Use these links to rapidly review the documentTABLE OF CONTENTS INDEX TO FINANCIAL STATEMENTS

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K

|ý                                           | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|------------------------------------------- | ----------------------------------------------------------------------------------------
|For the fiscal year ended December 31, 2002
|OR                                         
|o                                           | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 000-22433

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Brigham Exploration Company(Exact name of Registrant as Specified in its Charter)

|Delaware(State or other jurisdiction of
incorporation or organization)                                                   |  | 75-2692967(I.R.S. Employer 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)                                                      
|Securities registered pursuant to Section 12(b) of the Act:                                                             
|Title of Each Class                                                                                                      |  | Name of Each Exchange on Which Registered     
|None                                                                                                                     |  | None                                          
|Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.01 par value(Title of Class)                

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes ý    No o

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.

Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the
Act). Yes o    No ý

As
of June 28, 2002, the registrant had 16,061,042 shares of voting common outstanding. The aggregate market value of the registrants outstanding shares of voting common stock held by
non-affiliates, based on the closing price of these shares on June 28, 2002 of $4.25 per share as reported on The Nasdaq Stock MarketSM, was $34.2 million. Shares held by
each executive officer and director and by each person who owns 10% or more of the outstanding common stock are considered affiliates. The determination of affiliate status is not necessarily a
conclusive determination for other purposes.

As
of March 21, 2003, the registrant had 19,899,807 shares of voting common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions
of the definitive proxy statement for the Registrant's 2003 Annual Meeting of Stockholders to be held on May 28, 2003, 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, 2002.

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TABLE OF CONTENTS



|                              |  |                                                                                         |  | Page
|----------------------------- |  | --------------------------------------------------------------------------------------- |  | ----
|PART I                        |  |                                                                                        
|ITEM  1.                      |  | BUSINESS                                                                                |  | 1   
|ITEM  2.                      |  | PROPERTIES                                                                              |  | 9   
|ITEM  3.                      |  | LEGAL PROCEEDINGS                                                                       |  | 18  
|ITEM  4.                      |  | SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS EXECUTIVE OFFICERS OF THE REGISTRANT |  | 19  
|PART II                       |  |                                                                                        
|ITEM  5.                      |  | MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS                   |  | 20  
|ITEM  6.                      |  | SELECTED FINANCIAL DATA                                                                 |  | 22  
|ITEM  7.                      |  | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   |  | 23  
|ITEM  7A.                     |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                              |  | 46  
|ITEM  8.                      |  | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                             |  | 48  
|ITEM  9.                      |  | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE    |  | 48  
|PART III                      |  |                                                                                        
|ITEM  10.                     |  | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT                                      |  | 49  
|ITEM  11.                     |  | EXECUTIVE COMPENSATION                                                                  |  | 49  
|ITEM  12.                     |  | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT                          |  | 49  
|ITEM  13.                     |  | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                                          |  | 49  
|ITEM  14.                     |  | CONTROLS AND PROCEDURES                                                                 |  | 49  
|PART IV                       |  |                                                                                        
|ITEM  15.                     |  | EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K                         |  | 50  
|GLOSSARY OF OIL AND GAS TERMS |  | 51                                                                                     
|SIGNATURES                    |  | 54                                                                                     
|CERTIFICATIONS                |  | 55                                                                                     
|INDEX TO FINANCIAL STATEMENTS |  | F-1                                                                                    

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BRIGHAM EXPLORATION COMPANY2002 ANNUAL REPORT ON FORM 10-K

PART I

ITEM 1. BUSINESS

Overview

We are an independent exploration, development and production company that utilizes 3-D seismic imaging and other advanced technologies to
systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our activity in provinces where we believe 3-D seismic technology can be used effectively to
maximize our return on capital invested by reducing drilling risk and enhancing our ability to cost effectively grow reserves and production volumes. Our exploration and development activities are
concentrated in the onshore Texas Gulf Coast, the Anadarko Basin of western Oklahoma and the Texas Panhandle, and West Texas. We believe that our focused approach of utilizing large scale
3-D seismic surveys and related technology in our core areas allows us to create and maintain a large inventory of high quality exploration and development prospects and provides us with
the opportunity to enhance our exploration success and efficiently deploy our capital. The following is a brief summary of our assets at year-end 2002:

| |                    | For the Year Ended
December 31, 2002 |   | At December 31, 2002
| | ------------------ | ------------------------------------ | - | --------------------
|
|
| | Texas Gulf Coast   |                                      | $ | 13.3                
| | Anadarko Basin     |                                      |   | 5.5                 
| | West Texas / Other |                                      |   | 1.0                 
| |                    |                                      |   |                     
| |                    | Total                                |   | $                   
| |                    |                                      |   |                     

Business Strategy

Our business strategy is designed to create stockholder value by generating superior growth in reserves, production volumes and cash flow through the successful
execution of high rate of return exploration and development drilling. Key elements of our business strategy include:



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Core Exploration and Development Properties

From our inception in 1990 through 1999, the vast majority of our drilling expenditures were allocated to exploration-oriented projects. Given our recent
exploratory successes, we are benefiting from the allocation of a larger portion of our drilling expenditures toward the development of our recent discoveries.

For
the three-year period ended December 31, 2002, we completed 73 gross wells (26.4 net) in 84 attempts for a completion rate of 87% at an average drilling finding
cost of $0.96 per Mcfe. In 2002, we completed 22 gross wells (7.1 net) in 24 attempts for a completion rate of 92%, adding approximately 20.6 Bcfe of proved reserves at an average drilling finding
cost of $0.96 per Mcfe. Set forth below is a summary of our recent activity and expected future activity in our core areas.

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Texas Gulf Coast

The onshore Texas Gulf Coast province is a high-potential, multi-pay region that is extremely well suited for 3-D seismic
exploration due to its substantial structural and stratigraphic complexity. We believe our exploration approach and our staff's extensive experience in this area provides us with significant
competitive advantages. At December 31, 2002, our proved reserves in our Texas Gulf Coast province were approximately 65.3 Bcfe, representing 54% of our total proved reserves. We had also
accumulated approximately 2,686 square miles (1.7 million acres) of 3-D seismic data and approximately 20,339 gross leasehold acres in our Texas Gulf Coast province. Over the past
three years we have completed 36 gross wells (11.8 net) in 40 attempts for a completion rate of 90% and have added an estimated 43.1 Bcfe in estimated proved reserves at an average drilling finding
cost of $0.98 per Mcfe.

During
2002, we completed 10 gross wells (2.9 net) in 10 attempts for a completion rate of 100%. We operated six of the 10 wells that we drilled in the onshore Gulf Coast in 2002. Four
of the wells we drilled were exploratory and six were developmental. Our development drilling was focused on the Home Run and Providence Fields. In addition, we made a new field discovery adjacent to
our Home Run and Triple Crown Fields with the successful completion of our Floyd Fault Block discovery well.

For
2003, we intend to focus our drilling activity in this province on the development of our Home Run, Triple Crown and Floyd Fault Block field discoveries in the Vicksburg, the testing
of high reserve potential fault blocks adjacent to these fields, the development of our Providence Field in the Frio and the continued drilling of our 3-D delineated exploration inventory
in the Frio trend. We expect to spend approximately $17.7 million to drill 17 wells in the onshore Gulf Coast. Approximately 53% percent of these capital expenditures are budgeted for
development drilling, with the remainder allocated towards exploration drilling.

Anadarko Basin

The Anadarko Basin is a prolific natural gas province that we believe offers a combination of lower risk exploration and development opportunities in shallower
horizons, as well as higher potential opportunities in the deeper section. At December 31, 2002, our proved reserves in the Anadarko Basin were 46.0 Bcfe, representing 38% of our total proved
reserves. We had also accumulated approximately 2,197 square miles (1.4 million acres) of 3-D seismic data and approximately 70,130 gross leasehold acres in the Anadarko Basin. Over
the past three years we have completed 26 gross wells (8.8 net) in 31 attempts for a completion rate of 84% and have added an estimated 19.2 Bcfe in proved reserves at an average drilling finding cost
of $0.96 per Mcfe.

During
2002, we completed five gross wells (1.8 net) in seven attempts for a completion rate of 71%. We operated six of the seven wells that we drilled in the Anadarko Basin in 2002. Two
of the wells we drilled were exploratory and five were developmental.

For
2003, we intend to continue to focus our drilling activity in this province on our 3-D delineated exploration and development inventory in the Springer and Hunton trends.
We expect to spend approximately $7.6 million to drill 17 wells. Approximately 76% percent of these capital expenditures are budgeted for development drilling, with the remainder allocated
towards exploration drilling.

West Texas

In West Texas, we have explored various carbonate reservoirs, including the Canyon Reef and Fusselman formation of the Horseshoe Atoll trend, the Canyon Reef of
the Eastern Shelf, and the Mississippian Reef of the Hardeman Basin. At December 31, 2002, our proved reserves in this area were 9.7 Bcfe, representing approximately 8% of our total proved
reserves. We had also accumulated

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approximately 3,695 square miles (2.4 million acres) of 3-D seismic data and approximately 16,820 gross leasehold acres in our West Texas core province. Over the past three years
we have completed 11 gross wells (5.8 net) in 13 attempts for a completion rate of 85% and have added an estimated 6.1 Bcfe in proved reserves at an average drilling finding cost of $0.78 per Mcfe.

During
2002 we completed seven gross wells (2.4 net) in seven attempts for a completion rate of 100%. We operated six of the seven wells that we drilled in West Texas in 2002. Six of the
wells we drilled were exploratory and one was developmental.

For
2003, we intend to continue to focus our drilling activities on our 3-D delineated exploration inventory in the Canyon Reef and Fusselman formations of the Horseshoe
Atoll trend. We expect to spend approximately $2.6 million to drill seven wells. Approximately 48% of these capital expenditures are budgeted for development drilling, with the remainder
allocated towards exploration drilling.

3-D Seismic Exploration

We have accumulated 3-D seismic data covering approximately 8,854 square miles (5.7 million acres) in over 28 geologic plays in seven basins
and seven states. We typically acquire 3-D seismic data in and around existing producing fields where we can benefit from the imaging of producing analog wells. These 3-D
defined analogs, combined with our experience in drilling over 550 wells in our 3-D project areas, provide us with a knowledge base to evaluate other potential geologic trends,
3-D seismic projects within these trends and prospective 3-D delineated drilling locations. Through our experience in the early and mid 1990's, we developed an expertise in the
selection of geologic trends that are best suited for 3-D seismic exploration. As a result, in 1997 and 1998 we invested approximately $64 million in 3-D seismic and
land in plays that we believed were providing optimal 3-D delineated drilling economics. We have used the experience that we have gained within our core trends 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 enhance our return on capital.

Over
the last twelve years we have accumulated substantial experience exploring with 3-D seismic in a wide range of reservoir types and geologic trapping mechanisms. In
addition, we typically acquire digital data bases for integration on our CAEX workstations, including digital land grids, well
information, log curves, production information, geologic studies, geologic top data bases and existing 2-D seismic data. We use our 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, we believe our 3-D generated maps are more accurate than
previous reservoir maps (which generally are based on subsurface geological information and 2-D seismic surveys), enabling us to more precisely evaluate recoverable reserves and the
economic feasibility of projects and drilling locations.

We
have acquired most of our 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, we have participated in non-proprietary group shoots of 3-D seismic data (commonly referred
to as "spec data") when we believe the expected full cycle project economics are justified, and we have exchanged certain interests in some of our non-core proprietary seismic data to gain
access to additional 3-D seismic data. In most of our proprietary 3-D data acquisitions and alliances, we have selected the sites of projects, primarily guided by our knowledge
and experience in the core provinces we explore; established and monitored the seismic parameters of each project for which data was shot; and typically selected the equipment that was used.

Combining
our geologic and geophysical expertise with a sophisticated land effort, we manage the majority of our projects from conception through 3-D acquisition, processing
and interpretation and leasing. In addition, we manage the negotiation and drafting of most of our geophysical exploration agreements, resulting in reduced contract risk and more consistent deal
terms. Because we generate most of our projects, we can often control the size of the working interest that we retain as well as the

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selection of the operator and the non-operating participants. Consistent with our business strategy, we have increased the working interest we retain in our projects, based upon capital
availability and perceived risk. Our average working interest in our 3-D seismic projects acquired during 1996, 1997 and 1998 was 37%, 67% and 80%, respectively. The 3-D
seismic we acquired during 1999, 2000, 2001 and 2002 was primarily through the exchange of certain rights in some of our non-core 3-D seismic projects. Most of these exchanges
did not include an industry participant, therefore we retained potentially all interest in any prospects generated from the newly acquired 3-D seismic data. In early 2003, we acquired
approximately 84 square miles of new proprietary 3-D seismic data in our General Patton Project located in the Frio Trend of the Upper Texas Gulf Coast. We sold a working interest in this
project to an industry participant on a promoted basis and thus retained a 50% working interest in the project.

Exploration and Development Staff

Our experienced exploration staff includes five geophysicists, five geologists, two computer applications specialists and two geophysical/geological/engineering
technicians. Our geophysicists have different but complementary backgrounds, and their diversity of experience in varied geological and geophysical settings, combined with various technical
specializations (from hardware and systems to software and seismic data processing), provides us with valuable technical intellectual resources. Our exploration staff of ten geophysicists and
geologists has an average of more than 20 years of experience per person, most of which was acquired at both our company and various major and large independent oil companies.
Our team was assembled according to the expertise that these individuals have within producing basins where we focus our exploration and development activities. By integrating both geologic and
geophysical expertise within our project teams, we believe we possess a competitive advantage in our exploration approach. Occasionally, we will complement and leverage our 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.

Our
land department staff includes four landmen and three lease and division order analysts.

Operations and Operations Staff

In an effort to retain better control of our project timing, drilling and operational costs and production volumes, we have significantly increased the percentage
of the wells that we operate in the past several years. We operated 75% of the wells that we drilled during 2002, as compared with 10% of the wells we drilled during 1996. As a result of our increased
operational control in recent years, wells operated by us constituted 61% of the PV-10% value of our proved developed producing reserves at year-end 2002, as compared to only
8% at year-end 1996.

Our
operations staff includes five engineers that have drilling, reservoir, environmental and operations engineering experience primarily within our three core provinces. These engineers
work closely with our explorationists and are integrally involved in all phases of the exploration and development process, including preparation of pre- and post-drill reserve
estimates, well design, production management and analysis of full cycle risked drilling economics. We conduct field operations for our operated oil and natural gas properties through our field
production superintendent and third party contract personnel.

Oil and Natural Gas Marketing and Major Customers

Most of our oil and natural gas production is sold under price sensitive or spot market contracts. The revenues generated by our operations are highly dependent
upon the prices of and demand for oil and natural gas. The price we receive for our oil and natural gas production depends upon numerous factors beyond our control, including seasonality, weather,
competition, the condition of the United

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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 our proved reserves and
our revenues, profitability and cash flow. Although we are not currently experiencing any significant involuntary curtailment of our oil or natural gas production, market, economic and regulatory
factors may in the future materially affect our ability to sell our 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 Affect
Us; Oil And Natural Gas Prices Are Volatile" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsRisk FactorsThe Marketability
Of Our Production Is Dependent On Facilities The Typically Do Not Own". For the year ended December 31, 2001, sales to Highland Energy Company and Lantern Petroleum Corporation represented
approximately 60% of our oil revenue and 58% of our natural gas revenue. In 2002, in an effort to achieve better price realizations from the sale of our oil and natural gas, we decided to bring our
commodities marketing activities in-house, enabling us to market and sell our oil and natural gas to a broader universe of potential purchasers. As a consequence, on March 1, 2002,
we ended our oil purchase agreement with Lantern Petroleum and on July 1, 2002, we ended a similar gas sales and purchase arrangement with Highland Energy Company. Due to the availability of
other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Competition

The oil and gas industry is highly competitive in all of its phases. We encounter competition from other oil and gas companies in all areas of our operations,
including the acquisition of seismic and leasing options and oil and natural gas leases on properties to exploration and development of those properties. Our 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 our competitors are large, well established companies with
substantially larger operating staffs and greater capital resources than us. 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 our financial or human resources permit. Our ability to acquire additional properties and to
discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations" "Risk FactorsWe Face Significant Competition" and "Risk FactorsWe Have Substantial
Capital Requirements".

Operating Hazards and Uninsured Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that
new wells we drill will be productive or that we will recover all or any portion of our 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. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our 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. Our future drilling activities may not be successful and,
if unsuccessful, such failure may have a material adverse effect on our 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

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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 we believe that our 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 our business, financial condition or results of
operations.

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, 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 our properties and others. We maintain insurance against some but not all of the risks described above. In particular, the insurance we maintain 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, we 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 our business, financial condition and results of operations. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsRisk FactorsWe Are Subject To Various Casualty Risks" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsRisk FactorsWe May Not Have Enough Insurance To Cover Some Operating Risks".

Employees

On March 21, 2003, we had 52 full-time employees. None is represented by any labor union and we believe relations with our employees are good.

Facilities

Our principal executive offices are located in Austin, Texas, where we lease approximately 34,330 square feet of office space at 6300 Bridge Point Parkway,
Building 2, Suite 500, Austin, Texas 78730.

Title to Properties

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted
in the oil and gas industry. Our properties are subject to royalty interests, standard liens incident to operating agreements, liens for current taxes
and other inchoate burdens, which we believe, do not materially interfere with the use of or affect the value of such properties. Our senior credit facility and subordinated notes are secured by first
and second liens, respectively, against substantially all of our oil and natural gas properties and other tangible assets. See "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of OperationsLiquidity and Capital ResourcesSenior Credit Facility" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesSenior Subordinated Notes".

Governmental Regulation

Our 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 our
cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and

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regulations, we are 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

Our 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 our operations. The permits required for many of our 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, we are in substantial compliance with current applicable environmental laws and regulations, and we have 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 us, as well as the oil and gas industry in general. The
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict and arguably joint and several liability on owners and operators of certain
sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its
definition of "hazardous substance," state laws affecting our 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 us, 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 us. 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. The Clean Air Act of 1970 and its subsequent
amendments in 1990 and 1997 also

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impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides "NOX" and sulfur dioxide "SO2") and particulates
with respect to certain of our operations, we are required to maintain such permits or meet general permit requirements. The Environmental Protection Agency ("EPA") and designated state agencies have
in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group
or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and gas exploration and production operations. Both the EPA and Texas Commission on Environmental
Quality ("TCEQ") have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit air pollutants. We believe that we 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 us.

ITEM 2. PROPERTIES

Our exploration and development activities are focused primarily in the onshore Texas Gulf Coast, the Anadarko Basin of northwest Oklahoma and the Texas Panhandle
and West Texas. We focus our activity in provinces where we believe 3-D seismic technology can be used effectively to maximize our return on capital invested by reducing drilling risk and
enhancing our ability to cost effectively grow reserves and production volumes.

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. We believe our established 3-D seismic exploration approach and our exploration staff's extensive experience in the Texas Gulf Coast
provide us with significant competitive advantages. We have assembled a digital database including geographical, production, geophysical and geological information of the Texas Gulf Coast that our
staff evaluates on CAEX workstations. The majority of our Texas Gulf Coast activity is currently concentrated in the Vicksburg and Frio trends, where we completed eight wells in eight attempts in
2002.

Vicksburg Trend

Our 3-D seismic inventory in the Vicksburg trend consists of approximately 179 square miles of 3-D seismic data (114,560 acres) located
primarily in Brooks County in south Texas. The primary exploration targets within this area are structural features at depths ranging from 9,000 to 14,000 feet.

Since
late 1999, we have completed 13 wells in 13 attempts in the Vicksburg play in South Texas at a proved developed drilling finding cost of $1.55 per Mcfe. However, early in our
Vicksburg drilling program we experienced operational problems, primarily due to poor cement jobs. A few years ago we modified our drilling and completion techniques and have had excellent results
ever since. Excluding three of the early wells with the poor cement jobs, our average drilling finding cost for proved developed reserves for the other ten wells we have drilled in this play has been
approximately $1.34 Mcfe. For 2003, we have budgeted approximately $9.2 million to drill approximately four developmental wells and three exploratory wells in this area.

Since
1999, our exploration efforts in this trend have been focused in our Diablo Project. During 2002, we added to our exploration success in the Diablo project with our Floyd Fault
Block discovery. Including this discovery, the Diablo project has provided three significant Vicksburg field discoveries. In 1999, we discovered the Home Run Field and in 2001 we discovered the Triple
Crown Field. We own, along with a major integrated oil company participant, 10,000 gross and net acres of leasehold in the Diablo Project, and we acquired a 54 square mile proprietary 3-D
program over the area in 1997 and

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1998. We retain a 34% working interest in the project, but have increased our pre-payout working interest to 50% in select acreage that was subsequently drilled as our Triple Crown Field
discovery.

Floyd Fault Block Vicksburg Discovery.We drilled our Floyd Fault Block discovery, the Sullivan #8, in December 2002.
We retained a 34% working and 25% revenue interest in the Sullivan #8, which proves
up reserves in one of several fault blocks adjacent to our Home Run and Triple Crown Fields. The Sullivan #8 encountered approximately 172 feet of apparent net pay in several Lower Vicksburg pay
intervals at depths between 12,900 and 13,650 feet. The quantity of pay encountered is approximately triple that encountered in our typical Home Run Field Vicksburg wells.

The
Sullivan #8, began producing to sales in March 2003 at a rate of approximately 9.2 MMcf of natural gas and 580 barrels of condensate per day (12.7 MMcfed), or approximately
3.2 MMcfed net to our 25% revenue interest, with a flowing tubing pressure of approximately 8,900 psi. This flowing tubing pressure is approximately 4,000 psi higher than our typical Home Run Field
Vicksburg wells at comparable production rates, indicating the higher deliverability of the Floyd Fault Block reservoirs. The current production rate is limited by the production facilities, and we
expect the operator of the well to expand the facilities in order to produce the well at higher rates. We estimate that the Floyd Fault Block will require up to nine additional wells for full
development, four of which are proved undeveloped. We expect to spud our first development well in the second quarter of 2003 and could drill up to three additional wells in 2003.

Home Run Field & Triple Crown Vicksburg Field.We discovered the Home Run Field in late 1999 and the Triple Crown
Field in 2001. To date, we have drilled and completed 12 consecutive wells in these fields. During 2002, we drilled and completed three wells in the Home Run Field. These wells include:



We
believe the fields could require up to 35 additional wells for full development.

Adjacent Fault Blocks to Home Run and Triple Crown.We also anticipate testing at least one of the other adjacent fault
blocks during 2003. One of these fault blocks is adjacent to our Floyd Fault Block discovery, and we believe that a portion of this fault block is juxtaposed to pay intervals found in the Sullivan #8.
This fault block, and other adjacent fault blocks, provide up to 15 additional locations. We believe that all of the adjacent fault blocks are located structurally high to the adjacent Triple Crown
Field, and structurally low to the adjacent Home Run Field, providing us with significant probable and possible reserve potential.

Frio Trend

In the Frio trend of the Upper Texas Gulf Coast, we have accumulated an inventory of over 1,172 square miles of predominantly non-proprietary
3-D seismic data (696,320 acres) located primarily in Matagorda and Brazoria Counties in south Texas. In early 2003, we added to our 3-D seismic inventory when we acquired 84
square miles of proprietary seismic data within our General Patton project in the Frio trend. We sold a 50% working interest in the General Patton project to a participant on a

10

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promoted basis while retaining operations, and as a result we paid 33.3% of the seismic and pre-seismic land costs for a 50% working interest in the project. We are targeting both the
shallow non-pressured and the deeper pressured Frio sands, analogous to our recent high rate discoveries in the trend. Our completions in this play are typically providing quick payouts of
drilling and completion costs, and attractive rates of return on our drilling capital investments.

Since
late 2000, we have completed 10 Frio tests in 11 attempts, at an estimated average drilling finding cost for proved developed reserves of $0.89 per Mcfe. For 2003, we expect to
spend approximately $6.3 million to drill approximately two developmental wells and five exploratory wells in this area.

Providence Frio Field.We discovered the Providence Field during the fourth quarter of 2001, when we drilled and completed
the Staubach #1 well. Including the Staubach #1 discovery well in 2001, we have now successfully completed four wells in the Providence Field. These wells include:



We
are currently drilling the Huebner #3, our fifth Providence Field well, with a 40% working interest. The Huebner #3 is not subject to any reversionary interests. This well, like the
recently completed Matthes-Huebner #1, has two potential pay intervals and we expect results in the second quarter 2003.

Most
of our production from the Providence Field in 2002 came from the first two wells drilled, the Staubach #1 and the Burkhart #1R. Gross production from the Providence Field averaged
approximately 22 MMcfed during 2002. With the addition of the Huebner #1, average daily production from the Providence Field during the fourth quarter 2002 was approximately 38 MMcfed. In
March 2003, we had four Providence Field wells on line producing approximately 50 MMcfed, or 13 MMcfed net to our revenue interest.

Other Frio.As part of our ongoing Frio exploration program, in October 2002 we completed the Carr #1, a Frio bright
spot exploration discovery in Brazoria County. We operated and retained a 37%

11

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working interest in the well, which began producing to sales in early December 2002 at an initial rate of approximately 1.8 MMcf of natural gas per day and 50 barrels of oil per day (2.1
MMcfed), or approximately 0.6 MMcfed net to our 29% revenue interest.

In
addition to our ongoing drilling program in the Frio, we continue to generate additional drilling inventory from our data base of more than 1,170 square miles of 3-D
seismic date in the trend. Of this data, we are currently processing the 84 square miles of new proprietary 3-D seismic data that is our General Patton project. We acquired this data along
the same trend that has provided most of our recent Frio discoveries, including the prolific Providence Field. We operate and retain a 50% working interest in this new project and have a strong land
position of over 14,000 acres. Our staff began interpreting the data and defining drilling prospects during the first quarter of 2003, and we hope to commence our drilling program here during the
second half of 2003. The company is assembling additional 3-D projects targeting the highly prolific Frio objective.

Dinn Ranch Wilcox Field

The Dinn Ranch Field was reportedly producing over 100 MMcf of natural gas per day in early 2003. We have participated in two wells in the field thus far. The
first well, the Lopez #1, has experienced operational difficulties and its completion has been delayed. The second well, the Lopez #3, was producing to sales in February 2003 at a rate of
approximately 16.5 MMcf of natural gas per day. We retain an overriding royalty interest in the Lopez #1 and the Lopez #3 that converts into a 12.5% working interest at 100% payout of drilling and
completion costs, and a 25% working interest after 200% payout. At current production rates and commodity prices, we could convert to a 12.5% and possibly a 25% working interest in the Lopez #3 by
year-end 2003. We expect a third well to spud in 2003, in which we expect to retain a 25% ground floor working interest.

Anadarko Basin

The Anadarko Basin is located in northwest Oklahoma and the Texas Panhandle. We believe this prolific natural gas province offers a combination of lower risk
exploration and development opportunities in shallower horizons and deeper higher potential objectives that have been relatively under explored. The stratigraphic and structural objectives in the
Anadarko Basin can provide excellent targets for 3-D seismic imaging. In addition, drilling economics in the Anadarko Basin are enhanced by the multi-pay nature of many of
these prospects, with secondary or tertiary targets serving as either incremental value or as alternatives in the event the primary target zone is not productive. Our activity is currently focused in
the Springer Channel and Hunton trends, where we completed four wells in six attempts in 2002.

Springer Trend

Our 3-D inventory in the Springer trend consists of approximately 630 square miles (403,200 acres) of 3-D seismic data covering portions
of Dewey, Blaine, Canadian and Caddo Counties, Oklahoma. Our activities in this area target buried sand channels at depths of 9,000 to 12,000 feet, as well as other secondary objectives. We began our
operations in the Springer trend in 1991 and our interpretation and prospect generation efforts are still underway.

Since
2000, we have completed nine Springer wells in 13 attempts, at an estimated average drilling finding cost for proved developed reserves of $1.03 per Mcfe. Approximately 50% of
these completions perform at a very high level, and as a result our overall program has provided extremely strong rates of return. Recently we entered into a joint venture that encompasses
approximately 14,000 gross acres, greatly expanding our acreage position in this competitive trend. We have budgeted approximately $4.1 million to drill six developmental wells and six
exploratory wells in this area in 2003.

12

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Hunton Trend

Our 3-D seismic inventory in the Hunton trend consists of approximately 763 square miles (488,320 acres) of 3-D seismic data covering
portions of Wheeler, Hemphill and Roberts Counties, Texas and Beckham County, Oklahoma. The primary exploration targets within this area are high potential, structural features at depths ranging from
7,500 to 25,000 feet. The trend has historically provided longer life reserves relative to our typical Texas Gulf Coast wells, but with the same type of prolific recoveries.

Since
late 2000, we have completed two wells in the Hunton trend in two attempts. In late 2000, we drilled the discovery well for our Mills Ranch Field, the Mills Ranch #1, and in 2002
the first development well, the Mills Ranch #2, at an average estimated proved developed drilling finding cost of $0.58 per Mcfe. We have budgeted approximately $2.8 million to drill four
developmental wells during 2003.

Mills Ranch Field.In July 2000, we spud the Mills Ranch #1, which was drilled directionally to a total depth of over
25,000 feet. We operated and retained a 64% working interest in the well, which 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 Mills Ranch #1 began producing from one of the Hunton pay intervals in January 2001 at approximately 9.5 MMcf of natural gas and 90 barrels of
condensate per day. The discovery well paid out its drilling and completion costs during its first year of production, and at year-end 2002 had produced 3.2 Bcfe and was producing
approximately 3.2 MMcfed.

In
the third quarter 2002, we began drilling the first offset to this discovery, the Mills Ranch #2. We retained a 64% working interest in the Mills Ranch #2, which encountered the basal
Hunton porosity zone approximately 400 feet high to the comparable zone in the discovery well. After running production casing to a depth of approximately 23,900 feet, we perforated and stimulated the
lower Hunton intervals. The well began producing at an initial rate of approximately 6.7 MMcf of natural gas per day with associated condensate. The upper intervals were then stimulated and commingled
into the producing stream. The recent production rate was approximately 1.8 MMcfed, or approximately 0.9 MMcfed net to our 50% revenue interest. Given what we have learned about the remaining reserve
potential of the field, we plan to drill at least one additional development well in the Mills Ranch Field in 2003. We expect to operate and retain a 64% working interest in this well.

West Texas

Our drilling activity in our West Texas province has been focused primarily in various carbonate and predominantly oil reservoirs, including the Canyon Reef and
Fusselman formation of the Horseshoe Atoll trend, the Canyon Reef of the Eastern Shelf, and the Mississippian Reef of the Hardeman Basin, at depths ranging from 7,000 to 13,000 feet. We are currently
focused on the Canyon Reef and Fusselman formations in the Horseshoe Atoll trend, where we completed seven wells in seven attempts in 2002.

Horseshoe Atoll Trend

We have an inventory of approximately 778 square miles (497,920 acres) of 3-D seismic data primarily covering portions of Scurry, Howard, Dawson and
Borden Counties in the Horseshoe Atoll trend, where we have accumulated substantial experience exploring with 3-D seismic over the last twelve years. In 2002, and in prior years, we
frequently sold working interests in our West Texas drilling prospects to industry participants on a promoted basis, which has reduced our drilling risk while also contributing to lower finding costs
and higher rates of return.

13

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Since
2000, we have completed eight wells in eight attempts in the trend at an estimated average drilling finding cost for proved developed reserves of $0.52 per Mcfe. For 2003, we have
budgeted approximately $2.6 million to drill two developmental wells and five exploratory wells.

Our
most significant completions in West Texas during 2002 were in the Fusselman formation in the Horseshoe Atoll trend. In May 2002 we completed the Casa Grande 2 #1 as the
discovery well for the Conner Shea Fusselman Field in West Texas. We operated the Casa Grande 2 #1 with a 50% working interest, which began producing approximately 230 barrels of oil per day, or
approximately 0.6 MMcfed net to our 43% revenue interest. In February 2003, we completed another well in the Conner Shea Fusselman Field, the Brigham operated Casa Grande 12 #1. The Casa Grande
12 #1 began producing at approximately 100 barrels of oil per day, or approximately 0.2 MMcfed net to our 41% revenue interest.

Oil and Natural Gas Reserves

Our estimated total net proved reserves of oil and natural gas as of December 31, 2002, 2001 and 2000 and the present values attributable to these reserves
as of those dates were as follows:

As of December 31,2002

2001

2000Estimated net proved reserves:Natural gas (MMcf)


99,428


88,594


78,167Oil (MBbls)


3,607


3,748


2,870Natural gas equivalent (MMcfe)


121,070


111,081


95,388Proved developed reserves as a percentage of proved reserves


46%


49%


52%Present value of future net revenues (in thousands)

$
307,374

$
146,807

$
497,666Standardized measure (in thousands)

$
239,698

$
120,924

$
359,228Base price used to calculate reserves (1):Natural gas ($ per Mcf)

$
4.74

$
2.57

$
10.42Oil ($ per Bbl)

$
31.25

$
19.84

$
26.83


---

The
reserve estimates reflected above were prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum consultants, and are part of reports on our oil and
natural gas properties prepared by Cawley Gillespie.

In
accordance with applicable requirements of the SEC, estimates of our net 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 net 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 our 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 us, 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

14

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

Drilling Activities

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

Year Ended December 31,2002

2001(1)

2000(2)Gross

Net

Gross

Net

Gross

NetExploratory wells(3):Natural gas

3

0.8

5

1.6

6

1.9Oil

8

2.7

5

3.7

3

0.9Non-productive

1

0.7

4

1.1

2

1.0Total

12

4.2

14

6.4

11

3.8Development wells(4):Natural gas

8

2.4

15

4.6

15

5.8Oil

2

0.9

1

0.1

1

0.7Non-productive

2

0.6

2

0.2

1

0.8Total

12

3.9

18

4.9

17

7.3


---

We
do not own drilling rigs and the majority of our drilling activities have been conducted by independent contractors or industry participant operators under standard drilling
contracts. We operated 75% of the wells we participated in during 2002.

15

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Productive Wells and Acreage

Productive Wells

The following table sets forth our ownership interest as of December 31, 2002 in productive oil and natural gas wells in the areas indicated.

Natural Gas

Oil

TotalProvince:

Gross

Net

Gross

Net

Gross

NetTexas Gulf Coast

34

10.2

19

4.5

53

14.7Anadarko Basin

92

22.7

18

4.5

110

27.2West Texas

13

1.9

81

24.7

94

26.6Total

139

34.8

118

33.7

257

68.5


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.

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 that we held a leasehold,
mineral or other interest at December 31, 2002:

Developed

Undeveloped

TotalProvince:

Gross

Net

Gross

Net

Gross

NetTexas Gulf Coast

9,825

3,582

10,514

4,660

20,339

8,242Anadarko Basin

32,896

12,604

37,234

20,109

70,130

32,713West Texas

6,894

1,986

9,926

5,040

16,820

7,026Other

535

160

5,597

2,422

6,132

2,582Total

50,150

18,332

63,271

32,231

113,421

50,563


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

Acres ExpiringTwelve Months Ending:

Gross

NetDecember 31, 2003

9,014

6,324December 31, 2004

27,449

16,001December 31, 2005

5,366

5,333Thereafter



Total

41,829

27,658


In
addition, as of December 31, 2002 we had lease options to acquire an additional 18,316 gross and 12,656 net acres, all of which expire in 2003.

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Volumes, Prices and Production Costs

The following table sets forth the production volumes, average prices received before hedging, average prices received after hedging and average production costs
associated with our sale of oil and natural gas for the periods indicated.

Year Ended December 31,2002

2001

2000Production:Natural gas (MMcf)


5,791


6,766


4,431Oil (MBbls)


701


468


362Natural gas equivalent (MMcfe)


9,996


9,573


6,600Average sales price per unit:Natural gas revenues (per Mcf)

$
3.33

$
4.29

$
4.06Effects of hedging activities (per Mcf)


(0.12
)

(1.18
)

(2.12
)Average price (per Mcf)

$
3.21

$
3.11

$
1.94Oil revenues (per Bbl)

$
25.17

$
24.38

$
29.47Effects of hedging activities (per Bbl)


(1.62
)

(0.33
)

(0.30
)Average price (per Bbl)

$
23.55

$
24.05

$
29.17Total natural gas and oil revenues (per Mcfe)

$
3.70

$
4.22

$
4.34Effects of hedging activities (per Mcfe)


(0.19
)

(0.85
)

(1.44
)Average price (per Mcfe)

$
3.51

$
3.37

$
2.90Average production costs:Lease operating expenses (per Mcfe)

$
0.38

$
0.36

$
0.32Production taxes (per Mcfe)

$
0.20

$
0.16

$
0.27


Costs Incurred

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

Year Ended December 31,2002(1)

2001(2)

2000(3)(in thousands)Exploration

$
12,693

$
18,210

$
14,238Property acquisition


3,213


3,437


2,540Development


13,301


14,353


12,555Proceeds from participants


(703
)

(135
)

(40
)Costs incurred

$
28,504

$
35,865

$
29,293


---

17

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

ITEM 3. LEGAL PROCEEDINGS

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

On
June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed suit against us claiming that we transported natural gas under his property through an existing pipeline
without his consent. Mr. Garcia claimed $1.2 million in actual damages and $3 million in exemplary damages. In May 2002, we settled the case through mediation for a cash
payment of $125,000. We are now using an alternate pipeline.

On
November 20, 2001, we filed a lawsuit in the District Court of Travis County, Texas against Steve Massey Company, Inc. for breach of contract. The Petition claims Massey
furnished defective casing to us, which ultimately led to the casing failure of the Palmer "347" No. 5 well and the loss of the Palmer #5 as a producing well. We believe 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 been set for August 2003.

On
February 20, 2002, Massey filed an Original Petition to Foreclose Lien in Brooks County, Texas. Massey's Petition claims we breached our contract for failure to pay for the
casing Massey has furnished us for the Palmer #5 (and that our claim forming the basis of the lawsuit described in the paragraph above is defective). Massey's Petition claims we owe Massey a total of
$445,819. Our Motion to Transfer Venue to Travis County, Texas, and our Motion to Consolidate Massey's claim with our suit against Massey pending in Travis County, were recently granted. If Massey is
successful in its claim, Massey would have the right to foreclose its lien against the well, associated equipment and our leasehold interest related to the well. At this point in time, we cannot
predict the outcome of either our claim or Massey's claim.

On
July 11, 2002, an employee of a contractor on our Burkhart #1-R location, Matagorda County, Texas, was killed in an accident. The United States Department of Labor
Occupational Safety & Health Administration investigated the accident, and issued three citations and imposed a total of $168,000 in fines. We are appealing the citations, but at this time,
cannot predict the outcome of that appeal.

On
October 8, 2002, relatives of the contractor's employee filed, in the district court for Matagorda County, Texas, a wrongful death action against us and three of our
contractors in connection with his accidental death on July 11, 2002, on our Burkhart #1-R location. Plaintiffs are seeking unspecified actual and punitive damages. At this point in
time, we cannot predict the outcome of this case, but believe we have sufficient insurance to cover the claim.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

No matter was submitted to a vote of our security holders during the fourth quarter of 2002.

18

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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 21, 2003:

Name

Age

PositionBen M. Brigham

43

Chief Executive Officer, President and ChairmanEugene B. Shepherd, Jr.

44

Chief Financial OfficerDavid T. Brigham

42

Executive Vice PresidentLand and AdministrationA. Lance Langford

40

Senior Vice PresidentOperationsJeffery E. Larson

44

Senior Vice PresidentExploration


Ben M. "Bud" Brighamhas served as our Chief Executive Officer, President and Chairman of the Board since we were founded 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, Inc. 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, Executive Vice PresidentLand and Administration.

Eugene B. Shepherd, Jr., has served as Chief Financial Officer since June 2002. Mr. Shepherd has approximately
20 years of financial and operational experience in the energy industry. Prior to joining us, Mr. Shepherd served as Integrated Energy Managing Director at ABN AMRO Bank, a large
European bank, where he executed merger and acquisition advisory, capital markets and syndicated loan transactions for energy companies. From 1998 to 2000, Mr. Shepherd was an investment
banking Director for Prudential Securities Incorporated, where he executed a wide range of transactions for energy companies. Prior to joining Prudential Securities Incorporated, Mr. Shepherd
served as an investment banker with Stephens Inc. for eight years and with Merrill Lynch Capital Markets for four years. Prior to joining Merrill Lynch Capital Markets, Mr. Shepherd
worked for over four years as a petroleum engineer for both Amoco Production Company and the Railroad Commission of Texas. He has a B.S. in Petroleum Engineering and an MBA, both from the University
of Texas at Austin.

David T. Brighamjoined us in 1992 and has served as Executive Vice PresidentLand and Administration since June 2002
and Corporate Secretary from March 2001 to September 2002. Mr. Brigham served as Senior Vice PresidentLand and Administration from March 2001 to
June 2002, Vice PresidentLand and Administration and Corporate Secretary from February 1998 to March 2001, and as Vice PresidentLand and Legal from 1994
until February 1998. From 1987 to 1992, Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending law school, Mr. Brigham was a
landman for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the
University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board.

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

19

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Jeffrey E. Larsonjoined us in 1997 and was Vice PresidentExploration from August 1999 to March 2001, and has
been Senior Vice PresidentExploration since March 2001. Mr. Larson joined us in October 1997 as Gulf Coast Exploration Manager in our Houston office where he
co-managed our 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 our corporate office in Austin where he assumed an expanded role in directing our exploration activities in the Anadarko Basin, in addition to the further advancement of
our Gulf Coast activities. Prior to joining us, Mr. Larson was an
explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities.
Mr. Larson worked at Burlington for seven years in various roles of increasing responsibility within its exploration department. Prior to Burlington, Mr. Larson spent five years at Exxon
as a Production Geologist and Research Scientist. He has a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana.

PART II

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

Our common stock has been publicly traded on The NASDAQ Stock Marketsm under the symbol "BEXP" since our initial public offering effective
May 8, 1997. The following prices represent the range of high and low sales prices of our common stock on NASDAQ for the period indicated.

2002

2001High

Low

High

LowFirst Quarter

$
3.97

$
2.36

$
5.97

$
3.38Second Quarter

$
5.35

$
3.42

$
4.62

$
3.25Third Quarter

$
4.80

$
3.10

$
5.11

$
2.50Fourth Quarter

$
5.00

$
3.30

$
3.48

$
2.28


The
closing market price of our common stock on March 21, 2003 was $4.69 per share. As of March 21, 2003, there were an estimated 114 record owners of our common stock.

No
dividends have been declared or paid on our common stock to date. We intend to retain all future earnings for the development of our business. Our senior credit facility and
subordinated notes facility restrict our ability to pay dividends on our common stock.

We
are obligated to pay dividends on our Series A and Series B preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum or paid in kind
through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind on our Series A preferred stock expires in
October 2005 and March 2006.Our option to pay dividends in kind on our Series B preferred stock expires in December 2007.
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesSeries A Preferred Stock" and
"Liquidity and Capital ResourcesSeries B Preferred Stock".

20

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Securities Authorized for Issuance under Equity Compensation Plans

The following table includes information regarding our equity compensation plans as of the year ended December 31, 2002:

Plan category

Number of securities to be issued upon exercise of outstanding options

Weighted-average price of outstanding options

Number of securities remaining available for future issuance under equity compensation plansEquity compensation plans approved by security holders

1,782,135

$
3.34

Equity compensation plans not approved by security holders






Total

1,782,135

$
3.34




Recent Sales of Unregistered Securities

In December 2002, in a transaction exempted from registration under section 4(2) of the Securities Act of 1933, we issued 550,000 unregistered
shares of our common stock to Shell Capital in exchange for Shell Capital's warrant position, including 1,250,000 warrants associated with our senior subordinated notes facility, and to terminate
Shell Capital's right to convert $30 million of our senior credit facility into 5,480,769 shares of our common stock. We are required to register these shares under certain conditions as
outlined in a registration rights agreement with Shell Capital dated December 20, 2002.

In
December 2002, in a transaction exempted from registration under section 4(2) of the Securities Act of 1933, we issued CSFB Private Equity 500,000 shares of our
Series B preferred stock with a stated value of $20.00 per share. Net proceeds from the offering were $9.4 million and were used to reduce borrowings under our senior credit facility and
to fund our drilling program and working capital requirements. The Series B preferred stock has terms similar to our Series A preferred stock. We are required to pay dividends on our
Series B preferred stock as discussed above. The Series B preferred stock can be redeemed at our option after December 2007 and is mandatorily redeemable in December 2012.
In connection with the Series B preferred stock offering, we issued to CSFB Private Equity warrants to purchase 2,298,851 shares of our common stock at an exercise price of $4.35 per share. To
exercise the warrants, CSFB Private Equity has the option to use either cash or shares of our Series B preferred stock with an aggregate value equal to the exercise price. In the event that our
stock price averages at least $6.525 for 60 consecutive trading days, then the warrants must be exercised if we so require. For financial reporting purposes, the warrants issued with the
Series B preferred stock were valued at approximately $4.6 using the Black Scholes Option Pricing model and were recorded as additional paid in capital in December 2002.

21

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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 our consolidated financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data."

|                                                           |                                                    | 2002                         |         | 2001   |        | 2000        |        | 1999   |         | 1998    |        
|---------------------------------------------------------- | -------------------------------------------------- | ---------------------------- | ------- | ------ | ------ | ----------- | ------ | ------ | ------- | ------- | -------
|
|Statement of Operations Data:                              |                                                    |                              |         |        |        |             |        |        |         |         |        
|Revenues:                                                  |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           | Oil and natural gas sales                          |                              | $       | 35,100 |        | $           | 32,293 |        | $       | 19,143  |        
|                                                           | Other revenue                                      |                              |         | 76     |        |             | 255    |        |         | 69      |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           |                                                    | Total revenues               |         |        | 35,176 |             |        | 32,548 |         |         | 19,212 
|Costs and expenses:                                        |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           | Lease operating                                    |                              |         | 3,759  |        |             | 3,486  |        |         | 2,139   |        
|                                                           | Production taxes                                   |                              |         | 1,977  |        |             | 1,511  |        |         | 1,786   |        
|                                                           | General and administrative                         |                              |         | 4,971  |        |             | 3,638  |        |         | 3,100   |        
|                                                           | Depletion of oil and natural gas properties        |                              |         | 14,594 |        |             | 13,211 |        |         | 7,920   |        
|                                                           | Depreciation and amortization                      |                              |         | 440    |        |             | 677    |        |         | 620     |        
|                                                           | Capitalized ceiling impairment                     |                              |         |       |        |             |       |        |         |        |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           |                                                    | Total costs and expenses     |         |        | 25,741 |             |        | 22,523 |         |         | 15,565 
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           |                                                    | Operating income (loss)      |         |        | 9,435  |             |        | 10,025 |         |         | 3,647  
|Other income (expense):                                    |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           | Interest expense                                   |                              |         | (6,238 | )      |             | (6,681 | )      |         | (9,906  | )      
|                                                           | Interest income                                    |                              |         | 119    |        |             | 264    |        |         | 108     |        
|                                                           | Debt conversion expense                            |                              |         | (630   | )      |             |       |        |         |        |        
|                                                           | Other income (expense)                             |                              |         | (310   | )      |             | 8,080  |        |         | (9,504  | )      
|                                                           | Loss on sale of oil and natural gas properties     |                              |         |       |        |             |       |        |         |        |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           |                                                    | Total other income (expense) |         |        | (7,059 | )           |        | 1,663  |         |         | (19,302
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|Income (loss) before income taxes and extraordinary item   |                                                    |                              | 2,376   |        |        | 11,688      |        |        | (15,655 | )       |        
|Income tax benefit (expense)                               |                                                    |                              |        |        |        |            |        |        |        |         |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           | Income (loss) before extraordinary item            |                              |         | 2,376  |        |             | 11,688 |        |         | (15,655 | )      
|Extraordinary itemgain on refinancing of debt, net of tax |                                                    |                              |        |        |        |            |        |        | 32,267  |         |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           | Net income (loss)                                  |                              |         | 2,376  |        |             | 11,688 |        |         | 16,612  |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|Preferred dividend and accretion                           |                                                    |                              | 2,952   |        |        | 2,450       |        |        | 275     |         |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|                                                           | Net income (loss) available to common stockholders |                              | $       | (576   | )      | $           | 9,238  |        | $       | 16,337  |        
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|Net income (loss) per sharebasic                          |                                                    | $                            | (0.04   | )      | $      | 0.58        |        | $      | 1.01    |         | $      
|                                                           |                                                    |                              |         |        |        | Restated(1) |        |        |         |         |        
|Net income (loss) per sharediluted                        |                                                    |                              | (0.04   | )      |        | 0.44        |        |        | 1.01    |         |        
|Weighted average shares outstandingbasic                  |                                                    |                              | 16,138  |        |        | 15,988      |        |        | 16,241  |         |        
|Weighted average shares outstandingdiluted                |                                                    |                              | 16,138  |        |        | 28,205      |        |        | 16,241  |         |        
|Statement of Cash Flows Data:                              |                                                    |                              |         |        |        |             |        |        |         |         |        
|Net cash provided (used) by operating activities           |                                                    | $                            | 28,973  |        | $      | 18,922      |        | $      | (4,635  | )       | $      
|Net cash provided (used) by investing activities           |                                                    |                              | (27,206 | )      |        | (33,571     | )      |        | (26,071 | )       |        
|Net cash provided (used) by financing activities           |                                                    |                              | 8,439   |        |        | 18,924      |        |        | 28,801  |         |        
|Other Financial Data:                                      |                                                    |                              |         |        |        |             |        |        |         |         |        
|Oil and natural gas capital expenditures                   |                                                    | $                            | 27,696  |        | $      | 34,532      |        | $      | 28,910  |         | $      
|                                                           |                                                    |                              |         |        |        |             |        |        |         |         |        
|
|
|Balance Sheet Data:                                        |                                                    |                              |         |        |        |             |        |        |         |         |        
|Cash and cash equivalents                                  |                                                    | $                            | 15,318  |        | $      | 5,112       |        | $      | 837     |         | $      
|Oil and natural gas properties, net                        |                                                    |                              | 164,980 |        |        | 151,891     |        |        | 129,490 |         |        
|Total assets                                               |                                                    |                              | 202,059 |        |        | 173,075     |        |        | 146,911 |         |        
|Long-term debt                                             |                                                    |                              | 81,797  |        |        | 91,721      |        |        | 82,000  |         |        
|Series A Preferred Stock                                   |                                                    |                              | 19,540  |        |        | 16,614      |        |        | 8,558   |         |        
|Series B Preferred Stock                                   |                                                    |                              | 4,777   |        |        |            |        |        |        |         |        
|Total stockholders' equity                                 |                                                    |                              | 61,749  |        |        | 49,601      |        |        | 34,757  |         |        

---

22

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

Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should be read in conjunction with our
Consolidated Financial Statements and Notes hereto.

From
1990 to 1996 we acquired 3-D seismic data in 28 plays, seven basins and seven states. In 1997 and 1998 we invested $64 million on 3-D seismic data and
acreage in selected plays where we were experiencing attractive 3-D delineated drilling economics and repeatability. In 1999, we modified our business strategy to recognize the inherent
value of our 3-D delineated prospect inventory and to provide significant improvement in our financial and operating results. This business strategy includes the following elements:



As
a result of this strategy, we have accomplished the following for the three-year period ended December 31, 2002:



Recent Developments

In December 2002, we entered into a series of transactions whereby a number of warrants and convertible debt rights were extinguished or converted. We issued
550,000 unregistered shares of our common stock to Shell Capital in exchange for Shell Capital's warrant position and to terminate Shell Capital's right to convert $30 million of our senior
credit facility into shares of our common stock. Also, DLJ Merchant Banking Partners III, L.P. in conjunction with GlobalEnergy Partners, both affiliates of CSFB Private Equity, purchased
$10 million of our senior credit facility from Shall Capital and converted it into 2,564,102 shares of our common stock at an exercise price of $3.90 per share. We recorded $630,000 in debt
conversion expenses associated with this conversion.

23

---

In
December 2002, we issued CSFB Private Equity 500,000 shares of our Series B preferred stock with a stated value of $20.00 per share. Net proceeds from the offering were
$9.4 million and were used to reduce borrowings under our senior credit facility and to fund our drilling program and working capital requirements. The Series B preferred stock has terms
similar to our Series A preferred stock. We are required to pay dividends on our Series B preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum or
paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind on our Series B preferred stock expires
in December 2007. In connection with the Series B preferred stock offering, we issued to CSFB Private Equity warrants to purchase 2,298,851 shares of our common stock at an exercise
price of $4.35 per share. To exercise the warrants, CSFB has the option to use either cash or shares of our Series B preferred stock with an aggregate value equal to the exercise price. In the
event that our stock price averages at least $6.525 for 60 consecutive trading days, then the warrants must be exercised if we so require.

In
December 2002, we extended the maturity on our senior credit facility by one year to December 2004 and extended our option to pay interest in kind on our senior
subordinated notes facility by one year to October 2003.

In
March 2003, we replaced our senior credit facility with a new senior credit facility. The new senior credit facility provides for a maximum commitment of $80 million in
the form of a revolving bank credit facility, has an initial borrowing base of $70 million and matures in March 2006. As of the closing date of the facility, we had $56 million in
outstanding borrowings under the new senior credit facility. See "Liquidity and Capital ResourcesSenior Credit Facility".

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting
rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the
specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation.
We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical.
Our critical accounting policies are discussed below.

Property and Equipment

The method of accounting for oil and gas properties is a critical accounting policy because it determines what costs are capitalized, and how these costs are
ultimately matched with revenues and expensed.

We
use the full cost method of accounting for oil and properties. Under this method substantially all costs associated with oil and gas exploration and development activities are
capitalized, including costs for individual exploration projects that do not directly result in the discovery of hydrocarbon reserves that can be economically recovered. Payroll, interest, and other
internal costs we incur for the purpose of finding hydrocarbon reserves are also capitalized.

Full
cost pool amounts associated with properties that have been evaluated through drilling or seismic analysis are depleted using the units of production method. The depletion expense
per unit of production is the ratio of historical and estimated future development costs to hydrocarbon reserve volumes. Estimation of hydrocarbon reserves relies on professional judgment and use of
factors that
cannot be precisely determined. Reserve estimates materially different from those reported would change the depletion expense recognized during the reporting period. For the year ended
December 31,

24

---

2002, our depletion expense per unit of production was $1.46 per Mcfe. A change of 900,000 Mcfe in our estimated net proved reserves at December 31, 2002, would result in a $0.01 per Mcfe
change in our per unit depletion expense and a $100,000 change in net income available to common shareholders.

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 revenues from proved oil and natural gas reserves plus the capitalized cost of unproved
properties, such costs are charged to operations as a reduction of the carrying value of oil and natural gas properties, or a "capitalized ceiling impairment" charge. The risk that we will be required
to write down the carrying value of our 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 we experience 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 we will not experience a capitalized ceiling impairment charge in future
periods. In addition, capitalized ceiling impairment charges may occur if estimates of proved hydrocarbon reserves are substantially reduced or estimates of future development costs increase
significantly. See "Risk FactorsExploratory Drilling Is A Speculative Activity Involving Numerous Risks And Uncertain Costs; We are Dependent On Exloratory Drilling
Activities", "Risk FactorsMaintaining Reserves And Revenues In The Future Depends On Successful Exploration And Development" and "Risk FactorsWe Are
Subject To Uncertainties In Reserve Estimates and Futures Net Cash Flows".

Income Taxes

Deferred tax assets are recognized for temporary differences in financial statement and tax basis amounts that will result in deductible amounts and
carry-forwards 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 we expect the temporary differences to be deducted or settled. The effect of a change in tax law or rates on the valuation of 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.

Estimating
the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in shareholder ownership which would
trigger limits on use of net operating losses under Internal Revenue Code Section 382.

Revenue Recognition

Because revenue is a key component of our results of operations, and we derive revenue primarily from the sale of produced oil and gas, our revenue recognition
for these sales is significant.

We
recognize crude oil revenue using the sales method of accounting. Under this method, we recognize revenue when oil is delivered and title transfers.

We
recognize natural gas revenue using the entitlements method of accounting. Under this method, revenue is recognized based on our entitled ownership percentage of sales of natural gas
to purchasers. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. When we receive less than our entitled share, a receivable is
recorded. When we receive more than our entitled share, a liability is recorded.

25

---

Settlements
for hydrocarbon sales can occur up to two months after the end of the month in which the oil, gas or other hydrocarbon products were produced. We estimate and accrue for the
value of these sales using information available at the time financial statements are generated. Differences are reflected in the accounting period that payments are received from the purchaser. For
the month of December 2002 a $0.10 change in the price per Mcf of gas sold would change revenue by $50,000. A $0.70 change in the price per barrel of oil would change revenue by $50,000.

Derivative Instruments and Hedging Activities

We use derivative instruments to manage market risks resulting from fluctuations in commodity prices of natural gas and crude oil. We periodically enter into
commodity contracts, including price swaps, caps and 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.

We
adopted Statement of Financial Accounting Standards No. 133 on January 1, 2001 in accordance with Financial Accounting Standards Board 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
depending on the type of hedge transaction. Our derivative contracts consist primarily of cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted
transaction. Change 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. We assess 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.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States of America requires management to make
estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. Hydrocarbon reserve, future development costs, and certain hydrocarbon
production expense and revenue estimates are the most critical to our financial statements.

New Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Standards No. 143, "Asset Retirement Obligations" which
establishes accounting requirements for retirement obligations associated with tangible long-lived assets including the timing of the liability recognition, initial measurement of the
liability, allocation of asset retirement cost to expense, subsequent measurement of the liability and financial statement disclosures. SFAS 143 requires that an asset retirement cost be
capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic, rational method. We adopted this standard as required on
January 1, 2003. We are currently evaluating the effect of this statement on our consolidated financial position, results of operations and cash flows.

In
April 2002, the FASB issued SFAS No. 145, "Rescission of FASB statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections".
SFAS 145 requires, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early

26

---

extinguishment of debt to be classified as components of a company's income or loss from continuing operations. Prior to the adoption of the provisions of SFAS 145, gains or losses on the
early extinguishment of debt were required to be classified in a company's periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the
determination of
income or loss from continuing operations. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. Due to the requirements of SFAS No. 145, it is less likely that
a gain or loss on extinguishment of debt would be classified as an extraordinary item in our results of operations.

Off Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements or other such unrecorded obligations and we have not guaranteed the debt of any other
party.

Commodity Pricing

Changes in commodity prices significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can
indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. The prices we receive for our crude oil production are based on
global market conditions. The price we receive for our natural gas production is primarily driven by North American market forces. Oil and gas prices have fluctuated significantly in recent years in
response to numerous economic, political and environmental factors. The year 2002 began with a weakened commodity environment and lower prices. However, prices were on an upward trend through the
year. Prices are also affected by weather, factors of supply and demand, and commodity inventory levels. During 2002, the high and low settlement prices for oil on the NYMEX were $32.72 per Bbl and
$17.97 per Bbl, and the high and low settlement prices for natural gas on the NYMEX were $5.34 per MMBtu and $1.91 per MMBtu. We expect that commodity prices will continue to fluctuate significantly
in the future.

Results of Operations

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

Year Ended December 31,2002

2001

2000Production (in thousands):Natural gas (MMcf)


5,791


6,766


4,431Oil (MBbls)


701


468


362Natural gas equivalent (MMcfe)


9,996


9,573


6,600% Natural gas


58%


71%


67%Average sales prices per unit (After hedging)Natural gas (per Mcf)

$
3.21

$
3.11

$
1.94Oil (per Bbl)


23.55


24.05


29.17Natural gas equivalent (per Mcfe)


3.51


3.37


2.90Costs and expenses per Mcfe:Lease operating

$
0.38

$
0.36

$
0.32Production taxes


0.20


0.16


0.27General and administrative


0.50


0.38


0.47Depletion of oil and natural gas properties


1.46


1.38


1.20


27

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Overview

For the year ended December 31, 2002, we had a net loss to common stockholders of $576,000, or $0.04 per diluted share, on total revenues of
$35.2 million compared to net income of $9.2 million, or $0.44 per diluted share (as restated, refer to Note 10 to the Consolidated Financial Statements) on revenue of
$32.5 million for the year ended December 31, 2001, and net income of $16.3 million, or $1.01 per diluted share, on revenue of $19.2 million for the year ended
December 31, 2000. Net income in 2002 included $384,000 in non-cash gains related to changes in the fair-market value of derivative contracts that did not qualify for hedge accounting
treatment. This non-cash gain was partially offset by a $121,000 non-cash loss for ineffective hedging transactions. Net income in 2001 was significantly enhanced by $9.7 million in
non-cash gains related to changes in the fair-market value of derivative contracts that did not qualify for hedge accounting treatment. Net income in 2000 was significantly
enhanced by a $32.3 million extraordinary gain on the refinancing of our senior subordinated debt and was partially offset by a non-cash loss of $8.9 million related to
changes in the fair-market value of derivative contracts that did not qualify for hedge accounting treatment.

Production.Net equivalent production volumes for 2002 were 10.0 Bcfe compared to 9.6 Bcfe in 2001 and 6.6 Bcfe in 2000.
Average net daily equivalent production volumes for 2002 were 27.8 MMcfed, compared to 26.6 MMcfed in 2001 and 18.3 MMcfed in 2000. The increase in production from 2000 through 2002 is due to organic
production growth during the period. Additional production related to wells completed during the period was partially offset by the natural decline of existing production. Natural gas production
represented 58% of our total production volume on an equivalent basis in 2002 compared to 71% in 2001 and 67% in 2000.

Revenue from the sale of oil and natural gas.Revenue from the sale of oil and natural gas for 2002 was $35.1 million
compared to $32.3 million in 2001 and $19.1 million in 2000.

For
2002 compared to 2001, revenue from the sale of oil and natural gas was up $2.8 million or 9%. A 4% increase in our total production volume accounted for $2.6 million
of this change and a $0.14 per Mcfe increase in our average realized sales price for oil and natural gas accounted for $232,000 of this change. Revenue from the sale of oil and natural gas in 2002
included a loss of $1.8 million, or $0.19 per Mcfe, related to cash settlements on hedging transactions, compared to a loss of $8.2 million, or $0.85 per Mcfe, in 2001. Our average
realized sales price for oil and natural gas in 2002 was $3.51 per Mcfe compared to $3.37 per Mcfe in 2001.

For
2001 compared to 2000, revenue from the sale of oil and natural gas was up $13.2 million or 69%. A 45% increase in our total production volume accounted for
$7.7 million of this change and a $0.47 per Mcfe increase in our average realized sales price for oil and natural gas accounted for $5.5 million of this change. Revenue from the sale of
oil and natural gas in 2001 included a loss of $8.2 million, or $0.85 per Mcfe, related to cash settlements on hedging transactions, compared to a loss of $9.5 million, or $1.44 per
Mcfe, in 2000. Our average realized sales price for oil and natural gas in 2001 was $3.37 per Mcfe compared to $2.90 per Mcfe in 2000.

Other revenue.Other revenue was $76,000 in 2002, compared to $255,000 in 2001 and $69,000 in 2000. This revenue relates to
billings to other parties for gathering services.

28

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Lease operating expenses.Lease operating expenses, which includes lifting cost and ad valorem taxes, for 2002 were
$3.8 million compared to $3.5 million in 2001 and $2.1 million in 2000.

2002

2001

2000(in thousands)Lease operating expense, excluding ad valorem taxes

$
3,148

$
3,015

$
1,886Ad valorem taxes


611


471


253Total lease operating expenses

$
3,759

$
3,486

$
2,139($ per Mcfe)Lease operating expense per unit of production:Lease operating expense, excluding ad valorem taxes

$
0.32

$
0.31

$
0.28Ad valorem taxes


0.06


0.05


0.04Total lease operating expenses

$
0.38

$
0.36

$
0.32


For
2002 compared to 2001, total lease operating expenses increased 8%. On a per unit of equivalent production basis, lease operating expenses for 2002 were $0.38 per Mcfe, compared to
$0.36 per Mcfe in 2001. The change in our lease operating expense was primarily the result of higher ad valorem taxes due to an increase in property valuations because of higher average
commodity prices during 2001 and higher overall service cost.

For
2001 compared to 2000, total lease operating expenses increased 63%. The change in lease operating expenses is primarily due to an increase in the number of producing wells. Lease
operating expenses on a per unit of production in 2001 were $0.36 per Mcfe compared to $0.32 per Mcfe in 2000. The increase in our per unit lease operating expense was primarily due to higher overall
service cost and higher ad valorem taxes due to an increase in property valuations because of higher average commodity prices during 2000.

Production taxes.Production taxes for 2002 were $2.0 million compared to $1.5 million in 2001 and
$1.8 million in 2000.

For
2002 compared to 2001, the increase in production taxes was primarily due to a reduction in the number of wells that qualify for severance tax refunds in 2002. Our effective
production tax rate in 2002 was 5.4% of pre-hedge oil and natural gas sales revenue, compared to 3.7% in 2001.

For
2001 compared to 2000, the decrease in production taxes was primarily related to production tax refunds on wells that qualify for reduced severance tax rates. Our effective
production tax rate in 2001 was 3.7% of pre-hedge oil and natural gas sales revenue, compared to 6.2% in 2000.

General and administrative expenses.General and administrative expenses for 2002 were $5.0 million, compared to
$3.6 million in 2001 and $3.1 million in 2000.

For
2002 compared to 2001, the increase in general and administrative expenses included a non-recurring charge for non-cash compensation expense of $596,000
related to vesting of options by an officer who left the company. Excluding this non-cash charge, general and administrative expenses for 2002 increased 20% to $4.4 million. Other
items contributing to the increase in general and administrative expenses include the cost associated with bringing our oil and natural gas marketing activities in house, increased payroll and benefit
expense, higher office rent expense, higher other office expenses and an increase in corporate insurance expense.

For
2001 compared to 2000, general and administrative expenses increased 17%. This increase was primarily due to an increase in employee payroll and benefit expense, office expense,
public company expense and contract and professional expense.

29

---

Depletion of oil and natural gas properties.Depletion of oil and natural gas properties in 2002 was $14.6 million
compared to $13.2 million in 2001 and $7.9 million in 2000.

For
2002 compared to 2001, a $0.08 increase in our depletion rate accounted for $800,000 of the change and higher production volumes accounted for $584,000 of the change. This increase
in our per unit depletion expense was due to additional future development cost related to our Floyd Fault Block Field discovery.

For
2001 compared to 2000, depletion expense increased $5.3 million. Increased production volumes accounted for $4.1 million of this increase and a $0.18 increase in our
depletion rate accounted for a $1.2 million of the increase. The increase in the depletion rate per unit is primarily due to an increase in the estimated cost required to fully develop our Home
Run Field.

Net interest expense.Net interest expense for 2002 was $6.2 million compared to $6.7 million in 2001 and
$9.9 million in 2000.

2002

2001

2000(in thousands)Interest on outstanding indebtedness(1)

$
5,878

$
7,081

$
10,327Commitment fees


3


29


43Amortization of deferred loan and debt issuance cost


1,191


1,372


1,283Amortization of debt discount








673Other general interest expense


44


47


352Capitalized interest expense


(878
)

(1,848
)

(2,772
)Net interest expense

$
6,238

$
6,681

$
9,906Weighted average debt outstanding

$
95,562

$
90,646

$
97,424Average interest rate on outstanding indebtedness(2)


6.2%


7.8%


10.6%


---

For
2002 compared to 2001, the change in net interest expense was primarily due to a lower average interest rate on outstanding indebtedness during 2002 and to a lesser extent on a
decrease in the amount of deferred loan fees amortized. The change in the average interest rate on our outstanding borrowings was due to a decrease in the London Interbank Offered Rate (LIBOR), which
is used to determine the interest rate on borrowings outstanding under our senior credit facility. The average interest rate on borrowings outstanding under our senior credit facility during 2002 was
5.0% compared to 7.2% in 2001. At December 31, 2002, the interest rate on borrowings outstanding under our senior credit facility was 4.5%.

For
2001 compared to 2000, the change in net interest expense was primarily due to a lower weighted average outstanding debt balance and a lower average interest rate on our outstanding
borrowings during 2001. The repurchase of $51.2 million in subordinated notes in November 2000 that bore annual interest rates of 12% to 14% was the primary reason the for the decrease
in our weighted average debt balance and lower average interest rate in 2001. A decrease in the average interest rate on borrowings outstanding under our senior credit facility due to a lower London
Interbank Offered Rate (LIBOR) during also contributed to the decrease in our average interest rate.

30

---

Other income (expense).Other income (expense) in 2002 was an expense of $310,000 compared to $8.1 million in income
in 2001 and $9.5 million in expense in 2000. Other income (expense) consists primarily of items 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 2002 included (i) $384,000 in non-cash income related to the change in
the fair market value of derivative contracts during the period that did not qualify for hedge accounting treatment, (ii) $121,000 in non-cash expense related to the ineffective portion of
hedging transactions, and (iii) $559,000 of expenses related to cash settlements on derivative contracts that did 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 on derivative contracts that did 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 derivative contracts during the period, and (ii) $620,000 of expenses related to cash settlements on derivative
contracts that did not qualify for hedge accounting treatment.

Debt Conversion expense.Debt conversion expense of $630,000 represents the costs and fees we incurred to execute the
conversion of $10 million of our senior debt to common stock. Our total outstanding indebtedness at December 31, 2002 was $81.8 million, compared to $91.7 million at
December 31, 2001. There were no similar expenses in prior periods.

Extraordinary gain on refinancing of senior subordinated notes.In November 2000, we repurchased all of our debt and
equity securities held by affiliates of Enron North America at a substantial discount. With a portion of the proceeds from two new financing transactions, we repurchased all of the Enron Affiliates'
interests, 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 our common stock at $2.43 per share, and (iii) 1,052,632 shares of common stock, 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, we recorded an extraordinary gain of $32.3 million
in the fourth quarter of 2000. There were no similar items during 2002 or 2001.

Liquidity and Capital Resources

Our primary sources of capital have been funds generated by operations, our senior credit and subordinated notes facility, public and private equity financings
and the sale of interests in projects and properties. Our level of earnings and cash flows depends on market prices that we receive for our oil and natural gas production, our ability to find and
produce hydrocarbons and our ability to control and reduce cost.

Our
primary sources of cash during 2002 were funds generated from operations, proceeds from the sale of our Series B preferred stock and borrowings under our subordinated notes
facility. Funds were used primarily for costs associated with drilling, land acquisition and 3-D seismic acquisition, processing and interpretation and to reduce the level of borrowings
under our senior credit facility.

31

---

Cash Flows Provided (Used) By Operating Activities

2002

2001

2000(in thousands)Operating cash flow before changes in working capital

$
20,010

$
18,097

$
8,581Changes in working capital


8,963


825

$
(13,216
)Net cash flow provided (used) by operating activities

$
28,973

$
18,922

$
(4,635
)


For
2002 compared to 2001, cash flows provided by operating activities increased by $10.0 million. This change included a $1.9 million increase in cash flow provided by
operating activities before changes in working capital and an $8.1 million increase in cash flow from changes in working capital activities. The change in cash flow provided by operating
activities (exclusive of changes in working capital) was due to an increase in revenue from the sale of oil and natural gas, a decrease in cash interest expense and a decrease in cash settlements on
derivatives that do not qualify for hedging activities. These changes were partially offset by increases in our lease operating expense, production taxes, cash general and administrative expense and
debt conversion cost.

For
2001 compared to 2000, cash flows provided by operating activities increased by $23.6 million. This change included a $9.5 million (exclusive of changes in working
capital) increase. This increase is due to an increase in revenue from the sale of oil and natural gas which was partially offset by an increase in lease operating expense, cash general and
administrative expenses, cash interest expense and increase in cash losses on the settlement of derivative contracts that do not qualify for hedge accounting treatment.

Cash Flows Used By Investing Activities

2002

2001

2000(in thousands)Net cash flow used by investing activities

$
27,206

$
33,571

$
26,071


Our
primary capital requirements are for cost associated with drilling, land acquisition and 3-D seismic acquisition, processing and interpretation. Our initial capital
budget at the start of 2002 was projected to be $23.7 million and was down 33% when compared to capital expenditures in 2001. Due to lower forecasted oil and natural gas prices at the time, the
reduced capital expenditure program reflected our desire to fund our capital expenditure program with cash flow generated from operations, cash on hand at the start of the year and availability under
our senior subordinated notes facility. As the year progressed, we increased our capital budget to partially account for the increase in commodity prices.

For
2002 compared to 2001, cash flows used by investing activities decreased 19%. This change is primarily due to a reduction in capital spending on oil and gas properties.

For
2001 compared to 2000, cash flows used by investing activities increased 29%. This change is primarily due to an increase in capital spending on oil and gas activities.

Cash Flows Provided By Financing Activities

2002

2001

2000(in thousands)Net cash flow provided by financing activities

$
8,439

$
18,924

$
28,801


32

---

Over
the past three years, we have reduced our reliance on external sources to fund our capital expenditure programs. For 2002, net cash flow provided by financing activities decreased
by $10.5 million compared to 2001 and by $20.4 million when compared to 2000. The decrease in our reliance on external sources to fund our capital expenditures has primarily been the
result of an increase in the cash flow generated by our operating activities and reduced capital spending.

In
2002, cash inflows from financing activities included $4.0 million of additional borrowing under subordinated notes facility, $9.4 million in net proceeds from the
issuance of $10 million in Series B preferred stock and warrants to purchase our common stock and $921,000 in proceeds from the exercise of options and warrants that resulted in the
issuance of 376,409 shares of our common stock. These inflows were partially offset by the repayment of $5.0 million of outstanding indebtedness under our senior credit facility and debt issue
cost of $0.6 million. The remainder of the cash inflows will be used to fund our capital expenditures, fund working capital obligations and repay outstanding indebtedness under our senior
credit facility.

In
2001, cash inflows from financing activities included $9.0 million of additional borrowing under our subordinated notes facility, $9.8 million of net proceeds from the
issuance of $10 million in Series A preferred stock and warrants to purchase of our common stock and $252,000 in proceeds from the exercise of options that resulted in the issuance of
97,474 shares of our common stock. These cash inflows were used to fund capital expenditures and working capital obligations.

During
2000, cash inflows from financing activities included $19.0 million in additional borrowings under our senior credit facility, $7.0 million of borrowing under
subordinated notes facility, $20.1 million in net proceeds from the issuance of $20.0 million in Series A preferred stock and warrants to purchase of our common stock,
$4.2 million in net proceeds from the sale of 2.2 million shares of our common stock and the payment of $902,000 in loan cost. These inflows were partially offset by our purchase of
$51.2 million of our outstanding subordinated notes and associated accrued interest, warrants to purchase one million shares of common stock at $2.43 per share and 1.1 million shares of
our common
stock, for total cash consideration of $20.0 million. The remainder of the net proceeds were used to fund capital expenditures and working capital obligations.

Senior Credit Facility

At December 31, 2002, we had $60.0 million of indebtedness outstanding under our senior credit facility. In December 2002, DLJ Merchant
Banking Partners III, L.P. in conjunction with GlobalEnergy Partners, affiliates of CSFB Private Equity, purchased $10 million of our senior credit from Shell Capital and converted it into
2,564,102 shares of our common stock, at an exercise price of $3.90 per share. We also used $5.0 million of the net proceeds from the issuance of Series B preferred stock and warrants to
repay indebtedness outstanding under our senior credit facility. The credit facility agreement contains various covenants and restrictive provisions which limit our capital spending on land and
seismic, ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans, create liens and make certain acquisitions. The
senior credit facility requires us to maintain a current ratio (as defined) of at least 1 to 1 and an interest coverage ratio (as defined) of at least 2.5 to 1. Our current ratio at
December 31, 2002 and interest coverage ratio for the twelve-month period ending December 31, 2002, were 1.3 to 1 and 3.4 to 1, respectively. In December 2002, the maturity on our
senior credit facility was extended by one year to December 31, 2004.

In
March 2003, we replaced our senior credit facility with a new senior credit facility that provides for a maximum $80 million in commitments and an initial borrowing base
of $70 million and matures in March 2006. Borrowings under the new credit facility are secured by substantially all of our oil and natural gas properties and other tangible assets and
bear interest at either the base rate of Société Générale or London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies

33

---

according to facility usage. Interest is paid quarterly. The collateral value and borrowing base are redetermined periodically. The unused portion of the committed borrowing base is subject to an
annual commitment fee of 0.5%. As of March 21, 2003, we had $56 million of borrowings outstanding and $14 million in additional borrowing capacity under our new senior credit
facility.

The
new senior credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, purchase or
redeem our capital stock, make investments or loans, create liens and make certain acquisitions. The new senior credit facility requires us to maintain a current ratio (as defined) of at least 1 to 1
and an interest coverage ratio (as defined) of at least 3.25 to 1. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the
covenants in the future. In such instance, our liquidity may be adversely affected, which could in turn have an adverse impact on our future financial position and results of operations. If we should
fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due
and payable.

Senior Subordinated Notes

As of December 31, 2002, we had $21.8 million of senior subordinated notes outstanding. The notes bear interest at 10.75% per annum, payable
quarterly in arrears on the last day of January, April, July and October, are redeemable at our option for face value at any time and have no principal repayment obligations until maturity in
October 2005. At our option, up to 50% of the interest payments on the senior subordinated notes can be satisfied by payment in kind through the issuance of additional senior subordinated notes
in lieu of cash. In December 2002, as part of the exchange of our common stock for warrants and debt conversion rights held by Shell Capital, we extended our option to satisfy 50% of our
interest obligation through the issuance of additional subordinated notes through October 2003. For the year ended December 31, 2002, we exercised this option and issued an additional
$1.1 million in senior subordinated notes. As of March 21, 2003, we have exercised this option and have issued approximately $2.1 million in additional senior subordinated notes.
As of March 21, 2003, we had $22.1 million of borrowings outstanding with no additional borrowing capacity under our senior subordinated notes facility.

The
senior subordinated notes are issued pursuant to a senior subordinated notes facility dated October 31, 2000, which was amended and restated on March 21, 2003. Under
the facility, Shell Capital agreed to provide up to $20 million (plus any amount of interest paid in kind) in senior subordinated notes in borrowing increments of at least $1 million.
Once borrowings under the subordinated notes facility have been repaid, they cannot be withdrawn. The senior subordinated notes are secured obligations ranking junior to our new senior credit facility
and have covenants similar to the new senior credit facility. Our current ratio at December 31, 2002 and interest coverage ratio for the twelve-month period ending December 31, 2002,
were 1.3 to 1 and 3.4 to 1, respectively.

In
October 2000, in connection with the senior subordinated notes facility, we issued warrants to purchase 1,250,000 shares of our common stock at an exercise price of $3.00 per
share. Brigham valued the warrants using the Black-Scholes Option Pricing 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 senior subordinated notes facility. In December 2002, as part of the exchange of our common stock for warrants and debt conversion rights held by Shell
Capital, the warrants to purchase 1,250,000 shares of our common stock at $3.00 per share were extinguished.

Series A Preferred Stock

We have issued two tranches of mandatorily redeemable Series A preferred stock to CSFB Private Equity. The first tranche, $20 million, was issued in
November 2000 and the second tranche,

34

---

$10 million, was issued March 2001. We are required to pay dividends on our Series A preferred stock. At our option, these dividends may be paid in cash at a rate of 6% per annum
or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind on the first tranche expires in
October 2005 and the second tranche
expires in March 2006. To date, we have satisfied all of the dividend payments with issuance of additional shares of Series A preferred stock. The Series A preferred stock has a
ten-year maturity and is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity. As of March 21,
2003 the liquidation value of the Series A preferred stock was $35.9 million including accrued but unpaid dividends. Approximately $5.9 million of the liquidation value represents
additional Series A preferred stock issued and accrued to satisfy our dividend payments.

In
connection with the two tranches of Series A preferred stock, we issued to CSFB Private Equity warrants to purchase our common stock. With the first tranche we issued warrants
to purchase 6,666,667 shares of our common stock at an exercise price of $3.00. With the second tranche we issued warrants to purchase 2,105,263 shares of our common stock at an exercise price of
$4.75. In connection with the December 2002 Series B preferred stock and warrant offering (see Series B Preferred Stock below), the exercise price of the warrants originally
issued with the second tranche of Series A preferred stock was reset to $4.35. To exercise the warrants, CSFB Private Equity has the option to use either cash or shares of our Series A
preferred stock with an aggregate value equal to the exercise price.

Series B Preferred Stock

In December 2002, we issued CSFB Private Equity 500,000 shares of our Series B preferred stock with a stated value of $20.00 per share. Net proceeds
from the offering were $9.4 million and were used to reduce borrowings under our senior credit facility and fund our drilling program and working capital requirements. The Series B
preferred stock has terms similar to our Series A preferred stock. We are required to pay dividends on our Series B preferred stock. At our option, these dividends may be paid in cash at
a rate of 6% per annum or paid in kind through the issuance of additional shares of preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay dividends in kind on our
Series B preferred stock expires in December 2007. The Series B preferred stock can be redeemed at our option after December 2007 and is mandatorily redeemable in
December 2012.

As
of March 21, 2003 the liquidation value of the Series B preferred stock was $10.2 million including accrued but unpaid dividends in kind. Approximately
$0.2 million of the liquidation value represents additional Series B preferred stock issued and accrued to satisfy our dividend payments.

In
connection with the Series B preferred stock offering, we issued to CSFB Private Equity warrants to purchase 2,298,851 shares of our common stock at an exercise price of $4.35
per share. To exercise the warrants, CSFB has the option to use either cash or shares of our Series B preferred stock with an aggregate value equal to the exercise price. In the event that our
stock price averages at least $6.525 for 60 sixty consecutive trading days, then the warrants must be exercised if we so require. For financial reporting purposes, the warrants issued with the
Series B preferred stock were valued at approximately $4.6 million using the Black Scholes Option Pricing model and were recorded as additional paid in capital in December 2002.

35

---

Capital Expenditures

2002

2001

2000(in thousands)Drilling

$
19,800

$
27,209

$
18,461Land and G&G


3,751


2,750


4,585Capitalized G&A and interest


5,657


6,050


6,300Proceeds from participants and sales


(1,524
)

(397
)

(4,002
)Total capital expenditures on oil & gas properties

$
27,684

$
35,612

$
25,344Other property and equipment


249


241


135Total capital expenditures

$
27,933

$
35,853

$
25,479


Our
capital-spending budget for 2003 is $39.3 million. The majority of our planned 2003 expenditures will be directed towards drilling our prospect inventory in a continued effort
to focus resources on our primary objective of growing production volumes and cash flow. For 2003, we expect to spend approximately $27.9 million to drill 41 wells with an average working
interest of 36%. Capitalizing on the prior exploration successes at the Home Run, Mills Ranch, Triple Crown, Floyd Fault Block and Providence Fields, approximately 60% of our 2003 drilling
expenditures are dedicated to development drilling. Spending will be funded by our operating cash flow, cash on hand at the start of the year and available capacity under our new senior credit
facility. Capital expenditures for 2003 are expected to be up approximately 42% over 2002. This increase is primarily attributable to a more robust current and forecasted commodity price environment
and to lesser degree our additional financial flexibility resulting from the CSFB Private Equity Financings completed in December 2002.

Actual
capital spending may vary and is subject to changing market condition. The 2003 capital expenditure budget was developed using certain assumed price levels for the sales of crude
oil and natural gas and forecasted production growth. Changes in commodity prices or variances from forecasted production growth could impact our cash flows from operations and funds available for
reinvestment. For example, shortfalls in budgeted cash flows from operations could result in the reduction of the our capital spending program, increases in borrowing under our new senior credit
facility, issuance of additional equity or debt securities or divestments of properties. We evaluate our level of capital spending throughout the year based upon drilling results, commodity prices and
cash flows from operations.

36

---

Contractual Obligations

The following schedule summarizes our known contractual cash obligations at December 31, 2002 and the effect such obligations are expected to have on our
liquidity and cash flow in future periods.

|                                                    |  | Payments Due by Year
|--------------------------------------------------- |  | --------------------
|
|Senior credit facility                              |  | $                   
|Subordinated notes facility                         |  |                     
|Non-cancelable operating leases                     |  |                     
|Manditorily redeemable, Series A preferred stock(a) |  |                     
|Manditorily redeemable, Series B preferred stock(b) |  |                     
|                                                    |  |                     
|Total Contractual Cash Obligations                  |  | $                   
|                                                    |  |                     

---

Some
of our commodity price risk management arrangements have required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our
payment obligations with respect to our commodity price risk management transactions exceed certain levels. At December 31, 2002, we were required to post $1.9 million in collateral. It
is not anticipated that we will be required to post cash collateral with the new senior credit facility. However, future requirements are uncertain and will depend on arrangements with our
counterparities and highly volatile oil and natural gas prices.

Other Matters

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income (loss) plus interest expense, depletion, depreciation and amortization expenses, deferred income taxes and other
non-cash items.

37

---

We
believe that operating income is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA
as defined. The following table reconciles EBITDA as defined with our operating income, as derived from our financial statements.

2002

2001

2000(in thousands)Operating Income

$
9,435

$
10,025

$
3,647Depletion, depreciation and amortization


15,034


13,888


8,540Non-cash compensation expense


596





Interest Income


119


264


108Cash settlements on derivatives not qualifying for hedge accounting treatment


(559
)

(1,492
)

(620
)Amortization of deferred loss on derivative instruments








280Cash portion of other income/(expense)


(14
)




EBITDA

$
24,611

$
22,685

$
11,955


Derivative Instruments

Our results of operations and operating cash flow are impacted by changes in market prices for oil and gas. We believe the use of derivative instruments, although
not free of risk, allows us to reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. While the use of derivative instruments limits the
downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our hedging arrangements generally do not apply to all of our production
and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our 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".

Effects of Inflation and Changes in Prices

Our 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 we are required to bear for operations. Inflation has had a minimal effect on us.

Environmental and Other Regulatory Matters

Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of
oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of
potentially responsible parties. Although we believe that we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently
changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to
meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and
regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling
activity. 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".

38

---



Forward Looking Information

We or our representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC,
regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and
gas production, the number of wells we anticipate drilling during 2003 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the
expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if
substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general
economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in
oil and gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted below or in the
description of our business in Item 1 of this report. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their
entirety by these factors. We assume no obligation to update any of these statements.

Risk Factors

We Are Substantially Leveraged

Our outstanding long-term debt was $81.8 million as of December 31, 2002, and $78.1 million as of March 21, 2003. The
credit agreements related to our new senior credit facility and senior subordinated notes facility limit the amount of additional debt borrowings, including borrowings under these facilities or other
senior or subordinated indebtedness. As of March 21, 2003, we had $14 million of additional borrowing capacity under our new senior credit facility and no additional borrowing
availability under our senior subordinated notes facility.

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



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".

39

---

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, remaining availability under our new senior credit facility and 2003 beginning cash balance should allow us to finance our planned operations through 2003 based on current conditions and
expectations, additional financing could 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:



We
cannot predict future oil and natural gas price movements with certainty. During 2002, the high and low settlement prices for oil on the NYMEX were $32.72 per Bbl and $17.97 per Bbl,
and the high and
low settlement prices for natural gas on the NYMEX were $5.34 per MMBtu and $1.91 per MMBtu. Significant declines in oil and natural gas prices for an extended period may have the following effects on
our business:



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



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.

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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:



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. See "Item 1. BusinessOperating Hazards and Uninsured Risks".

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

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



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, 2002, we had an accumulated deficit of $24.4 million and total
stockholders' equity of $61.7 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".

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Our Future Operating Results May Fluctuate

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



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

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

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

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

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

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

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



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:



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 "Item 1. BusinessEnvironmental Matters".

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Our Business May Suffer If We Lose Key Personnel

We have assembled a team of geologists and geophysicists 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Exploration and Development 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 21, 2003, our directors, executive officers and 10% or greater stockholders, and certain of their affiliates, beneficially owned approximately
54% of our outstanding common stock. Accordingly, these stockholders, as a group, will be able to control the outcome of stockholder votes, including votes concerning the election of directors, the
adoption or amendment of provisions in our certificate of incorporation or bylaws, and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership
concentrated in a few persons makes it unlikely that any other holder of common stock will be able to affect our management or direction. These factors may also have the effect of delaying or
preventing a change in our management or voting control.

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

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

The Market Price Of Our Stock 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

We limit our use of derivative instruments principally to commodity price hedging activities, whereby gains and losses are generally offset by price changes in
the underlying commodity. Our 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 our ability to benefit from favorable oil and natural gas price movements.

Commodity Price Risk

Our 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, we employ established policies and procedures to manage our exposure to fluctuations in the sales
prices we receives for its oil and natural gas production using derivative instruments.

We
believe the use of derivative instruments, although not free of risk, allows us to reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more
predictable cash
flow. While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our hedging
arrangements generally do not apply to all of its production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from
time to time.

The
gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract
month. The oil derivative transactions are generally settled based on the average reporting settlement prices on the NYMEX for each trading day of a particular calendar month.

The
table below summarizes our total natural gas production volumes subject to derivative transactions during 2002 and the weighted average NYMEX reference price for those volumes.

Natural gas swaps




Natural gas capsVolumes (MMbtu)


3,358,500

Volumes (MMbtu)


1,810,000Average price ($/MMbtu)

$
3.132

Average price ($/MMbtu)

$
2.633


The
table below summarizes our total crude oil production volumes subject to derivative transactions during 2002 and the weighted average NYMEX reference price for those volumes.

Crude oil swaps




Crude oil collarsVolumes (Bbls)


126,500

Volumes (Bbls)


204,500Average price ($/Bbls)

$
25.96

Average price ($/Bbls)Floor

$
18.00Ceiling

$
22.36


As
of March 21, 2003, our oil and gas derivative instruments were comprised of swaps, collars and floors.

For
swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, to the counterparty. These instruments are settled
monthly. When the floating price exceeds the fixed price for a contract month, we pay the counterparty. When the fixed price exceeds the floating price, the counterparty is required to make a

46

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payment to us. We have designated theses swap instruments as cash flow hedges designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility.

For
collar instruments, we establish a floor and ceiling price on future commodity production. These instruments are settled monthly. When the settlement price for a period is above the
ceiling price the, we pay the counterparty. When the settlement price for a period is below the floor price, the counterparty is required to pay us. We have designated these collar instruments as cash
flow hedges designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility.

For
floor instruments, we establish a floor price on future commodity production. When the settlement price for a period is below the floor price, the counterparty is required to pay us.

The
following tables reflect our natural gas derivative instruments, associated volumes and the corresponding weighted average NYMEX reference price by quarter.

|                        |  | 2003 |         | 2004
|----------------------- |  | ---- | ------- | ----
|
|Natural gas swaps:      |  |      |         |     
|Volumes (MMbtu)         |  |      | 832,500 |     
|Average price ($/MMBtu) |  | $    | 3.632   |     
|Natural gas floors:     |  |      |         |     
|Volumes (MMbtu)         |  |      |        |     
|Average price ($/MMBtu) |  | $    |        |     

The
following tables reflect our crude oil derivative instruments, associated volumes and the corresponding weighted average NYMEX reference price by quarter.

|                      |  | 2003 |        | 2004
|--------------------- |  | ---- | ------ | ----
|
|Crude oil swaps:      |  |      |        |     
|Volumes (Bbls)        |  |      | 67,500 |     
|Average price ($/Bbl) |  | $    | 25.29  |     
|Crude oil collars:    |  |      |        |     
|Volumes (Bbls)        |  |      | 22,500 |     
|Average price ($/Bbl) |  |      |        |     
|Floor                 |  | $    | 18.00  |     
|Ceiling               |  |      | 22.56  |     

Interest Rate Risk

We are subject to interest rate risk as borrowings under our senior credit facility ($60.0 million outstanding as of December 31, 2002) accrue
interest at floating rates based on the lender's base rate or LIBOR. We do not utilize derivative instruments to protect against changes in interest rates on debt borrowings. Based on our outstanding
borrowing under our senior credit facility at December 31, 2002, an adverse change (defined as a hypothetical 1% and 2% increase in interest rates on such borrowings) would reduce cash flow by
approximately $600,000 and $1.2 million, respectively, from currently projected levels.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our 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.

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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 our definitive 2003 Proxy Statement for our annual meeting of stockholders to be held on Wednesday,
May 28, 2003. The 2003 Proxy Statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2002.

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 2003 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2002.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this item is incorporated herein by reference to the 2003 Proxy Statement, which will be filed with the Securities and Exchange
Commission not later than 120 days subsequent to December 31, 2002. See "Item 5. Market for Registrants Common Equity and Related Stockholder Matters", which sets forth certain
information with respect to our equity compensation plans.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The information required by this item is incorporated herein by reference to the 2003 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2002.

ITEM 14. CONTROLS AND PROCEDURES

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

(b)Changes in internal controls.    There have been no significant changes in our internal controls or in other factors that
could significantly affect our internal controls subsequent to the evaluation referred to in Item 14. (a), above, nor have there been any corrective actions with regard to significant deficiencies or
material weaknesses.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K





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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.

All Sources Finding Costs.Net capitalized costs incurred in the acquisition, exploration and development of proved oil and
natural gas reserves divided by total proved reserve additions. Total reserve additions includes extensions, discoveries, revisions of previous estimates and purchases of properties but excludes sales
of properties.

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 Finding Costs.The costs associated with drilling and completing a well divided by total proved reserve additions.
The costs do not include seismic and land acquisition costs for that well, future development costs associated with proved undeveloped reserves added by the well, capitalized general and
administrative cost or capitalized interest.

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.

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

MMcf.One million cubic feet of natural gas.

MMcfe.One million cubic feet of natural gas equivalents.

Net Acres or Net Wells.Gross acres or wells multiplied, in each case, by the percentage working interest owned by 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 Finding Costs.The costs associated with drilling and completing a well divided by total proved developed
reserve additions. The costs do not include seismic and land acquisition costs for that well, future development costs associated with proved undeveloped reserves added by the well, capitalized
general and administrative cost or capitalized interest.

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

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administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

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

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

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

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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 31, 2003.

| |  | BRIGHAM EXPLORATION COMPANY
| |  | ---------------------------
| |  | By:                        

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of March 31, 2003, by the following persons on
behalf of the Registrant and in the capacity indicated.

|/s/BEN M. BRIGHAMBen M. Brigham Chief Executive Officer, President and
Chairman of the Board
(Principal Executive Officer)
|--------------------------------------------------------------------------------------------------------------------------
|/s/EUGENE B. SHEPHERD, JR.Eugene B. Shepherd, Jr. Chief Financial Officer
(Principal Financial and Accounting Officer)    
|/s/ANNE L. BRIGHAMAnne L. Brigham Director                                                                                
|/s/HAROLD D. CARTERHarold D. Carter Director                                                                              
|/s/STEPHEN C. HURLEYStephen C. Hurley Director                                                                            
|/s/STEPHEN P. REYNOLDSStephen P. Reynolds Director                                                                        
|/s/HOBART. A. SMITHHobart A. Smith Director                                                                               
|/s/STEVEN A. WEBSTERSteven A. Webster Director                                                                            
|/s/R GRAHAM WHALINGR. Graham Whaling Director                                                                             

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CERTIFICATIONS

I, Bud M. Brigham, Chief Executive Officer of Brigham Exploration Company (the "Registrant"), certify that:





Date:
March 31, 2003

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

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CERTIFICATIONS

I, Eugene B. Shepherd, Jr., Chief Financial Officer of Brigham Exploration Company, (the "Registrant"), certify that:





Date:
March 31, 2003

|/s/EUGENE B. SHEPHERD, JR.Eugene B. Shepherd, Jr.
Chief Financial Officer |  | 
|------------------------------------------------------------------------- |  | 

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BRIGHAM EXPLORATION COMPANY
INDEX TO FINANCIAL STATEMENTS



|                                                                                                     |  | Page
|---------------------------------------------------------------------------------------------------- |  | ----
|Report of Independent Accountants                                                                    |  | F-2 
|Consolidated Balance Sheets as of December 31, 2002 and 2001                                         |  | F-3 
|Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000           |  | F-4 
|Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2002, 2001 and 2000 |  | F-5 
|Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000           |  | F-7 
|Notes to the Consolidated Financial Statements                                                       |  | F-8 

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, 2002 and 2001, and the results of their operations and their cash
flows for the three years in the period ended December 31, 2002 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.

As
discussed in Note 10 to the consolidated financial statements, the Company has restated diluted earnings per share data for 2001.

PricewaterhouseCoopers
LLP

March 27,
2003
Dallas, Texas

F-2

---



BRIGHAM EXPLORATION COMPANY  CONSOLIDATED BALANCE SHEETS  (in thousands, except share data)

|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  | December 31,               |                     
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | -------------------------- | --------------------
|
|ASSETS                                                                                                                                                                                                                            |                                                                                                                                                                                                 
|Current assets:                                                                                                                                                                                                                   |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  | Cash and cash equivalents                                                                                                                                                                        |                            | $                   
|                                                                                                                                                                                                                                  | Accounts receivable                                                                                                                                                                              |                            |                     
|                                                                                                                                                                                                                                  | Other current assets                                                                                                                                                                             |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            | Total current assets
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|Oil and natural gas properties, using the full cost method of accounting                                                                                                                                                          |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  | Unproved                                                                                                                                                                                         |                            |                     
|                                                                                                                                                                                                                                  | Proved                                                                                                                                                                                           |                            |                     
|                                                                                                                                                                                                                                  | Accumulated depletion                                                                                                                                                                            |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            | 164,980             
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|Other property and equipment, net                                                                                                                                                                                                 |                                                                                                                                                                                                  |                            | 1,234               
|Deferred loan fees                                                                                                                                                                                                                |                                                                                                                                                                                                  |                            | 2,391               
|Other noncurrent assets                                                                                                                                                                                                           |                                                                                                                                                                                                  |                            | 132                 
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  | $                          | 202,059             
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                                                                                                                                                              |                                                                                                                                                                                                 
|Current liabilities:                                                                                                                                                                                                              |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  | Accounts payable                                                                                                                                                                                 |                            | $                   
|                                                                                                                                                                                                                                  | Royalties payable                                                                                                                                                                                |                            |                     
|                                                                                                                                                                                                                                  | Accrued drilling costs                                                                                                                                                                           |                            |                     
|                                                                                                                                                                                                                                  | Participant advances received                                                                                                                                                                    |                            |                     
|                                                                                                                                                                                                                                  | Other current liabilities                                                                                                                                                                        |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  | Total current liabilities  |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|Senior credit facility                                                                                                                                                                                                            |                                                                                                                                                                                                  |                            | 60,000              
|Senior subordinated notes                                                                                                                                                                                                         |                                                                                                                                                                                                  |                            | 21,797              
|Other noncurrent liabilities                                                                                                                                                                                                      |                                                                                                                                                                                                  |                            | 186                 
|Commitments and contingencies                                                                                                                                                                                                     |                                                                                                                                                                                                  |                            |                     
|Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 1,765,132 and 1,630,692 shares issued and outstanding at December 31, 2002 and 2001, respectively |                                                                                                                                                                                                  |                            | 19,540              
|Series B Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 1,000,000 shares authorized, 501,226 shares issued and outstanding at December 31, 2002                                        |                                                                                                                                                                                                  |                            | 4,777               
|Stockholders' equity:                                                                                                                                                                                                             |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  | Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000 and 1,000,000 shares are designated as Series A and Series B, respectively                                     |                            |                     
|                                                                                                                                                                                                                                  | Common stock, $.01 par value, 50 million shares authorized, 20,618,161 and 17,127,650 shares issued and 19,479,979 and 16,016,113 shares outstanding at December 31, 2002 and 2001, respectively |                            |                     
|                                                                                                                                                                                                                                  | Additional paid-in capital                                                                                                                                                                       |                            |                     
|                                                                                                                                                                                                                                  | Treasury stock, at cost; 1,138,182 and 1,111,537 shares at December 31, 2002 and 2001, respectively                                                                                              |                            |                     
|                                                                                                                                                                                                                                  | Unearned stock compensation                                                                                                                                                                      |                            |                     
|                                                                                                                                                                                                                                  | Accumulated other comprehensive (loss) income                                                                                                                                                    |                            |                     
|                                                                                                                                                                                                                                  | Accumulated deficit                                                                                                                                                                              |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  | Total stockholders' equity |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  | $                          | 202,059             
|                                                                                                                                                                                                                                  |                                                                                                                                                                                                  |                            |                     

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)

|                                                                                   |                                             | Year Ended December 31,                 |                 
|---------------------------------------------------------------------------------- | ------------------------------------------- | --------------------------------------- | ----------------
|
|Revenues:                                                                          |                                             |                                         |                 
|                                                                                   | Oil and natural gas sales                   |                                         | $               
|                                                                                   | Other revenue                               |                                         |                 
|                                                                                   |                                             |                                         |                 
|                                                                                   |                                             |                                         | 35,176          
|                                                                                   |                                             |                                         |                 
|Costs and expenses:                                                                |                                             |                                         |                 
|                                                                                   | Lease operating                             |                                         |                 
|                                                                                   | Production taxes                            |                                         |                 
|                                                                                   | General and administrative                  |                                         |                 
|                                                                                   | Depletion of oil and natural gas properties |                                         |                 
|                                                                                   | Depreciation and amortization               |                                         |                 
|                                                                                   |                                             |                                         |                 
|                                                                                   |                                             |                                         | 25,741          
|                                                                                   |                                             |                                         |                 
|                                                                                   |                                             |                                         | Operating income
|                                                                                   |                                             |                                         |                 
|Other income (expense):                                                            |                                             |                                         |                 
|                                                                                   | Interest income                             |                                         |                 
|                                                                                   | Interest expense                            |                                         |                 
|                                                                                   | Debt conversion expense                     |                                         |                 
|                                                                                   | Other income (expense)                      |                                         |                 
|                                                                                   |                                             |                                         |                 
|                                                                                   |                                             |                                         | (7,059          
|                                                                                   |                                             |                                         |                 
|Income (loss) before income taxes and extraordinary item                           |                                             |                                         | 2,376           
|Income taxes                                                                       |                                             |                                         |                
|                                                                                   |                                             |                                         |                 
|Income (loss) before extraordinary item                                            |                                             |                                         | 2,376           
|Extraordinary itemgain on refinancing of senior subordinated notes, net of $0 tax |                                             |                                         |                
|                                                                                   |                                             |                                         |                 
|Net income                                                                         |                                             |                                         | 2,376           
|Less accretion and dividends on redeemable preferred stock                         |                                             |                                         | 2,952           
|                                                                                   |                                             |                                         |                 
|Net income (loss) available to common stockholders                                 |                                             | $                                       | (576            
|                                                                                   |                                             |                                         |                 
|Net income (loss) per share available to common stockholders:                      |                                             |                                         |                 
|                                                                                   | Basic                                       |                                         |                 
|                                                                                   |                                             | Income (loss) before extraordinary item |                 
|                                                                                   |                                             | Extraordinary item                      |                 
|                                                                                   |                                             |                                         |                 
|                                                                                   |                                             | $                                       | (0.04           
|                                                                                   |                                             |                                         |                 
|                                                                                   | Diluted                                     |                                         |                 
|                                                                                   |                                             | Income (loss) before extraordinary item |                 
|                                                                                   |                                             | Extraordinary item                      |                 
|                                                                                   |                                             |                                         |                 
|                                                                                   |                                             | $                                       | (0.04           
|                                                                                   |                                             |                                         |                 

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

F-4

---



BRIGHAM EXPLORATION COMPANY  CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY  (in thousands)

|                                                                     |                                                  | Common Stock |   |   |     |   |   |        |   | Accumulated
Other
Comprehensive
Income |        |   |   |        |  
|-------------------------------------------------------------------- | ------------------------------------------------ | ------------ | - | - | --- | - | - | ------ | - | -------------------------------------- | ------ | - | - | ------ | -
|
|
|Balance, December 31, 1999                                           |                                                  | 14,518       |   | $ | 145 |   | $ | 64,171 |   | $                                      |       |   | $ | (290   | )
|Net income                                                           |                                                  |             |   |   |    |   |   |       |   |                                        |       |   |   |       |  
|Exercise of employee stock options                                   |                                                  | 8            |   |   |    |   |   | 19     |   |                                        |       |   |   |       |  
|Issuance of common stock                                             |                                                  | 2,195        |   |   | 22  |   |   | 4,166  |   |                                        |       |   |   |       |  
|Issuance of restricted stock                                         |                                                  | 309          |   |   | 3   |   |   | 1,137  |   |                                        |       |   |   | (1,140 | )
|Issuance of stock options                                            |                                                  |             |   |   |    |   |   | 185    |   |                                        |       |   |   | (185   | )
|Forfeiture of stock options                                          |                                                  |             |   |   |    |   |   | (60    | ) |                                        |       |   |   | 10     |  
|Issuance of warrants                                                 |                                                  |             |   |   |    |   |   | 13,910 |   |                                        |       |   |   |       |  
|Cancellation of warrants                                             |                                                  |             |   |   |    |   |   | (4,979 | ) |                                        |       |   |   |       |  
|Amortization of unearned stock compensation                          |                                                  |             |   |   |    |   |   |       |   |                                        |       |   |   | 284    |  
|Purchase of treasury stock                                           |                                                  |             |   |   |    |   |   |       |   |                                        | (3,950 | ) |   |       |  
|In kind dividends on Series A mandatorily redeemable Preferred Stock |                                                  |             |   |   |    |   |   | (267   | ) |                                        |       |   |   |       |  
|Accretion on Series A mandatorily redeemable Preferred Stock         |                                                  |             |   |   |    |   |   | (8     | ) |                                        |       |   |   |       |  
|                                                                     |                                                  |              |   |   |     |   |   |        |   |                                        |        |   |   |        |  
|Balance, December 31, 2000                                           |                                                  | 17,030       |   |   | 170 |   |   | 78,274 |   |                                        | (3,950 | ) |   | (1,321 | )
|Comprehensive income (loss):                                         |                                                  |              |   |   |     |   |   |        |   |                                        |        |   |   |        |  
|                                                                     | Net income                                       |              |  |   |     |  |   |        |  |                                        |        |  |   |        | 
|                                                                     | Cumulative effect (loss) on adoption of SFAS 133 |              |  |   |     |  |   |        |  |                                        |        |  |   |        | 
|                                                                     | Unrealized gain on cash flow hedges              |              |  |   |     |  |   |        |  |                                        |        |  |   |        | 
|                                                                     |                                                  |              |   |   |     |   |   |        |   |                                        |        |   |   |        |  
|                                                                     | Comprehensive income                             |              |   |   |     |   |   |        |   |                                        |        |   |   |        |  
|                                                                     |                                                  |              |   |   |     |   |   |        |   |                                        |        |   |   |        |  
|Exercise of employee stock options                                   |                                                  | 97           |   |   | 1   |   |   | 251    |   |                                        |       |   |   |       |  
|Forfeitures of employee stock options                                |                                                  |             |   |   |    |   |   | (115   | ) |                                        |       |   |   | 31     |  
|Forfeitures of restricted stock                                      |                                                  |             |   |   |    |   |   | 6      |   |                                        | (148   | ) |   | 121    |  
|Purchases of restricted stock                                        |                                                  |             |   |   |    |   |   |       |   |                                        | (67    | ) |   |       |  
|Issuance of warrants                                                 |                                                  |             |   |   |    |   |   | 4,500  |   |                                        |       |   |   |       |  
|In kind dividends on Series A mandatorily redeemable Preferred Stock |                                                  |             |   |   |    |   |   | (2,347 | ) |                                        |       |   |   |       |  
|Accretion on Series A mandatorily redeemable Preferred Stock         |                                                  |             |   |   |    |   |   | (103   | ) |                                        |       |   |   |       |  
|Amortization of unearned stock compensation                          |                                                  |             |   |   |    |   |   |       |   |                                        |       |   |   | 675    |  
|                                                                     |                                                  |              |   |   |     |   |   |        |   |                                        |        |   |   |        |  
|Balance, December 31, 2001                                           |                                                  | 17,127       |   |   | 171 |   |   | 80,466 |   |                                        | (4,165 | ) |   | (494   | )

F-5

---

BRIGHAM EXPLORATION COMPANY  CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)  (in thousands)

|                                                                         |                                     | Common Stock                |   |   |     |   |   |        |   | Accumulated
Other
Comprehensive
Income |        |   |   |      |  
|------------------------------------------------------------------------ | ----------------------------------- | --------------------------- | - | - | --- | - | - | ------ | - | -------------------------------------- | ------ | - | - | ---- | -
|
|
|Balance, December 31, 2001                                               |                                     | 17,127                      |   |   | 171 |   |   | 80,466 |   |                                        | (4,165 | ) |   | (494 | )
|Comprehensive income (loss):                                             |                                     |                             |   |   |     |   |   |        |   |                                        |        |   |   |      |  
|                                                                         | Net income                          |                             |  |   |     |  |   |        |  |                                        |        |  |   |      | 
|                                                                         | Unrealized loss on cash flow hedges |                             |  |   |     |  |   |        |  |                                        |        |  |   |      | 
|                                                                         | Net losses included in net income   |                             |  |   |     |  |   |        |  |                                        |        |  |   |      | 
|                                                                         |                                     |                             |   |   |     |   |   |        |   |                                        |        |   |   |      |  
|                                                                         |                                     | Comprehensive income (loss) |   |   |     |   |   |        |   |                                        |        |   |   |      |  
|                                                                         |                                     |                             |   |   |     |   |   |        |   |                                        |        |   |   |      |  
|Exercise of employee stock options                                       |                                     | 133                         |   |   | 1   |   |   | 295    |   |                                        |       |   |   |     |  
|Expiration of employee stock options                                     |                                     |                            |   |   |    |   |   | (46    | ) |                                        |       |   |   |     |  
|Forfeitures of restricted stock                                          |                                     |                            |   |   |    |   |   | (1     | ) |                                        | (41    | ) |   | 15   |  
|Revision of terms of employee stock options                              |                                     |                            |   |   |    |   |   | 596    |   |                                        |       |   |   |     |  
|Repurchases of common stock                                              |                                     |                            |   |   |    |   |   |       |   |                                        | (76    | ) |   |     |  
|Issuance of warrants                                                     |                                     |                            |   |   |    |   |   | 4,605  |   |                                        |       |   |   |     |  
|Warrants exercised for common stock                                      |                                     | 244                         |   |   | 2   |   |   | 623    |   |                                        |       |   |   |     |  
|Common stock issued in exchange for warrants and convertible debt rights |                                     | 550                         |   |   | 6   |   |   | (56    | ) |                                        |       |   |   |     |  
|Debt converted to common stock                                           |                                     | 2,564                       |   |   | 26  |   |   | 9,906  |   |                                        |       |   |   |     |  
|In kind dividends on Series A mandatorily redeemable preferred stock     |                                     |                            |   |   |    |   |   | (2,689 | ) |                                        |       |   |   |     |  
|Accretion on Series A mandatorily redeemable preferred stock             |                                     |                            |   |   |    |   |   | (238   | ) |                                        |       |   |   |     |  
|In kind dividends on Series B mandatorily redeemable preferred stock     |                                     |                            |   |   |    |   |   | (24    | ) |                                        |       |   |   |     |  
|Accretion on Series B mandatorily redeemable preferred stock             |                                     |                            |   |   |    |   |   | (1     | ) |                                        |       |   |   |     |  
|Amortization of unearned stock compensation                              |                                     |                            |   |   |    |   |   |       |   |                                        |       |   |   | 267  |  
|                                                                         |                                     |                             |   |   |     |   |   |        |   |                                        |        |   |   |      |  
|Balance, December 31, 2002                                               |                                     | 20,618                      |   | $ | 206 |   | $ | 93,436 |   | $                                      | (4,282 | ) | $ | (212 | )
|                                                                         |                                     |                             |   |   |     |   |   |        |   |                                        |        |   |   |      |  

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

F-6

---



BRIGHAM EXPLORATION COMPANY  CONSOLIDATED STATEMENTS OF CASH FLOWS  (in thousands)

|                                                     |                                                                                      | Year Ended December 31,                                                |                               
|---------------------------------------------------- | ------------------------------------------------------------------------------------ | ---------------------------------------------------------------------- | ------------------------------
|
|Cash flows from operating activities:                |                                                                                      |                                                                        |                               
|                                                     | Net income                                                                           |                                                                        | $                             
|                                                     | Adjustments to reconcile net income to cash provided (used) by operating activities: |                                                                        |                               
|                                                     |                                                                                      | Depletion of oil and natural gas properties                            |                               
|                                                     |                                                                                      | Depreciation and amortization                                          |                               
|                                                     |                                                                                      | Interest paid through issuance of additional senior subordinated notes |                               
|                                                     |                                                                                      | Amortization of deferred loan fees                                     |                               
|                                                     |                                                                                      | Amortization of discount on senior subordinated notes                  |                               
|                                                     |                                                                                      | Amortization of deferred loss on derivative instruments                |                               
|                                                     |                                                                                      | Market value adjustment for derivative instruments                     |                               
|                                                     |                                                                                      | Extraordinary gain on refinancing of senior subordinated notes         |                               
|                                                     |                                                                                      | Loss on investment in Brigham Duke LLC                                 |                               
|                                                     |                                                                                      | Stock option compensation expense                                      |                               
|                                                     |                                                                                      | Changes in working capital and other items:                            |                               
|                                                     |                                                                                      |                                                                        | Accounts receivable           
|                                                     |                                                                                      |                                                                        | Other current assets          
|                                                     |                                                                                      |                                                                        | Accounts and royalties payable
|                                                     |                                                                                      |                                                                        | Other current liabilities     
|                                                     |                                                                                      |                                                                        | Noncurrent assets             
|                                                     |                                                                                      |                                                                        | Noncurrent liabilities        
|                                                     |                                                                                      |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|Cash flows from investing activities:                |                                                                                      |                                                                        |                               
|                                                     | Additions to oil and natural gas properties                                          |                                                                        |                               
|                                                     | Proceeds from sale of oil and natural gas properties                                 |                                                                        |                               
|                                                     | Additions to other property and equipment                                            |                                                                        |                               
|                                                     | (Increase) decrease in drilling advances paid                                        |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|Cash flows from financing activities:                |                                                                                      |                                                                        |                               
|                                                     | Proceeds from issuance of common stock                                               |                                                                        |                               
|                                                     | Proceeds from issuance of preferred stock and warrants                               |                                                                        |                               
|                                                     | Proceeds from issuance of senior subordinated notes and warrants                     |                                                                        |                               
|                                                     | Proceeds from exercise of employee stock options                                     |                                                                        |                               
|                                                     | Proceeds from exercise of warrants                                                   |                                                                        |                               
|                                                     | Fees paid due to common stock exchange for warrants                                  |                                                                        |                               
|                                                     | Repurchases of common stock                                                          |                                                                        |                               
|                                                     | Increase in senior credit facility                                                   |                                                                        |                               
|                                                     | Repayment of senior credit facility                                                  |                                                                        |                               
|                                                     | Principal payments on senior subordinated notes                                      |                                                                        |                               
|                                                     | Principal payments on capital lease obligations                                      |                                                                        |                               
|                                                     | Deferred loan fees paid                                                              |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|                                                     |                                                                                      |                                                                        |                               
|Net increase (decrease) in cash and cash equivalents |                                                                                      |                                                                        | 10,206                        
|Cash and cash equivalents, beginning of year         |                                                                                      |                                                                        | 5,112                         
|                                                     |                                                                                      |                                                                        |                               
|Cash and cash equivalents, end of year               |                                                                                      | $                                                                      | 15,318                        
|                                                     |                                                                                      |                                                                        |                               

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

F-7

---



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.

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.

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

F-8

---

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 yearsMachinery and equipment

5 years3-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, 2002, Brigham had recorded a receivable of approximately 1,180 MMcf
and $3.7 million and a liability of approximately 1,486 MMcf and $5.7 million associated with gas imbalances. At December 31, 2001, Brigham had recorded a receivable of
approximately 441 MMcf and $1.5 million and a liability of approximately 758 MMcf and $2.7 million associated with gas imbalances.

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 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

F-9

---

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 did 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 qualified 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. 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.

F-10

---

Other Comprehensive Income

Brigham follows the provisions of Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income," which establishes standards for
reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to
stockholders of Brigham. Brigham had no such changes prior to 2001. The components of other comprehensive income for the years ended December 31 follow (in thousands):

2002

2001

2000Balance, beginning of year

$
351

$


$
Cumulative effect of adoption of SFAS No. 133





(11,800
)

Current period settlements reclassified to earnings


1,847


(9,646
)

Current period change in fair value of hedges


(5,366
)

21,797


Net losses included in earnings


121





Balance, end of year

$
(3,047
)
$
351

$



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").

The
weighted average fair value per share of stock compensation issued during 2002, 2001 and 2000 was $3.44, $2.19, and $1.92, respectively. The fair value for these options was
estimated using the Black-Scholes model with the following weighted average assumptions for grants made in 2002, 2001 and 2000; risk free interest rate of 4.1%, 4.9% and 6.2%; volatility of the
expected market prices of Brigham's common stock of 102%, 60% and 67%; expected dividend yield of zero and weighted average expected option lives of 7.0, 7.0 and 6.6 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 as

F-11

---

amended by SFAS 148, Brigham's net income (loss) and net income (loss) per share for the years ended December 31, 2002, 2001 and 2000 would have been the pro forma amounts indicated
below:

2002

2001

2000Net income available to common stockholders
(in thousands):As reported

$
(576
)
$
9,238

$
16,337Add back: Stock compensation expense previously included in net income


101


295


124Effect of total employee stock-based compensation expense, determined under fair value method for all awards


(513
)

(347
)

1,009Pro forma

$
(988
)
$
9,186

$
17,470Net income per share:Basic:As reported

$
(0.04
)
$
0.58

$
1.01Pro forma


(0.06
)

0.57


1.08Diluted:As reported

$
(0.04
)
$
0.44

$
1.01Pro forma


(0.06
)

0.44


1.08


F-12

---

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.

Deferred Loan Fees

Deferred loan fees 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 Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations". 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. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of
the related asset. If the liability is settled for an amount other than the recorded amount,
a gain or loss is recognized. Brigham will adopt this standard as required on January 1, 2003. Brigham is currently evaluating the effect of this statement on its consolidated financial
position, results of operations and cash flows.

In
April 2002, the FASB issued SFAS No. 145, "Rescission of FASB statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections"
("SFAS 145"). SFAS 145 requires, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be
classified as components of a company's income or loss from continuing operations. Prior to the adoption of the provisions of SFAS 145, gains or losses on the early extinguishment of debt were
required to be classified in a company's periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from
continuing operations. SFAS No. 145 is effective for fiscal years

F-13

---

beginning after May 15, 2002. Due to the requirements of SFAS No. 145, it is less likely that a gain or loss on extinguishment of debt would be classified as an extraordinary item in
Brigham's results of operations.

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 was 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 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 had 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 the Brigham-Duke LLC.

4. Property and Equipment

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

December 31,2002

2001Oil and natural gas properties

$
267,394

$
239,711Accumulated depletion


(102,414
)

(87,820
)164,980


151,891Other property and equipment:3-D seismic interpretation workstations and software


2,445


2,307Office furniture and equipment


2,337


2,225Accumulated depreciation


(3,548
)

(3,201
)1,234


1,331$
166,214

$
153,222


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

F-14

---

the periods benefited by these activities. During the years ended December 31, 2002, 2001 and 2000, these capitalized costs amounted to $4.2 million, $3.9 million and
$3.4 million, respectively. Capitalized costs do not include any costs related to production, general corporate overhead, or similar activities. Interest costs of $0.9 million,
$1.8 million and $2.8 million were capitalized in 2002, 2001 and 2000, respectively.

5. Senior Credit Facility and Senior Subordinated Notes

December 31,2002

2001Senior Credit Facility

$
60,000

$
75,000Senior Subordinated Notes


21,797


16,721Total Debt

$
81,797

$
91,721Less: Current Maturities





Total Long-Term Debt

$
81,797

$
91,721


Senior Credit Facility

As of December 31, 2002, Brigham had $60.0 million in borrowings outstanding under its senior credit facility. Principal outstanding under the
senior credit facility is due at maturity with interest due monthly for base rate tranches or periodically as London Interbank Offered Rate (LIBOR) tranches mature. The annual interest rate for
borrowings under the senior credit facility is either the lender's base rate or London Interbank Offered Rate (LIBOR) (1.5% on December 31, 2002) plus 3.00%, at Brigham's option. Obligations
under the senior credit facility are secured by substantially all of Brigham's oil and natural gas properties and other tangible assets.

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, 2002 and for the year then ended, Brigham was in compliance with all covenant
requirements.

In
December 2002, the senior credit facility was amended to extend the maturity date to December 31, 2004 and to provide Brigham with $65 million in funding
commitments under a revolving credit structure. In December 2001, the senior credit facility was amended to extend the maturity date to December 31, 2003. Brigham recognized $323,000 and
$200,000 during 2002 and 2001, respectively, as additional deferred loan fees relating to these amendments. The additional deferred loan fees and the unamortized deferred loan fees will be amortized
over the remaining life of the senior credit facility.

The
senior credit facility was amended in February 2000, to provide Brigham with $75 million in borrowing availability. As part of the amendment, $30 million of the
senior credit facility held by Shell Capital was designated as convertible notes. To facilitate this conversion Brigham issued to Shell Capital warrants to be converted into shares of Brigham common
stock 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.

F-15

---

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.

In
December 2002, Brigham entered into a series of transactions whereby a number of warrants and convertible debt rights were extinguished or converted. Brigham issued 550,000
unregistered shares of its common stock to Shell Capital in exchange for Shell Capital's warrant position (see Senior Subordinated Notes below), and to terminate Shell Capital's right to convert
$30 million of Brigham's senior credit facility into shares of Brigham common stock. Also, DLJ Merchant Banking Partners III, L.P. in conjunction with GlobalEnergy Partners, both
affiliates of CSFB Private Equity, purchased $10 million of Brigham's senior credit facility from Shell Capital and converted it into 2,564,102 shares of Brigham's common stock at an exercise
price of $3.90 per share. Brigham recorded $0.6 million in debt conversion expenses associated with this conversion.

The
following table details the warrant position and convertible debt rights that were extinguished or converted as a result of the these transactions:

Exercise
Price

# Shares$10 million of Convertible Notes

$
3.90

2,564,102$10 million of Convertible Notes

$
6.00

1,666,667$10 million of Convertible Notes

$
8.00

1,250,000Warrants issued with Senior Subordinated Notes Facility

$
3.00

1,250,0006,730,769


As
further discussed in Note 6, Brigham issued 500,000 shares of Series B preferred stock and 2.3 million warrants to purchase Brigham's common stock for net
proceeds of $9.4 million. In addition, Brigham used $5.0 million of the net proceeds from the Series B preferred offering to repay outstanding indebtedness under its senior credit
facility.

In
March 2003, Brigham replaced its senior credit facility with a new senior credit facility that provides for a maximum $80 million in commitments, an initial borrowing
base of $70 million and matures in March 2006. As of the closing date of the facility, Brigham had $56 million in outstanding borrowings under the new senior credit facility.
Borrowings under the new senior credit facility are secured by substantially all of Brigham's oil and natural gas properties and other tangible assets and bear interest at either the base rate of
Société Générale or LIBOR, at Brigham's option, plus a margin that varies according to facility usage. Interest is paid quarterly. The
collateral value and borrowing base are redetermined periodically. The unused portion of the committed borrowing base is subject to an annual commitment fee of 0.50%.

The
new senior credit facility agreement contains various covenants and restrictive provisions, which limit Brigham's ability to incur additional indebtedness, sell properties, purchase
or redeem capital stock, make investments or loans, create liens and make certain acquisitions. The new senior credit facility requires Brigham to maintain a current ratio (as defined) of at least 1
to 1 and an interest coverage ratio (as defined) of at least 3.25 to 1.

F-16

---

Senior Subordinated Notes

As of December 31, 2002, Brigham had $21.8 million of senior subordinated notes outstanding. The senior subordinated notes bear interest at 10.75%
per annum, payable quarterly in arrears on the last day of January, April, July and October, are redeemable at Brigham's option for face value at any time and have no principal repayment obligations
until maturity in October 2005. At Brigham's option, up to 50% of the interest payments on the senior subordinated notes can be satisfied by payment in kind through the issuance of additional
senior subordinated notes in lieu of cash. In December 2002, Brigham extended its option to satisfy 50% of its interest obligation in this manner through October 2003. For the years
ended December 31, 2002 and 2001, Brigham exercised this option and issued an additional $1.1 and $0.7 million, respectively, of senior subordinated notes.

The
senior subordinated notes are issued pursuant to the senior subordinated notes facility dated October 31, 2000. Under the senior subordinated notes facility, Shell Capital
agreed to provide up to $20 million (plus any amount of interest paid in kind) in senior subordinated notes in borrowing increments of at least $1 million. Once borrowings under the
senior subordinated notes facility have been repaid they cannot be withdrawn. The senior subordinated notes are secured obligations ranking junior to Brigham's senior credit facility and have
covenants similar to the senior credit facility. In connection with the senior subordinated credit agreement in October 2000, Brigham issued warrants to purchase 1,250,000 shares of Brigham
common stock at an exercise price of $3.00 per share. The warrants had a term of seven years and a cashless exercise feature. Brigham valued the warrants using the Black-Scholes Option Pricing 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 senior subordinated notes. The warrants were
extinguished in December 2002 (see Senior Credit Facility above).

At
January 1, 2000, Brigham had a subordinated notes agreement with $41.3 million total outstanding and warrants issued to the notes holders to purchase one million shares
of common stock at an exercise price of $3.50 per share. In February 2000, in connection with an amendment to the agreement, the exercise price on the warrants was reduced to $2.43 per share.
Brigham issued an additional $4.6 million in subordinated notes as payment in kind of interest for the year ended December 31, 2000. In November 2000, these subordinated notes and
warrants were purchased by Brigham for $20 million resulting in an extraordinary gain of $32.3 million, net of transaction costs of $1.7 million.

6. Preferred Stock

In October 2000, Brigham designated 1.5 million shares of preferred stock as Series A Preferred Stock, and in November 2000, issued
1.0 million shares of mandatorily redeemable preferred stock (the "Series A Preferred Stock") and warrants to purchase 6,666,667 shares of 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 and
warrants held by the holder of the subordinated notes as described in Note 5.

The
Series A Preferred Stock 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

F-17

---

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 stated value (depending upon certain conditions) at anytime
prior to maturity.

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
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 Option Pricing model and were recorded as additional paid-in
capital in 2000. This discount accretes to the Series A Preferred Stock dividends during the life of the securities using the effective interest method.

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 above 150% of the exercise price (currently $6.525 per share) for 60 consecutive
trading days. The Additional Series A Warrants were valued at approximately $4.5 million using the Black-Scholes Option Pricing model and were recorded as additional paid-in
capital in March 2001. This discount accretes to the Series A Preferred Stock dividends during the life of the securities using the effective interest method. In connection with the
issuance of Series B Preferred Stock in December 2002, the exercise price of the Additional Series A warrants was reset from the then current exercise price of $4.75 per share to
$4.35 per share.

Brigham
had 1,765,132 and 1,630,692 shares of Series A Preferred Stock issued and outstanding with a redemption value of $35.3 million and $32.6 million at
December 31, 2002 and 2001, respectively. For the year ended December 31, 2002 and 2001, Brigham issued an additional 134,430 and 130,692 shares, respectively, of Series A
Preferred Stock as PIK dividends.

In
December 2002, Brigham designated 1,000,000 shares of preferred stock as Series B and issued 500,000 shares of Series B Preferred Stock and warrants to purchase
2,298,851 shares of Brigham's common stock (the "Series B Warrants") for net proceeds of $9.4 million. A portion of the proceeds were used to reduce borrowings under the Senior Credit
Facility by $5 million. The Series B 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 PIK through the issuance of additional Series B Preferred Stock in lieu of cash. At Brigham's option, up to 100% of the dividend payments on the Series B Preferred Stock
can be paid by the issuance of PIK dividends for five years. The Series B Preferred Stock matures in ten years and is redeemable in whole at Brigham's option at 101% of the stated value five
years after closing.

The
Series B Preferred Stock ranks in parity with the Series A Preferred Stock and senior as to dividend, redemption and liquidation rights to all other classes and series
of capital stock of Brigham authorized on the date of issuance, or to any other class or series of capital stock issued while any

F-18

---

shares of the Series B Preferred Stock remain outstanding. The Series B Preferred Stock does not generally have any voting rights, except for certain approval rights and as required by
law.

The
Series B Warrants have terms similar to the Series A Warrants described above with an exercise price of $4.35 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 ($6.525 per share) for 60 consecutive trading days. The Series B Warrants were valued at
approximately $4.6 million using the Black-Scholes Option Pricing model and were recorded as additional paid-in capital in December 2002. This discount accretes to the
Series B Preferred Stock dividends during the life of the securities using the effective interest method.

Brigham
had 501,226 shares of Series B Preferred Stock issued and outstanding with a redemption value of $10.0 million at December 31, 2002. For the year ended
December 31, 2002, Brigham issued an additional 1,226 shares of Series B Preferred Stock as PIK dividends.

7. Issuance of Common Stock

In December 2002, Brigham issued 550,000 shares of Brigham common stock to Shell Capital in exchange for Shell Capital's warrants and associated
convertible debt rights. In addition, Brigham issued 2,564,102 shares of Brigham common stock upon the conversion of $10 million of the senior credit facility. See further discussion above in
Note 5.

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. In
December 2002, 243,902 of these warrants were exercised for common stock resulting in net proceeds of approximately $625,000. In February 2003, the remaining 487,805 warrants were
exercised under a cashless feature resulting in the issuance of 248,028 shares of Brigham common stock.

8. Capital Lease Obligations

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

December 31,2002

20013-D seismic interpretation workstations and software

$


$
45Office furniture and equipment





167


212Accumulated depreciation and amortization





(175
)$


$
37


There
are no obligations under capital leases as of December 31, 2002.

F-19

---

9. Income Taxes

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

Year Ended December 31,2002

2001

2000Current income taxes:Federal

$


$


$
State








Deferred income taxes:Federal








State








$


$


$



The
differences in income taxes provided and the amounts determined by applying the federal statutory tax rate to income before income taxes result from the following (in thousands):

Year Ended December 31,2002

2001

2000Tax at statutory rate

$
832

$
4,091

$
5,814Add the effect of:Nondeductible expenses


223


4


12Deductible stock compensation


(110
)

(9
)

Valuation allowance


(945
)

(4,086
)

(5,826
)$


$


$



F-20

---

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

December 31,2002

2001Deferred tax assets:Net operating loss carryforwards

$
34,814

$
31,085Capital loss carryforwards


1,001


438Stock compensation


808


745Gas imbalances


698


445Unrealized hedging losses


1,066


Other


32


738,419


32,720Deferred tax liability:Depreciable and depletable property


(29,544
)

(24,058
)Derivative liabilities


(325
)

(233
)(29,869
)

(24,291
)Net deferred tax asset


8,550


8,429Valuation allowance


(8,550
)

(8,429
)$


$



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, 2002, 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 $8.6 million against them. The valuation allowance was increased by $0.1 million in 2002 due to an increase of $5.6 million in deferred tax liabilities,
partially offset by a $5.7 million increase in carryforward and other amounts. Deferred tax assets of $1.1 million related to unrealized hedging losses in other comprehensive income are
included in this $5.7 million increase.

At
December 31, 2002, Brigham has regular tax NOLs of approximately $99.5 million. Additionally, Brigham has approximately $84.9 million of alternative minimum tax
("AMT") NOLs available as a deduction against future AMT income. The NOLs expire from 2012 through 2022. The

F-21

---

value of these NOLs depends on the ability of Brigham to generate taxable income. A summary of our NOLs follows:

Regular
NOLs

AMT
NOLsExpiration Date:December 31, 2012

$
13,327

$
8,703December 31, 2018


26,411


23,170December 31, 2019


20,806


20,196December 31, 2020


12,512


7,587December 31, 2021


19,116


18,440December 31, 2022


7,298


6,799$
99,470

$
84,895


In
addition, at December 31, 2002, Brigham has capital loss carryforwards of approximately $2.9 million that expire in varying years through 2007.

Brigham
believes it has a $5 million limitation on its NOLs under Internal Revenue Code Section 382 due to a potential 50% change in ownership among its 5% shareholders
over a three-year period.

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 resulted in the issuance of common stock that would then share in the earnings of Brigham.

Year Ended December 31,2002

2001

2000RestatedBasic EPS:Income (loss) available to common stockholders before extraordinary item

$
(576
)
$
9,238

$
(15,930
)Extraordinary item








32,267Income (loss) available to common stockholders

$
(576
)
$
9,238

$
16,337Common shares outstanding


16,138


15,988


16,241Basic EPSIncome (loss) available to common stockholders before extraordinary item

$
(0.04
)
$
0.58

$
(0.98
)Extraordinary item








1.99$
(0.04
)
$
0.58

$
1.01


F-22

---

Diluted EPS:Income (loss) available to common stockholders before extraordinary item

$
(576
)
$
9,238

$
(15,930
)Extraordinary item








32,267Income (loss) available to common stockholders

$
(576
)
$
9,238

$
16,337Adjustments for assumed conversions:Interest on convertible debt





826


Dividends and accretion on mandatorily redeemable preferred stock





2,364





3,190


Income (loss) available to common stockholders before extraordinary itemdiluted

$
(576
)
$
12,428

$
(15,930
)Extraordinary item








32,267Income (loss) available to common stockholdersdiluted

$
(576
)
$
12,428

$
16,337Common shares outstanding


16,138


15,988


16,241Effect of dilutive securities:Convertible debt





2,564


Warrants





926


Mandatorily redeemable preferred stock





8,426


Stock options





301


Potentially dilutive common shares





12,217


Adjusted common shares outstandingdiluted


16,138


28,205


16,241Diluted EPS (as restated for 2001see below)Income (loss) available to common stockholders before extraordinary item

$
(0.04
)
$
0.44

$
(0.98
)Extraordinary item








1.99$
(0.04
)
$
0.44

$
1.01


At
December 31, 2002, 2001, and 2000, potential dilution of approximately 14.3 million, 3.0 million and 11.1 million shares of common stock, respectively,
related to mandatorily redeemable preferred stock, convertible debt, warrants and options were outstanding, but were not included in the computation of diluted income (loss) per share because the
effect of these instruments would have been anti-dilutive.

RestatementDiluted earnings per share for 2001 have been restated (downward) to appropriately reflect the impact of Brigham's
convertible debt, mandatorily redeemable preferred stock and associated warrants. The revised calculations utilize the "if-converted" method, as the holders can

F-23

---

exercise the warrants either by paying cash or tendering the related convertible debt or mandatorily redeemable preferred stock.

Quarter

Year to DateAs Reported

Restated

As Reported

RestatedMarch 31, 2001

$
0.02

$
0.02

$
0.02

$
0.02June 30, 2001

$
0.46

$
0.30

$
0.51

$
0.36September 30, 2001

$
0.17

$
0.13

$
0.67

$
0.49December 31, 2001

$
(0.15
)
$
(0.15
)
$
0.54

$
0.44


There
is no impact on previously reported diluted earnings per share data for 2002 or 2000.

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
June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed suit against Brigham claiming that Brigham transported natural gas under his property through an
existing pipeline without his consent. Mr. Garcia claimed $1.2 million in actual damages and $3 million in exemplary damages. In May 2002, Brigham settled the case through
mediation for a cash payment of $125,000. Subsequently, Brigham began using an alternate pipeline.

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 been set for August 2003.

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

On
July 11, 2002, an employee of a contractor on Brigham's Burkhart #1-R location, Matagorda County, Texas, was involved in a fatal accident. The United States
Department of Labor Occupational

F-24

---

Safety & Health Administration investigated the accident and issued three citations and imposed a total of $168,000 in fines. Brigham is appealing the citations, but at this time, cannot
predict the outcome of that appeal.

On
October 8, 2002, relatives of the contractor's employee filed a wrongful death action in the district court for Matagorda County, Texas, against Brigham and three of Brigham's
contractors in connection with his accidental death on July 11, 2002. Plaintiffs are seeking unspecified both actual and punitive damages. Brigham cannot predict the outcome of this case,
however Brigham believes it has sufficient insurance to cover the claim.

As
of December 31, 2002, 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 an additional five years. The future minimum annual rental payments under the noncancelable terms of these leases at December 31, 2002 are as follows (in
thousands):

2003

$
8852004


8852005


8852006


8852007


443$
3,983


Future
minimum rental payments are not reduced by minimum sublease rental income of approximately $13,000 due in 2003 under noncancelable subleases.

Rental
expense for the years ended December 31, 2002, 2001 and 2000 was approximately $868,000, $731,000 and $805,000, 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, 2002, 2001 and 2000:

2002

2001

2000Purchaser A

19
%
45
%
36
%Purchaser B



15
%
20
%Purchaser C

15
%


Purchaser D

11
%





F-25

---

Brigham
believes that the loss of any individual purchaser would not have a long-term material adverse impact on its financial position or results 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.

Natural Gas Derivative Contracts

The following table sets forth Brigham's outstanding natural gas hedging contracts and the weighted average NYMEX prices for those contracts as of
December 31, 2002:

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Outstanding
Average2003Swap ContractsVolume (MMbtu)


832,500


591,500


460,000


322,000


549,851Price per MMBtu

$
3.63

$
3.32

$
3.50

$
3.73

$
3.54


The
following table sets forth the natural gas hedging contracts Brigham entered subsequent to December 31, 2002 and the weighted average NYMEX prices for those contracts:

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Outstanding
Average2003Swap ContractsVolume (MMbtu)





227,500


138,000


92,000


114,692Price per MMBtu

$


$
5.21

$
5.08

$
5.12

$
5.152003FloorsVolume (MMbtu)





150,000


460,000


460,000


187,912Price per MMBtu

$


$
4.50

$
4.50

$
4.50

$
4.502004Swap ContractsVolume (MMbtu)


295,750


227,500


138,000


92,000


187,912Price per MMBtu

$
4.96

$
4.25

$
4.18

$
4.36

$
4.53


F-26

---

Oil Derivative Contracts

The following table sets forth Brigham's outstanding oil hedging contracts and the weighted average NYMEX prices for those contracts as of December 31,
2002:

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Outstanding
Average2003Swap ContractsVolume (Bbl)


67,500


50,050


55,200


41,400


53,471Price per Bbl

$
25.29

$
24.28

$
23.77

$
23.21

$
24.262003CollarsVolume (Bbl)


22,500


22,750





Ceiling price per Bbl

$
22.56

$
22.56

$


$
Floor price per Bbl

$
18.00

$
18.00

$


$



The
following table sets forth the oil hedging contracts Brigham entered subsequent to December 31, 2002 and the weighted average NYMEX prices for those contracts:

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Outstanding
Average2003Swap ContractsVolume (Bbl)





11,375








2,836Price per Bbl

$


$
29.33

$


$


$
29.332004Swap ContractsVolume (Bbl)


29,575


20,475


13,800


9,200


18,145Price per Bbl

$
25.35

$
24.52

$
23.91

$
23.80

$
24.65


At
December 31, 2002, the fair value of hedging contracts included in accumulated other comprehensive income and other current liabilities was approximately $3.2 million
which is expected to be included in the results of operations for the year ended December 31, 2003. 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.

Brigham
reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham's oil and natural gas prices
including and

F-27

---

excluding the hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three year period ended December 31, 2002:

Year Ended December 31,2002

2001

2000Natural GasAverage price per Mcf as reported (including hedging results)

$
3.21

$
3.11

$
1.94Average price per Mcf realized (excluding hedging results)

$
3.33

$
4.29

$
4.06Decrease in revenue (in thousands)

$
712

$
8,001

$
9,400OilAverage price per Bbl as reported (including hedging results)

$
23.55

$
24.05

$
29.17Average price per Bbl realized (excluding hedging results)

$
25.17

$
24.38

$
29.47Decrease in revenue (in thousands)

$
1,135

$
153

$
107


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, 2002 and 2001, the fair value of these derivatives included in other liabilities
was $0 and $0.4 million, respectively. Brigham recognized $0.4 million, $9.7 million and $(8.9) million in non-cash gains (losses) related to
changes in the fair values of these derivative contracts and $0.6 million, $1.5 million, and $0.6 million in losses related to the cash settlement payments made by Brigham to the
counterparty for the years ended December 31, 2002, 2001 and 2000, respectively.

For
the year ended December 31, 2002, ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges decreased earnings by approximately
$0.1 million. These amounts are included in other income and expense. There was no ineffectiveness for the year ended December 31, 2001.

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 Senior Subordinated Notes at
December 31, 2002 and 2001 was $24.0 million and $13.9 million, respectively.

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, 2002 and 2001
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.

F-28

---

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 2002 and 2001, Brigham matched 25% of eligible employee contributions. Based on attainment of performance goals established at the beginning of 2002, Brigham
matched an additional 62.5% and 17% of eligible employee contributions made during 2002 and 2001, respectively. Brigham contributed $260,000 and $102,000 to the 401(k) plan for the years ended
December 31, 2002 and 2001, respectively, to match eligible contributions by employees. Brigham did not match employee contributions in 2000.

15. Stock Based Compensation

Brigham provides an incentive plan 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. At December 31, 2002, Brigham has issued approximately 85,000 incentive awards in excess of the amount currently
authorized by the plan. Brigham will ask stockholders to approve an increase in the total shares available for incentive awards at the next annual meeting in May 2003. The requested increase
will be greater than 85,000 shares. 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.

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

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-29

---

The
following table summarizes activity under the incentive plan for each of the three years ended December 31, 2002:

Shares

Weighted Average
Exercise PriceOptions outstanding December 31, 1999

1,519,726

$
4.47Options granted

793,500


2.83Options forfeited or cancelled

(898,112
)

(5.57
)Options exercised

(8,000
)

(5.11
)Options outstanding December 31, 2000

1,407,114


2.89Options granted

546,500


3.44Options forfeited or cancelled

(239,369
)

(3.48
)Options exercised

(97,474
)

(2.59
)Options outstanding December 31, 2001

1,616,771


3.00Options granted

475,000


4.12Options forfeited or cancelled

(177,129
)

(3.25
)Options exercised

(132,507
)

(2.23
)Options outstanding December 31, 2002

1,782,135

$
3.34


Brigham
is required to use variable accounting for 252,500 of the stock options granted during 2000 of which 217,000 remain outstanding at December 31, 2002. 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.

The
following table summarizes information about stock options outstanding at December 31, 2002:

Options Outstanding

Options ExercisableExercise Price

Number
Outstanding at
December 31,
2002

Weighted-
Average
Remaining
Contractual Life

Weighted-
Average
Exercise Price

Number
Exercisable at
December 31,
2002

Weighted-
Average
Exercise Price$1.55 to $1.83

181,500

4.1 years

$
1.83

105,000

$
1.832.38 to 3.41

869,635

5.0 years


2.48

414,293


2.643.61 to 5.19

719,000

5.7 years


4.07

129,300


3.756.31 to 14.38

12,000

2.8 years


6.98

9,533


7.16$1.55 to $14.38

1,782,135

5.2 years

$
3.34

658,126

$
2.79


F-30

---

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, 2002, 2001 and 2000, Brigham incurred costs of approximately $1.1 million, $0.4 million and
$0.1 million, 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 Executive 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, 2002 and 2001,
Brigham had recorded a liability in accounts payable of approximately $0 and $30,000, respectively, related to services performed by this company.

A
director of Brigham served as a consultant to Brigham on various aspects of its business and strategic issues. Fees paid for these services by Brigham were approximately $45,000,
$44,000 and
$33,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Additional disbursements totaling approximately $12,000, $6,000 and $12,000 were made during 2002, 2001 and 2000,
respectively, for the reimbursement of certain expenses. At December 31, 2002 and 2001, there were no payables related to these services recorded by Brigham.

At
December 31, 2002 Brigham had short-term accounts receivable of approximately $94,000 from a director of Brigham. These receivables represent the director's share
of costs related to his working interest ownership in the Staubach No. 1, Burkhart #1R and Matthes-Huebner #1 wells that are operated by Brigham. The director obtained his interest in these
wells through an exploration and production company that is not affiliated with Brigham. At December 31, 2002, $23,000 of the balance due was current and the remainder was over ninety days past
due. Open short-term accounts receivable with the director are approximately $15,000 as of March 2003 and are thirty days past due.

On
March 1, 2002, Brigham ended an agreement to sell substantially all of its crude production to a single company, and began utilizing a broader range of purchasers. In
April 2002, Brigham began selling a portion of its oil production to Citation Crude Marketing, Inc. based on an evaluation of terms and capabilities offered by several companies.
Brigham's Executive Vice President and CFO and

F-31

---

board member through July 12, 2002 is the brother of the President of Citation Crude Marketing, Inc., and the son of the President and Chief Executive Officer of Citation Oil &
Gas Corporation. Brigham sold approximately 212,000 barrels of oil with a value of $5.6 million to Citation Crude Marketing, Inc. during 2002.

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 to the drilling company during 2002 and 2001 were $0.4 million and $3.9 million, respectively. At December 31, 2002, Brigham owed the drilling company approximately
$0.4 million. At December 31, 2001 the drilling company was not performing work for Brigham and there were no amounts owed.

From
time to time during 2002, in the normal course of business, Brigham has engaged a service company in which one of Brigham's current directors owns stock and serves on the board of
directors. Total payments to the service company during 2002 were $130,000. At December 31, 2002, Brigham owed the service company approximately $76,000. For the year ended December 31,
2001, the service company was not a related party.

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. In November and December of 2002, Brigham and Carrizo entered into agreements that increased Brigham's
interest in some of the leasehold within the South Texas prospect. One of Brigham's current directors was a co-founder of Carrizo and is currently chairman of Carrizo's board of
directors. At December 31, 2002 and 2001, Brigham was owed $413,000 and $158,000, respectively, by Carrizo for exploration and production activities. Brigham owed Carrizo $11,000 and $13,000 at
December 31, 2002 and 2001, respectively.

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 was a director of Brigham and a member of the Compensation Committee for a portion of 2002 and all of 2001. Total amounts paid to Aspect during
2002 and 2001 for exploration, development and production operations were $189,000 and $588,000, respectively. Total amounts paid to Brigham by Aspect, or on their behalf, during 2002 and 2001 for
exploration, development and production operations were $1,008,000 and $524,000, respectively. Brigham owed Aspect $0 and $174,000 at December 31, 2002 and 2001, respectively, for various
exploration and production activities. Aspect owed Brigham $312,000 and $291,000 at December 31, 2002 and 2001, respectively, for various oil and gas exploration and production activities.
Brigham was also owed $2,800 and $20,000 by Aspect Management Corp., an affiliate of Aspect, at December 31, 2002 and 2001, respectively, for joint venture operations.

F-32

---

17. Supplemental Cash Flow Information

Year Ended December 31,2002

2001

2000Cash paid for interest

$
3,974

$
4,257

$
3,894Noncash investing and financing activities:Increase in current liabilities for deferred loan fees to be paid in future





200


Increase in deferred loan fees for issuance of warrants








2,400Dividends and accretion on mandatorily redeemable preferred stock


2,952


2,450


275Conversion of senior credit facility to common stock


10,000








18. Other Assets and Liabilities

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

December 31,2002

2001Gas imbalance receivables

$
3,656

$
1,537Deposits


1,909


Other


1,078


873$
6,643

$
2,410


Deposits
are amounts held by Brigham's derivative counterparty.

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

December 31,2002

2001Gas imbalance liabilities

$
5,650

$
2,717Derivative liabilities


3,168


384Other


1,516


1,414$
10,334

$
4,515


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.

F-33

---

Costs Incurred and Capitalized Costs

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

December 31,2002

2001

2000Costs incurred for the year:Exploration

$
12,693

$
18,210

$
14,238Property acquisition


3,213


3,437


2,540Development


13,301


14,353


12,555Proceeds from participants


(703
)

(135
)

(40
)$
28,504

$
35,865

$
29,293


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.

Following
is a summary of capitalized costs (in thousands) excluded from depletion at December 31, 2002 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.

December 31,Prior
Years2002

2001

2000

TotalProperty acquisition

$
682

$
565

$
195

$
11,990

$
13,432Exploration


1,406


418


77


19,838


21,739Capitalized interest


516


405


15


1,296


2,232Total

$
2,604

$
1,388

$
287

$
33,124

$
37,403


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 engineers.

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

F-34

---

will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. A substantial portion of the reserve balances was
estimated utilizing the volumetric method, as opposed to the production performance method.

Natural
Gas
(MMcf)

Oil
(MBbls)Proved reserves at December 31, 1999

65,457

3,027Revisions of previous estimates

83

(554
)Extensions, discoveries and other additions

17,058

758Production

(4,431
)
(361
)Proved reserves at December 31, 2000

78,167

2,870Revisions of previous estimates

(1,959
)
351Extensions, discoveries and other additions

22,554

1,101Sales of minerals-in-place

(3,402
)
(106
)Production

(6,766
)
(468
)Proved reserves at December 31, 2001

88,594

3,748Revisions of previous estimates

(824
)
(31
)Extensions, discoveries and other additions

18,005

599Sales of minerals-in-place

(556
)
(8
)Production

(5,791
)
(701
)Proved reserves at December 31, 2002

99,428

3,607Proved developed reserves at December 31:2000

39,271

1,8022001

38,633

2,6092002

42,161

2,330


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-35

---

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

December 31,2002

2001

2000Future cash inflows

$
601,081

$
301,201

$
899,819Future development and production costs


(131,357
)

(84,413
)

(154,295
)Future income tax expense


(104,724
)

(34,062
)

(216,342
)Future net cash inflows


365,000


182,726


529,18210% annual discount for estimated timing of cash flows


(125,302
)

(61,802
)

(169,954
)Standardized measure of discounted future net cash flows

$
239,698

$
120,924

$
359,228


The
base sales prices for Brigham's reserves were $4.74 per Mcf for natural gas and $31.25 per Bbl for oil as of December 31, 2002, $2.57 per Mcf for natural gas and $19.84 per
Bbl for oil as of December 31, 2001, and $10.42 per Mcf for natural gas and $26.83 per Bbl for oil as of December 31, 2000. These base prices were adjusted to reflect applicable
transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate Brigham's reserves at these dates.

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

December 31,2002

2001

2000Beginning of period

$
120,924

$
359,228

$
113,546Sales of oil and natural gas produced, net of production costs


(31,475
)

(27,296
)

(15,218
)Development costs incurred


8,625


8,310


5,308Extensions and discoveries


60,872


41,278


295,239Sales of minerals-in-place


(1,064
)

(22,476
)

Net change of prices and production costs


136,808


(322,047
)

175,018Change in future development costs


(8,000
)

(15,956
)

6,990Changes in production rates and other


(17,003
)

(29,545
)

(83,322
)Revisions of quantity estimates


(2,876
)

(22,676
)

(12,262
)Accretion of discount


14,681


49,766


11,447Change in income taxes


(41,794
)

102,338


(137,518
)End of period

$
239,698

$
120,924

$
359,228


F-36

---

21. Quarterly Financial Data (Unaudited)

|                             |         | Year Ended December 31, 2002 |       
|---------------------------- | ------- | ---------------------------- | ------
|
|Revenue                      |         | $                            | 6,444 
|Operating income             |         |                              | 1,016 
|Net income (loss)            |         |                              | (1,332
|Net income (loss) per share: |         |                              |       
|                             | Basic   |                              | $     
|                             | Diluted |                              | $     

|                             |          | Year Ended December 31, 2001 |      
|---------------------------- | -------- | ---------------------------- | -----
|
|Revenue                      |          | $                            | 7,043
|Operating income (loss)      |          |                              | 2,425
|Net income (loss)            |          |                              | 424  
|Net income (loss) per share: |          |                              |      
|                             | Basic    |                              | $    
|                             | Diluted* |                              | $    

---

F-37

---

INDEX TO EXHIBITS

|Number |  |   |  | Description                                                                                                                                                                                                                                                                                                                                                
|------ |  | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1    |  |  |  | Certificate of Incorporation (filed as Exhibit 3.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                    
|3.2    |  |  |  | Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to Brigham's Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated herein by
reference).                                                                                                                                                     
|3.3    |  |  |  | Bylaws (filed as Exhibit 3.2 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                                          
|4.1    |  |  |  | Form of Common Stock Certificate (filed as Exhibit 4.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                
|4.2    |  |  |  | Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brigham's Current Report on Form 8-K,
as amended (filed November 8, 2000), and incorporated herein by reference).                                                                        
|4.3    |  |  |  | Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to Brigham's Annual
Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).                     
|4.4 +  |  |  |  | Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed December 20, 2002.                                                                                                                                                                                                                 
|10.1   |  |  |  | Amended and Restated Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated December 30, 1997 by and among Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings II,
 L.L.C. (filed as Exhibit 10.1.4 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference)             
|10.2*  |  |  |  | Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit 10.4 to Brigham's Registration Statement on Form S-1 (Registration
No. 33-53873), and incorporated herein by reference).                                                                                                            
|10.3*  |  |  |  | Letter agreement, dated as of March 20, 2000, setting forth amendments effective January 1, 2000, to the Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and
Harold D. Carter (filed as Exhibit 10.5.1 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference).
|10.4*  |  |  |  | Employment Agreement, by and between Brigham Exploration Company and Ben M. Brigham (filed as Exhibit 10.7 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated
herein by reference).                                                                                                                            
|10.5*  |  |  |  | Form of Confidentiality and Noncompete Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.8 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491),
 and incorporated herein by reference).                                                                                                    
|10.6*  |  |  |  | 1997 Incentive Plan of Brigham Exploration Company as amended through March 6, 2001 (filed as an amendment to Brigham's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001, and incorporated
herein by reference).                                                                                                                          
|10.7*  |  |  |  | Form of Option Agreement for certain executive officers (filed as Exhibit 10.9.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by
reference).                                                                                                                                                      
|10.8*  |  |  |  | Form of Restricted Stock Agreement for certain executive officers dated as of October 27, 2000 (filed as Exhibit 10.8.2 to Brigham's Annual Report on Form 10-K for the year ended December 31, 2000
(filed March 23, 2001), and incorporated herein by reference).                                                                                        

---

|10.9* |  |  |  | Incentive Bonus Plan dated as of February 28, 1997 of Brigham, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.10 to Brigham's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                                                                                      
|----- |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.10 |  |  |  | Two Bridgepoint Lease Agreement, dated September 30, 1996, by and between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to Brigham's
Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                              
|10.11 |  |  |  | First Amendment to Two Bridge Point Lease Agreement dated April 11, 1997 between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.1 to Brigham's
Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference).                                                                                                                                                                                      
|10.12 |  |  |  | Second Amendment to Two Bridge Point Lease Agreement dated October 13, 1997 between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.2 to
Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference).                                                                                                                                                                                   
|10.13 |  |  |  | Letter dated April 17, 1998 exercising Right of First Refusal to Lease "3rd Option Space" (filed as Exhibit 10.9.3 to Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and
incorporated herein by reference).                                                                                                                                                                                                                                                           
|10.14 |  |  |  | Agreement and Assignment of Interest, West Bradley Project, dated September 1, 1995, by and between Aspect Resources Limited Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.21 to
Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                           
|10.15 |  |  |  | Agreement and Assignment of Interests in lands located in Grady County, Oklahoma, West Bradley Project, dated December 1, 1995, by and between Aspect Resources Limited Liability Company, Brigham Oil & Gas,
 L.P. and Venture Acquisitions, L.P. (filed as Exhibit 10.22 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                   
|10.16 |  |  |  | Agreement and Assignment of Interests, West Bradley Project, dated December 1, 1995, by and between Aspect Resources Limited Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.23 to
Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                           
|10.17 |  |  |  | Form of Indemnity Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.28 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated
herein by reference).                                                                                                                                                                                                                                                                
|10.18 |  |  |  | Registration Rights Agreement dated February 26, 1997 by and among Brigham Exploration Company, General Atlantic Partners III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II, RIMCO Partners
L.P. III, and RIMCO Partners, L.P. IV, Ben M. Brigham, Anne L. Brigham, Harold D. Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.29 to Brigham's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein by reference).
|10.19 |  |  |  | 1997 Director Stock Option Plan (filed as Exhibit 10.30 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                                                                                                                                                      
|10.20 |  |  |  | Form of Employee Stock Ownership Agreement (filed as Exhibit 10.31 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                                                                                                                                                                           
|10.21 |  |  |  | Agreement and Assignment of Interest in Geophysical Exploration Agreement, Esperson Dome Project, dated November 1, 1994, by and between Brigham Oil & Gas, L.P. and Vaquero Gas Company (filed as
Exhibit 10.33 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                                                                                                                             

---

|10.22 |  |  |  | Proposed Trade Structure, RIMCO/Tigre Project, Vermillion Parish, Louisiana, among Brigham Oil & Gas, L.P., Tigre Energy Corporation and Resource Investors Management Company (filed as Exhibit 10.36 to
Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                     
|----- |  | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.23 |  |  |  | Letter relating to Proposed Trade Structure, RIMCO/Tigre Project, dated January 31, 1997, from Resource Investors Management Company to Brigham Oil & Gas, L.P. (filed as Exhibit 10.36 to Brigham's
Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).                                                    
|10.24 |  |  |  | Agreement dated March 6, 2000 by and between RIMCO Production Co., Tigre Energy Corporation and Brigham Oil & Gas, L.P. regarding modifications to the Proposed Trade Structure, RIMCO/Tigre Project,
dated January 31, 1997.                                                                                                                                   
|10.25 |  |  |  | Form Change of Control Agreement dated as of September 20, 1999 between Brigham Exploration Company and certain Officers (filed as Exhibit 10.3 to Brigham's Quarterly Report on Form 10-Q for the fiscal
quarter ended September 30, 1999 and incorporated by reference herein).                                                                               
|10.26 |  |  |  | Warrant Agreement for the Purchase of Common Stock dated as of July 19, 1999 by and between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.4 to Brigham's Quarterly Report on Form 10-Q
for the fiscal quarter ended September 30, 1999 and incorporated by reference herein).                                                           
|10.27 |  |  |  | Warrant Agreement for the Purchase of Common Stock dated as of July 19, 1999 by and between Brigham Exploration Company and Societe Generale, Southwest Agency (filed as Exhibit 10.5 to Brigham's Quarterly Report
on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein).                                         
|10.28 |  |  |  | First Amendment to Warrant Agreement dated as of February 17, 2000 between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.4 to Brigham's Current Report on Form 8-K filed
February 29, 2000 and incorporated herein by reference).                                                                                                       
|10.29 |  |  |  | First Amendment to Warrant Agreement dated as of February 17, 2000 between Brigham Exploration Company and Societe Generale, Southwest Agency (filed as Exhibit 10.5 to Brigham's Current Report on Form 8-K
filed February 29, 2000 and incorporated herein by reference).                                                                                     
|10.30 |  |  |  | Joint Development Agreement, dated as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. (filed as Exhibit 10.65 to Brigham's Annual Report on
Form 10-K for the year ended December 31, 1999, and incorporated herein by reference).                                                                                       
|10.31 |  |  |  | First Amendment, dated as of May 10, 1999, to that certain Joint Development Agreement entered into effective as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect
Resources LLC. (filed as Exhibit 10.65.1 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference).          
|10.32 |  |  |  | Acquisition and Participation Agreement, dated October 21, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. (filed as Exhibit 10.65.2 to Brigham's Annual Report on
Form 10-K for the year ended December 31, 1999, and incorporated herein by reference).                                                                                
|10.33 |  |  |  | Letter agreement, dated as of December 30, 1999, regarding amendments to Joint Development Agreement, dated as of February 10, 1999, as amended, by and between Brigham Oil & Gas, L.P. and Aspect
Resources LLC. (filed as Exhibit 10.65.3 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference).
|10.34 |  |  |  | Letter agreement dated as of September 6, 1999 between Brigham Oil & Gas, L.P. and Brigham Land Management Company, Inc. regarding work to be performed within Brigham's Angelton Project. (filed as
Exhibit 10.66 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference).                         

---

|10.35 |  |  |  | Securities Purchase Agreement dated as of November 1, 2000 between Brigham Exploration Company, DLJ MB Funding III, Inc., and DLJ ESC II, LP., (filed as Exhibit 10.9 to Brigham's Current
Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference).                                                                                                                                                 
|----- |  | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.36 |  |  |  | Registration Rights Agreement dated November 1, 2000 by and between Brigham Exploration Company, DLJ MB Funding III, Inc., and DLJ ESC II, LP. (filed as Exhibit 10.10 to Brigham's
Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference).                                                                                                                                                
|10.37 |  |  |  | Warrant Certificate dated as of November 1, 2000 by and between Brigham Exploration Company and DLJ MB Funding III, Inc. (filed as Exhibit 10.11 to Brigham's Current Report on Form 8-K, as
amended (filed November 8, 2000), and incorporated herein by reference).                                                                                                                                                                      
|10.38 |  |  |  | Warrant Certificate dated as of November 1, 2000 by and between Brigham Exploration Company and DLJ ESC II, LP. (filed as Exhibit 10.12 to Brigham's Current Report on Form 8-K, as amended (filed
November 8, 2000), and incorporated herein by reference).                                                                                                                                                                               
|10.39 |  |  |  | Stockholders Voting Agreement dated as of October 31, 2000 by and among Brigham Exploration Company, DLJ ESC II, L.P., DLJ MB Funding III, Inc., and certain shareholders of Brigham
Exploration Company (filed as Exhibit 10.13 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference).                                                                                      
|10.40 |  |  |  | Securities Purchase Agreement dated as of March 5, 2001 among Brigham Exploration Company, DLJ MB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP and
DLJ Offshore Partners III, CV (filed as Exhibit 10.70 to Brigham's Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).                                                           
|10.41 |  |  |  | First Amendment to Registration Rights Agreement, dated March 5, 2001, by and among Brigham Exploration Company, DLJMB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC
II, LP and DLJ Offshore Partners III, CV (filed as Exhibit 10.71 to Brigham's Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by
reference).                                      
|10.42 |  |  |  | Warrant Certificate dated as of March 5, 2001 by and between Brigham Exploration Company and DLJMB Funding III, Inc. (filed as Exhibit 10.72 to Brigham's Annual Report on Form 10-K for the year
ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).                                                                                                                                                   
|10.43 |  |  |  | Warrant Certificate dated as of March 5, 2001 by and between Brigham Exploration Company and DLJ ESC II, LP. (filed as Exhibit 10.73 to Brigham's Annual Report on Form 10-K for the year ended
December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).                                                                                                                                                           
|10.44 |  |  |  | Warrant Certificate dated as of March 5, 2001 by and between Brigham Exploration Company and DLJ Merchant Banking Partners III, LP. (filed as Exhibit 10.74 to Brigham's Annual Report on Form 10-K
for the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).                                                                                                                                    
|10.45 |  |  |  | Warrant Certificate dated as of March 5, 2001 by and between Brigham Exploration Company and DLJ Offshore Partners III, CV(filed as Exhibit 10.75 to Brigham's Annual Report on Form 10-K for
the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).                                                                                                                                              
|10.46 |  |  |  | Stockholders Voting Agreement dated as of March 5, 2001 by and among Brigham Exploration Company, DLJMB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP,
DLJ Offshore Partners III, CV and certain shareholders of Brigham Exploration Company (filed as Exhibit 10.76 to Brigham's Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and
incorporated herein by reference).

---

|10.47 + |  |  |  | Exchange Agreement, dated November 21, 2002 between Brigham Exploration Company, Brigham Oil & Gas, L.P. and Shell Capital Inc.                                                                                                                                                                                                         
|------- |  | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.48 + |  |  |  | Omnibus Agreement, dated November 21, 2002 between Brigham Exploration Company, Brigham Oil & Gas, L.P. and certain Credit Suisse First Boston entities.                                                                                                                                                                                
|10.49 + |  |  |  | Securities Purchase Agreement dated December 20, 2002 between Brigham Exploration Company and certain Credit Suisse First Boston Entities.                                                                                                                                                                                              
|10.50 + |  |  |  | Registration Rights Agreement dated December 20, 2002 between Brigham Exploration Company and Shell Capital Inc.                                                                                                                                                                                                                        
|10.51 + |  |  |  | Second Amendment to Registration Rights Agreement dated December 21, 2002 between Brigham Exploration Company and Credit Suisse First Boston Entities.                                                                                                                                                                                  
|10.52 + |  |  |  | Stockholders Voting Agreement, dated December 20, 2002 between Brigham Exploration Company, certain Credit Suisse First Boston entities, Ben M. and Anne L. Brigham, Harold D. Carter, General Atlantic
Partners, III, L.P., GAP-Brigham Partners, L.P. GAP Co Investment Partners II, L.P., Aspect Resources, LLC and certain officers.
|10.53 + |  |  |  | Second Amended and Restated Credit Agreement, dated March 21, 2003 between Brigham Oil & Gas, L.P., Société Générale, Societe Generale, The Royal Bank of Scotland plc
and Bank of America, N.A.                                                                                                                                        
|10.54 + |  |  |  | Amended and Restated Subordinated Credit Agreement, dated March 21, 2003 between Brigham Oil & Gas, L.P., and The Royal Bank of Scotland plc.                                                                                                                                                                                           
|21 +    |  |  |  | Subsidiaries of the Registrant.                                                                                                                                                                                                                                                                                                         
|23.1 +  |  |  |  | Consent of PricewaterhouseCoopers LLP, independent public accountants.                                                                                                                                                                                                                                                                  
|99.1 +  |  |  |  | Section 906 Certification by Ben M. Brigham                                                                                                                                                                                                                                                                                             
|99.2 +  |  |  |  | Section 906 Certification by Eugene B. Shepherd                                                                                                                                                                                                                                                                                         

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