hedging contracts included in
accumulated other comprehensive income and other current assets was
approximately $351,000 of which approximately $50,000 was classified as
noncurrent assets.

EFFECTS OF INFLATION AND CHANGES IN PRICES

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

ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Brigham's business is subject to certain federal, state and local laws and
regulations relating to the exploration for and the development, production and
marketing of oil and natural gas, as well as environmental and safety matters.
Many of these laws and regulations have become more stringent in recent years,
often imposing greater liability on a larger number of potentially responsible
parties. Although Brigham believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by laws and
regulations are frequently changed and subject to interpretation, and Brigham is
unable to predict the ultimate cost of compliance with these requirements or
their effect on its operations. Any suspensions, terminations or inability to
meet applicable bonding requirements could materially adversely affect Brigham's
financial condition and operations. Although significant expenditures may be
required to comply with governmental laws and regulations applicable to Brigham,
compliance has not had a material adverse effect on the earnings or competitive
position of Brigham. Future regulations may add to the cost of, or significantly
limit, drilling activity. See "--Risk Factors--We Are Subject To Various
Governmental Regulations And Environmental Risks" and "Item 1.
Business--Governmental Regulation" and "Item 1. Business--Environmental Matters"

CRITICAL ACCOUNTING POLICIES

PROPERTY AND EQUIPMENT

Brigham uses the full cost method of accounting for oil and natural gas
properties. Under this method, all acquisition, exploration and development
costs, including payroll, interest, and other internal costs, incurred for the
purpose of finding oil and natural gas reserves are capitalized. Costs
associated with production and general corporate activities are expensed in the
period incurred. Proceeds from the sale of oil and natural gas properties are
applied to reduce the capitalized costs of properties unless the sale would
significantly alter the relationship between capitalized costs and proved
reserves, in which case a gain or loss is recognized.

To the extent costs capitalized in the full-cost pool (net of depreciation,
depletion and amortization and related deferred taxes) exceed the present value
(using a 10% discount rate and based on period-end oil and natural gas prices)
of estimated future net after-tax cash flows from proved oil and natural gas
reserves plus the capitalized cost of unproved properties, such costs are
charged to

43

operations as a reduction of the carrying value of oil and natural gas
properties, or a "capitalized ceiling impairment" charge. The risk that Brigham
will be required to write down the carrying value of its oil and gas properties
increases when oil and gas prices are depressed, even if the low prices are
temporary. In addition, capitalized ceiling impairment charges may occur if
Brigham experiences poor drilling results or estimations of proved reserves are
substantially reduced.

A capitalized ceiling impairment is a reduction in earnings that does not
impact cash flows, but does impact operating income and stockholders' equity.
Once recognized, a capitalized ceiling impairment charge to oil and natural gas
properties cannot be reversed at a later date. No assurance can be given that
Brigham will not experience a capitalized ceiling impairment charge in future
periods. See "--Risk Factors--Exploratory Drilling Is A Speculative Activity
Involving Numerous Risks And Uncertain Costs; We Are Dependent On Exploratory
Drilling Activities"; "--Risk Factors--Volatility Of Oil And Gas Markets Affects
Us; Oil And Natural Gas Prices Are Volatile"; and "--Risk Factors--We Are
Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows"

Other property and equipment is depreciated on a straight-line basis over
the estimated useful lives of the assets after considering salvage value.
Brigham uses a 10 year life for furniture and fixtures, a 5 year life for
machinery and equipment, and a 3 year life for 3-D seismic interpretation
workstations and software.

Expenditures for repairs or maintenance are expensed as incurred.

INCOME TAXES

Deferred tax assets are recognized for temporary differences in financial
statement and tax basis amounts that will result in deductible amounts and
carryforwards in future years. Deferred tax liabilities are recognized for
temporary differences that will result in taxable amounts in future years.
Deferred tax assets and liabilities are measured using enacted tax law and tax
rate(s) for the year in which Brigham expects the temporary differences to be
deducted or settled. The effect of a change in tax law or rates on the valuation
deferred tax assets and liabilities is recognized in income in the period of
enactment. Deferred tax assets are reduced by a valuation allowance when, in the
opinion of management, it is more likely than not that some portion or all of
the deferred tax assets will not be realized.

REVENUE RECOGNITION

Brigham recognizes crude oil revenue using the sales method of accounting.
Under this method, Brigham recognizes revenue when oil is delivered and title
transfers.

Brigham recognizes natural gas revenue using the entitlements method of
accounting. Under this method, revenue is recognized based on Brigham's entitled
ownership percentage of sales of natural gas to purchasers. Gas imbalances occur
when Brigham sells more or less than its entitled ownership percentage of total
natural gas production. When Brigham receives less than its entitled share, a
receivable is recorded. When Brigham receives more than its entitled share, a
liability is recorded.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, 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. The most significant estimates relate to
proved oil and natural gas reserve volumes and the future development costs as
well as estimates relating to certain oil and natural gas revenues and expenses.
Actual results may differ from those estimates.

44

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Brigham adopted Statement of Financial Accounting Standards ("SFAS") No.
133 on January 1, 2001 in accordance with Financial Accounting Standards Board
(the "FASB") requirements.

SFAS No. 133, as amended, establishes accounting and reporting standards for
derivative instruments and for hedging activities. All derivative instruments
are recorded on the balance sheet at fair value and changes in the fair value of
the derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if it is, depending on the type of hedge transaction.
Brigham's derivative contracts consist primarily of cash flow hedge transactions
in which Brigham is hedging the variability of cash flow related to a forecasted
transaction. Changes in the fair value of these derivative instruments are
reported in other comprehensive income and reclassified as earnings in the
period(s) in which earnings are impacted by the variability of the cash flow of
the hedged item. Brigham assesses the effectiveness of hedging transactions
every three months, consistent with documented risk management strategy for the
particular hedging relationship. Changes in fair value of ineffective hedges are
included in earnings.

In January 2001, Brigham recorded a net of tax cumulative effect adjustment
of $11.8 million to other comprehensive income to recognize the fair value
(liability) of all derivative instruments that qualify for hedge accounting
treatment in accordance with SFAS No. 133.

NEW PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board issued SFAS No. 141,
"Business Combinations", SFAS No. 142, "Goodwill and Other Intangible Assets",
and SFAS No. 143, "Accounting for Asset Retirement Obligations". In
August 2001, The FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets".

SFAS No. 141 requires the use of the purchase method of accounting for all
business combinations. SFAS No. 141 applies to all business combinations
initiated after June 30, 2001 and to all business combinations accounted for by
the purchase method that are completed after June 30, 2001. SFAS No. 142
requires that goodwill as well as other intangible assets with indefinite lives
not be amortized, but be tested annually for impairment and is effective for
fiscal years beginning after December 15, 2001. SFAS No. 144 addresses financial
accounting and reporting for the impairment of long-lived assets to be disposed
of and supersedes, with exceptions, SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets to Be Disposed Of" and is effective for fiscal years
beginning after December 15, 2001. Brigham does not expect the adoption of these
statements to have a material effect on its consolidated financial position,
results of operations or cash flows.

SFAS No. 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset retirement cost should be allocated to expense using a
systematic and rational method. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. Brigham is currently assessing the impact of this
statement and for this reason cannot reasonably estimate the effect of the
pronouncement on its consolidated financial position, results of operations or
cash flows at this time.

FORWARD LOOKING INFORMATION

Brigham or its representatives may make forward looking statements, oral or
written, including statements in this report, press releases and filings with
the SEC, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells it anticipates drilling during 2002 and Brigham's financial position,
business strategy and other plans and

45

objectives for future operations. Although Brigham believes that the
expectations reflected in these forward looking statements are reasonable, there
can be no assurance that the actual results or developments anticipated by
Brigham will be realized or, even if substantially realized, that they will have
the expected effects on its business or operations. Among the factors that could
cause actual results to differ materially from Brigham's expectations are
general economic conditions, inherent uncertainties in interpreting engineering
data, operating hazards, delays or cancellations of drilling operations for a
variety of reasons, competition, fluctuations in oil and gas prices,
availability of sufficient capital resources to Brigham and its project
participants, government regulations and other factors set forth among the risk
factors noted below or in the description of Brigham's business in Item 1 of
this report. All subsequent oral and written forward looking statements
attributable to Brigham or persons acting on its behalf are expressly qualified
in their entirety by these factors. Brigham assumes no obligation to update any
of these statements.

46

RISK FACTORS

WE ARE SUBSTANTIALLY LEVERAGED

Our outstanding long-term debt was $91.7 million as of December 31, 2001,
and $95.7 million as of March 22, 2002. The credit agreements related to our
Senior Credit Facility and Subordinated Notes Facility limit the amount of
additional debt borrowings, including borrowings under these facilities or other
senior or subordinated indebtedness. As of March 22, 2002, we had no additional
borrowing availability under our Senior Credit Facility or our Subordinated
Notes Facility.

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

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

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

- 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, availability under our Subordinated Notes Facility and 2002
beginning cash balance should allow us to finance our planned operations through
2002 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:

- worldwide and domestic supplies of oil and natural gas;

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

47

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

- the price and level of foreign imports;

- the level of consumer demand;

- the price and availability of alternative fuels;

- the availability of pipeline capacity;

- weather conditions;

- domestic and foreign governmental regulations and taxes; and

- the overall economic environment.

We cannot predict future oil and natural gas price movements with certainty.
During 2001, the high and low settlement prices for oil on the NYMEX were $32.19
per Bbl and $17.45 per Bbl, and the high and low settlement prices for natural
gas on the NYMEX were $9.82 per MMBtu and $1.83 per MMBtu. Significant declines
in oil and natural gas prices for an extended period may have the following
effects on our business:

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

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

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

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

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

OUR HEDGING TRANSACTIONS MAY NOT PREVENT LOSSES

In an attempt to reduce our sensitivity to energy price volatility, we use
swap and collar hedging arrangements that generally result in a fixed price or a
range of minimum and maximum price limits over a specified monthly time period.
If we do not produce our oil and natural gas reserves at rates equivalent to our
hedged position, we would be required to satisfy our obligations under hedging
contracts on potentially unfavorable terms without the ability to hedge that
risk through sales of comparable quantities of our own production. This
situation occurred during a portion of 1999 and again during portions of 2000,
due in part to our sale of certain producing reserves in mid-1999. As a result,
our cash flow was significantly reduced, particularly during 2000. Because the
terms of our hedging contracts are based on assumptions and estimates of
numerous factors such as cost of production and pipeline and other
transportation and marketing costs to delivery points, substantial differences
between the hedged prices and actual results could harm our anticipated profit
margins and our ability to manage the risk associated with fluctuations in oil
and natural gas prices. Hedging contracts limit the benefits we will realize if
actual prices rise above the contract prices. We could be financially harmed if
the other party to the hedging contracts proves unable or unwilling to perform
its obligations under such contracts. See "--Other Matters--Derivative
Instruments" and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk"

EXPLORATORY DRILLING IS A SPECULATIVE ACTIVITY INVOLVING NUMEROUS RISKS AND
UNCERTAIN COSTS; WE ARE DEPENDENT ON EXPLORATORY DRILLING ACTIVITIES

Our revenues, operating results and future rate of growth depend highly upon
the success of our exploratory drilling program. Exploratory drilling involves
numerous risks, including the risk that we will not encounter commercially
productive natural gas or oil reservoirs. We cannot always predict the

48

cost of drilling, and we may be forced to limit, delay or cancel drilling
operations as a result of a variety of factors, including:

- unexpected drilling conditions;

- pressure or irregularities in formations;

- equipment failures or accidents;

- adverse weather conditions;

- compliance with governmental requirements; and

- 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:

- fires;

- natural disasters;

- formations with abnormal pressures;

- blowouts, cratering and explosions; and

- pipeline ruptures and spills.

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

WE MAY NOT HAVE ENOUGH INSURANCE TO COVER SOME OPERATING RISKS

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

49

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:

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

- tax and energy policies;

- changes in supply and demand; and

- general economic conditions.

WE HAVE HISTORICAL OPERATING LOSSES AND OUR FUTURE RESULTS MAY VARY

We cannot assure you that we will be profitable in the future. At
December 31, 2001, we had an accumulated deficit of $26.7 million and total
stockholders' equity of $49.6 million. We have recognized the following annual
net losses before extraordinary items since 1995: $1.6 million in 1995, $450,000
in 1996, $1.1 million (including a net $1.2 million non-cash deferred income tax
charge incurred in connection with our conversion from a partnership to a
corporation) in 1997, $33.3 million (including a $25.9 million non-cash
writedown in the carrying value of our oil and natural gas properties) in 1998,
$21.6 million (including a $12.2 million non-cash loss on the sale of oil and
natural gas properties) in 1999, and $15.7 million in 2000. See "Item 6.
Selected Financial Data"

OUR FUTURE OPERATING RESULTS MAY FLUCTUATE

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

- industry conditions;

- prices of oil and natural gas;

- rates of drilling success;

- capital availability;

- rates of production from completed wells; and

- the timing and amount of capital expenditures.

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

MAINTAINING RESERVES AND REVENUES IN THE FUTURE DEPENDS ON SUCCESSFUL
EXPLORATION AND DEVELOPMENT

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

The business of exploring for or developing reserves is capital intensive.
Reductions in our cash flow from operations and limitations on or unavailability
of external sources of capital may impair our

50

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

WE ARE SUBJECT TO UNCERTAINTIES IN RESERVE ESTIMATES AND FUTURE NET CASH FLOWS

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

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

- the amount and timing of actual production;

- supply and demand for oil and natural gas;

- limits or increases in consumption by gas purchasers; and

- 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.

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:

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

- marketing our oil and natural gas production; and

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

51

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 22, 2002, our directors, executive officers and 10% or greater
stockholders, and certain of their affiliates, beneficially owned approximately
78% 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.

52

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.

53

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MANAGEMENT OPINION CONCERNING DERIVATIVE INSTRUMENTS

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

COMMODITY PRICE RISK

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

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

INTEREST RATE RISK

Brigham is subject to interest rate risk as borrowings under its Senior
Credit Facility ($75 million outstanding as of December 31, 2001) accrue
interest at floating rates based on the lender's base rate or LIBOR. Brigham
does not utilize derivative instruments to protect against changes in interest
rates on debt borrowings. Based on Brigham's $75 million of outstanding
borrowings under its Senior Credit Facility at December 31, 2001, an adverse
change (defined as a hypothetical 1% and 2% increase in interest rates on such
borrowings) would reduce cash flow by approximately $750,000 and $1.5 million,
respectively, from currently projected levels.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

54

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this item is incorporated by reference to
information under the caption "Proposal One--Election of Directors" and to the
information under the caption "Section 16(a) Beneficial Ownership Reporting
Compliance" in Brigham's definitive Proxy Statement (the "2002 Proxy Statement")
for its annual meeting of stockholders to be held on May 17, 2002. The 2002
Proxy Statement will be filed with the Securities and Exchange Commission (the
"Commission") not later than 120 days subsequent to December 31, 2001.

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

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to
the 2002 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2001.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this item is incorporated herein by reference to
the 2002 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2001.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The information required by this item is incorporated herein by reference to
the 2002 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2001.

55

PART IV

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

(a) 1. Consolidated Financial Statements:

See Index to Financial Statements on page F-1.

2. Exhibits:

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

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

Brigham filed a report on Form 8-K on October 19, 2001 to
report Brigham had issued an operational press release
announcing success in its South Texas drilling program and
reaffirmed guidance for the third quarter 2001.

Brigham filed a report on Form 8-K on November 6, 2001 to
report Brigham announced that it would host a conference
call to discuss Brigham's operational and financial results
for the third quarter ended September 30, 2001 with
investors, analyst and other interested parties on
Wednesday, November 7, at 9:00 am Central time.
Additionally, Brigham announced that it plans to issue a
press release regarding its third quarter 2001 financial
results after the close of market trading on Tuesday,
November 06, 2001.

Brigham filed a report on Form 8-K on November 12, 2001 to
report Brigham announced its financial results for the third
quarter ended September 30, 2001 and to provide guidance for
fourth quarter financial results.

Brigham filed a report on Form 8-K on November 15, 2001 to
report Brigham announced the successful completion of its
first two wells at the Triple Crown Field.

56

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 Brigham 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.

57

NET ACRES OR NET WELLS. Gross acres or wells multiplied, in each case, by
the percentage working interest owned by Brigham.

NET PRODUCTION. Production that is owned by Brigham less royalties and
production due others.

OIL. Crude oil, condensate or other liquid hydrocarbons.

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

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

PROVED 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.

PSI. Pounds per square inch.

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%.

TCFE. One trillion cubic feet of natural gas equivalents.

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.

58

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 29, 2002.

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 29, 2002, 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
EXECUTIVE VICE PRESIDENT, 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

59

/s/ STEPHEN P. REYNOLDS
-------------------------------------------
Stephen P. Reynolds
DIRECTOR

/s/ STEVEN A. WEBSTER
-------------------------------------------
Steven A. Webster
DIRECTOR

/s/ R. GRAHAM WHALING
-------------------------------------------
R. Graham Whaling
DIRECTOR

60

BRIGHAM EXPLORATION COMPANY

INDEX TO FINANCIAL STATEMENTS

F-1

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 (the "Company") and its subsidiaries at December 31, 2001
and 2000, and the results of their operations and their cash flows for the three
years in the period ended December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities effective January 1, 2001.

PricewaterhouseCoopers LLP

February 22, 2002
Houston, Texas

F-2

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS, EXCEPT SHARE DATA)

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

F-3

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(IN THOUSANDS, EXCEPT PER SHARE DATA)

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

F-4

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(IN THOUSANDS)

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

F-5

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

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

F-6

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 "Brigham." Brigham, Inc. is a Nevada
corporation whose only asset is its ownership interest in the Partnership. The
Partnership was formed in May 1992 to explore and develop onshore domestic oil
and natural gas properties using 3-D seismic imaging and other advanced
technologies. Since its inception, the Partnership has focused its exploration
and development of oil and natural gas properties primarily in 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 Brigham in exchange
for 3,859,821 shares of common stock of Brigham. Pursuant to the Exchange
Agreement, the Partnership's other general partner and the limited partners also
transferred all of their partnership interests to Brigham in exchange for
3,314,286 shares of common stock of Brigham. Furthermore, the holders of the
Partnership's subordinated convertible notes transferred these notes to Brigham
in exchange for 1,754,464 shares of common stock. These transactions are
referred to as "the Exchange." In completing the Exchange, Brigham 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, Brigham now owns all the partnership
interests in the Partnership. In May 1997, Brigham 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

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles in the United States of America 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. The most significant estimates relate to
proved oil and natural gas reserve volumes and the future development costs as
well as estimates relating to certain oil and natural gas revenues and expenses.
Actual results may differ from those estimates.

PRINCIPLES OF CONSOLIDATION

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

CASH AND CASH EQUIVALENTS

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

F-7

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

PROPERTY AND EQUIPMENT

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

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

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

Capitalized costs associated with properties that have not been evaluated
through drilling or seismic analysis are excluded from the unit-of-production
amortization. Exclusions are adjusted annually based on drilling results and
interpretative analysis.

Other property and equipment, which primarily consists of 3-D seismic
interpretation workstations, is 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

Brigham recognizes crude oil revenues using the sales method of accounting.
Under this method, Brigham recognizes revenues when oil is delivered and title
transfers.

Brigham recognizes natural gas revenues using the entitlements method of
accounting. Under this method, revenues are recognized based on Brigham's
entitled ownership percentage of sales of natural gas to purchasers. Gas
imbalances occur when Brigham sells more or less than its entitled ownership
percentage of total natural gas production. When Brigham receives less than its
entitled share, a receivable is recorded. When Brigham receives more than its
entitled share, a liability is recorded. At December 31, 2001, Brigham had
recorded a receivable of approximately 441 MMcf and $1.7 million and a liability
of approximately 758 MMcf and $2.9 million associated with gas imbalances. Gas
balancing receivables and liabilities as of December 31, 2000 were not
significant.

F-8

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

Prior to January 1, 2001, in order for a derivative instrument to qualify
for hedge accounting, there must have been clear correlation between the
derivative instrument and the forecasted transaction. Correlation of the
commodity contracts was determined by evaluating whether the contract gains and
losses would substantially offset the effects of price changes on the underlying
natural gas and crude oil sales volumes. To the extent that correlation existed
between the contracts and the underlying natural gas and crude oil sales
volumes, realized gains or losses and related cash flows arising from the
contracts were recognized as a component of oil and natural gas sales in the
same period as the sale of the underlying volumes. To the extent that
correlation did not exist between the contracts and the underlying natural gas
and crude oil sales volumes, realized gains or losses and related cash flows
arising from the contracts were recognized in the period incurred as a component
of other income or loss. The fair market value of any contract that does not
meet the correlation test outlined above was recorded as a deferred gain or loss
on the balance sheet and was adjusted to current market value at each balance
sheet date with any deferred gains or losses recognized as a component of other
income.

On January 1, 2001, Brigham adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"), as amended. Effective with the adoption of SFAS 133,
all derivatives are recorded on the balance sheet at fair value and changes in
the fair value of derivatives are recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction and, if it is, depending on the type of hedge
transaction. Brigham's derivatives consist primarily of cash flow hedge
transactions in which Brigham is hedging the variability of cash flows related
to a forecasted transaction. Changes in the fair value of these derivative
instruments designated as cash flow hedges will be reported in other
comprehensive income and will be reclassified as earnings in the periods in
which earnings are impacted by the variability of the cash flows of the hedged
item. The ineffective portion of the cash flow hedges will be recognized in
current period earnings. Gains and losses on derivative instruments that do not
qualify for hedge accounting are included in other income (expense) in the
period in which they occur. The resulting cash flows from derivatives are
reported as cash flows from operating activities.

The adoption of SFAS 133 resulted in a January 1, 2001 transition adjustment
to record a net of tax cumulative effect of $11.8 million to other comprehensive
income to recognize the fair value (liability) of all derivative instruments
that qualify for hedge accounting treatment. Gains and losses on derivatives
that were previously deferred as adjustments to the carrying amount of hedged
items were not adjusted.

At the inception of a derivative contract, Brigham may designate the
derivative as a cash flow hedge. For all derivatives designated as cash flow
hedges, Brigham formally documents the relationship between the derivative
contract and the hedged items, as well as the risk management objective for
entering into the derivative contract. To be designated as a cash flow hedge
transaction, the relationship between the derivative and the hedged items must
be highly effective in achieving the offset of changes in cash flows
attributable to the risk both at the inception of the derivative and on an
ongoing basis.

F-9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Brigham measures hedge effectiveness on a quarterly basis and hedge accounting
is discontinued prospectively if it is determined that the derivative is no
longer effective in offsetting changes in the cash flows of the hedged item.
Gains and losses deferred in accumulated other comprehensive income related to
cash flow hedge derivatives that become ineffective remain unchanged until the
related production is delivered. If Brigham determines that it is probable that
a hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately. See Note 12 for a
description of the derivative contracts in which Brigham participates.

STOCK BASED COMPENSATION

Brigham accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the
disclosure-only provisions of Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). See Note 15 for
the pro forma disclosures of compensation expense determined under the
fair-value provisions of SFAS 123.

INCOME TAXES

Deferred tax assets and liabilities are recognized for the estimated future
tax consequences attributable to the differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using the tax rate in
effect for the year in which those temporary differences are expected to be
recovered or settled. The effect of a change in tax rates of deferred tax assets
and liabilities is recognized in income in the year of the enacted rate change.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of
management, it is more likely than not that some portion or all of the deferred
tax assets will not be realized.

DEBT ISSUE COSTS

Debt issue costs are incurred in connection with the issuance of debt and
are recorded on the balance sheet as deferred assets. The debt issue costs are
amortized to interest expense over the life of the debt using the straight-line
method. The results obtained using the straight-line method are not materially
different than those that would result from using the effective interest method.

SEGMENT INFORMATION

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

TREASURY STOCK

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

NEW PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board issued Statements of
Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", SFAS
No. 142, "Goodwill and Other Intangible Assets", and SFAS No. 143, "Accounting
for Asset Retirement Obligations". In

F-10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

August 2001, SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" was also issued.

SFAS No. 141 requires the use of the purchase method of accounting for all
business combinations, applies to all business combinations initiated after
June 30, 2001 and to all business combinations accounted for by the purchase
method that are completed after June 30, 2001. SFAS No. 142 requires that
goodwill as well as other intangible assets with indefinite lives not be
amortized but be tested annually for impairment and is effective for fiscal
years beginning after December 15, 2001. SFAS No. 144 addresses financial
accounting and reporting for the impairment of long-lived assets to be disposed
of. It supersedes, with exceptions, SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets to Be Disposed Of" and is effective for fiscal years
beginning after December 15, 2001. Brigham does not believe that the adoption of
these statements will have a material effect on its financial position, results
of operations or cash flows.

SFAS No. 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset retirement cost should be allocated to expense using a
systematic and rational method. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. Brigham is currently assessing the impact of this
statement and therefore, at this time, cannot reasonably estimate the effect of
these statements on its consolidated financial position, results of operations
or cash flows.

RECLASSIFICATIONS

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

3. ASSET DISPOSITIONS

In February 1999, Brigham 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, Brigham conveyed 100% of its working
interest in land and seismic in these project areas to a newly formed limited
liability company (the "Brigham-Duke LLC") for a total consideration of
$10 million. Brigham is the managing member of the Brigham-Duke LLC with a 1%
interest and Duke is the sole remaining member with a 99% interest. Pursuant to
the terms of the Brigham-Duke LLC agreement, Brigham pays 100% of the drilling
and completion costs for all wells drilled by the Brigham-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, Brigham has
certain rights to back-in for up to a 94% effective working interest in the
Brigham-Duke LLC properties. In February 2001, Duke, as majority member of the
Brigham-Duke LLC elected to dissolve the Brigham-Duke LLC. As a result of the
dissolution of the Brigham-Duke LLC, the remaining undeveloped land and seismic
data in the Brigham-Duke LLC project areas were unconditionally owned by Duke
and, in December 2001, Brigham recorded a loss of approximately $94,000 on its
investment in Brigham-Duke LLC.

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

F-11

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

recognized a loss of $12.2 million, which was the difference between the sales
price received, after adjustment for transaction costs, and the $28.9 million
basis allocated to the divested properties in accordance with the full-cost
method of accounting for oil and natural gas properties.

4. PROPERTY AND EQUIPMENT

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

Brigham capitalizes certain payroll and other internal costs directly
attributable to acquisition, exploration and development activities as part of
its investment in oil and natural gas properties over the periods benefited by
these activities. During the years ended December 31, 2001, 2000 and 1999, these
capitalized costs amounted to $3.9 million, $3.4 million and $3.3 million,
respectively. Capitalized costs do not include any costs related to production,
general corporate overhead, or similar activities. Interest costs of
$1.8 million, $2.8 million and $3.0 million were capitalized in 2001, 2000 and
1999, respectively.

5. NOTES PAYABLE AND SENIOR SUBORDINATED NOTES PAYABLE

NOTES PAYABLE

In January 1998, Brigham entered into a reserve-based revolving credit
facility (as amended the "Senior Credit Facility") that originally provided for
initial borrowing availability of $75 million. Principal outstanding under the
Senior Credit Facility was due at maturity on January 26, 2001 with interest due
monthly for base rate tranches or periodically as LIBOR tranches mature. Amounts
outstanding under the Senior Credit Facility accrued interest at either the
lender's Base Rate or LIBOR plus 2.25%, at Brigham's option. In connection with
the origination of the Senior 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 Senior Credit Facility was amended in March 1999 to reduce the borrowing
availability, extend the date of borrowing base redetermination, modify certain
financial covenants, include certain additional covenants that place significant
restrictions on Brigham'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 Brigham's option. Brigham incurred a $500,000
transaction fee due to the lender over a ten-month period.

F-12

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

In July 1999, the Senior Credit Facility was amended to provide Brigham with
borrowing availability of $56 million. As consideration for this amendment,
Brigham issued to its senior lenders one million warrants to purchase Brigham'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 Brigham and was recognized as
additional deferred loan fees to be amortized over the remaining period to
maturity of the Senior Credit Facility. Brigham's obligations under the Senior
Credit Facility are secured by substantially all of the oil and natural gas
properties and other tangible assets of Brigham.

In February 2000, Brigham entered into an amended and restated Senior Credit
Facility with its existing senior lenders and a new lender. The Senior Credit
Facility was further amended in October 2000 and December 2001. The amended and
restated Senior Credit Facility provides Brigham with $75 million in borrowing
availability with a maturity date of December 31, 2003.

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

In October 2000, the Senior Credit Facility was amended in connection with
the refinancing of the subordinated notes. The Senior Credit Facility was
amended to, among other things, permit the issuance of new subordinated notes
and new preferred stock to provide funding for the repurchase of the
subordinated notes and equity interests. In addition, the minimum interest
coverage ratio test of the Senior Credit Facility was amended to reflect
Brigham's expected cash flow and interest expense beginning in the fourth
quarter of 2000 and Brigham conditionally waived certain rights to force
conversion of the portion of the borrowings under the Senior Credit Facility
that are convertible at $3.90 per share.

The December 2001 amendment to the Senior Credit Facility extended the
maturity date from December 31, 2002 to December 31, 2003. Brigham recognized
$200,000 as additional deferred loan costs that will be amortized over the
remaining period to maturity of the Senior Credit Facility. In addition, the
unamortized deferred loan fees relating to the Senior Credit Facility as
previously amended will be amortized over the remaining period to maturity of
the Senior Credit Facility.

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

As of December 31, 2001, Brigham had $75 million in borrowings outstanding
under the Senior Credit Facility, of which the Convertible Notes are
$30 million. Principal outstanding under the Senior Credit Facility is due at
maturity with interest due monthly for base rate tranches or periodically as
LIBOR tranches mature. The annual interest rate for borrowings under the Senior
Credit Facility is either the lender's base rate or LIBOR (1.88% on
December 31, 2001) plus 3.00%, at Brigham's

F-13

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

option. Obligations under the Senior Credit Facility are secured by
substantially all of Brigham's oil and natural gas properties and other tangible
assets.

The Senior Credit Facility contains various restrictive covenants and
compliance requirements, which include minimum current ratio, interest coverage
ratio, limitations on capital expenditures related to seismic and land
activities, and various other financial covenants. At December 31, 2001 and for
the year then ended, Brigham was in compliance with the covenants.

SENIOR SUBORDINATED NOTES PAYABLE

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

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

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

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

In February 2000, the indenture governing the Subordinated Notes was amended
to, among other things, provide Brigham with an extension of its right to pay
interest through the issuance of additional Subordinated Notes in lieu of cash
(or "in kind") through the third quarter of 2000 and potentially through the
fourth quarter of 2000 if certain conditions were met. In exchange for granting
these amendments, Brigham (i) reset the price of the warrants previously issued
to the holders of the

F-14

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Subordinated Notes to purchase one million shares of Brigham's common stock from
an exercise price of $3.50 per share to $2.43 per share and (ii) granted to the
holders of the Subordinated Notes a term overriding royalty interest that
provided for the limited right to receive 4%, or 3% if certain conditions were
met, of Brigham's net production revenue to reduce any outstanding Subordinated
Notes issued as interest paid in kind. As payments were made pursuant to the
term overriding royalty interest, they were recorded by Brigham as a reduction
of the balance payable pursuant to the Subordinated Notes.

On November 1, 2000, the Subordinated Notes, the term overriding royalty
interest and all of the equity securities of Brigham held by the holders of the
Subordinated Notes were purchased by Brigham for $20 million cash resulting in
an extraordinary gain of $32.3 million, net of transaction costs of
$1.7 million.

In October 2000, Brigham issued $20 million of new subordinated notes to
Shell Capital Inc. (the "SCI Notes") and 1,250,000 warrants to purchase
Brigham's common stock (the "SCI Warrants"). The SCI Notes are issued pursuant
to a multi-draw facility at borrowing increments of at least $1 million, and
such funds cannot be redrawn once they have been repaid. Principal is due at
maturity in 2005 and interest at the rate of 10.75% per annum is payable
quarterly on the last day of each January, April, July and October. At Brigham's
option, up to 50% of the interest payments during the first two years can be
satisfied by payment-in-kind ("PIK") through the issuance of additional SCI
Notes in lieu of cash. The SCI Notes are secured obligations ranking junior to
Brigham's existing $75 million Senior Credit Facility, are redeemable at
Brigham's option for face value at anytime and have certain financial and other
covenants. The SCI Warrants have a term of seven years, an exercise price of
$3.00 per share and a cashless exercise feature. Brigham valued the SCI Warrants
using the Black-Scholes valuation model and recorded the estimated value of
$2.9 million as deferred loan costs which are being amortized over the five-year
term of the SCI Notes. The outstanding balance of the SCI Notes totaled $16.7
and $7.0 million at December 31, 2001 and 2000, respectively.

The SCI Notes contain various restrictive covenants and compliance
requirements, which include minimum current ratio, interest coverage ratio,
limitations on capital expenditures related to seismic and land activities, and
various other financial covenants. At December 31, 2001 and for the year then
ended, Brigham was in compliance with the covenants.

6. SERIES A PREFERRED STOCK

In October 2000, Brigham designated 1.5 million shares of preferred stock as
Series A Preferred Stock, which has a par value of $.01 per share and a stated
value of $20 per share. The Series A Preferred Stock is cumulative and pays
dividends quarterly at a rate of 6% per annum of the stated value if paid in
cash or 8% per annum of the stated value if paid-in-kind ("PIK") through the
issuance of additional Series A Preferred Stock in lieu of cash. At Brigham's
option, up to 100% of the dividend payments on the Series A Preferred Stock can
be paid by the issuance of PIK dividends for five years. The Series A Preferred
Stock matures in ten years and is redeemable at Brigham's option at 100% or 101%
of par value (depending upon certain conditions) at anytime prior to maturity.

On November 1, 2000, Brigham issued one million shares of mandatorily
redeemable preferred stock (the "Series A Preferred Stock") and 6,666,667
warrants to purchase Brigham's common stock (the "Series A Warrants") for net
proceeds of $19.8 million. The proceeds from the issuance of the Series A
Preferred Stock and Series A Warrants were used to purchase the Subordinated
Notes, the term overriding royalty interest and all of the equity securities of
Brigham held by the holder of the Subordinated Notes as described in Note 5.

F-15

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

In March 2001, Brigham designated an additional 750,000 shares of preferred
stock as Series A and issued 500,000 shares of Series A Preferred Stock and
2,105,263 warrants to purchase Brigham's common stock (the "Additional Series A
Warrants") for net proceeds of $9.8 million.

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

Brigham had 1,630,692 and 1,000,000 shares of Series A Preferred Stock
issued and outstanding with a redemption value of $32.6 million and
$20.0 million at December 31, 2001 and 2000, respectively,

7. ISSUANCE OF COMMON STOCK

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

8. CAPITAL LEASE OBLIGATIONS

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

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

F-16

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

leases and the present value of the net minimum lease payments at December 31,
2001 are as follows (in thousands):

2002........................................................ $ 30
2003........................................................ --
----
Total minimum lease payments................................ 30
Estimated executory costs included in capital leases...... (1)
----
Net minimum lease payments.................................. 29
Amounts representing interest............................. (1)
----
Present value of net minimum lease payments................. 28
Less: current portion....................................... (28)
----
Noncurrent portion.......................................... $ --
====

9. INCOME TAXES

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

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):

F-17

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

Realization of deferred tax assets associated with net operating loss
carryforwards ("NOLs") and other credit carryforwards is dependent upon
generating sufficient taxable income prior to their expiration. At December 31,
2001, management believes it is more likely than not that these NOLs and other
credit carryforwards may expire unused and, accordingly, has established a
valuation allowance of $8.4 million against them. The valuation allowance was
reduced by $4.1 million in 2001 due to an increase of $6.7 million in deferred
tax liabilities, partially offset by a $2.4 million increase in carryforward
amounts.

At December 31, 2001, Brigham has regular tax net operating loss
carryforwards of approximately $88.8 million of which $13.3 million expires in
2012, $26.4 million expires in 2018, $21.0 expires in 2019, $11.7 million
expires in 2020 and $16.4 million expires in 2021. In addition, at December 31,
2001, Brigham has alternative minimum tax net operating loss carryforwards of
approximately $74.5 million of which $8.7 million expires in 2012,
$23.2 million expires in 2018, $20.4 million expires in 2019, $6.7 million
expires in 2020 and $15.5 million expires in 2021. Also, at December 31, 2001,
Brigham has capital loss carryforwards of approximately $1.3 million that expire
in 2006.

Brigham believes it has a limitation on its net operating losses under
Internal Revenue Code Section 382 due to a potential 50% change in ownership
among its 5% shareholders over a three-year period. This limitation is
approximately $4.5 million per year.

10. NET INCOME (LOSS) PER SHARE

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

F-18

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

resulted in the issuance of common stock that would then share in the earnings
of Brigham. The number of common share equivalents outstanding is computed using
the treasury stock method.

F-19

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

At December 31, 2001, 2000, and 1999 options and warrants to purchase
approximately 7.7 million, 11.1 million and 3.5 million shares of common stock,
respectively, were outstanding but were not included in the computation of
diluted income (loss) per share because the effect of including the options and
warrants would have been anti-dilutive.

11. CONTINGENCIES, COMMITMENTS AND FACTORS WHICH MAY AFFECT FUTURE OPERATIONS

LITIGATION

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

On November 20, 2001, Brigham filed a lawsuit in the District Court of
Travis County, Texas against Steve Massey Company, Inc. ("Massey") for breach of
contract. The Petition claims Massey furnished defective casing to Brigham,
which ultimately led to the casing failure of the Palmer "347" No. 5 well (the
"Palmer #5") and the loss of the Palmer #5 as a producing well. Brigham believes
the amount of damages incurred due to the loss of the Palmer #5 may exceed
$5 million. Massey joined as additional defendants to the lawsuit other parties
that had responsibility for the manufacture, importation or fabrication of the
casing for its use in the Palmer #5. The case is currently in discovery. A trial
has not been set. Brigham believes a trial will not take place before the first
quarter of 2003.

On February 20, 2002, Massey filed an Original Petition to Foreclose Lien in
Brooks County, Texas. Massey's Petition claims Brigham breached its contract for
failure to pay for the casing it furnished Brigham for the Palmer #5 (and that
Brigham's claim is defective, forming the basis of the lawsuit described in the
paragraph above). Massey's Petition claims Brigham owes Massey a total of
$445,819. Brigham recently filed a Motion to Transfer Venue to Travis County,
Texas, to join this case with Brigham's suit against Masses pending in Travis
County. In the addition, Brigham has asked for a Plea in Abatement to place the
case on hold until the Travis County suit has been resolved. If Massey is
successful in its Brooks County case, Massey would have the right to foreclose
its lien against the well, associated equipment and Brigham's leasehold
interest. At this point in time, Brigham cannot predict the outcome of either
the Travis County case or the Brooks County case.

On June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed
suit against Brigham, claiming Brigham transported natural gas under his
property through an existing pipeline, without his consent. Brigham is now using
an alternate pipeline. Mr. Garcia is claiming $1.2 million in actual damages and
$3 million in exemplary damages. Brigham is strenuously defending this lawsuit,
believing there is no basis for the damages being claimed. The case has been set
for mediation on May 2, 2002. At this point in time, Brigham cannot predict the
outcome of this case.

As of December 31, 2001, there were no known environmental or other
regulatory matters related to Brigham's operations that are reasonably expected
to result in a material liability to Brigham. Compliance with environmental laws
and regulations has not had, and is not expected to have, a material adverse
effect on Brigham's capital expenditures, earnings or competitive position.

OPERATING LEASE COMMITMENTS

Brigham leases office equipment and space under operating leases expiring at
various dates. The noncancelable term of the lease for Brigham's office space
expires in 2007 with an option to renew for

F-20

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

an additional five years. The future minimum annual rental payments under the
noncancelable terms of these leases at December 31, 2001 are as follows (in
thousands):

2002........................................................ $ 864
2003........................................................ 881
2004........................................................ 881
2005........................................................ 881
2006........................................................ 881
Thereafter.................................................. 440
------
$4,828
======

Future minimum rental payments are not reduced by minimum sublease rental
income of approximately $45,000 due in 2002 under noncancelable subleases.

Rental expense for the years ended December 31, 2001, 2000 and 1999 was
approximately $731,000, $805,000 and $938,000, respectively.

MAJOR PURCHASERS

The following purchasers accounted for 10% or more of Brigham's oil and
natural gas sales for the years ended December 31, 2001, 2000 and 1999:

Brigham ended its existing relationship with Purchaser A effective March 1,
2002 and has given notice as required by contract of its intent to end its
relationship with Purchaser B at the end of the notice period. Due to the
availability of other purchasers, Brigham does not believe that the loss of
either of these purchasers will adversely affect Brigham's result of operations.

FACTORS WHICH MAY AFFECT FUTURE OPERATIONS

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

12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Brigham utilizes various commodity swap and option contracts to (i) reduce
the effects of volatility in price changes on the oil and natural gas
commodities it produces and sells, (ii) support its capital budgeting plans, and
(iii) lock-in prices to protect the economics related to certain capital
projects.

As of December 31, 2001, Brigham has three fixed price swap derivative
contracts that are designated as hedges and one fixed price cap derivative
contract that is not designated as a hedge. The

F-21

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

following table sets forth Brigham's outstanding natural gas derivative
contracts as of December 31, 2001:

NATURAL GAS DERIVATIVE CONTRACTS

Derivative instruments that do not qualify as hedging contracts are recorded
at fair value on the balance sheet. At each balance sheet date, the value of
these derivatives is adjusted to reflect current fair value and any gains or
losses are recognized as other income or expense. At December 31, 2001 and 2000,
the fair value of these derivatives included in other liabilities was $384,000
and $10.1 million, respectively. Brigham recognized $9.7 million, $(8.9) million
and $(115,000) in non-cash gains (losses) related to changes in the fair values
of these derivative contracts and $1.5 million, $620,000 and $48,000 in losses
related to the cash settlement payments made by Brigham to the counterparty for
the years ended December 31, 2001, 2000 and 1999, respectively.

13. FINANCIAL INSTRUMENTS

Brigham'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-term
maturities. The carrying value of Brigham's Senior Credit Facility approximates
its fair market value since it bears interest at floating market interest rates.
The fair value of Brigham's SCI Notes at December 31, 2001 was $13.9 million.

F-23

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Brigham's accounts receivable relate to oil and natural gas sold to various
industry companies, and amounts due from industry participants for expenditures
made by Brigham on their behalf. Credit terms, typical of industry standards,
are of a short-term nature and Brigham does not require collateral. Brigham's
accounts receivable at December 31, 2001 and 2000 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.

14. EMPLOYEE BENEFIT PLANS

Brigham has adopted a defined contribution 401(k) plan for substantially all
of its employees. The plan provides for Brigham matching of employee
contributions to the plan, at Brigham's discretion. During 2001, Brigham matched
25% of eligible employee contributions. Based on attainment of performance goals
established at the beginning of 2001, Brigham matched an additional 17% of
eligible employee contributions made during 2001. Brigham contributed $102,000
to the 401(k) plan for the year ended December 31, 2001 to match eligible
contributions by employees. Prior to 2001, Brigham had not matched employee
contributions.

15. STOCK BASED COMPENSATION

Brigham 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 Brigham. An
aggregate of 1,588,170 shares of Brigham's common stock was reserved for
issuance pursuant to this plan. By resolution of the stockholders in May 2001,
the number of shares of common stock available under the plan was amended to
equal the lesser of 13% of the shares of common stock of Brigham issued and
outstanding at any time or 2,077,335 shares. The Compensation Committee of the
Board of Directors determines the type of awards made to each participant and
the terms, conditions and limitations applicable to each award. Options granted
subsequent to March 4, 1997 have an exercise price equal to the fair market
value of Brigham's common stock on the date of grant and generally vest over
three to five years.

Brigham 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 Brigham's common stock on the
date of grant and generally vest over five years.

F-24

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table summarizes activity under the incentive plan for each of
the three years ended December 31, 2001:

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

Exercise prices for options outstanding at December 31, 2001 and 2000 range
from $1.5545 to $14.375 and have remaining contract lives of 1 to 7 years.
Exercise prices for options outstanding at December 31, 1999 range from $1.5545
to $14.375 and remaining contractual lives range from 4.5 to 7 years. Options
exercisable at December 31, 2001, 2000 and 1999 were 378,495, 247,450, and
291,242, respectively.

The weighted average fair value per share of stock compensation issued
during 2001, 2000 and 1999 was $2.19, $1.92, and $1.42, respectively. The fair
value for these options was estimated using the Black-Scholes model with the
following weighted average assumptions for grants made in 2001, 2000 and 1999;
risk free interest rate of 4.9%, 6.2%, and 6.0%; volatility of the expected
market prices of Brigham's common stock of 60%, 67% and 57%; expected dividend
yield of zero and weighted average expected option lives of 7.0, 6.6, and
5.6 years, respectively.

The Black-Scholes valuation model was developed for use in estimating the
fair value of traded options that have no vesting restrictions and are
transferable. Additionally, the assumptions required by the valuation model are
highly subjective. Because Brigham'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 Brigham's stock options.

Had compensation cost for Brigham's stock options been determined based on
the fair market value at the grant dates of the awards consistent with the
methodology prescribed by SFAS 123,

F-25

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Brigham's net income (loss) and net income (loss) per share for the years ended
December 31, 2001, 2000 and 1999 would have been the pro forma amounts indicated
below:

EXCHANGE OF CERTAIN OPTIONS FOR SHARES OF RESTRICTED STOCK

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

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

16. RELATED PARTY TRANSACTIONS

During the years ended December 31, 2001, 2000 and 1999, Brigham incurred
costs of approximately $355,000, $138,000 and $180,000, respectively, in fees
for land acquisition services performed by a company owned by a brother of
Brigham's President and Chief Executive Officer and its Senior Vice
President--Land and Administration. Other participants in Brigham's 3-D seismic
projects reimbursed Brigham for a portion of these amounts. At December 31, 2001
and 2000, Brigham had recorded a liability in accounts payable of approximately
$30,000 and $19,000, respectively, related to services performed by this
company.

A director of Brigham served as a consultant to Brigham on various aspects
of Brigham's business and strategic issues. Fees paid for these services by
Brigham were approximately $44,000, $33,000 and $63,000 for the years ended
December 31, 2001, 2000 and 1999, respectively. Additional disbursements
totaling approximately $6,000, $12,000 and $12,000 were made during 2001, 2000
and 1999, respectively,

F-26

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

for the reimbursement of certain expenses. At December 31, 2001 and 2000, there
were no payables related to these services recorded by Brigham.

From time to time, in the normal course of business, Brigham has engaged a
drilling company in which one of Brigham's current directors owns stock and
serves on the board of directors. Total payments during 2001 and 2000 were
$3.9 million and $2.4 million, respectively. At December 31, 2001 the drilling
company was not performing work for Brigham and there were no amounts owed.

In October 2001, Brigham entered into a Joint Exploration Agreement with
Carrizo Oil & Gas, Inc. ("Carrizo"). Under the terms of this agreement the
parties (1) blended their existing oil and gas leasehold positions covering a
South Texas prospect, (2) identified five separate areas of mutual interest
within the prospect, and (3) agreed upon procedures for the future exploration
and development of the prospect. One of Brigham's current directors was a
co-founder of Carrizo and is currently a member of Carrizo's board of directors.
At December 31, 2001 Brigham was owed $158,000 by Carrizo for exploration and
production activities. Brigham owed Carrizo $13,000 at December 31, 2001.

During 2001, Brigham entered into three agreements with Aspect Resources,
LLC ("Aspect"). These agreements included (1) a Joint Development Agreement
extending the term of an area of mutual interest arrangement, and establishing
cost sharing for potential expenditures within the project area; (2) an
Agreement and Partial Assignment of Seismic Participation Agreement under which
Aspect assigned Brigham an interest in an existing 3-D seismic project and
Brigham must pay the assigned interest portion of future costs; (3) a
Geophysical Exploration Agreement under which Brigham assigned Aspect an
interest in an existing 3-D project area (with certain exclusion) and Aspect
agreed to provide certain seismic data overlapping the project area and share in
future costs. The President of Aspect is a current director of Brigham and a
member of the Compensation Committee. Total amounts paid to Aspect during 2001
for exploration, development and production operations were $588,000. Total
amounts paid to Brigham by Aspect during 2001 for exploration, development and
production operations were $524,000. Brigham owed Aspect $174,000 at
December 31, 2001 for various exploration and production activities. Aspect owed
Brigham $291,000 and $41,000 at December 31, 2001 and 2000, respectively, for
various oil and gas exploration and production activities. Brigham was also owed
$20,000 by Aspect Management Corp., an affiliate of Aspect, at December 31, 2001
for joint venture operations.

17. SUPPLEMENTAL CASH FLOW INFORMATION

F-27

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

18. OTHER ASSETS AND LIABILITIES

Other current assets consist of the following (in thousands):

Other noncurrent liabilities consist of the following (in thousands):

19. OIL AND NATURAL GAS EXPLORATION AND PRODUCTION ACTIVITIES

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

COSTS INCURRED AND CAPITALIZED COSTS

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

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

F-28

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Following is a summary of costs (in thousands) excluded from depletion at
December 31, 2001 by year incurred. At this time, Brigham 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.

20. OIL AND NATURAL GAS RESERVES AND RELATED FINANCIAL DATA (UNAUDITED)

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

OIL AND NATURAL GAS RESERVE DATA

The following tables present Brigham's estimates of its proved oil and
natural gas reserves. Brigham emphasizes reserves are approximates and are
expected to change as additional information becomes available. Reservoir
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact way, and the accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Accordingly, there can
be no assurance that the reserves set forth herein will ultimately be produced
nor can there be assurance that the proved undeveloped reserves will be

F-29

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

developed within the periods anticipated. A substantial portion of the reserve
balances was estimated utilizing the volumetric method, as opposed to the
production performance method.

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN

The following table presents a standardized measure of discounted future net
cash inflows (in thousands) relating to proved oil and natural gas reserves.
Future cash flows were computed by applying year-end prices of oil and natural
gas relating to Brigham's proved reserves to the estimated year-end quantities
of those reserves. Future price changes were considered only to the extent
provided by contractual agreements in existence at year-end. Future production
and development costs were computed by estimating those expenditures expected to
occur in developing and producing the proved oil and natural gas reserves at the
end of the year, based on year-end costs. Actual future cash inflows

F-30

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

may vary considerably and the standardized measure does not necessarily
represent the fair value of Brigham's oil and natural gas reserves.

The base sales prices for Brigham's reserves were $2.57 per Mcf for natural
gas and $19.84 per Bbl for oil as of December 31, 2001, $10.42 per Mcf for
natural gas and $26.83 per Bbl for oil as of December 31, 2000, 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 Brigham's reserves at these dates.

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

F-31

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

21. QUARTERLY FINANCIAL DATA (UNAUDITED)

F-32

INDEX TO EXHIBITS

The following documents are filed as exhibits to this report:

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

* Management contract or compensatory plan.

+ Filed herewith.