<Page> - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 -------------------------- FORM 10-K --------------- <Table> (MARK ONE) /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER: 000-22433 </Table> BRIGHAM EXPLORATION COMPANY (Exact name of Registrant as Specified in its Charter) <Table> DELAWARE 75-2692967 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 6300 BRIDGE POINT PARKWAY BUILDING 2, SUITE 500 AUSTIN, TEXAS 78730 (Address of principal executive offices) (Zip Code) (512) 427-3300 (Registrant's telephone number, including area code) </Table> -------------------------- Securities registered pursuant to Section 12(b) of the Act: <Table> <Caption> NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS WHICH REGISTERED - --------------------------------------- --------------------------------------- None None </Table> Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, $.01 PAR VALUE (Title of Class) Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ No / / Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. / / As of March 22, 2002, the Registrant had 16,016,113 shares of common stock outstanding. The aggregate market value of the common stock held by non-affiliates of the Registrant, based upon the closing sale price of the common stock on March 22, 2002, as reported on The Nasdaq Stock Market(SM), was $25.3 million. For purposes of determination of the foregoing amount, only directors, executive officers and 10% or greater stockholders have been deemed affiliates. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 2002 Annual Meeting of Stockholders to be held on May 17, 2002, are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2001. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- <Page> TABLE OF CONTENTS <Table> <Caption> PAGE -------- PART I ITEM 1. BUSINESS.................................................... 1 ITEM 2. PROPERTIES.................................................. 11 ITEM 3. LEGAL PROCEEDINGS........................................... 24 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS.......... 24 EXECUTIVE OFFICERS OF THE REGISTRANT.................................. 25 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS....................................... 27 ITEM 6. SELECTED FINANCIAL DATA..................................... 28 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................. 29 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...................................................... 54 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 54 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.................................. 54 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 55 ITEM 11. EXECUTIVE COMPENSATION...................................... 55 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT................................................ 55 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS........ 55 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.................................................. 56 GLOSSARY OF OIL AND GAS TERMS......................................... 57 SIGNATURES............................................................ 59 INDEX TO FINANCIAL STATEMENTS......................................... F-1 </Table> i <Page> BRIGHAM EXPLORATION COMPANY 2001 ANNUAL REPORT ON FORM 10-K ITEM 1. BUSINESS OVERVIEW Brigham Exploration Company ("Brigham" or the "Company") is an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore and develop onshore oil and natural gas provinces in the United States. Brigham focuses its activity in provinces where it believes 3-D seismic technology may be effectively applied to discover relatively large potential reserve volumes (on both a per well and per field basis) with high potential production rates and multiple producing objectives. Brigham's exploration activities are concentrated primarily in three core provinces: - the Anadarko Basin of western Oklahoma and the Texas Panhandle; - the onshore Texas Gulf Coast; and - West Texas. Brigham pioneered the acquisition of large-scale onshore 3-D seismic surveys for exploration, obtaining extensive 3-D seismic data and experience in capturing undiscovered oil and natural gas reserves. As of December 31, 2001, Brigham had accumulated approximately 6,633 square miles (4.2 million acres) of 3-D seismic data and had drilled 530 wells in its 3-D project areas. Brigham generates most of its exploratory projects and as a result, can retain a sizeable working interest in these projects. Since its inception in 1990 through 2001, Brigham has drilled 420 exploratory and 110 development wells on its 3-D generated prospects with an aggregate completion rate of 67% and an average working interest of 30%. Also during this period, Brigham has added an estimated 191 Bcfe (including revisions to previous estimates) of net proved reserves, 168 Bcfe of which were discovered by Brigham through its systematic 3-D exploration drilling activities at an average drilling finding cost of $0.79 per Mcfe. Since 1999, Brigham has focused the majority of its capital expenditures on drilling its 3-D delineated prospect inventory. Drilling activity has been concentrated in the five focus plays where the Company believes it benefits from a superior knowledge base and an optimal seismic and leasehold position. For the three-year period ended December 31, 2001, the Company's average drilling finding cost was $0.74 per Mcfe and its average all-sources finding cost was $1.00 per Mcfe. During this same three-year period, Brigham's equivalent production volumes have grown by 44% to average 26.6 MMcfe per day in 2001 and EBITDA (net income (loss) plus interest expense, depletion, depreciation and amortization expenses, deferred income tax and other non-cash items) has grown 244% to $22.7 million in 2001. Brigham's estimated net proved reserves as of December 31, 2001 were 111 Bcfe with a present value of future net revenues of $147 million, compared to estimated net proved reserves as of December 31, 1996 of 22 Bcfe with a present value of future net revenues of $45 million. Brigham's net proved reserve volumes as of December 31, 2001 were 80% natural gas and 49% proved developed. BUSINESS STRATEGY Brigham's principal objective and business strategy is to achieve superior growth in shareholder value through the application of its systematic exploration approach, which emphasizes the integrated 1 <Page> use of 3-D seismic imaging and other advanced technologies to reduce drilling risks and finding costs. Key elements of Brigham's long-term growth strategy include: - delineate the geologic plays that provide higher potential reserve impact and superior 3-D driven drilling economics; - acquire large scale 3-D seismic surveys in such geologic plays to expand the Company's competitive knowledge base and to identify and capture high quality potential drilling locations; - retain significant working interests to capture a greater share of the reserve potential; - leverage capital investments by selling promoted working interests in selected prospects and projects; - generate high rates of growth in reserves, production volumes and cash flow; and - efficiently grow net asset value per share. Brigham's corporate history can be described in three distinct phases: From 1990 to 1996, Brigham acquired approximately 2,760 square miles of 3-D seismic in over 28 different geologic plays, seven basins and seven states with an average working interest of approximately 28%. During this period, to reduce its capital exposure, Brigham typically retained carried interests in its 3-D projects by selling promoted working interest to industry participants. Brigham also identified geologic objectives and trends that it believed would provide optimal 3-D drilling economics. In 1997, Brigham completed its initial public offering and accelerated its acquisition of 3-D seismic data in the plays that it believed were most likely to provide attractive 3-D delineated drilling economics. Brigham acquired an additional 2,475 square miles of 3-D seismic data and retained substantially higher working interests (averaging approximately 73%) in its newly acquired projects and prospects. These acquisitions were the largest in Brigham's history and nearly doubled its inventory of onshore 3-D seismic data, as compared to year-end 1996, to approximately 5,235 square miles. With these significant investments, Brigham believes it has assembled a superior knowledge base and the premier seismic and leasehold position in each of its current focus plays. Brigham further believes it has captured a high quality, multi-year inventory of 3-D delineated potential drilling locations and the quality and depth of this inventory is evidenced by its recent drilling results. Starting in 1999, the Company entered the third phase of its corporate history by focusing the majority of its capital on the drilling of its inventory of potential drilling locations to grow reserves, production volumes and cash flow. For the three-year period ended December 31, 2001, Brigham achieved a net completion rate of 81%, an average all-sources finding cost of $1.00 per Mcfe and an average drilling finding cost of $0.74 per Mcfe. Drilling in this inventory has generated several field discoveries, including the Home Run Field in 1999, the Mills Ranch Field in 2000, and the Triple Crown Field and the Providence Field in 2001. Also during this period, Brigham has focused on improving its cash flow margin and its return on invested capital by controlling costs while growing production volumes and revenue. From 1998 to 2001, Brigham reduced its discretionary unit operating costs (general and administrative expense plus lease operating expense) from $1.03 per Mcfe to $0.74 per Mcfe. This lower cost structure, combined with higher oil and gas revenue per unit of equivalent production, resulted in an increase in gross profit per unit of equivalent production from $0.98 per Mcfe in 1998 to $2.50 per Mcfe in 2001. Furthermore, Brigham's reduced debt levels have led to a decline in net interest expense (net of interest income) on a per unit of equivalent production basis, from $1.52 per Mcfe in 1999 and $1.48 per Mcfe in 2000 to $0.67 per Mcfe in 2001. As a result, unit cash flow improved from ($0.15) per Mcfe in 1999 and $0.37 per Mcfe in 2000 to $1.83 per Mcfe in 2001, and cash flow margins improved from (6%) in 1999 2 <Page> and 13% in 2000 to 54% in 2001. Brigham believes that by focusing its capital on its large prospect inventory, while controlling its costs, the inherent value of its prospect inventory will become apparent through its operating and financial results. In 2001, relative to 2000, Brigham grew its oil and natural gas reserves by 17%, its equivalent production volumes by 45%, and its operating cash flow before changes in working capital by 111%. In 2002, Brigham's strategy is composed of the following key elements: - focus the majority of its resources on the drilling of its established 3-D delineated project inventory in its five focus plays, targeting primarily natural gas prospects in established producing trends; - development of the Home Run Field, Mills Ranch Field, Triple Crown Field and Providence Field discoveries; - continue its active and high potential exploration program; - leverage its prior investments in 3-D seismic and land by selectively selling interests in prospects and projects to mitigate risk and enhance its corporate rate of return; and - continue to focus upon improving its cash flow margin and return on invested capital by controlling costs while growing reserves, production volumes and cash flow. FOCUS ON DRILLING During the first six years of its history, Brigham acquired 3-D seismic in over 28 different geologic plays, seven basins and seven states. The Company also identified geologic objectives and trends that it believed would provide optimal 3-D drilling economics. During the second phase of Brigham's corporate history, from 1997 to 1998, the Company accumulated a multi-year inventory of 3-D delineated exploration drilling locations in the plays that it believed were most likely to provide attractive 3-D delineated drilling economics. Beginning in 1999, Brigham began to focus the majority of its resources toward drilling activities within its five focus plays to generate growth in proved reserves, production volumes and cash flow. Since 1999, the Company has achieved a net completion rate of 81%, an average all-sources finding cost of $1.00 per Mcfe, an average drilling finding cost of $0.74 per Mcfe and has discovered four potentially substantial fields. For 2002, approximately 80% of Brigham's exploration and development budget of $17.9 million has been allocated to drilling expenditures in its three core provinces, over 90% of which is dedicated to drilling in its five focus plays. DEVELOP HOME RUN, MILLS RANCH, TRIPLE CROWN AND PROVIDENCE FIELD DISCOVERIES From 1990 to 1999, a majority of Brigham's drilling expenditures were directed toward exploration-oriented projects. Due to the success of Brigham's past exploration drilling programs and the discovery of the Home Run Field and Mills Ranch Field, over 50% of the Company's drilling expenditures in 2001 were developmental. Capitalizing on the discovery of the Triple Crown Field and Providence Field in 2001, approximately 80% of Brigham's 2002 drilling expenditures have been allocated to development drilling. Given that Brigham is early in the development of these fields, the Company anticipates an ongoing, multi-year drilling program to fully develop these fields. CONTINUE AN ACTIVE EXPLORATION PROGRAM Beginning in 1999, Brigham began to focus its drilling investments in the five focus plays it believed would provide excellent 3-D delineated drilling economics. These plays include the Vicksburg 3 <Page> and Frio trends in the onshore Texas Gulf Coast, the Springer and Hunton trends in the Anadarko Basin and the Horseshoe Atoll trend of West Texas. In these trends Brigham has completed 25 wells in its 28 most recent attempts and in the process discovered the Home Run Field in 1999, the Mills Ranch Field in 2000, and the Triple Crown Field and the Providence Field in 2001. Approximately 20% of Brigham's 2002 budgeted drilling capital expenditures will be dedicated to exploration. In 2001, to supplement its exploration drilling prospect inventory, Brigham exchanged licensing rights in certain non-core 3-D data volumes for licenses in additional 3-D seismic data programs located within its focus trends. For 2002, Brigham expects to continue looking for opportunities to acquire additional 3-D seismic data within its focus trends with very little capital investment. LEVERAGE PRIOR INVESTMENTS TO MITIGATE RISK AND ENHANCE CORPORATE RATE OF RETURN In addition to supporting a multi-year drilling program, Brigham believes that its substantial investments in 3-D seismic data and undeveloped acreage provide a significant advantage in attracting participants to invest in its projects. Often times, Brigham can recoup a portion of its initial capital investment on a promoted basis. Historically, Brigham has been effective at raising capital and attaining promoted working interests in its 3-D seismic projects and prospects, thereby utilizing leverage extensively to manage its risk and enhance its corporate rate of return. Given the depth of Brigham's land and 3-D seismic inventory, and in particular the Company's inventory of 3-D delineated drilling prospects, Brigham plans to again leverage its investments in 2002. MAXIMIZE RETURN ON INVESTED CAPITAL AND OPERATING MARGINS Brigham seeks to maximize its return on invested capital by achieving low finding and development costs and by reducing and controlling its per unit operating costs. From inception through 1998, Brigham's average drilling finding cost was $0.82 per Mcfe. Since 1999, Brigham has achieved improved returns on its drilling investments with an average drilling finding cost of $0.74 per Mcfe. Additionally, Brigham's average all-sources finding cost from 1999-2001 was $1.00 per Mcfe, a substantial improvement from its average all-sources finding cost of $1.59 per Mcfe from inception through 1998. Brigham believes these improvements are due to the following: - Brigham's considerable prior investments in 3-D seismic and land, principally during 1997 and 1998; - significantly lower non-drilling capital expenditures in 1999, 2000 and 2001; - improved drilling returns achieved during 1999, 2000 and 2001; and - sales of interests in certain 3-D seismic projects and prospects in 1999 and 2000 that provided reimbursements of previously incurred expenditures. Brigham expects this convergence of its all-sources finding cost and its drilling finding cost to continue in 2002. Brigham will continue to capitalize on its extensive inventory of 3-D delineated drilling prospects by allocating the majority of its capital expenditures to drilling within its existing 3-D seismic project areas. Brigham's low per unit lease operating expenses over the past few years can be attributed to the relatively new nature of many of its producing wells, its focused operations in three core provinces and the operation of a greater percentage of the wells that it drills. Brigham intends to continue to maintain low operating expenses per unit by monitoring and controlling production efficiency from its existing producing wells, adding new producing wells that typically cost less to operate than more mature wells and by seeking to achieve operating cost efficiencies through increased economies of scale resulting from a greater concentration of producing assets within its core project areas. 4 <Page> 3-D SEISMIC TECHNOLOGY Brigham's strategy is to use 3-D seismic and other advanced technologies, including computer-aided exploration ("CAEX"), to systematically explore and develop domestic onshore oil and natural gas provinces. In general, 3-D seismic is the process of acquiring seismic data along multiple lines and grids. The primary advantage of 3-D seismic over 2-D seismic is that it provides information with respect to multiple horizontal and vertical points within a geologic formation instead of information on a single vertical line or multiple vertical lines within the formation. Acquiring larger amounts of data relating to a geologic formation allows a user to better correlate the data and, in some cases, to obtain a greater understanding and image of the formation. Although it is impossible to predict with certainty the specific configuration or composition of any underground geologic formation, the use of 3-D seismic data provides clearer and more accurate projected images of complex geologic formations, which can assist a user in evaluating whether to drill for oil and natural gas reserves. If a decision to drill is made, 3-D seismic data can also help in determining the optimal location to drill. CAEX is the process of accumulating and analyzing the various seismic, production and other data obtained relating to a geographic area. In general, CAEX involves accumulating various 2-D and 3-D seismic data with respect to a potential drilling location, correlating that data with historical well control and production data from similar properties and analyzing the available data through computer programs and modeling techniques to project the likely geologic composition of a potential drilling location and potential locations of undiscovered oil and natural gas reserves. This process relies on a comparison of data with respect to the potential drilling location and historical data with respect to the density and sonic characteristics of different types of rock formations, hydrocarbons and other subsurface minerals, resulting in a projected three dimensional image of the subsurface. This modeling is performed through the use of advanced interactive computer workstations and various combinations of available computer programs that have been developed solely for this application. EXPLORATION AND OPERATING APPROACH Brigham has acquired 3-D seismic data covering approximately 6,633 square miles (4.2 million acres) in over 28 geologic plays in seven basins and seven states. Through this activity, Brigham has developed expertise in the selection of geologic trends that are best suited for 3-D seismic exploration. Brigham uses experience that it gains within a trend to enhance the quality of subsequent projects in the same trend and other analogous trends, to lower finding and development costs, to compress project cycle times and to increase its project rate of return. Brigham typically acquires 3-D seismic data in and around existing producing fields where it can benefit from the imaging of producing analogs. These 3-D defined analogs, combined with Brigham's experience in drilling over 500 wells in its 3-D project areas, provide Brigham with a knowledge base to evaluate other potential geologic trends, 3-D seismic projects within trends and prospective 3-D delineated drilling locations. Brigham's knowledge base assists in identifying geologic trends where Brigham believes it can find and develop economic volumes of oil and natural gas. Brigham has experience exploring with 3-D seismic in a wide range of reservoir types and geologic trapping styles, both stratigraphic and structural (including reefs, salt domes, channel sands, complex faulted and fractured reservoirs and pinchout plays). Occasionally, Brigham seeks to supplement its knowledge base with the best local geologic expertise available for a particular geologic trend. In addition, Brigham typically acquires digital data bases for integration on its CAEX workstations, including digital land grids, well information, log curves, production information, geologic studies, geologic top data bases and existing 2-D seismic data. Brigham uses its knowledge base, local geological expertise and digital data bases integrated with 3-D seismic data to create maps of producing and potentially productive reservoirs. As such, Brigham believes its 3-D generated maps are more accurate than previous reservoir maps (which generally were 5 <Page> based on subsurface geological information and 2-D seismic surveys), enabling it to more precisely evaluate recoverable reserves and the economic feasibility of projects and drilling locations. Brigham has acquired most of its raw 3-D seismic data using seismic acquisition vendors on either a proprietary basis or through alliances affording the alliance members the exclusive right to interpret and use data for extended periods of time. In addition, Brigham has participated in non-proprietary group shoots of 3-D seismic data (commonly referred to as "spec data") when it believes the expected full cycle project economics are justified. In most of its proprietary 3-D data acquisitions and alliances, Brigham has selected the sites of projects, primarily guided by its knowledge and experience in the core provinces it explores; established and monitored the seismic parameters of each project for which data was shot; and typically selected the equipment that was used. The acquisition of 3-D seismic data has generally been priced on the basis of the number of square miles shot. Combining its geologic and geophysical expertise with a sophisticated land effort, Brigham manages the majority of its projects from conception through 3-D acquisition, processing and interpretation and leasing. In addition, Brigham manages the negotiation and drafting of most of its geophysical exploration agreements, resulting in reduced contract risk and more consistent deal terms. Because it generates most of its projects, Brigham can often control the size of the working interest that it retains as well as the selection of the operator and the non-operating participants. Consistent with its business strategy, Brigham has increased the working interest it retains in its projects, based upon capital availability and perceived risk. Brigham's average working interest in its 3-D seismic projects acquired during 1996, 1997 and 1998 was 37%, 67% and 80%, respectively. Brigham did not shoot any new 3-D seismic during the three-year period ended December 31, 2001. However, in 2001, Brigham exchanged licensing rights in certain non-core 3-D data volumes for licenses to additional 3-D seismic data programs, many of which were located in Brigham's focus plays in the Texas Gulf Coast. As a result, Brigham added approximately 1,400 square miles of 3-D seismic data in 2001, with very little capital investment. The Company believes that by applying its knowledge base and expertise to this newly acquired 3-D seismic data it should generate additional drilling inventory in its current focus plays, thereby further capitalizing on its recent drilling successes. One of Brigham's 2001 Gulf Coast Frio discoveries was drilled on this recently acquired data. Brigham anticipates that in 2002, it will enter into transactions similar to those entered into in 2001 to acquire additional 3-D seismic data. Brigham's operations personnel (including management) includes six engineers that have drilling, reservoir, environmental and operations engineering experience primarily within Brigham's three core areas of operations. These engineers work closely with Brigham's explorationists and are integrally involved in all phases of the exploration and development process, including preparation of pre- and post-drill reserve estimates, analysis of full cycle risked drilling economics, well design and production management. Brigham conducts field operations for its operated oil and natural gas properties through a Company employed field superintendent and third party contract personnel. In an effort to retain better control of its project timing, drilling and operational costs and production volumes, over the past several years Brigham has significantly increased the percentage of the wells that it operates. Brigham operated 45% of the gross and 67% of the net wells that it participated in during 2001, as compared with 10% and 17%, respectively, of the wells it drilled during 1996. As a result of its increased operational control in recent years, Brigham-operated wells constituted 72% of the PV10% value of its proved developed producing reserves at year-end 2001, as compared with only 8% at year-end 1996. TECHNICAL STAFF Brigham's experienced technical staff (excluding management) includes five geophysicists, seven geologists, five engineers, three computer applications specialists, two geophysical/geological/engineering technicians, three landmen and three lease and division order analysts. Brigham's geophysicists have different but complementary backgrounds, and their diversity of experience in varied geological and geophysical settings, combined with various technical specializations (from hardware and systems to 6 <Page> software and seismic data processing), provide Brigham with valuable technical intellectual resources. Brigham's team of explorationists has over 253 years of exploration experience, or an average of more than 21 years per person, most of which was acquired at Brigham and various major and large independent oil companies. Brigham's team of technical specialists was assembled according to the expertise that these individuals have within producing basins where Brigham focuses its exploration and development activities. By integrating both geologic and geophysical expertise within its project teams, Brigham believes it possesses a competitive advantage in its exploration approach. Occasionally, Brigham will complement and leverage its exploration staff by seeking out alliances or retainer relationships with geologists and other technical professionals who have extensive experience in a particular area of interest. OIL AND NATURAL GAS MARKETING AND MAJOR CUSTOMERS Most of Brigham's oil and natural gas production is sold under price sensitive or spot market contracts. The revenues generated by Brigham's operations are highly dependent upon the prices of and demand for oil and natural gas. The price received by Brigham for its oil and natural gas production depends upon numerous factors beyond Brigham's control, including seasonality, competition, the condition of the United States economy, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries, and domestic government regulation, legislation and policies. Decreases in the prices of oil and natural gas could have an adverse effect on the carrying value of Brigham's proved reserves and its revenues, profitability and cash flow. Although Brigham is not currently experiencing any significant involuntary curtailment of its oil or natural gas production, market, economic and regulatory factors may in the future materially affect Brigham's ability to sell its oil or natural gas production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", "--Risk Factors--Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are Volatile" and "--Risk Factors--The Marketability Of Our Production Is Dependent On Facilities That We Typically Do Not Own Or Control" For the year ended December 31, 2001, sales to Highland Energy Company and Lantern Petroleum Corporation represented approximately 60% of Brigham's oil revenue and 58% of its natural gas revenue. On March 1, 2002 the Company ended its oil purchase agreement with Lantern Petroleum and began selling oil to a broader range of purchasers. Effective July 1, 2002, Brigham is ending a similar gas sales and purchase arrangement with Highland Energy Company. Due to the availability of other markets and pipeline connections, Brigham does not believe that the loss of any single oil or natural gas customer would have a material adverse effect on its results of operations. COMPETITION The oil and gas industry is highly competitive in all of its phases. Brigham encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of seismic and leasing options and oil and natural gas leases on properties. Brigham's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of its competitors are large, well established companies with substantially larger operating staffs and greater capital resources than Brigham. Such companies may be able to pay more for seismic and lease options on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than Brigham's financial or human resources permit. Brigham's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Risk Factors--We Face Significant Competition" and "--Risk Factors--We Have Substantial Capital Requirements" 7 <Page> OPERATING HAZARDS AND UNINSURED RISKS Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by Brigham will be productive or that Brigham will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Brigham's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond Brigham's control, including title problems, weather conditions, delays by project participants, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. Brigham's future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on its business, financial condition or results of operations. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Risk Factors--Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are Dependent On Exploratory Drilling Activities" In addition, use of 3-D seismic technology requires greater pre-drilling expenditures than traditional drilling strategies. Although Brigham believes that its use of 3-D seismic technology will increase the probability of drilling success, some unsuccessful wells are likely, and there can be no assurance that unsuccessful drilling efforts will not have a material adverse effect on Brigham's business, financial condition or results of operations. Brigham's operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to properties of Brigham and others. Brigham maintains insurance against some but not all of the risks described above. In particular, the insurance maintained by Brigham does not cover claims relating to failure of title to oil and natural gas leases, trespass during 3-D survey acquisition or surface change attributable to seismic operations, business interruption or loss of revenues due to well failure. Furthermore, in certain circumstances in which insurance is available, Brigham may not purchase it. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on Brigham's business, financial condition and results of operations. EMPLOYEES On March 22, 2002, Brigham had 52 full-time employees. None is represented by any labor union and Brigham believes its relations with its employees are good. In addition, Brigham relies on several regional consulting service companies to provide field landmen to support Brigham on a project-by-project basis. One of these companies, Brigham Land Management, is owned by Vincent M. Brigham, who is the brother of Ben M. Brigham, Brigham's Chief Executive Officer, President and Chairman of the Board and David T. Brigham, Brigham's Senior Vice President of Land and Administration. FACILITIES Brigham's principal executive offices are located in Austin, Texas, where it leases approximately 34,330 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730. In an effort to reduce corporate overhead expenses, Brigham subleased approximately 5,400 square feet of excess office space at its principal executive offices to a third party for a two-year term beginning in November 1999 and extended that sublease by an additional six months in October 2001. 8 <Page> TITLE TO PROPERTIES Brigham believes it has satisfactory title, in all material respects, to substantially all of its producing properties in accordance with standards generally accepted in the oil and gas industry. Brigham's properties are subject to royalty interests, standard liens incident to operating agreements, liens for current taxes and other inchoate burdens, which Brigham believes, do not materially interfere with the use of or affect the value of such properties. Brigham's Senior Credit Facility is secured by a first lien against substantially all of Brigham's oil and natural gas properties and other tangible assets, and Brigham's Subordinated Notes Facility. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Senior Credit Facility" and "--Liquidity and Capital Resources--Refinancing Transactions--Subordinated Notes Facility" GOVERNMENTAL REGULATION Brigham's oil and natural gas exploration, production and marketing activities are subject to extensive laws, rules and regulations promulgated by federal and state legislatures and agencies. Failure to comply with such laws, rules and regulations can result in substantial penalties. The legislative and regulatory burden on the oil and gas industry increases Brigham's cost of doing business and affects its profitability. Although Brigham believes it is in substantial compliance with all applicable laws and regulations, Brigham is unable to predict the future cost or impact of complying with such laws and regulations because they are frequently amended, interpreted and reinterpreted. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. These states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. ENVIRONMENTAL MATTERS Brigham's operations and properties are, like the oil and gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from Brigham's operations. The permits required for various of Brigham's operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines or injunction, or both. In the opinion of management, Brigham is in substantial compliance with current applicable environmental laws and regulations, and Brigham has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on Brigham, as well as the oil and gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict and arguably joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released 9 <Page> into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting Brigham's operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as Brigham, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on Brigham. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. With respect to certain of its operations, Brigham is required to maintain such permits or meet general permit requirements. The Environmental Protection Agency ("EPA") has in place regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Brigham believes that it will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on Brigham. Brigham has acquired leasehold interests in numerous properties that for many years have produced oil and natural gas. Although Brigham believes that the previous owners of these interests have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties. In addition, some of Brigham's properties are operated by third parties over whom it has little control. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Other Matters" and "--Risk Factors--We Are Subject To Various Governmental Regulations And Environmental Risks" 10 <Page> ITEM 2. PROPERTIES PRIMARY EXPLORATION PROVINCES Brigham focuses its 3-D seismic exploration efforts in oil and natural gas producing provinces where it believes 3-D technology may be effectively applied to discover relatively large potential reserve volumes (on both a per well basis and per field basis) with high potential production rates and multiple producing objectives. Brigham's exploration activities are concentrated primarily in three core provinces: the Anadarko Basin of western Oklahoma and the Texas Panhandle; the onshore Texas Gulf Coast; and West Texas. Since inception in 1990 through 2001, Brigham has drilled 420 exploratory and 110 development wells on its 3-D generated prospects with an aggregate completion rate of 67% and an average working interest of 30%. During this period, Brigham has added an estimated 191 Bcfe of net proved reserves, 168 net Bcfe of which were discovered by Brigham through its systematic 3-D exploration drilling activities at an average drilling finding cost of $0.79 per Mcfe. Brigham was a pioneer in 3-D exploration in domestic onshore provinces. From 1990 to 1996 Brigham acquired approximately 2,760 square miles of 3-D seismic data in over 28 different geologic plays, seven basins and seven states, and in the process identified the geologic objectives that it believed would provide optimal 3-D drilling economics. During 1997 and 1998, Brigham aggressively capitalized on its 3-D exploration experience by accumulating a multi-year inventory of 3-D delineated drilling locations in the plays that it believed were most likely to provide attractive 3-D delineated drilling economics. During this period, Brigham acquired an additional 2,475 square miles of 3-D seismic data and retained a substantially higher than historical project working interests of 73%. These acquisitions were the largest in Brigham's history and nearly doubled Brigham's inventory of onshore 3-D seismic data, as compared to year-end 1996, to 5,235 square miles. With these significant investments, Brigham believes it has assembled a superior knowledge base and the premier seismic and leasehold position in each of its current focus plays. Brigham further believes it has captured a high quality, multi-year inventory of 3-D delineated potential drilling locations and the quality and depth of this inventory is evidenced by its recent drilling results. Beginning in 1999, Brigham began to focus the majority of its capital expenditures on drilling in its 3-D delineated prospect inventory in the five plays where it has assembled a superior knowledge base and an optimal seismic and leasehold position. As a result of this focus, for the three-year period ending December 31, 2001, Brigham achieved an average drilling finding cost and all-sources finding cost of $0.74 and $1.00 per Mcfe, respectively. Also, during this same three-year period Brigham's production volumes grew by 44% to average 26.6 MMcfe per day in 2001, while EBITDA grew by 244% to $22.7 million in 2001. Brigham's exploration success achieved through the drilling of its 3-D delineated prospect inventory has resulted in four substantial field discoveries since 1999 and has added a substantial number of developmental locations to Brigham's large inventory of 3-D delineated exploration prospects. As a result, the Company's annual drilling investments have evolved from pure 3-D delineated exploration to a blended exploration and development portfolio. For example, while Brigham's drilling capital expenditures in 1999 were almost 100% exploration, capital expenditures in 2001 were approximately 50% developmental. Growth in the proportion of the drilling expenditures allocated to development drilling should continue in 2002, particularly given the discovery of the Triple Crown Field and the Providence Field in 2001. Although these new field discoveries did not materially impact production volumes and cash flow in 2001, management believes they will have a material impact on production volumes in 2002. Continuing its strategic focus implemented during 1999, Brigham intends to direct substantially all of its efforts and available capital resources in 2002 to the drilling and monetization of the prospective 11 <Page> drilling locations within its over 6,600 square mile inventory of 3-D seismic data. Brigham's planned 2002 capital budget is estimated to be approximately $23.7 million. The spending will be funded out of Brigham's discretionary cash flow and availability under its Subordinated Notes Facility. Depressed commodity prices have led to a budgeted decrease in capital spending of $12.3 million (34%) for 2002 when compared to 2001. Brigham's budget is based upon anticipated commodity prices and is subject to change if market conditions shift. For 2002, Brigham plans to spend approximately 80% of its $17.9 million exploration and development budget to drill 26 planned wells with an average working interest of 32%. Brigham's planned 2002 drilling program represents a blend of capital investments consisting of both, development projects to recent discoveries and high potential exploration prospects. Approximately 80% of budgeted drilling expenditures are allocated to development activities with the remaining 20% targeted for exploratory drilling. In addition, over 90% of Brigham's budgeted drilling expenditures are focused in the Company's five focus plays, which include the Frio and Vicksburg trends in the Texas Gulf Coast, the Springer and Hunton trends in the Anadarko Basin, and the Horseshoe Atoll trend in West Texas. In these focus plays Brigham has completed 25 wells in 28 recent attempts, generated four significant field discoveries and achieved an average proved developed drilling finding cost of $0.75 per Mcfe. Brigham's actual capital expenditures in 2002 may differ from the estimates discussed herein based upon cash flow and capital availability during the year. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" There can be no assurance that any potential drilling locations identified by Brigham will be drilled at all or within the expected time frame. The final determination with respect to the drilling of any well, including those currently budgeted, will depend upon a number of factors, including: - the availability of leases on reasonable terms and permitting for the potential drilling location; - economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and cost of drilling rigs and crews; - the results of exploration and development efforts and the continuing review and analysis of seismic data; and - the availability of sufficient capital resources by Brigham and other participants to fund drilling and completion expenditures. In addition, there can be no assurance that the budgeted wells will, if drilled, encounter reservoirs of commercial quantities of oil or natural gas. ANADARKO BASIN The Anadarko Basin is a prolific natural gas province that Brigham believes offers a combination of lower risk exploration and development opportunities in shallower horizons and deeper, higher potential objectives that have been relatively under explored. This province has produced approximately 100 Tcfe to date from numerous, historically elusive stratigraphic targets, such as the Red Fork, Upper Morrow and Springer channel sands, as well as from deeper, higher potential structural objectives, such the Lower Morrow sandstones and the Hunton and Arbuckle carbonates. In some cases, these objectives have produced in excess of 50 Bcf of natural gas from a single well at rates of up to 30 MMcf of natural gas per day. In addition, drilling economics in the Anadarko Basin are enhanced by the multi-pay nature of many of the prospects, with secondary or tertiary targets serving as either incremental value or as a bailout alternative in the event the primary target zone is not productive. Each of the stratigraphic and structural objectives in the Anadarko Basin can provide excellent targets for 3-D seismic imaging. Brigham has assembled an extensive digital database in this province, 12 <Page> including geologic studies, basin-wide geologic tops, production data, well data, geographic data and over 8,400 miles of 2-D seismic data. Brigham's explorationists integrate this data with their extensive expertise and knowledge base to generate 3-D delineated drilling prospects. As of December 31, 2001, Brigham had accumulated 2,259 square miles (1.4 million acres) of 3-D seismic data in the Anadarko Basin. Since 1994, Brigham has completed 104 (37.8 net) wells in 133 (48.8 net) attempts for a net completion rate of 77% and has found cumulative net proved reserves of 81 Bcfe at an average drilling finding cost of $0.60 per Mcfe. For the three-year period ended December 31, 2001, Brigham completed 33 (11.8 net) wells in 38 (13.0 net) attempts in the Anadarko Basin for a net completion rate of 91%. The Company retained an average working interest of 34% in these wells and added 33 net Bcfe of proved reserves at an average drilling finding cost of $0.47 per Mcfe. For 2002, Brigham intends to focus the majority of its Anadarko Basin drilling activities in the following key focus trends: SPRINGER TREND Brigham's inventory of 3-D projects in the Springer trend consists of approximately 630 square miles of 3-D seismic data covering approximately 400,000 acres in Dewey, Blaine, Canadian and Caddo Counties, Oklahoma. These projects target stratigraphic fluvial sand channels in the Springer-aged Old Woman and Britt intervals, as well as secondary objectives including the Morrow. Brigham initiated the acquisition of 3-D seismic data in the area in 1991 by acquiring a 13 square mile program, and subsequently acquired 14 square miles in 1994, and 219 square miles in 1996. To capitalize on its prior experiences and successes in the play, the Company accelerated its 3-D acquisitions in the trend in 1997 and 1998, when it acquired 383 square miles of 3-D seismic data with an average working interest of 72%. The processing of the majority of this data was completed in 1998 and 1999, and Brigham's interpretation and prospect generation efforts are still underway. In May 2000, Brigham completed the Price #2, a 3-D delineated Springer channel test in Blaine County, Oklahoma. The Company retained a 71% working interest and 56% net revenue interest in the discovery, which began producing to sales at a curtailed rate of approximately 3.5 MMcf of natural gas and 350 barrels of condensate per day. Due to increased pipeline capacity, production rates were increased in December 2000 to approximately 6.5 MMcf of natural gas and 250 barrels of condensate per day. At year-end 2001, the Price #2 had produced 2.7 Bcfe and was producing approximately 2.4 MMcfe per day. During 2001, Brigham drilled the Price #3, a successful offset to its earlier Price #2 discovery. Brigham operated the Price #3 and retained a 41% net revenue interest in the well, which began producing to sales in May 2001 at 2.8 MMcf of natural gas and 70 barrels of condensate per day. At year-end 2001, the Price #3 had produced 0.5 Bcfe and was producing approximately 1.3 MMcfe per day. In February 2001, Brigham completed the Zachary #1, another Springer channel discovery, which was drilled to a total depth of approximately 9,750 feet. The Company began producing the well to sales in March 2001 at a pipeline-curtailed rate of approximately 2.2 MMcf of natural gas and 75 barrels of condensate per day. In April 2001, the production rate was increased to approximately 6.0 MMcf of natural gas and 200 barrels of condensate per day, or approximately 1.4 MMcfe per day to Brigham's 20% net revenue interest. At year-end, 2001 the Zachary #1 had produced 2.0 Bcfe and was producing approximately 8.4 MMcfe per day. In July 2001, Brigham completed two offset wells to this discovery. The Company retained a 24% working interest and 20% net revenue interest in the first offset, which began producing to sales in September 2001 at 3.3 MMcfe per day. Brigham retained a 47% working interest and 38% net revenue interest in the second offset, which also began producing to sales in September 2001 at 2.1 MMcfe per day. The Company plans to stimulate both of these wells in early 2002. 13 <Page> Since 2000, Brigham has completed six Springer channel tests in eight attempts at an estimated proved developed drilling finding cost of $0.58 per Mcfe. Based on this recent drilling success, Brigham plans to drill four to six Springer channel tests in 2002. These wells target similar objectives as its previous producers, and the Company expects to retain an average working interest of approximately 35% in these planned wells. HUNTON TREND Brigham's 3-D seismic inventory in the deep Hunton play of the southwestern portion of the Anadarko Basin consists of approximately 763 square miles of 3-D seismic data covering approximately 488,000 acres in the southern portion of the Texas Panhandle in Wheeler, Hemphill and Roberts Counties, Texas and Beckham County, Oklahoma. The primary exploration targets within these projects are high potential, structural features at depths ranging from 7,500 to 25,000 feet. Brigham initiated acquisition of data in the Hunton trend in 1994 when it retained a 25% working interest in 67 square miles of 3-D seismic. Following Brigham's 3-D seismic acquisition in 1994, it acquired an additional 85 square miles of 3-D seismic (average working interest of 15%) in 1995, 254 square miles (average working interest of 30%) in 1996, and 123 square miles (average working interest of 38%) in 1997. Based upon the interpretation of these data sets Brigham acquired an additional 99 square miles of 3-D data in 1998 where it retained a 100% working interest. In 2001, Brigham traded ownership interest in a less active 3-D project to obtain an additional 135 square miles of 3-D seismic data in the Hunton trend. MILLS RANCH FIELD In July 2000, Brigham spud the Mills Ranch #1, which targeted a large high potential Hunton structure adjacent to a currently producing Hunton well that has produced over 15 Bcfe. The Company operated and retained a 64% working interest in the well, which was drilled directionally to a total depth of over 25,000 feet. Brigham completed the discovery in the targeted Hunton formation in December 2000. The well encountered approximately 1,200 feet of gross pay and 340 feet of measured depth net pay (240 feet of calculated true vertical net pay) in three Hunton intervals. The well began producing to sales from one Hunton interval in January 2001 at approximately 9.5 MMcf of natural gas and 90 barrels of condensate per day, or 5.1 MMcfe per day to Brigham's 51% net revenue interest. As of December 31, 2001 the Mills Ranch #1 had produced 1.9 Bcfe and was producing approximately 4.0 MMcfe per day. The Company estimates its proved developed drilling finding cost for the Mills Ranch discovery well was $0.31 per Mcfe, and currently plans to drill an offset well during 2002 or early in 2003. TEXAS GULF COAST The onshore Texas Gulf Coast region is a high potential, multi-pay province that lends itself to 3-D seismic exploration due to its substantial structural and stratigraphic complexity. Brigham was attracted to the Gulf Coast province because of the opportunity to apply its established 3-D seismic exploration approach and its exploration staff's extensive Gulf Coast experience to a prolific, structurally complex province with the potential to discover significant natural gas reserves with associated high production rates. Brigham has assembled a digital database including geographical, production, geophysical and geological information that it evaluates on CAEX workstations. A portion of Brigham's 3-D seismic data acquisition in the Texas Gulf Coast has been accomplished through participation in certain non-proprietary, or speculative, seismic programs. By converting certain of Brigham's proprietary seismic projects in core exploration areas to speculative data, Brigham was able to leverage these proprietary projects for access to substantially larger non-proprietary speculative data for minimal or no additional cost. While increasing its exposure to 14 <Page> competition in speculative seismic programs, Brigham believes this 3-D seismic acquisition strategy in the Gulf Coast, in certain circumstances, can accelerate the addition of attractive potential drilling locations in targeted trends at costs that are considerably less than those associated with proprietary 3-D seismic programs, thereby enhancing the expected project rate of return. As of December 31, 2001, Brigham had accumulated 2,233 square miles (1.4 million acres) of 3-D seismic data in its Texas Gulf Coast province. The Company began to acquire 3-D seismic in the Texas Gulf Coast in 1995 when it acquired 39 square miles of 3-D seismic data. Brigham subsequently acquired 115 square miles in 1996, and in 1997 and 1998 accelerated its acquisition of 3-D seismic data by acquiring approximately 990 square miles in the plays it believed would provide optimal 3-D drilling economics. The Company further capitalized on its experience by retaining an average working interest of 78% in this newly acquired data. In 2001, Brigham exchanged licensing rights in certain non-core 3-D data volumes for licenses to additional 3-D seismic data programs located in Brigham's focus plays in the Texas Gulf Coast. As a result, Brigham added approximately 1,100 square miles of 3-D seismic data in the Texas Gulf Coast in 2001, with very little capital investment. The Company believes that by applying its knowledge base and expertise to this newly acquired 3-D seismic data it should generate additional drilling inventory in its current focus plays. One of Brigham's 2001 Frio discoveries was drilled on this recently acquired data. Since 1996 Brigham has completed 59 (21.7 net) wells in 75 (27.3 net) attempts in the Texas Gulf Coast for a net completion rate of 79%. Brigham has discovered cumulative net proved reserves of 60 Bcfe at an average net drilling finding cost of $0.85 per Mcfe. For the three-year period ended December 31, 2001, Brigham completed 34 (10.8 net) wells in 43 (14.5 net) attempts in the Texas Gulf Coast for a net completion rate of 74%. Brigham retained an average working interest in these wells of 34% and added approximately 36 net Bcfe of proved reserves at an average drilling finding cost of $1.02 per Mcfe. For 2002, Brigham intends to focus the majority of its Texas Gulf Coast drilling activities in the following key focus plays: VICKSBURG TREND Brigham has made two significant field discoveries (Home Run Field and Triple Crown Field) in the Vicksburg trend since 1999. Brigham and its participant, a major integrated oil company, acquired a 54 square mile program in 1997 and 1998, and jointly control 10,000 gross and net acres of leasehold. Brigham retained a 34% working interest in the project to explore and develop the Vicksburg formation below 10,000 feet, but increased its pre-payout working interest to 50% in select acreage that was subsequently drilled as its Triple Crown Field discovery. Also in the project, in the prospective zones above 10,000 feet, the Company retained a 100% working interest in its original 4,000 acre lease block. Since 1999, excluding the Palmer #5 well (which experienced a casing failure) Brigham has completed eight Vicksburg wells in eight attempts at an estimated proved developed drilling finding cost of $1.47 per Mcfe. HOME RUN FIELD Brigham discovered the Home Run Field in late 1999 with its Palmer State #2 discovery well. The Brigham operated Palmer State #2 began producing in February 2000 at an initial rate of 10.1 MMcf of natural gas and 650 barrels of condensate per day, or 4.1 MMcfe to Brigham's 29% net revenue interest. At year-end 2001, the Palmer #2 had produced 3.2 Bcfe and was producing 2.0 MMcfe per day. In 2001, Brigham completed four wells in its Home Run Field. Two of these wells, the Palmer #4 and the D.J. Sullivan #C-25, were spud in the fourth quarter of 2000 and completed during the first quarter of 2001. Brigham retained a 34% working interest in both wells. The Palmer #4, an offset to 15 <Page> the previously drilled Palmer #2 and Palmer #3 wells, was drilled to a total depth of approximately 13,550 feet and encountered prospective pay intervals in several of the targeted Lower Vicksburg objectives. The Palmer #4 was fracture stimulated in four Vicksburg pay intervals and began producing to sales in March 2001 at 6.8 MMcf of natural gas and 280 barrels of condensate per day, or 2.5 MMcfe net to Brigham's 29% net revenue interest. The D.J. Sullivan #C-25 began producing to sales in March at 9.8 MMcf of natural gas and 390 barrels of condensate per day, or 3.0 MMcfe net to Brigham's 25% net revenue interest. At year-end 2001, the D.J. Sullivan #C-25 had produced 1.5 Bcfe and was producing 3.1 MMcfe per day. During August 2001, Brigham drilled the Palmer #5, its fourth successive development well in the Home Run Field and encountered pay intervals comparable to the previously completed D.J. Sullivan #C-25 well. Subsequent to fracture stimulation, Brigham's initial completion of one of several potential pay intervals in the Palmer #5 tested at an estimated 1.6 MMcf of natural gas per day. However, surface production facilities subsequently plugged with large pieces of formation and steel casing fragments, and repeated attempts to restore the well to production were unsuccessful. The Company believes that the well's problems were created by a poor cement job caused by a casing failure during cementing operations. As a result, Brigham is currently pursuing compensation for losses, and anticipates drilling a replacement well late in 2002. See "Item 3. Legal Proceedings" In November 2001, Brigham completed and began producing to sales the D.J. Sullivan #C-27 at 11.3 MMcf of natural gas and 506 barrels of condensate per day, or 3.6 MMcfe per day to Brigham's 25% net revenue interest. Brigham completed the D.J. Sullivan #C-28 in January 2002, which began producing to sales in February at 9.3 MMcfe per day, or 2.3 MMcfe per day to Brigham's 25% net revenue interest. Excluding the Palmer #5, which experienced a casing failure, Brigham has completed six consecutive wells in its Home Run Field. The Company believes the field could require ten to twenty additional wells for full development. Excluding the undeveloped reserves in this field, and excluding the Palmer #5 (which the Company anticipates will be redrilled) Brigham estimates it has achieved an average proved developed drilling finding cost of $1.36 per Mcfe. The Company plans to drill two to three development wells in the Home Run Field during 2002 and expects to retain an average working interest of approximately 34% in these planned wells. TRIPLE CROWN FIELD In October 2001, Brigham completed the Dawson #1, which was drilled as an exploratory test of one of several downthrown fault blocks adjacent to the Company's Home Field in Brooks County, Texas. The Dawson #1 was drilled to a depth of 14,256 feet and encountered approximately 179 feet of net pay in seven Vickburg sand intervals. Approximately 149 feet of the net pay was located in the Upper Vicksburg and 25 feet of apparent pay in the Lower Vicksburg. Brigham retained a 50% working interest and 37.5% net revenue interest in the well, which is subject to a back in working interest that ultimately reduces Brigham's working interest in the well to 42% at 200% payout. Given the volume of apparent pay in the well, Brigham's completion plans were similar to the procedures utilized in completing Lower Vicksburg sand intervals in the Company's Home Run Field, including the sequential perforation and fracture stimulation of each of seven pay intervals, all of which were to be subsequently commingled. Individual production tests from three Lower Vicksburg intervals ranged from 300 Mcf of natural gas per day with flowing tubing pressure of 1,000 psi to 3.6 MMcf of natural gas and 54 barrels of condensate per day with flowing tubing pressure of 5,800 psi. The Company subsequently tested the "Loma Blanca" interval in the Upper Vicksburg at 2.3 MMcf of natural gas per day with flowing tubing pressure of 7,320 psi. Brigham's interpretation of wireline logs and drilling shows indicated that the highest production rates in the Dawson #1 well should have been achieved by producing three Upper Vicksburg "9800" 16 <Page> sand lobes (the "A", "B" and "C"). However, subsequent to fracture stimulation of both the "B" and "C" zones, the well tested both natural gas and significant quantities of formation sand. Brigham subsequently stimulated the 9800 "A" zone utilizing a fracture stimulation and completion technique designed to limit production of formation sand (a "fracpack"). As a result the Dawson #1 began producing to sales in November 2001, from only the shallowest of several pay intervals at 3.4 MMcf of natural gas and 24 barrels of condensate per day with flowing tubing pressure of 6,000 psi. At year-end 2001, the Dawson #1 was producing approximately 2.5 MMcfe per day. Brigham completed its first development well in the Triple Crown Field in November 2001. The Company retained a 50% working interest and 37.5% net revenue interest in the Sullivan #1, which encountered the objective Upper and Lower Vicksburg sands approximately 200 feet structurally low to the Dawson #1 discovery well with diminished reservoir quality sands. As a result, the production performance of the Sullivan #1 has been disappointing. In late December 2001, Brigham spud the Sullivan F-31, its second development well in the Triple Crown Field. Brigham retained a 42% working interest and 31% net revenue interest in the Sullivan F-31, which encountered approximately 65 feet of apparent Upper Vicksburg net pay with porosity greater than 15%, including several intervals with porosity as high as 26%. Given the quality of the pay, and the risk associated with drilling deeper for Lower Vicksburg sands that the Company found to be productive in the Dawson #1 discovery well, Brigham decided to set casing and complete the well in the Upper Vicksburg. The Company plans to fracture stimulate the various productive intervals in the well beginning in March and to subsequently commingle and produce all zones to sales by May 2002. Brigham plans to drill between two and four development wells in the Triple Crown Field in 2002 and expects to retain an average working interests of 42% and 34% in these wells. FRIO TREND In the Frio trend of the Upper Texas Gulf Coast, Brigham has accumulated an inventory of over 1,088 square miles of predominantly non-proprietary 3-D seismic data. The Company added over 500 square miles of this data in 2001 by exchanging licensing rights in non-core 3-D data volumes. This trade was intended to capitalize on Brigham's recent success in the Frio play and supplement its inventory of 3-D delineated drilling prospects. In this trend Brigham is targeting both the shallow, non-pressured and the deeper, pressured Frio sands. Several high production rate 3-D delineated drilling discoveries ignited the Frio play in the mid to late 1990's. In Matagorda County, Texas, in 1998 a 3-D discovery and two offset wells were each completed at initial rates of over 40 MMcfe per day. These three wells averaged over 10 Bcfe of production in their first year, and produced a total of approximately 40 Bcfe in less than eighteen months, thus illustrating the play's potential for generating extraordinary production rates. Late in 2000, Brigham completed a high rate Frio bright spot discovery in Matagorda County, Texas. This discovery began producing to sales in December 2000 at 10.0 MMcf of natural gas and 200 barrels of condensate per day, or 2.1 MMcfe net to Brigham's 18.75% revenue interest. In February 2001, Brigham drilled and completed a subsequent Frio bright spot discovery that began producing to sales in March 2001 at 17.5 MMcf of natural gas and 290 barrels of condensate per day, or 4.4 MMcfe net to Brigham's 23% net revenue interest. In April 2001, Brigham completed its third consecutive Frio bright spot discovery, the Pitchfork Ranch #1, which began producing to sales in early May 2001 at 12.1 MMcfe, or 2.8 MMcfe per day to the Company's 23% net revenue interest. Brigham completed its fourth consecutive Frio bright spot discovery in August 2001. The Heckendorn #1 began producing to sales at 6.5 MMcfe per day, or 1.0 MMcfe per day to Brigham's 15% net revenue interest. After drilling a dry hole in the third quarter 2001, the Company completed its fifth Frio test in six recent attempts, in Brazoria County, Texas. The 17 <Page> Sebesta Cloud #1 began producing to sales at 2.4 MMcfe per day, or 0.6 MMcfe per day to Brigham's 24% net revenue interest. Brigham has developed particular expertise in the Frio play that it believes is contributing to its recent drilling success. As a result, since late 2000, Brigham has completed six Frio tests in seven attempts and has achieved an estimated drilling finding cost for proved developed reserves of $0.73 per Mcfe. PROVIDENCE FIELD During the fourth quarter of 2001, Brigham drilled and completed a significant Frio test targeting a large structure with multiple pay sands. Brigham operated and retained a 41% working interest and 31% net revenue interest in the Staubach #1, which reached total depth in December and encountered approximately 36 feet of net pay in the over pressured Frio formation. In February 2002, Brigham began producing this well to sales at approximately 2,000 barrels of oil and 5.0 MMcf of natural gas per day, or approximately 5.3 MMcfe per day to Brigham's 31% net revenue interest. The Company believes that the field could require four to six wells to fully develop. Brigham spud the first offset to this discovery, the Burkhart #1, in March 2002. The Company operates and retained a 41% working interest in the well. In 2002, Brigham plans to drill between five and seven wells in the Frio and expects to maintain an average working interest of 41% in these wells. WEST TEXAS Brigham's drilling activity in its West Texas province has been focused primarily in the Horseshoe Atoll trend, the Midland Basin and the Eastern Shelf of the Permian Basin and in the Hardeman Basin. In response to reduced market prices for oil and comparatively higher potential natural gas projects in its Anadarko Basin and Gulf Coast provinces, Brigham substantially reduced its 3-D seismic acquisition and drilling activities in West Texas during 1998 and 1999. In response to improved oil prices during 2000 and the first half of 2001, Brigham began reprocessing and reinterpreting certain 3-D seismic projects in its West Texas 3-D seismic projects. As of December 31, 2001, Brigham had accumulated 2,141 square miles (1.4 million acres) in its West Texas province. Since 1990, Brigham has completed 189 (46.4 net) wells in 305 (77.7 net) attempts for a net completion rate of 60% and an average working interest of 25%. During this period, Brigham has added cumulative net proved reserves of 27 Bcfe at an average net drilling finding cost of $1.15 per Mcfe. For the three-year period ended December 31, 2001, Brigham completed four (3.4 net) wells in seven (4.5 net) attempts for a net completion rate of 76% and an average working interest of 64%. During this same three-year period, Brigham has added 7.5 net Bcfe of proved reserves at an average net drilling finding cost of $0.52 per Mcfe. HORSESHOE ATOLL TREND Brigham has completed four consecutive oil discoveries in the Horseshoe Atoll trend in West Texas that have positively impacted the Company's net oil production. The first of these was completed in February 2001, when Brigham successfully drilled a 9,400 foot Canyon Reef test that logged over 90 feet of reef pay. This discovery began producing to sales in March 2001 at 200 barrels of oil per day, or 140 barrels per day to Brigham's 71% net revenue interest. At year-end 2001, this well had produced a cumulative 58,000 barrels of oil and was producing approximately 180 barrels of oil per day. 18 <Page> In April 2001, Brigham retained a 100% working interest in its second consecutive Horseshoe Atoll trend discovery, which encountered approximately 100 feet of pay in the Canyon Reef at a depth of 9,100 feet. This discovery began producing to sales at 250 barrels of oil per day, or 200 barrels of oil per day to the Company's 80% net revenue interest. At December 31, 2001, this well had produced a cumulative 57,000 barrels of oil and was producing approximately 230 barrels of oil per day. Also in April 2001, Brigham retained a 55% working interest in its third consecutive Horseshoe Atoll trend discovery. This well was completed in the targeted Fusselman formation, and began producing to sales at 170 barrels of oil per day, or 80 barrels per day to Brigham's net revenue interest. At December 31, 2001, this well had produced a cumulative 21,000 barrels of oil, and was producing approximately 47 barrels of oil per day. In May 2001, Brigham retained a 100% working interest in its fourth consecutive Horseshoe Atoll trend discovery, which encountered approximately 179 feet of Canyon Reef pay at a depth of approximately 9,400 feet. This discovery began producing to sales in May at 250 barrels of oil per day, or 193 barrels per day to Brigham's 77% net revenue interest. At December 31, 2001 this well had produced a cumulative 55,000 barrels of oil and was producing approximately 200 barrels of oil per day. In the Horseshoe Atoll trend of West Texas, Brigham has completed four wells in four recent attempts at an estimated average drilling finding cost for proved developed reserves of $0.48 per Mcfe. In 2002, Brigham plans to drill up to six wells in the Horseshoe Atoll trend. The Company has sold a portion of its working interest to industry participants on a promoted basis, thus the majority of its drilling costs will be carried to casing point. Brigham expects to retain an average 35% working interest after casing point in these wells. 19 <Page> OIL AND NATURAL GAS RESERVES Brigham's estimated total net proved reserves of oil and natural gas as of December 31, 1999, 2000 and 2001 and the present values attributable to these reserves as of those dates were as follows: <Table> <Caption> AS OF DECEMBER 31, ------------------------------ 1999 2000 2001 -------- -------- -------- Estimated net proved reserves: Natural gas (MMcf).................................. 65,457 78,167 88,594 Oil (MBbls)......................................... 3,027 2,870 3,748 Natural gas equivalent (MMcfe)...................... 83,618 95,388 111,081 Proved developed reserves as a percentage of proved reserves............................................ 48% 52% 49% Present Value of Future Net Revenues (in thousands)... $114,466 $497,666 $146,807 Standardized Measure (in thousands)................... $113,546 $359,228 $120,924 </Table> The reserve estimates reflected above were prepared by Cawley, Gillespie & Associates, Inc. ("Cawley Gillespie"), Brigham's independent petroleum consultants, and are part of reports on Brigham's oil and natural gas properties prepared by Cawley Gillespie. The base sales prices for Brigham's reserves were $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31, 1999, $10.42 per Mcf for natural gas and $26.83 per Bbl for oil as of December 31, 2000, and $2.57 per Mcf for natural gas and $19.84 per Bbl for oil as of December 31, 2001. These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate Brigham's reserves at these dates. In accordance with applicable requirements of the SEC, estimates of Brigham's proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond Brigham's control. The reserve data set forth in this Form 10-K represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by Brigham, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Brigham's estimated proved reserves have not been filed with or included in reports to any federal agency. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Risk Factors--We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows" Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the estimated reserves that may be substantial. 20 <Page> DRILLING ACTIVITIES Brigham drilled, or participated in the drilling of, the following number of wells during the periods indicated: <Table> <Caption> YEAR ENDED DECEMBER 31, --------------------------------------------------------------- 1999 2000(1) 2001 ------------------- ------------------- ------------------- GROSS NET GROSS NET GROSS NET -------- -------- -------- -------- -------- -------- EXPLORATORY WELLS (2): Natural gas................................................. 8 3.4 6 1.9 5 1.6 Oil......................................................... 2 0.1 3 0.9 5 3.7 Non-productive.............................................. 7 2.4 2 1.0 4 1.1 -- --- -- --- -- --- Total..................................................... 17 5.9 11 3.8 14 6.4 == === == === == === DEVELOPMENT WELLS (3): Natural gas................................................. 8 2.3 15 5.8 16 5.0 Oil......................................................... 1 0.5 1 0.7 1 0.1 Non-productive.............................................. 1 0.6 1 0.8 2 0.2 -- --- -- --- -- --- Total..................................................... 10 3.4 17 7.3 19 5.3 == === == === == === </Table> - ------------------------ (1) Excludes one gross (1.0 net) exploratory well that was temporarily abandoned during drilling due to operational difficulties encountered prior to reaching total depth. Brigham re-entered and completed this temporarily abandoned well during 2001. (2) From January 1, 2002 through March 22, 2002, Brigham drilled, or participated in the drilling of one gross (0.4 net) exploratory well, which was non-productive. In addition, Brigham is carried for a 25% working interest in the drilling and completion of a second exploratory well that was drilling at March 22, 2002. (3) From January 1, 2002 through March 22, 2002, Brigham drilled, or participated in the drilling of, one gross (0.4 net) development well which was in the process of drilling at March 22, 2002. Brigham does not own any drilling rigs and the majority of its drilling activities have been conducted by independent contractors or industry participant operators under standard drilling contracts. Brigham operated 45% of the gross and 67% of the net wells it participated in during 2001. PRODUCTIVE WELLS AND ACREAGE PRODUCTIVE WELLS The following table sets forth Brigham's ownership interest as of December 31, 2001 in productive oil and natural gas wells in the areas indicated. <Table> <Caption> NATURAL GAS OIL TOTAL ------------------- ------------------- ------------------- GROSS NET GROSS NET GROSS NET -------- -------- -------- -------- -------- -------- PROVINCE: Anadarko Basin........................................ 67 23.1 14 3.5 81 26.6 Texas Gulf Coast...................................... 28 10.4 16 3.7 44 14.1 West Texas............................................ 13 1.6 74 23.9 87 25.5 --- ---- --- ---- --- ---- Total............................................... 108 35.1 104 31.1 212 66.2 === ==== === ==== === ==== </Table> Productive wells consist of producing wells and wells capable of production, including wells waiting on pipeline connection. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, two had multiple completions. 21 <Page> ACREAGE Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves. The following table sets forth the approximate developed and undeveloped acreage in which Brigham held a leasehold, mineral or other interest at December 31, 2001: <Table> <Caption> DEVELOPED UNDEVELOPED TOTAL ------------------- ------------------- ------------------- GROSS NET GROSS(1) NET(1) GROSS NET -------- -------- -------- -------- -------- -------- PROVINCE: Anadarko Basin............................ 32,013 13,832 24,049 13,836 56,062 27,668 Gulf Coast................................ 9,092 3,506 21,600 12,474 30,692 15,980 West Texas................................ 6,022 1,914 6,399 3,824 12,421 5,738 Other..................................... 480 148 5,725 2,364 6,205 2,512 ------ ------ ------ ------ ------- ------ Total................................... 47,607 19,400 57,773 32,498 105,380 51,898 ====== ====== ====== ====== ======= ====== </Table> All the leases for the undeveloped acreage summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed, production has been obtained from the acreage subject to the lease prior to that date, or some other "savings clause" is implicated. The following table sets forth the minimum remaining terms of leases for the gross and net undeveloped acreage: <Table> <Caption> ACRES EXPIRING ------------------- GROSS(1) NET(1) -------- -------- TWELVE MONTHS ENDING: December 31, 2002........................................... 16,157 9,043 December 31, 2003........................................... 8,623 4,826 December 31, 2004........................................... 30,767 17,220 Thereafter.................................................. 322 180 ------ ------ Total..................................................... 55,869 31,269 ====== ====== </Table> - ------------------------ (1) Total undeveloped leasehold includes 1,904 gross and 1,229 net mineral acres, which are not included in total undeveloped acres expiring. In addition, Brigham had lease options as of December 31, 2001 to acquire an additional 1,759 gross and 1,426 net acres, all of which expire in 2002. VOLUMES, PRICES AND PRODUCTION COSTS The following table sets forth the production volumes, average prices received net of hedging and average production costs associated with Brigham's sale of oil and natural gas for the periods indicated. <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 1999 2000 2001 -------- -------- -------- Production: Natural gas (MMcf)........................................ 4,197 4,431 6,766 Oil (MBbls)............................................... 346 362 468 Natural gas equivalent (MMcfe)............................ 6,270 6,600 9,573 Average sales price: Natural gas (per Mcf)..................................... $ 2.11 $ 1.94 $ 3.11 Oil (per Bbl)............................................. $17.79 $29.17 $24.05 Average production costs: Lease operating expenses (per Mcfe)....................... $ 0.36 $ 0.32 $ 0.36 Production taxes (per Mcfe)............................... $ 0.15 $ 0.27 $ 0.16 </Table> 22 <Page> COSTS INCURRED The costs incurred in oil and natural gas acquisition, exploration and development activities are as follows (in thousands): <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 1999(1) 2000(2) 2001(3) -------- -------- -------- Exploration.............................................. $19,224 $14,238 $18,210 Property acquisition..................................... 3,462 2,540 3,437 Development.............................................. 4,632 12,555 14,353 Proceeds from participants............................... (2,439) (40) (135) ------- ------- ------- Costs incurred....................................... $24,879 $29,293 $35,865 ======= ======= ======= </Table> - ------------------------ (1) Excludes $27.1 million of proceeds from the sale of interests in properties, projects and prospects in 1999. (2) Excludes $3.9 million of proceeds from the sale of interests in properties, projects and prospects in 2000. (3) Excludes $262,000 of proceeds from the sale of interests in properties, projects and prospects in 2001. Costs incurred represent amounts incurred by Brigham for exploration, property acquisition and development activities. Periodically, Brigham will receive reimbursement of certain costs from participants in its projects subsequent to project initiation in return for an interest in the project. These payments are described as "Proceeds from participants" in the table above. 23 <Page> ITEM 3. LEGAL PROCEEDINGS On November 20, 2001, the Company filed a lawsuit in the District Court of Travis County, Texas, against Steve Massey Company, Inc. ("Massey") for breach of contract. The Petition claims Massey furnished defective casing to the Company, which ultimately led to the casing failure of the Palmer "347" No. 5 Well (the "Palmer #5") and the loss of the Palmer #5 as a producing well. The Company believes the amount of damages incurred by it due to loss of the Palmer #5 may exceed $5 million. Massey joined as additional defendants to the lawsuit other parties that had responsibility for the manufacture, importation or fabrication of the casing for its use in the Palmer #5. The case is currently in discovery. A trial has not been set, but the Company believes a trial will not take place before the first quarter of 2003. On February 20, 2002, Massey filed an Original Petition to Foreclose Lien in Brooks County, Texas. Massey's Petition claims the Company breached its contract for failure to pay for the casing it furnished the Company for the Palmer #5 (and that the Company's claim is defective, forming the basis of the lawsuit described in the paragraph above). Massey's Petition claims the Company owes Massey a total of $445,819. The Company recently filed a Motion to Transfer Venue to Travis County, Texas, to join this case with the Company's suit against Massey pending in Travis County. In the addition, the Company has asked for a Plea in Abatement to place the case on hold until after the Travis County suit has been resolved. If Massey is successful in its Brooks County case, Massey would have the right to foreclose its lien against the well, associated equipment and the Company's leasehold interest. At this point in time, the Company cannot predict the outcome of either the Travis County case or the Brooks County case. On June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed suit against the Company, claiming the Company transported natural gas under his property through an existing pipeline, without his consent. The Company is now using an alternate pipeline. Mr. Garcia is claiming $1.2 million in actual damages and $3 million in exemplary damages. The Company is strenuously defending this lawsuit, believing there is no basis for the damages being claimed. The case has been set for mediation on May 2, 2002. At this point in time, the Company cannot predict the outcome of this case. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS No matter was submitted to a vote of Brigham's securityholders during the fourth quarter of 2001. 24 <Page> EXECUTIVE OFFICERS OF THE REGISTRANT Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this report. The following table sets forth certain information concerning Brigham's executive officers as of March 20, 2002: <Table> <Caption> NAME AGE POSITION - ---- -------- -------------------------------------------- Ben M. Brigham................. 42 Chief Executive Officer, President and Chairman Curtis F. Harrell.............. 38 Executive Vice President, Chief Financial Officer and Director David T. Brigham............... 41 Senior Vice President--Land and Administration, Corporate Secretary A. Lance Langford.............. 39 Senior Vice President--Operations Jeffery E. Larson.............. 43 Senior Vice President--Exploration </Table> Set forth below is a description of the backgrounds of Brigham's executive officers. BEN M. "BUD" BRIGHAM has served as Chief Executive Officer, President and Chairman of the Board since founding Brigham in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas. Mr. Brigham is the husband of Anne L. Brigham, Director, and the brother of David T. Brigham, Senior Vice President--Land and Administration and Corporate Secretary. CURTIS F. HARRELL has served as Chief Financial Officer and Director of Brigham since August 1999, and as Executive Vice President since March 2001. From 1997 to August 1999, he was Executive Vice President and Partner at R. Chaney & Company, Inc., an equity investment firm focused on the energy industry, where he managed the firm's investment origination efforts in the U.S., focusing on investments in corporate equity securities of energy companies in the exploration and production and oilfield service industry segments. From 1995 to 1997, Mr. Harrell was a Director of Domestic Corporate Finance for Enron Capital & Trade Resources, Inc., where he was responsible for initiating and executing a variety of debt and equity financing transactions for independent exploration and production companies. Before joining Enron Capital & Trade Resources, Mr. Harrell spent eight years working in corporate finance and reservoir engineering positions for two public independent exploration and production companies, Kelley Oil & Gas Corporation and Pacific Enterprises Oil Company, Inc. He has a B.S. in Petroleum Engineering from the University of Texas at Austin and an M.B.A. from Southern Methodist University. DAVID T. BRIGHAM joined Brigham in 1992 and has served as Senior Vice President--Land and Administration and Corporate Secretary since March 2001. Mr. Brigham served as Vice President--Land and Administration and Corporate Secretary from February 1998 to March 2001, and as Vice President--Land and Legal of Brigham from 1994 until February 1998. From 1987 to 1992, Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending law school, Mr. Brigham worked as a landman for a short period of time for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board. A. LANCE LANGFORD joined Brigham as Manager of Operations in 1995 and served as Vice President--Operations from January 1997 to March 2001, and as Senior Vice President--Operations 25 <Page> since March 2001. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University. JEFFERY E. LARSON joined Brigham in 1997 and served as Vice President--Exploration from August 1999 to March 2001, and as Senior Vice President--Exploration since March 2001. Mr. Larson joined Brigham in October 1997 as Gulf Coast Exploration Manager in its Houston office where he co-managed Brigham's expansion into the onshore Gulf Coast province through the initiation and assemblage of 3-D seismic projects and drilling opportunities. In November 1998, Mr. Larson relocated to Brigham's corporate office in Austin where he assumed an expanded role in directing Brigham's exploration activities in the Anadarko Basin, in addition to the further advancement of its Gulf Coast activities. Prior to joining Brigham, Mr. Larson was an explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities. Mr. Larson worked at Burlington for seven years in various roles of increasing responsibility within its exploration and production departments. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and Research Scientist. He has a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana. 26 <Page> PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Brigham's common stock has been publicly traded on The NASDAQ Stock Market(SM) under the symbol "BEXP" since Brigham's initial public offering effective May 8, 1997. The following table summarizes the high and low sales prices of Brigham's common stock on NASDAQ for each quarterly period during the past two fiscal years: <Table> <Caption> 2000 2001 ------------------- ------------------- HIGH LOW HIGH LOW -------- -------- -------- -------- First Quarter................................... $2.88 $1.47 $5.97 $3.38 Second Quarter.................................. $2.88 $1.88 $4.62 $3.25 Third Quarter................................... $3.50 $2.00 $5.11 $2.50 Fourth Quarter.................................. $6.00 $2.00 $3.48 $2.28 </Table> The closing market price of Brigham's common stock on March 22, 2002 was $3.55 per share. As of March 22, 2002, there were an estimated 112 record owners of Brigham's common stock. No dividends have been declared or paid on Brigham's common stock to date. Brigham intends to retain all future earnings for the development of its business. In addition, the Senior Credit Facility and the Subordinated Notes Facility restrict Brigham's ability to pay dividends on its common stock. Brigham is obligated to pay dividends on its Series A Preferred Stock which may be paid, at Brigham's option, in cash at a rate of 6% per annum or in additional shares of Series A Preferred Stock at a rate of 8% per annum for a period of five years. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Equity Placements Stock--Series A Preferred Stock" and "--Liquidity and Capital Resources--Equity Placements Stock--Additional Series A Preferred Stock") 27 <Page> ITEM 6. SELECTED FINANCIAL DATA The following selected consolidated financial data should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Brigham's consolidated financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data." <Table> <Caption> YEAR ENDED DECEMBER 31, ---------------------------------------------------- 1997 1998 1999 2000 2001 -------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA: Revenues: Oil and natural gas sales................................... $ 9,184 $ 13,799 $ 14,992 $ 19,143 $ 32,293 Other revenue............................................... 637 390 285 69 255 -------- -------- -------- -------- -------- Total revenues............................................ 9,821 14,189 15,277 19,212 32,548 Costs and expenses: Lease operating............................................. 1,151 2,172 2,259 2,139 3,486 Production taxes............................................ 549 850 968 1,786 1,511 General and administrative.................................. 3,570 4,672 3,481 3,100 3,638 Depletion of oil and natural gas properties................. 2,743 8,483 7,792 7,920 13,211 Depreciation and amortization............................... 694 785 526 620 677 Capitalized ceiling impairment.............................. -- 25,926 -- -- -- -------- -------- -------- -------- -------- Total costs and expenses.................................. 8,707 42,888 15,026 15,565 22,523 -------- -------- -------- -------- -------- Operating income (loss)................................... 1,114 (28,699) 251 3,647 10,025 Other income (expense): Interest expense, net....................................... (1,190) (5,968) (9,697) (9,906) (6,681) Interest income............................................. 145 136 176 108 264 Other income (expense)...................................... -- -- (163) (9,504) 8,080 Loss on sale of oil and natural gas properties.............. -- -- (12,195) -- -- -------- -------- -------- -------- -------- Total other income (expense).............................. (1,045) (5,832) (21,879) (19,302) 1,663 -------- -------- -------- -------- -------- Income (loss) before income taxes and extraordinary item.... 69 (34,531) (21,628) (15,655) 11,688 Income tax benefit (expense)................................ (1,186) 1,186 -- -- -- -------- -------- -------- -------- -------- Income (loss) before extraordinary item................... (1,117) (33,345) (21,628) (15,655) 11,688 Extraordinary item--gain on refinancing of debt, net of tax....................................................... -- -- -- 32,267 -- -------- -------- -------- -------- -------- Net income (loss)......................................... (1,117) (33,345) (21,628) 16,612 11,688 Preferred dividend and accretion............................ -- -- -- 275 2,450 -------- -------- -------- -------- -------- Net income (loss) available to common stockholders........ $ (1,117) $(33,345) $(21,628) $ 16,337 $ 9,238 ======== ======== ======== ======== ======== Net income (loss) per share--basic.......................... $ (0.10) $ (2.64) $ (1.53) $ 1.01 $ 0.58 Net income (loss) per share--diluted........................ (0.10) (2.64) (1.53) 1.01 0.54 Weighted average shares outstanding--basic.................. 11,081 12,626 14,152 16,241 15,988 Weighted average shares outstanding--diluted................ 11,081 12,626 14,152 16,241 17,243 STATEMENT OF CASH FLOWS DATA: Net cash provided (used) by operating activities............ $ 9,806 $ 14,774 $ 2,578 $ (4,635) $ 18,922 Net cash provided (used) by investing activities............ (57,300) (86,227) 1,644 (26,071) (33,571) Net cash provided (used) by financing activities............ 47,748 72,321 (4,049) 28,801 18,924 OTHER FINANCIAL DATA: Oil and natural gas capital expenditures.................... $ 57,170 $ 85,207 $ 25,560 $ 28,910 $ 34,532 </Table> <Table> <Caption> AS OF DECEMBER 31, ---------------------------------------------------- 1997 1998 1999 2000 2001 -------- -------- -------- -------- -------- BALANCE SHEET DATA: Cash and cash equivalents................................... $ 1,701 $ 2,569 $ 2,742 $ 837 $ 5,112 Oil and natural gas properties, net......................... 84,294 134,317 112,066 129,490 151,891 Total assets................................................ 92,519 150,516 125,683 146,911 173,408 Long-term debt.............................................. 32,000 94,786 97,341 82,000 91,721 Series A Preferred Stock.................................... -- -- -- 8,558 16,614 Total stockholders' equity.................................. 43,313 24,681 8,998 34,757 49,601 </Table> 28 <Page> ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW In 1999, Brigham outlined a business strategy that would enable the recognition of the inherent value of its 3-D delineated prospect inventory and would provide significant improvement in its financial and operating results. This business strategy includes the following elements: - FOCUS THE MAJORITY OF CAPITAL RESOURCES TOWARD DRILLING ACTIVITIES WITHIN ITS FIVE FOCUS PLAYS TO GENERATE GROWTH IN PROVED RESERVES, PRODUCTION VOLUMES AND CASH FLOW. In 2001, relative to 2000, Brigham grew its oil and natural gas reserves by 17%, its equivalent production volumes by 45%, and its operating cash flow before changes in working capital by 111%. The Company's net completion rate was 89% for 2001 and was 81% for the three-year period ended 2001. All-sources finding cost for 2001 were $1.23 per Mcfe and were $1.00 per Mcfe for the three-year period ended 2001. Average drilling finding cost for 2001 were $0.93 per Mcfe and, since 1999, have been $0.74 per Mcfe. This focus has also resulted in the discovery of four potentially substantial fields. - IMPROVE CASH FLOW MARGINS AND RETURN ON INVESTED CAPITAL BY CONTROLLING COSTS. For 2001, discretionary unit operating costs were $0.74 per Mcfe, down 28% from $1.03 per Mcfe in 1998. This lower cost structure, combined with higher oil and gas revenue per unit of equivalent production, has resulted in an increase in gross profit per unit of equivalent production from $0.98 per Mcfe in 1998 to $2.50 per Mcfe in 2001. In addition, Brigham's reduced debt levels have led to a decline in net interest expense (net of interest income) per unit of production, from $1.52 per Mcfe in 1999 and $1.48 per Mcfe in 2000 to $0.67 per Mcfe in 2001. As a result, unit cash flow improved from ($0.15) per Mcfe in 1999 and $0.37 per Mcfe in 2000 to $1.83 per Mcfe in 2001, and cash flow margins improved from (6%) in 1999 and 13% in 2000 to 54% in 2001. - ALLOCATE A HIGHER PERCENTAGE OF DRILLING CAPITAL TOWARD THE DEVELOPMENT OF ITS PRIOR DISCOVERIES. Prior to 2000, a majority of Brigham's drilling capital expenditures were allocated to exploration-oriented projects. Due to the success of Brigham's past exploration drilling programs and the discovery of the Home Run Field and Mills Ranch Field, over 50% of the Company's 2001 drilling capital expenditures were developmental. - EXECUTE AN ACTIVE, HIGH POTENTIAL EXPLORATION DRILLING PROGRAM WITHIN ITS LARGE INVENTORY OF EXPLORATION PROSPECTS. In 1999, Brigham began focusing its drilling investments in the five plays in its three core provinces that the Company believed provided excellent 3-D delineated drilling economics. These focus plays include the Vicksburg and Frio trends in the onshore Texas Gulf Coast, the Springer and Hunton trends in the Anadarko Basin and the Horseshoe Atoll trend of West Texas. In these trends, Brigham has completed 25 wells in its 28 most recent attempts, and in the process discovered the Home Run Field in 1999, the Mills Ranch Field in 2000 and the Triple Crown Field and Providence Field in 2001. For 2001, approximately 44% of Brigham's drilling capital was spent on exploration drilling and approximately 85% was allocated to Brigham's five focus plays where the Company has achieved significant recent drilling success. - LEVERAGE PRIOR INVESTMENTS TO MITIGATE RISK AND ENHANCE ITS CORPORATE RATE OF RETURN. In addition to supporting a multi-year drilling program, Brigham believes that its substantial investments in 3-D seismic data and undeveloped acreage provide a significant advantage in attracting participants to invest in its projects. Often times, Brigham can recoup a portion of its initial capital investment on a promoted basis. Historically, Brigham has been effective at raising capital and attaining promoted working interests in its 3-D seismic projects and prospects, thereby utilizing leverage extensively to manage its risk and enhance its corporate rate of return. Given the depth 29 <Page> of Brigham's land and 3-D seismic inventory, and in particular the Company's inventory of 3-D delineated drilling prospects, Brigham plans to again leverage its investments in 2002. 2001 RESULTS The year ended December 31, 2001, was a highly successful year for Brigham. Driven by the Company's active drilling program, total production for 2001 increased 45% over total production for 2000, to average 26.6 MMcfe per day. Compared to 2000, revenue from the sale of natural gas and oil increased 69% to $32.3 million, EBITDA increased 90% to $22.7 million, net interest expense decreased 33% to $6.7 million, and operating cash flow before working capital items increased 111% to $18.1 million. At year-end 2001, Brigham's proved reserves totaled 3.7 MMbbls of oil and 89 Bcf of natural gas. Proved reserves were 80% natural gas, 49% proved developed and distributed 46% in its Texas Gulf Coast province, 43% in the Anadarko Basin and the remaining 11% in its West Texas province. For 2001, the Company completed 27 (10.4 net) wells in 33 (11.7 net) attempts for a completion rate of 82% (89% net). The Company spent $27.0 million on drilling and added 29 Bcfe in proved reserves, replacing 306% of its 2001 production of 9.6 Bcfe. 2002 OUTLOOK The Company's capital spending budget for 2002 is $23.7 million. The majority of Brigham's planned 2002 expenditures will be directed toward the drilling of its prospect inventory in a continued effort to focus resources on its primary objective of growing production volumes and cash flow. For 2002, Brigham expects to drill 26 wells with an average working interest of 32%. Capitalizing on the prior discovery of the Home Run Field, Mills Ranch Field, Triple Crown Field and Providence Field, approximately 80% of Brigham's 2002 drilling expenditures are allocated to development drilling. Spending will be funded by Brigham's 2002 discretionary cash flow, availability under its Subordinated Notes Facility and by its beginning cash balance. As a result, capital expenditures for 2002 are expected to be down approximately 34% from 2001. This decline is primarily attributable to lower forecasted oil and natural gas prices and is subject to change if market conditions shift. In the event that commodity prices decrease, Brigham may be required to curtail or delay some of its planned activities. 30 <Page> RESULTS OF OPERATIONS The following table sets forth certain operating data for the periods presented. <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Production (in thousands): Natural gas (MMcf)................................ 6,766 4,431 4,197 Oil (MBbls)....................................... 468 362 346 Natural gas equivalent (MMcfe).................... 9,573 6,600 6,270 % Natural gas..................................... 71% 67% 67% Average sales prices per unit(1): Natural gas (per Mcf)............................. $ 3.11 $ 1.94 $ 2.11 Oil (per Bbl)..................................... 24.05 29.17 17.79 Natural gas equivalent (per Mcfe)................. 3.37 2.90 2.39 Costs and expenses per Mcfe: Lease operating................................... $ 0.36 $ 0.32 $ 0.36 Production taxes.................................. 0.16 0.27 0.15 General and administrative........................ 0.38 0.47 0.56 Depletion of oil and natural gas properties....... 1.38 1.20 1.24 </Table> - ------------------------ (1) Reflects the effects of Brigham's hedging activities. See "--Other Matters--Derivative Instruments" YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 PRODUCTION. Net equivalent production volumes for 2001 were 9.6 Bcfe compared to 6.6 Bcfe in 2000. Average net daily equivalent production volumes for 2001 increased 45% to 26.6 MMcfe per day from 18.3 MMcfe per day in 2000. This increase is the result of additional production related to wells completed during 2001 and is offset partly by the natural decline of existing production. Natural gas production represented 71% of total equivalent production volumes in 2001 compared to 67% in 2000. Natural gas production increased 53% from 4,431 MMcf in 2000 to 6,766 MMcf in 2001 and average net daily production volumes for natural gas increased from 12.3 MMcf per day in 2000 to 18.8 MMcf per day in 2001. Oil production increased by 29% from 362 MBbls in 2000 to 468 MBbls in 2001. Average net daily production volumes for oil during 2001 were 1,300 barrels per day compared to 1,006 barrels per day in 2000. REVENUE FROM THE SALE OF NATURAL GAS AND OIL. Natural gas and oil sales increased 69% from $19.1 million in 2000 to $32.3 million in 2001. Higher net equivalent production volumes accounted for $7.7 million of this increase while a 16% increase in the average equivalent sales price received for natural gas and oil sales accounted for $5.5 million of the increase. The average realized price for natural gas increased 60% from $1.94 per Mcf in 2000 to $3.11 per Mcf in 2001. Revenues from the sale of natural gas increased 61% from $18.0 million in 2000 to $29.0 million in 2001. Cash settlements on natural gas hedging contracts of $8.0 million ($1.18 per Mcf) negatively impacted Brigham's average realized natural gas sales price and revenues in 2001 compared to $9.4 million ($2.12 per Mcf) in cash settlements on natural gas hedging contracts in 2000. See "--Other Matters--Derivative Instruments" The average realized price for oil decreased 18% from $29.17 per barrel in 2000 to $24.05 per barrel in 2001. Revenue from the sale of oil increased 7% from $10.7 million in 2000 to $11.4 million in 2001. Revenues from the sale of oil and Brigham's average realized oil price were negatively affected 31 <Page> by hedging losses of $153,000 ($0.33 per barrel) in 2001 compared to hedging loses of $107,000 ($0.30 per barrel) in 2000. See "--Other Matters--Derivative Instruments" OTHER REVENUE. Other revenue increased 270% from $69,000 in 2000 to $255,000 in 2001. This increase is related to an increase in transportation revenue that Brigham receives from other parties for using its pipelines. LEASE OPERATING EXPENSES. Lease operating expenses increased 67% from $2.1 million in 2000 to $3.5 million in 2001. On a per unit of production basis, lease operating expense increased 13% from $0.32 per Mcfe in 2000 to $0.36 per Mcfe in 2001. The increase in lease operating expense was related to higher than expected charges for well repair and maintenance, increased production volumes from a greater total well count, and higher overall service costs. PRODUCTION TAXES. Production taxes decreased 17% from $1.8 million ($0.27 per Mcfe) in 2000 to $1.5 million ($0.16 per Mcfe) in 2001. This decrease is primarily related to production tax refunds on wells that qualify for reduced severance tax rates and resulted in a decrease in Brigham's effective production tax rate from 6.2% of pre-hedge oil and natural gas sales in 2000 to 3.7% in 2001. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased 16% from $3.1 million in 2000 to $3.6 million in 2001. This increase was primarily due to an increase in employee payroll and benefit expenses, office expenses, public company expenses and contract and professional expenses. On a per unit of equivalent production basis, general and administrative expenses decreased by 19% from $0.47 per Mcfe in 2000 to $0.38 per Mcfe in 2001. This decrease is primarily due to increased production volumes for 2001. DEPLETION OF OIL AND NATURAL GAS PROPERTIES. Depletion of oil and natural gas properties increased 67% from $7.9 million in 2000 to $13.2 million in 2001. Of this increase, $4.1 million was attributable to higher production volumes and $1.2 million was due to an increase in the depletion rate per unit of production. On a per unit of equivalent production basis, depletion expense increased 15% from $1.20 per Mcfe in 2000 to $1.38 per Mcfe in 2001. The increase in the depletion rate per unit is primarily due to an increase in the estimated cost required to fully develop Brigham's Home Run Field. INTEREST EXPENSE. Interest expense decreased from $9.9 million in 2000 to $6.7 million in 2001 due to a lower weighted average outstanding debt balance and a lower effective interest rate for 2001. Brigham's weighted average outstanding debt balance decreased 7% from $97.4 million in 2000 to $90.6 million in 2001. The reduction in debt was primarily attributable to the November 2000 refinancing of its senior subordinated notes due 2003. See "--Liquidity and Capital Resources--Refinancing Transactions" The effective annual interest rate on Brigham's total outstanding indebtedness decreased from 12.7% in 2000 to 9.3% in 2001. In addition, interest expense for 2001 included (i) $721,000 in interest expense that was paid in kind through the issuance of additional debt in lieu of cash, and (ii) $1.4 million of non-cash charges related to the amortization of deferred loan fees. Borrowings under Brigham's Senior Credit Facility had an interest rate of 4.9% at December 31, 2001. OTHER INCOME (EXPENSE). Other income (expense) increased from a $9.5 million expense in 2000 to $8.1 million in income for 2001. Brigham recognizes other income or expense primarily related to the change in the fair market value and the related cash flows of certain oil and natural gas derivative contracts that do not qualify for hedge accounting treatment. Other income (expense) in 2001 included (i) $9.7 million of non-cash income related to the change in the fair market value of derivative contracts during the period, and (ii) $1.5 million of expenses related to cash settlements incurred during the period pursuant to derivative contracts. Other expense in 2000 included (i) $8.9 million of non-cash expenses related to the change in the fair market value of derivative contracts during the 32 <Page> period, and (ii) $620,000 of expenses related to cash settlements incurred during the period pursuant to derivative contracts. YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 PRODUCTION. Net equivalent production volumes for 2000 were 6.6 Bcfe compared to 6.3 Bcfe in 1999. Brigham's average net daily production volumes for 2000 increased 5% to 18.3 MMcfe per day compared to 17.4 MMcfe per day for 1999. Natural gas production represented 67% of total equivalent production during 1999 and 2000. Natural gas production volumes for 2000 increased 6% from 4,197 MMcf in 1999 to 4,431 MMcf. Average net daily production volume for natural gas was 12.3 MMcf per day in 2000 compared to 11.7 MMcf per day for 1999. Natural gas production volumes for 1999 include 442 MMcf attributable to properties sold by Brigham in June 1999. Excluding production attributable to these divested properties, natural gas production volumes increased 18% in 2000 as compared with adjusted production volumes in 1999. Oil production volumes for 2000 increased 5% from 346 MBbls in 1999 to 362 MBbls. Average net daily production volume for oil during 2000 were 1,006 barrels per day compared to 961 barrels per day for 1999. Oil production volumes for 1999 include 22 MBbls attributable to properties sold by Brigham in June 1999. Excluding production attributable to these divested properties, oil production volumes increased 12% in 2000 as compared with adjusted production volumes in 1999. REVENUE FROM THE SALE OF NATURAL GAS AND OIL. Revenue from the sale of natural gas and oil increased 27% from $15.0 million in 1999 to $19.1 million in 2000. A 21% increase in the average equivalent sales price received for natural gas and oil sales accounted for $3.4 million and an increase in net equivalent production volumes accounted for $780,000. The average price received for natural gas decreased 8% from $2.11 per Mcf in 1999 to $1.94 per Mcf in 2000. Revenues from the sale of natural gas increased 98% from $9.1 million in 1999 to $18.0 million in 2000. Cash settlements on natural gas hedging contracts of $9.4 million ($2.12 per Mcf) negatively impacted Brigham's average realized natural gas sales price and revenues for 2000 versus a $486,000 ($0.12 per Mcf) reduction in the realized natural gas sales price and revenues in 1999. See "--Other Matters--Derivative Instruments" The average realized price for oil increased 64% from $17.79 per Bbl in 1999 to $29.17 per Bbl in 2000. Revenue from the sale of oil increased 75% from $6.1 million in 1999 to $10.7 million in 2000. Revenues from the sale of oil were negatively affected by hedging losses of $107,000 ($0.30 per barrel) in 2000. There were no gains or losses on crude oil hedges during 1999. See "--Other Matters--Derivative Instruments" OTHER REVENUE. Other revenue decreased 76% from $285,000 in 1999 to $69,000 in 2000. Brigham recognizes workstation revenue as industry participants in its seismic programs are charged an hourly rate for the work Brigham performs on its 3-D seismic interpretation workstations. This decrease in 2000 is primarily attributable a reduction in the volume of 3-D seismic interpretation activity billable to industry participants as compared with 1999. LEASE OPERATING EXPENSES. Lease operating expenses decreased 9% from $2.3 million ($0.36 per Mcfe) in 1999 to $2.1 million ($0.32 per Mcfe) in 2000. This decrease was primarily due to a decrease in the number of producing wells in 2000 as compared with 1999 that was attributable to Brigham's June 1999 property divestitures and the plugging and abandonment of certain uneconomic wells. PRODUCTION TAXES. Production taxes increased 86% from $968,000 ($0.15 per Mcfe) in 1999 to $1.8 million ($0.27 per Mcfe) in 2000 primarily due to higher average oil and natural gas sales prices and revenues before the effects of hedging gains or losses. The effective average production tax rate decreased from 6.3% of pre-hedge oil and natural gas sales in 1999 to 6.2% in 2000 resulting primarily from changes in the geographic distribution of Brigham's producing wells. 33 <Page> GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses decreased 11% from $3.5 million in 1999 to $3.1 million in 2000. This decrease was primarily attributable to the reduction of various administrative costs, including lower office rent due to the subleasing of a portion of Brigham's headquarters space, reduced equipment rental and maintenance expenses, and lower employee payroll and benefits expenses. DEPLETION OF OIL AND NATURAL GAS PROPERTIES. Depletion of oil and natural gas properties increased 2% from $7.8 million in 1999 to $7.9 million in 2000. Of this increase, $396,000 was attributable to higher production volumes, partially offset by $268,000 due to the reduction in the depletion rate per unit of production. On a per unit of equivalent production basis, depletion expense decreased 3% from $1.24 per Mcfe in 1999 to $1.20 per Mcfe in 2000. The decrease in depletion rate per unit of production was primarily the result of the addition of oil and natural gas reserves at lower average capital costs due to improved average finding costs during 2000. INTEREST EXPENSE. Interest expense increased from $9.7 million in 1999 to $9.9 million in 2000 due to a higher effective interest rate that was partly offset by a lower weighted average outstanding debt balance. The effective annual interest rate on Brigham's total outstanding indebtedness increased slightly from 12.6% in 1999 to 12.7% in 2000. Brigham's weighted average outstanding debt balance decreased 2% from $99.5 million in 1999 to $97.4 million in 2000. This reduction in debt was primarily attributable to Brigham's refinancing of its senior subordinated notes due 2003 in November 2000. In addition, interest expense in 2000 included (i) $4.6 million of interest expense that was paid in kind through the issuance of additional debt in lieu of cash, and (ii) $2.0 million of non-cash charges related to the amortization of deferred loan fees and the amortization of discount on senior subordinated notes. Borrowings under Brigham's Senior Credit Facility had an effective annual interest rate of 9.7% for year-end December 31, 2000. In November 2000, Brigham refinanced its senior subordinated notes due 2003 at a substantial discount to the principal amount then outstanding. OTHER INCOME (EXPENSE). Other expense increased from $163,000 in 1999 to $9.5 million in 2000. Brigham recognizes other income or expense primarily related to the change in the fair market value and the related cash flows of certain oil and natural gas derivative contracts that do not qualify for hedge accounting treatment. Other income (expense) in 2000 included (i) $8.9 million of non-cash expense related to the change in the fair market value of these derivative contracts during the period, and (ii) $620,000 of expenses related to cash settlements incurred during the period pursuant to these derivative contracts. Other income (expense) in 1999 included (i) $115,000 of non-cash expenses related to the change in the fair market value of these derivative contracts during the period, and (ii) $48,000 of expenses related to cash settlements incurred during the period pursuant to these derivative contracts. EXTRAORDINARY GAIN ON REFINANCING OF SENIOR SUBORDINATED NOTES. In November 2000, Brigham repurchased all of the debt and equity securities in Brigham held by affiliates of Enron North America (the "Enron Affiliates") at a substantial discount. With a portion of the proceeds from two new financing transactions, Brigham repurchased all of the Enron Affiliates' interests in Brigham, which included (i) $51.2 million of senior subordinated notes due 2003 (which bore interest at annual rates of 12% to 14%) and associated accrued interest obligations, (ii) warrants to purchase an aggregate of one million shares of common stock at $2.43 per share, and (iii) 1,052,632 shares of common stock (collectively, the "Enron Securities"), for total cash consideration of $20 million. As a result of the repurchase of the senior subordinated notes due 2003 at a discount to the principal amount outstanding, Brigham recorded an extraordinary gain of $32.3 million in the fourth quarter of 2000. 34 <Page> LIQUIDITY AND CAPITAL RESOURCES Brigham's primary sources of capital have been credit facility and other debt borrowings, public and private equity financings, the sale of interests in projects and properties and funds generated by operations. Brigham's primary capital requirements are 3-D seismic acquisition, processing and interpretation costs, land acquisition costs and drilling expenditures. The following table summarizes the Company's contractual cash obligations at December 31, 2001 and the effect such obligations are expected to have on its liquidity and cash flow in future periods: <Table> <Caption> PAYMENTS DUE BY YEAR --------------------------------------------------------------- TOTAL CONTRACTUAL OBLIGATIONS: OUTSTANDING 2002 2003 - 2004 2005 - 2006 THEREAFTER - ------------------------ ----------- -------- ----------- ----------- ---------- (IN THOUSANDS) Senior Credit Facility(1)................... $75,000 $ -- $75,000 $ -- $ -- Subordinated Notes Facility(2).............. 16,721 -- -- 16,721 -- Capital Leases(3)........................... 30 30 -- -- -- Non-cancelable Operating Leases(4).......... 4,828 864 1,762 1,762 440 ------- ---- ------- ------- ---- Total Contractual Cash Obligations.......... $96,579 $894 $76,762 $18,483 $440 ======= ==== ======= ======= ==== </Table> - ------------------------ (1) The $75 million shown as scheduled for payment in 2003 represents the December 31, 2001 balance outstanding on the Senior Credit Facility. The Company expects to renew as this Senior Credit Facility comes due. See "--Liquidity and Capital Resources--Senior Credit Facility" and Note 5 of Consolidated Financial Statements (2) Through November 2002, up to 50% of Brigham's interest payment obligation on its Subordinated Notes Facility can be satisfied by payment-in-kind ("PIK") through the issuance of additional SCI Notes to Shell Capital Inc. in lieu of cash. See "--Liquidity and Capital Resources Refinancing Transactions--Subordinated Notes Facility" and Note 5 of Consolidated Financial Statements (3) See discussion in Note 8 of Consolidated Financial Statements (4) See discussion in Note 11 of Consolidated Financial Statements SENIOR CREDIT FACILITY In January 1998, Brigham entered into a revolving credit agreement (as amended, the "Senior Credit Facility"), which provided for an initial borrowing availability of $75 million. The Senior Credit Facility was amended in March 1999 to reduce the borrowing availability, extend the date of borrowing base redetermination, modify certain financial covenants, include certain additional covenants that place restrictions on Brigham's ability to incur certain capital expenditures, and to increase the interest rate on outstanding borrowings. As a result of the completion of the majority of Brigham's strategic initiatives to improve its capital resources, including its June 1999 property divestitures and the application of the net sales proceeds to reduce borrowings outstanding under the Senior Credit Facility, Brigham and its senior lenders entered into an amendment to the Senior Credit Facility in July 1999. This amendment provided Brigham with borrowing availability of $56 million. As consideration for this amendment, in July 1999 Brigham issued to its senior lenders warrants to purchase an aggregate of 1,000,000 shares of Brigham common stock at an exercise price of $2.25 per share. The warrants have a seven-year term from the date of issuance and are exercisable at the holders' option at any time. An estimated value of $1.2 million was attributed to these warrants by Brigham and was recognized as additional deferred loan fees that will be amortized and included in interest expense over the remaining period to maturity of the Senior Credit Facility. 35 <Page> In February 2000, Brigham entered into an amended and restated Senior Credit Facility with its existing senior lenders and a new senior lender. The Senior Credit Facility was further amended in October 2000. The amended and restated Senior Credit Facility provides Brigham with $75 million in borrowing availability for a three-year term. In December 2001, Brigham extended the maturity of the amended and restated Senior Credit Facility by one year to December 31, 2003. As a result of the February 2000 amendments, $30 million of the Senior Credit Facility held by one of the lenders is convertible into shares of Brigham common stock (the "Convertible Notes") in the following amounts and prices: (i) $10 million is convertible at $3.90 per share, (ii) $10 million is convertible at $6.00 per share and (iii) $10 million is convertible at $8.00 per share. As of December 31, 2001, Brigham had $75 million in borrowings outstanding under the Senior Credit Facility, of which the Convertible Notes were $30 million. In connection with Brigham's refinancing of its subordinated notes due 2003 (see "--Subordinated Notes" and "--Refinancing Transactions") in October 2000, Brigham entered into an amendment to the Senior Credit Facility that, among other things, permitted the issuance of new subordinated notes and new preferred stock to provide funding for the repurchase of the subordinated notes due 2003 and equity interests in Brigham held by the Enron Affiliates. In addition, the minimum interest coverage ratio test of the Senior Credit Facility was amended to reflect Brigham's expected cash flow and interest expense beginning in the fourth quarter of 2000 subsequent to the Refinancing Transactions, and Brigham conditionally waived certain rights to force conversion of the portion of the borrowings under the Senior Credit Facility that are convertible at $3.90 per share. If the Senior Credit Facility is repaid at maturity or is prepaid prior to maturity without payment of cash premiums, the warrants to purchase Brigham common stock issued to the new participant in the Senior Credit Facility become exercisable. Further, to the extent Brigham chooses to prepay any of the Convertible Notes without the warrants becoming exercisable, and also assuming the lender chooses not to convert to equity upon notice of such prepayment, Brigham will be required to a pay a premium above the face value of the Convertible Notes to the lender. Such premium amounts would range from 150% to 110%, depending upon the timing of the prepayment. Such prepayment, however, would require prior approval of the original lenders to the Senior Credit Facility. In addition, certain financial covenants of the Senior Credit Facility were amended or added in the July 1999, February 2000 and October 2000 amendments. In connection with the February 2000 amendment, Brigham reset the price of the warrants previously issued to its existing senior lenders to purchase one million shares of Brigham common stock from the then current exercise price of $2.25 per share to $2.02 per share. Principal outstanding under the Senior Credit Facility is due at maturity on December 31, 2003, with interest due monthly for base rate tranches or periodically as LIBOR tranches mature. The annual interest rate for borrowings under the Senior Credit Facility is either the lender's base rate or LIBOR plus 3.00%, at Brigham's option. The interest rate on the Senior Credit facility at December 31, 2001 was 4.9%. Obligations under the Senior Credit Facility are secured by substantially all of Brigham's oil and natural gas properties and other tangible assets. At March 22, 2002, Brigham had $75 million in borrowings outstanding under the Senior Credit Facility, which bear an interest rate of approximately 4.9%. The Senior Credit Facility has certain financial covenants, including current and interest coverage ratios. Brigham and its senior lenders effected the amendments to the Senior Credit Facility described above in part to enable Brigham to comply with certain financial covenants of the Senior Credit Facility, including the minimum current ratio minimum interest coverage ratio and the limitation on capital expenditures related to seismic and land activities. Should Brigham be unable to comply with certain of the financial or other covenants, its senior lenders may be unwilling to waive compliance or amend the covenants in the future. In such instance, Brigham's liquidity may be adversely affected, 36 <Page> which could in turn have an adverse impact on its future financial position and results of operations. At December 31, 2001 and for the year then ended, Brigham was in compliance with the covenants. SUBORDINATED NOTES In August 1998, Brigham issued $50 million of debt and equity securities to affiliates of Enron Corp. The securities issued by Brigham in connection with this financing transaction included: (i) $40 million of subordinated notes due 2003, (ii) warrants to purchase an aggregate of one million shares of Brigham common stock at a price of $10.45 per share, and (iii) 1,052,632 shares of Brigham common stock at a price of $9.50 per share. As described below, Brigham repurchased the subordinated notes due 2003, together with all equity interests in Brigham held by the Enron Affiliates, for $20 million in cash in November 2000. See "--Refinancing Transactions") REFINANCING TRANSACTIONS On October 31, 2000 and November 1, 2000, Brigham entered into a series of financing agreements to provide funding (i) to repurchase all the debt and equity securities in Brigham held by affiliates of Enron North America at a substantial discount, and (ii) to continue and expand Brigham's planned drilling program. FINANCING AND REPURCHASE TRANSACTIONS. Brigham raised an aggregate of $40 million in these financing transactions through the issuance of (i) $20 million in new subordinated notes and warrants to purchase Brigham common stock to Shell Capital Inc., and (ii) $20 million in new mandatorily redeemable preferred stock and warrants to purchase Brigham common stock to affiliates of Credit Suisse First Boston (USA), Inc. (the "CSFB Affiliates"). With a portion of the proceeds from these two financing transactions, Brigham purchased all of the Enron Affiliates' interests in Brigham, which included (i) $51.2 million of outstanding subordinated notes due 2003 and associated accrued interest obligations, (ii) warrants to purchase one million shares of common stock at $2.43 per share, and (iii) 1,052,632 shares of common stock (collectively, the "Enron Securities"), for total cash consideration of $20 million. The remaining approximate $17.5 million in net capital availability raised from these financing transactions, after the repurchase of the Enron Securities and the payment of fees and expenses, was available for Brigham to fund its planned drilling program. SUBORDINATED NOTES FACILITY. The $20 million of new subordinated notes issued to Shell Capital Inc. (the "SCI Notes") bear interest at 10.75% per annum and have no principal repayment obligations until maturity in 2005. The SCI Notes will be issued pursuant to a multi-draw facility (the "Subordinated Notes Facility") at borrowing increments of at least $1 million, and such funds cannot be redrawn once they have been repaid. At Brigham's option, up to 50% of the interest payments on the SCI Notes during the first two years can be satisfied by payment-in-kind ("PIK") through the issuance of additional SCI Notes in lieu of cash. The SCI Notes are secured obligations ranking junior to Brigham's existing $75 million Senior Credit Facility. The SCI Notes have a five-year maturity, are redeemable at Brigham's option for face value at anytime, and have certain financial and other covenants. The warrants to purchase an aggregate of 1,250,000 shares of Brigham common stock issued to Shell Capital Inc. (the "SCI Warrants") have a term of seven years, an exercise price of $3.00 per share and a cashless exercise feature. For financial reporting purposes, the SCI Warrants were valued using the Black-Scholes valuation model and the estimated value of $2.9 million was recorded as deferred loan costs that will be amortized over the five-year term of the SCI Notes. During 2001 Brigham exercised its option to PIK 50% of the interest payments on the SCI Notes resulting in the issuance of an additional $721,000 in SCI Notes. As of December 31, 2001 and March 22, 2002, Brigham had $16.7 million and $20.7 million, respectively, of borrowings outstanding under the 37 <Page> Subordinated Notes Facility and $4.0 million and $0.0 million, respectively, in additional borrowing capacity. The SCI Notes contain various restrictive covenants and compliance requirements, which include minimum current ratio, interest coverage ratio, limitations on capital expenditures related to seismic and land activities, and various other financial covenants. At December 31, 2001 and for the year then ended, Brigham was in compliance with the covenants. SERIES A PREFERRED STOCK. See "--Liquidity and Capital Resources--Equity Placements--Series A Preferred Stock" SALES OF INTERESTS IN PROJECTS AND OIL AND NATURAL GAS PROPERTIES DUKE PROJECT FINANCING. In February 1999, Brigham entered into a project financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund the continued exploration of five Anadarko Basin projects covered by approximately 200 square miles of 3-D seismic data acquired in 1998. In this transaction, Brigham conveyed 100% of its working interest (land and seismic) in these project areas to a newly formed limited liability company (the "Brigham-Duke LLC") for total consideration of $10 million. Brigham entered into this project financing arrangement to enable it to recoup substantially all of its pre-seismic land and seismic data acquisition costs incurred in these project areas and to provide the capital to fund the drilling of the first six wells within these projects. Brigham served as the managing member of the Brigham-Duke LLC with a 1% interest, and Duke was the sole remaining member with a 99% interest. Pursuant to the terms of the Brigham-Duke LLC agreement, Brigham paid 100% of the drilling and completion costs for all wells drilled by the Brigham-Duke LLC within the designated project areas in exchange for a 70% working interest in the wells (and their allocable drilling and spacing units), with the remaining 30% working interest remaining in the Brigham-Duke LLC, subject in each instance to proportionate reduction by any ownership rights held by third parties. Upon 100% project payout, Brigham had the right to back-in for 80% of the Brigham-Duke LLC's working interest in all of the then producing wells (and their allocable drilling and spacing units) and a 94% working interest in any wells (and their allocable drilling and spacing units) drilled after payout within the designated project areas governed by the Brigham-Duke LLC agreement, thereby increasing Brigham's effective working interest in the Brigham-Duke LLC wells from 70% to 94%. In February 2001, Duke, as majority member of the Brigham-Duke LLC, elected to dissolve the Brigham-Duke LLC. As a result of the dissolution of the Brigham-Duke LLC, the remaining undeveloped land and seismic data in the Brigham-Duke LLC project areas was unconditionally owned by Duke. In December 2001, Brigham recorded a loss of $94,000 on its investment in the Brigham-Duke LLC. MID-1999 PROPERTY SALES. In June 1999, Brigham sold certain producing and non-producing oil and natural gas properties located in its Anadarko Basin province to two separate parties for a total of $17.1 million. The divested properties were located in two fields operated by third parties--the Chitwood Field in Grady County, Oklahoma (originally acquired by Brigham for $13.4 million in the Chitwood Acquisition in November 1997), and the Red Deer Creek Field in Roberts County, Texas. Brigham's independent reservoir engineers estimated net proved reserve volumes attributable to the properties as of June 1, 1999 of approximately 36 Bcfe, of which 33% were classified as proved developed producing reserves and 59% were natural gas. Brigham estimated that net production volumes from the divested properties were 2.8 MMcfe per day at the time of the sales. Brigham used the proceeds from these transactions to reduce borrowings under its credit facility, which contributed to an $8 million increase in borrowing availability under Brigham's then existing credit facility which was used to fund working capital needs and capital expenditures during the second half of 1999. The effective date of each transaction was June 30, 1999. 38 <Page> EQUITY PLACEMENTS VERITAS EQUITY ISSUANCES. On March 30, 1999, Brigham entered into an agreement with Veritas DGC Land, Inc. to exchange 1,002,865 shares of newly issued Brigham common stock valued at $3.50 per share for approximately $3.5 million of payment obligations due to Veritas in 1999 for certain seismic acquisition and processing services previously performed. In addition, this agreement provided for the payment by Brigham of up to $1 million in future seismic processing services to be performed by Veritas in newly issued shares of Brigham common stock valued at $3.50 per share, in the event that Brigham did not elect to pay for such services in cash. The settlement of these future seismic processing services was determined on a quarterly basis through September 30, 1999. Pursuant to this agreement, Brigham issued a total of 1,211,580 shares of common stock to Veritas to satisfy $4.2 million in aggregate payment obligations due to Veritas for seismic acquisition and processing services performed prior to 1999 and certain seismic processing services performed during 1999. PRIVATE PLACEMENT OF COMMON STOCK. On February 22, 2000, Brigham entered into an agreement to issue 2,195,122 shares of common stock and 731,707 warrants to purchase common stock for total consideration of $4.5 million in a private placement to a group of institutional investors led by affiliates of two members of Brigham's board of directors. The equity sale consisted of units that include one share of common stock priced at $2.0525 per share and one-third of a warrant to purchase Brigham common stock at an exercise price of $2.5625 per share with a three-year term. Pricing of this private equity placement was based on the average market price of Brigham common stock during a twenty trading day period prior to issuance. Net proceeds from this equity placement were used to fund a portion of Brigham's capital expenditures and working capital obligations during 2000. Warrants associated with this transaction will expire February 22, 2003. SERIES A PREFERRED STOCK. On November 1, 2000, $20 million of mandatorily redeemable preferred stock (the "Series A Preferred Stock") was issued to affiliates of Credit Suisse First Boston (USA), Inc., which bear dividends at a rate of 6% per annum if paid in cash and 8% per annum if paid-in-kind through the issuance of additional Series A Preferred Stock in lieu of cash. At Brigham's option, up to 100% of the dividend payments on the Series A Preferred Stock during the first five years (expiring November 2005) can be satisfied through the issuance of PIK dividends. The Series A Preferred Stock has a ten-year maturity and is redeemable at Brigham's option at 100% or 101% of par value (depending upon certain conditions) at anytime prior to maturity. Warrants, to purchase an aggregate of 6,666,667 shares of Brigham common stock were also issued to the CSFB Affiliates (the "Series A Warrants"), which have a term of ten years, an exercise price of $3.00 per share and must be exercised, if Brigham so requires, in the event that Brigham common stock trades at or above $5.00 per share for 60 consecutive trading days. The exercise price of the Series A Warrants is payable either in cash or in shares of Series A Preferred Stock, valued at liquidation value plus accrued dividends. If Brigham requires exercise of the Series A Warrants, proceeds from the exercise of the Series A Warrants will be used to fund the redemption of a similar value of then outstanding Series A Preferred Stock. For financial reporting purposes, the Series A Warrants were valued at $11.5 million using the Black-Scholes valuation model and were recorded as additional paid-in capital in the year ended December 31, 2000. Pursuant to the terms of the securities purchase agreement related to the Series A Preferred Stock, Brigham agreed to nominate one representative of one of the CSFB Affiliates to serve as a member of Brigham's board of directors so long as the CSFB Affiliates or their affiliates own at least 10% of the Series A Preferred Stock issued in November 2000, or at least 5% of the outstanding shares of Brigham common stock. ADDITIONAL SERIES A PREFERRED STOCK. On March 5, 2001, Brigham sold $10 million of additional Series A Preferred Stock and warrants (the "New CSFB Warrants") to the CSFB affiliates in a private placement transaction. The conditions to Brigham's receipt of the proceeds from this transaction were 39 <Page> fulfilled on March 22, 2001. The New CSFB Warrants to purchase an aggregate of 2,105,263 shares of Brigham common stock have a term of ten years, an exercise price of $4.75 per share and must be exercised, if Brigham so requires, in the event that Brigham common stock trades at an average of at least 150% of the exercise price (currently, $7.125 per share) for 60 consecutive trading days. The exercise price of the New CSFB Warrants is payable either in cash or in shares of Series A Preferred Stock, valued at liquidation value plus accrued dividends. If Brigham requires exercise of the New CSFB Warrants, proceeds from the exercise of the New CSFB Warrants will be used to fund the redemption of a similar value of then outstanding Series A Preferred Stock. For financial reporting purposes, the New CSFB Warrants were valued at approximately $4.5 million using the Black-Scholes valuation model and were recorded as additional paid-in capital in March 2001. As of December 31, 2001 and March 22, 2002, Brigham had $32.6 million (in Liquidation Value) of Series A Preferred stock outstanding. CASH FLOW ANALYSIS CASH FLOWS FROM OPERATING ACTIVITIES. Cash flows provided (used) by operating activities were $18.9 million in 2001, ($4.6) million in 2000, and $2.6 million in 1999. The increase in cash flows from operating activities for 2001 as compared to 2000 is due to a 45% increase in total production volumes, a 16% increase in Brigham's average realized natural gas equivalent sales price and a reduction in overhead cost per unit of equivalent production. The decrease in cash flows for 2000 as compared to 1999 is due to changes in working capital (a $13.2 million reduction in cash flow from working capital items in 2000 compared to a $5 million reduction in cash flow from working capital items in 1999), offset in part by a $1.1 million increase in cash flow from operations before working capital. Cash flow from operations before working capital changes were $8.6 million in 2000 as compared to $7.5 million in 1999. CASH FLOWS FROM INVESTING ACTIVITIES. Cash flows provided (used) by investing activities were ($33.6) million in 2001, ($26.1) million in 2000 and $1.6 million in 1999. The increase in cash flows used by investing activities in 2001 were primarily the result of an increase in capital expenditures for exploration and development activities and a reduction in proceeds from the sale of assets, as compared with those in 2000. The decrease in cash flow from investing activities in 2000 compared to 1999 were primarily attributable to an increase in Brigham's capital expenditures related to exploration and development activities and a reduction in proceeds received from the sale of oil and natural gas properties, as compared with those in 1999. Capital expenditures (before the application of net proceeds received from the sales of interests in projects) were $34.5 million in 2001, $28.9 million in 2000 and $25.6 million in 1999. After acquiring 2,475 square miles of 3-D seismic data in 1997 and 1998, Brigham did not acquire any new 3-D seismic data during the three-year period ended 2001. However, in 2001, Brigham exchanged licensing rights in certain non-core 3-D data volumes for licenses to additional 3-D seismic data programs, many of which were located in Brigham's focus plays in the Texas Gulf Coast. As a result, Brigham added approximately 1,400 square miles of 3-D seismic data in 2001. Brigham's drilling efforts during the past three years resulted in the completion of 27(10.4 net) wells in 2001, 25 (9.3 net) wells in 2000 and 19 (6.3 net) wells in 1999, which contributed to an aggregate net increase in proved reserve volumes (net of revisions to previous estimates) of 29 Bcfe in 2001, 18 Bcfe in 2000 and 29 Bcfe in 1999. In addition, Brigham sold interests in certain 3-D seismic data for $3.9 million in 2000 and sold interests in certain producing and non-producing properties in 1999 for a total of $27.1 million. CASH FLOWS FROM FINANCING ACTIVITIES. Cash flows from financing activities in 2001 were $18.9 million, principally due to the issuance of $10 million in additional Series A Preferred Stock and New CSFB Warrants in March 2001 and increased borrowings of $9.0 million under its Subordinated Notes Facility. Cash flows from financing activities in 2000 were $28.8 million, principally due to the 40 <Page> combined effects of increased borrowings under its Senior Credit Facility and Subordinated Notes Facility, the repurchase of its senior subordinated notes due 2003, the issuance of $20 million of Series A Preferred Stock and Series A Warrants, and the placement of common stock that provided $4.2 million. Cash flows used by financing activities in 1999 were $4.1 million, principally due to the net repayment of borrowings outstanding under Brigham's Senior Credit Facility and the payment of deferred loan fees. CAPITAL EXPENDITURES The Company's capital spending budget for 2002 is $23.7 million. The majority of Brigham's planned 2002 expenditures will be directed towards drilling in its prospect inventory in a continued effort to focus resources on its primary objective of growing production volumes and cash flow. For 2002, Brigham expects to drill 26 wells with an average working interest of 32%. Capitalizing on the prior discovery of Home Run, Mills Ranch, Triple Crown and Providence Fields, approximately 80% of Brigham's 2002 drilling expenditures are allocated to development drilling. Spending will be funded by Brigham's 2002 discretionary cash flow, availability under its Subordinated Notes Facility and its 2002 beginning cash balance. As a result, capital expenditures for 2002 are expected to be down approximately 34% from 2001. This decline is primarily attributable to lower forecasted oil and natural gas prices and is subject to change if market conditions shift. In the event that commodity prices decrease, Brigham may be required to curtail or delay some of its planned activities. OTHER MATTERS DERIVATIVE INSTRUMENTS Brigham believes that hedging, although not free of risk, allows it to reduce its exposure to oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. However, hedging arrangements, when utilized, may limit the benefit to Brigham of increases in the prices of the hedged commodity. Moreover, Brigham's hedging arrangements generally do not apply to all of its production and thus provide only partial price protection against declines in commodity prices. Brigham expects that the amount of its hedges will vary from time to time. See "--Risk Factors--Our Hedging Transactions May Not Prevent Losses" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" In 1998, Brigham began using natural gas swap arrangements in an attempt to reduce its sensitivity to volatile commodity prices as its production base became increasingly weighted toward natural gas. Pursuant to these arrangements, Brigham exchanges a floating market price for a fixed contract price. Brigham makes payments when the floating price exceeds the fixed price for a contract month, and Brigham receives payments when the fixed price exceeds the floating price. Settlements of these swaps are based on the difference between regional market index prices for a contract month and the fixed contract price for the same month. Total natural gas purchased and sold subject to swap arrangements entered into by Brigham was 5,025,000 MMBtu in 1999, 5,490,000 MMBtu in 2000 and 1,800,000 MMBtu in 2001. Brigham accounted for these transactions as hedging activities and, accordingly, adjusted the price received for natural gas production during the period the hedged transactions occurred. Adjustments to the price received for natural gas under these swap arrangements resulted in decreases in natural gas revenues of $486,000 in 1999, $9.4 million in 2000 and $8.0 million in 2001. In addition, Brigham's oil revenues were reduced by $107,000 in 2000 and $153,000 in 2001 as a result of its crude oil collar hedging arrangements outstanding during the year. Brigham did not have any outstanding crude oil hedging contracts during 1999. In September 1999, Brigham sold call options on a portion of its future oil and natural gas production. Brigham applied the proceeds from the sale of these call options to increase the effective 41 <Page> fixed swap price on its then existing natural gas hedging contracts during the months of October 1999 through January 2000 by an average of $0.57 per MMBtu. For accounting purposes, the improvement in Brigham's fixed natural gas swap price attributable to these transactions was not reflected in reported revenues. Rather, it was reflected in (i) other income (expense) on the income statement, and (ii) amortization of deferred loss on derivatives instruments and market value adjustment for derivatives instruments on the cash flow statement. In March 2000, Brigham purchased put options on a portion of its future oil and natural gas production. These transactions effectively converted a portion of its existing call options into collars, thus providing a hedge to future changes in oil and natural gas prices. Brigham also entered into costless collars on additional future oil and natural gas production thus providing further protection to Brigham's exposure to potential oil and natural gas price declines. As of December 31, 2001, Brigham has three fixed price swap derivative contracts that are designated as hedges and one fixed price cap derivative contract that is not designated as a hedge. The following table sets forth Brigham's outstanding natural gas derivative contracts as of December 31, 2001: NATURAL GAS DERIVATIVE CONTRACTS <Table> <Caption> 2002 2003 -------------------- -------------------- AVERAGE CONTRACT AVERAGE VOLUMES PRICE VOLUMES CONTRACT REMAINING HEDGED ($/ HEDGED PRICE PRICING BASIS CONTRACT TERM (MMBTU) MMBTU) (MMBTU) ($/MMBTU) ------------------ ------------------ --------- -------- -------- --------- Fixed Price Swaps: Contract #1........ NYMEX January 2002 - 452,500 $2.8000 -- -- June 2002 Contract #2........ NYMEX January 2002 - 912,500 $2.9000 -- -- December 2002 Contract #3........ NYMEX January 2002 - 912,500 $3.0000 452,500 $3.0000 June 2003 Fixed Price Cap...... ANR January 2002 - 1,810,000 $2.6326 -- -- Oklahoma June 2002 </Table> There were no outstanding oil derivative contracts as of December 31, 2001. However, in February 2002, Brigham entered into a combination of crude oil cap and floor option contracts. Under these option contracts, which together form collars, Brigham will receive a maximum of $21.95 per Bbl and a minimum of $18.00 per Bbl for 250 Bbls per day for the period from February 2002 to June 2002, a maximum of $22.35 per Bbl and minimum of $18.00 per Bbl for 250 Bbls per day for the period from February 2002 to December 2002, and a maximum of $22.56 per Bbl and minimum of $18.00 per Bbl for 250 Bbls per day for the period from February 2002 to June 2003. These contracts settle based on the NYMEX price for West Texas Intermediate and are designated as cash flow hedges. In March 2002, Brigham entered into six crude oil fixed price swap agreements whereby Brigham exchanged a floating market price for a fixed contract price of $25.06 per Bbl for 500 Bbls per day for the period from July 2002 to September 2002, $24.50 per Bbl for 250 Bbls per day for the period from October 2002 to December 2002, $23.92 per Bbl for 250 Bbls per day for the period from January 2003 to March 2003, $23.50 per Bbl for 250 Bbls per day for the period from April 2003 to June 2003, $23.15 per Bbl for 250 Bbls per day for the period from July 2003 to September 2003, and $22.90 per Bbl for 250 Bbls per day for the period from October 2003 to December 2003. These contracts settle based on the NYMEX price for West Texas Intermediate and are designated as cash flow hedges. 42 <Page> Also in March 2002, Brigham entered into six natural gas fixed price swap agreements whereby Brigham exchanged a floating market price for a fixed contract price of $3.20 per MMBtu for 2,500 MMBtu per day for the period from July 2002 to September 2002, $3.46 per MMBtu for 1,000 MMBtu per day for the period from October 2002 to December 2002, $3.70 per MMBtu for 2,500 MMBtu per day for the period from January 2003 to March 2003, $3.40 per MMBtu for 1,000 MMBtu per day for the period from April 2003 to June 2003, $3.45 per MMBtu for 2,500 MMBtu per day for the period from July 2003 to September 2003, and $3.67 per MMBtu for 1,000 MMBtu per day for the period from October 2003 to December 2003. These contracts settle based on the NYMEX price for natural gas and are designated as cash flow hedges. At December 31, 2001, the fair value of hedging contracts included in accumulated other comprehensive income and other current assets was approximately $351,000 of which approximately $50,000 was classified as noncurrent assets. EFFECTS OF INFLATION AND CHANGES IN PRICES Brigham's results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that Brigham is required to bear for operations. Inflation has had a minimal effect on Brigham. ENVIRONMENTAL AND OTHER REGULATORY MATTERS Brigham's business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although Brigham believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and Brigham is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect Brigham's financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to Brigham, compliance has not had a material adverse effect on the earnings or competitive position of Brigham. Future regulations may add to the cost of, or significantly limit, drilling activity. See "--Risk Factors--We Are Subject To Various Governmental Regulations And Environmental Risks" and "Item 1. Business--Governmental Regulation" and "Item 1. Business--Environmental Matters" CRITICAL ACCOUNTING POLICIES PROPERTY AND EQUIPMENT Brigham uses the full cost method of accounting for oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including payroll, interest, and other internal costs, incurred for the purpose of finding oil and natural gas reserves are capitalized. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and natural gas properties are applied to reduce the capitalized costs of properties unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. To the extent costs capitalized in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate and based on period-end oil and natural gas prices) of estimated future net after-tax cash flows from proved oil and natural gas reserves plus the capitalized cost of unproved properties, such costs are charged to 43 <Page> operations as a reduction of the carrying value of oil and natural gas properties, or a "capitalized ceiling impairment" charge. The risk that Brigham will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if Brigham experiences poor drilling results or estimations of proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders' equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. No assurance can be given that Brigham will not experience a capitalized ceiling impairment charge in future periods. See "--Risk Factors--Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are Dependent On Exploratory Drilling Activities"; "--Risk Factors--Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are Volatile"; and "--Risk Factors--We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows" Other property and equipment is depreciated on a straight-line basis over the estimated useful lives of the assets after considering salvage value. Brigham uses a 10 year life for furniture and fixtures, a 5 year life for machinery and equipment, and a 3 year life for 3-D seismic interpretation workstations and software. Expenditures for repairs or maintenance are expensed as incurred. INCOME TAXES Deferred tax assets are recognized for temporary differences in financial statement and tax basis amounts that will result in deductible amounts and carryforwards in future years. Deferred tax liabilities are recognized for temporary differences that will result in taxable amounts in future years. Deferred tax assets and liabilities are measured using enacted tax law and tax rate(s) for the year in which Brigham expects the temporary differences to be deducted or settled. The effect of a change in tax law or rates on the valuation deferred tax assets and liabilities is recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. REVENUE RECOGNITION Brigham recognizes crude oil revenue using the sales method of accounting. Under this method, Brigham recognizes revenue when oil is delivered and title transfers. Brigham recognizes natural gas revenue using the entitlements method of accounting. Under this method, revenue is recognized based on Brigham's entitled ownership percentage of sales of natural gas to purchasers. Gas imbalances occur when Brigham sells more or less than its entitled ownership percentage of total natural gas production. When Brigham receives less than its entitled share, a receivable is recorded. When Brigham receives more than its entitled share, a liability is recorded. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes and the future development costs as well as estimates relating to certain oil and natural gas revenues and expenses. Actual results may differ from those estimates. 44 <Page> DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Brigham adopted Statement of Financial Accounting Standards ("SFAS") No. 133 on January 1, 2001 in accordance with Financial Accounting Standards Board (the "FASB") requirements. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. All derivative instruments are recorded on the balance sheet at fair value and changes in the fair value of the derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. Brigham's derivative contracts consist primarily of cash flow hedge transactions in which Brigham is hedging the variability of cash flow related to a forecasted transaction. Changes in the fair value of these derivative instruments are reported in other comprehensive income and reclassified as earnings in the period(s) in which earnings are impacted by the variability of the cash flow of the hedged item. Brigham assesses the effectiveness of hedging transactions every three months, consistent with documented risk management strategy for the particular hedging relationship. Changes in fair value of ineffective hedges are included in earnings. In January 2001, Brigham recorded a net of tax cumulative effect adjustment of $11.8 million to other comprehensive income to recognize the fair value (liability) of all derivative instruments that qualify for hedge accounting treatment in accordance with SFAS No. 133. NEW PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations", SFAS No. 142, "Goodwill and Other Intangible Assets", and SFAS No. 143, "Accounting for Asset Retirement Obligations". In August 2001, The FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS No. 141 requires the use of the purchase method of accounting for all business combinations. SFAS No. 141 applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized, but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets to be disposed of and supersedes, with exceptions, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of" and is effective for fiscal years beginning after December 15, 2001. Brigham does not expect the adoption of these statements to have a material effect on its consolidated financial position, results of operations or cash flows. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Brigham is currently assessing the impact of this statement and for this reason cannot reasonably estimate the effect of the pronouncement on its consolidated financial position, results of operations or cash flows at this time. FORWARD LOOKING INFORMATION Brigham or its representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and gas production, the number of wells it anticipates drilling during 2002 and Brigham's financial position, business strategy and other plans and 45 <Page> objectives for future operations. Although Brigham believes that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by Brigham will be realized or, even if substantially realized, that they will have the expected effects on its business or operations. Among the factors that could cause actual results to differ materially from Brigham's expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and gas prices, availability of sufficient capital resources to Brigham and its project participants, government regulations and other factors set forth among the risk factors noted below or in the description of Brigham's business in Item 1 of this report. All subsequent oral and written forward looking statements attributable to Brigham or persons acting on its behalf are expressly qualified in their entirety by these factors. Brigham assumes no obligation to update any of these statements. 46 <Page> RISK FACTORS WE ARE SUBSTANTIALLY LEVERAGED Our outstanding long-term debt was $91.7 million as of December 31, 2001, and $95.7 million as of March 22, 2002. The credit agreements related to our Senior Credit Facility and Subordinated Notes Facility limit the amount of additional debt borrowings, including borrowings under these facilities or other senior or subordinated indebtedness. As of March 22, 2002, we had no additional borrowing availability under our Senior Credit Facility or our Subordinated Notes Facility. Our level of indebtedness will have several important effects on our operations, including those listed below. - We will dedicate a substantial portion of our cash flow from operations to the payment of interest on our indebtedness and to the payment of our other current obligations, and will not have these cash flows available for other purposes. - The covenants in our credit facilities limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions. - Our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. We may also be required to alter our capitalization significantly to accommodate future exploration, development or acquisition activities. These changes in capitalization may significantly alter our leverage and dilute the equity interests of existing stockholders. Our ability to meet our debt service obligations and to reduce our total indebtedness will be dependent upon our future performance, which will be subject to general economic conditions and to financial, business and other factors affecting our operations, many of which are beyond our control. We cannot assure you that our future performance will not be harmed by such economic conditions and financial, business and other factors. See "--Liquidity and Capital Resources" WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS We make and will continue to make substantial capital expenditures in our exploration and development projects. While we believe that our cash flow from operations, availability under our Subordinated Notes Facility and 2002 beginning cash balance should allow us to finance our planned operations through 2002 based on current conditions and expectations. Additional financing will be required in the future to fund our exploration and development activities. We cannot assure you that we will be able to secure additional financing on reasonable terms or at all, or that financing will continue to be available to us under our existing or new financing arrangements. Without additional capital resources, our drilling and other activities may be limited and our business, financial condition and results of operations may suffer. See "--Liquidity and Capital Resources" VOLATILITY OF OIL AND GAS MARKETS AFFECTS US; OIL AND NATURAL GAS PRICES ARE VOLATILE Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our oil and natural gas production. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Market prices of oil and natural gas depend on many factors beyond our control, including: - worldwide and domestic supplies of oil and natural gas; - the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; 47 <Page> - political instability or armed conflict in oil-producing regions; - the price and level of foreign imports; - the level of consumer demand; - the price and availability of alternative fuels; - the availability of pipeline capacity; - weather conditions; - domestic and foreign governmental regulations and taxes; and - the overall economic environment. We cannot predict future oil and natural gas price movements with certainty. During 2001, the high and low settlement prices for oil on the NYMEX were $32.19 per Bbl and $17.45 per Bbl, and the high and low settlement prices for natural gas on the NYMEX were $9.82 per MMBtu and $1.83 per MMBtu. Significant declines in oil and natural gas prices for an extended period may have the following effects on our business: - limit our financial condition, liquidity, ability to finance planned capital expenditures and results of operations; - reduce the amount of oil and natural gas that we can produce economically; - cause us to delay or postpone some of our capital projects; - reduce our revenues, operating income and cash flow; and - reduce the carrying value of our oil and natural gas properties. OUR HEDGING TRANSACTIONS MAY NOT PREVENT LOSSES In an attempt to reduce our sensitivity to energy price volatility, we use swap and collar hedging arrangements that generally result in a fixed price or a range of minimum and maximum price limits over a specified monthly time period. If we do not produce our oil and natural gas reserves at rates equivalent to our hedged position, we would be required to satisfy our obligations under hedging contracts on potentially unfavorable terms without the ability to hedge that risk through sales of comparable quantities of our own production. This situation occurred during a portion of 1999 and again during portions of 2000, due in part to our sale of certain producing reserves in mid-1999. As a result, our cash flow was significantly reduced, particularly during 2000. Because the terms of our hedging contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation and marketing costs to delivery points, substantial differences between the hedged prices and actual results could harm our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and natural gas prices. Hedging contracts limit the benefits we will realize if actual prices rise above the contract prices. We could be financially harmed if the other party to the hedging contracts proves unable or unwilling to perform its obligations under such contracts. See "--Other Matters--Derivative Instruments" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" EXPLORATORY DRILLING IS A SPECULATIVE ACTIVITY INVOLVING NUMEROUS RISKS AND UNCERTAIN COSTS; WE ARE DEPENDENT ON EXPLORATORY DRILLING ACTIVITIES Our revenues, operating results and future rate of growth depend highly upon the success of our exploratory drilling program. Exploratory drilling involves numerous risks, including the risk that we will not encounter commercially productive natural gas or oil reservoirs. We cannot always predict the 48 <Page> cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: - unexpected drilling conditions; - pressure or irregularities in formations; - equipment failures or accidents; - adverse weather conditions; - compliance with governmental requirements; and - shortages or delays in the availability of drilling rigs and the delivery of equipment. We may not be successful in our future drilling activities because even with the use of 3-D seismic and other advanced technologies, exploratory drilling is a speculative activity. We could incur losses because our use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies. Even when fully utilized and properly interpreted, our 3-D seismic data and other advanced technologies only assist us in identifying subsurface structures and do not indicate whether hydrocarbons are in fact present in those structures. Because we interpret the areas desirable for drilling from 3-D seismic data gathered over large areas, we may not acquire option and lease rights until after the seismic data is available and, in some cases, until the drilling locations are also identified. Although we have identified numerous potential drilling locations, we cannot assure you that we will ever lease, drill or produce oil or natural gas oil from these or any other potential drilling locations. We cannot assure you that we will be successful in our drilling activities, that our overall drilling success rate for activity within a particular province will not decline, or that our completed wells will ultimately produce our estimated economically recoverable reserves. Unsuccessful drilling activities could materially harm our operations and financial condition. WE ARE SUBJECT TO VARIOUS CASUALTY RISKS Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as: - fires; - natural disasters; - formations with abnormal pressures; - blowouts, cratering and explosions; and - pipeline ruptures and spills. Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. See "Item 1. Business--Operating Hazards and Uninsured Risks" WE MAY NOT HAVE ENOUGH INSURANCE TO COVER SOME OPERATING RISKS We maintain insurance coverage against some, but not all, potential losses in order to protect against operating hazards. We may elect to self-insure if our management believes that the cost of insurance, although available, is excessive relative to the risks presented. We generally maintain insurance for the hazards and risks inherent in drilling for and producing and transporting oil and natural gas and believe this insurance is adequate. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition and results of operations. In addition, we cannot fully insure against pollution and environmental risks. 49 <Page> THE MARKETABILITY OF OUR PRODUCTION IS DEPENDENT ON FACILITIES THAT WE TYPICALLY DO NOT OWN OR CONTROL The marketability of our production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own. Our ability to produce and market oil and natural gas could be harmed by any dramatic change in market factors or by: - federal and state regulation of oil and natural gas production and transportation; - tax and energy policies; - changes in supply and demand; and - general economic conditions. WE HAVE HISTORICAL OPERATING LOSSES AND OUR FUTURE RESULTS MAY VARY We cannot assure you that we will be profitable in the future. At December 31, 2001, we had an accumulated deficit of $26.7 million and total stockholders' equity of $49.6 million. We have recognized the following annual net losses before extraordinary items since 1995: $1.6 million in 1995, $450,000 in 1996, $1.1 million (including a net $1.2 million non-cash deferred income tax charge incurred in connection with our conversion from a partnership to a corporation) in 1997, $33.3 million (including a $25.9 million non-cash writedown in the carrying value of our oil and natural gas properties) in 1998, $21.6 million (including a $12.2 million non-cash loss on the sale of oil and natural gas properties) in 1999, and $15.7 million in 2000. See "Item 6. Selected Financial Data" OUR FUTURE OPERATING RESULTS MAY FLUCTUATE Our future operating results may fluctuate significantly depending upon a number of factors, including: - industry conditions; - prices of oil and natural gas; - rates of drilling success; - capital availability; - rates of production from completed wells; and - the timing and amount of capital expenditures. This variability could cause our business, financial condition and results of operations to suffer. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our ability to invest and participate in economically attractive projects. MAINTAINING RESERVES AND REVENUES IN THE FUTURE DEPENDS ON SUCCESSFUL EXPLORATION AND DEVELOPMENT In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production depends highly upon our ability to economically find, develop or acquire reserves in commercial quantities. The business of exploring for or developing reserves is capital intensive. Reductions in our cash flow from operations and limitations on or unavailability of external sources of capital may impair our 50 <Page> ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves. In addition, we cannot be certain that our future exploration and development activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Furthermore, although significant increases in prevailing prices for oil and natural gas could cause increases in our revenues, our finding and development costs could also increase. Finally, we participate in a percentage of our wells as a non-operator. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could harm us. WE ARE SUBJECT TO UNCERTAINTIES IN RESERVE ESTIMATES AND FUTURE NET CASH FLOWS There is substantial uncertainty in estimating quantities of proved reserves and projecting future production rates and the timing of development expenditures. No one can measure underground accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve engineering requires subjective estimations of those accumulations. Estimates of other engineers might differ widely from those of our independent petroleum engineers. Accuracy of reserve estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Our independent petroleum engineers may make material changes to reserve estimates based on the results of actual drilling, testing, and production. As a result, our reserve estimates often differ from the quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. See "Item 2. Properties--Oil and Natural Gas Reserves" Actual future net cash flows from our oil and natural gas properties also will be affected by factors such as: - the amount and timing of actual production; - supply and demand for oil and natural gas; - limits or increases in consumption by gas purchasers; and - changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the SEC reporting requirements may not necessarily be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. WE FACE SIGNIFICANT COMPETITION We operate in the highly competitive areas of oil and natural gas exploration, exploitation, acquisition and production with other companies. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent oil and natural gas companies in a number of areas such as: - seeking to acquire desirable producing properties or new leases for future exploration; - marketing our oil and natural gas production; and - seeking to acquire the equipment and expertise necessary to operate and develop those properties. 51 <Page> Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could harm our business. See "Item 1. Business--Competition." WE ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL RISKS Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Although we believe we are in substantial compliance with all applicable laws and regulations, legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. Our operations are subject to complex environmental laws and regulations adopted by federal, state and local governmental authorities. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm us. The discharge of natural gas, oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation. We cannot be certain that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our results of operations and financial condition. See "Item 1. Business--Governmental Regulation" and "--Environmental Matters." OUR BUSINESS MAY SUFFER IF WE LOSE KEY PERSONNEL We have assembled a team of geologists, geophysicists and engineers who have considerable experience in applying 3-D imaging technology to explore for and to develop oil and natural gas. We depend upon the knowledge, skills and experience of these experts to provide 3-D imaging and to assist us in reducing the risks associated with our participation in oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management, particularly Ben M. Brigham, our Chief Executive Officer, President and Chairman of the Board. We have an employment agreement with Ben M. Brigham, but do not have an employment agreement with any of our other employees. We have key man life insurance on Mr. Brigham in the amount of $2 million. If we lose the services of our key management personnel or technical experts, or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We cannot assure you that we will be successful in attracting and retaining such executives, geophysicists, geologists and engineers. See "Item 1. Business--Technical Staff" and "Executive Officers of the Registrant" CONTROL BY CERTAIN STOCKHOLDERS AND CERTAIN ANTI-TAKEOVER PROVISIONS MAY AFFECT YOU; CERTAIN OF OUR AFFILIATES CONTROL A MAJORITY OF THE OUTSTANDING COMMON STOCK As of March 22, 2002, our directors, executive officers and 10% or greater stockholders, and certain of their affiliates, beneficially owned approximately 78% of our outstanding common stock. Accordingly, these stockholders, as a group, will be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws, and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership concentrated in a few persons makes it unlikely that any other holder of common stock will be able to affect our management or direction. These factors may also have the effect of delaying or preventing a change in our management or voting control. 52 <Page> CERTAIN ANTI-TAKEOVER PROVISIONS MAY AFFECT YOUR RIGHTS AS A STOCKHOLDER Our certificate of incorporation authorizes our Board of Directors to issue up to 10 million shares of preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights, of those shares as the Board of Directors may determine. These provisions, alone or in combination with the other matters described in the preceding paragraph may discourage transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock. We are also subject to provisions of the Delaware General Corporation Law that may make some business combinations more difficult. THE MARKET PRICE OF OUR STOCK PRICE IS VOLATILE The trading price of our common stock and the price at which we may sell securities in the future is subject to large fluctuations in response to any of the following: limited trading volume in our stock, changes in government regulations, quarterly variations in operating results, our involvement in litigation, general market conditions, the prices of oil and natural gas, announcements by us and our competitors, our liquidity, our ability to raise additional funds and other events. 53 <Page> ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT OPINION CONCERNING DERIVATIVE INSTRUMENTS Brigham limits its use of derivative instruments principally to commodity price hedging activities, whereby gains and losses are generally offset by price changes in the underlying commodity. Brigham's use of derivative instruments for hedging activities could materially affect its results of operations in particular quarterly or annual periods since such instruments can limit Brigham's ability to benefit from favorable oil and natural gas price movements. COMMODITY PRICE RISK Brigham's primary commodity market risk exposure is to changes in the prices related to the sale of its oil and natural gas production. The market prices for oil and natural gas have been volatile and are likely to continue to be volatile in the future. As such, Brigham employs established policies and procedures to manage its exposure to fluctuations in the sales prices it receives for its oil and natural gas production through hedging activities. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Other Matters--Derivative Instruments." Brigham believes that hedging, although not free of risk, allows it to reduce its exposure to oil and natural gas sales price fluctuations and thereby to achieve more predictable cash flows. However, hedging arrangements, when utilized, may limit the benefit to Brigham of increases in the prices of the hedged commodity. Moreover, Brigham's hedging arrangements generally do not apply to all of its production and thus provide only partial price protection against declines in commodity prices. Brigham expects that the amount of its hedges will vary from time to time. INTEREST RATE RISK Brigham is subject to interest rate risk as borrowings under its Senior Credit Facility ($75 million outstanding as of December 31, 2001) accrue interest at floating rates based on the lender's base rate or LIBOR. Brigham does not utilize derivative instruments to protect against changes in interest rates on debt borrowings. Based on Brigham's $75 million of outstanding borrowings under its Senior Credit Facility at December 31, 2001, an adverse change (defined as a hypothetical 1% and 2% increase in interest rates on such borrowings) would reduce cash flow by approximately $750,000 and $1.5 million, respectively, from currently projected levels. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Brigham's Consolidated Financial Statements required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 54 <Page> PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to information under the caption "Proposal One--Election of Directors" and to the information under the caption "Section 16(a) Beneficial Ownership Reporting Compliance" in Brigham's definitive Proxy Statement (the "2002 Proxy Statement") for its annual meeting of stockholders to be held on May 17, 2002. The 2002 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 2001. Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to Brigham's executive officers is set forth in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to the 2002 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2001. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 2002 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2001. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to the 2002 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2001. 55 <Page> PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K <Table> (a) 1. Consolidated Financial Statements: See Index to Financial Statements on page F-1. 2. Exhibits: The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by reference as part of the annual report. (b) The following reports on Form 8-K were filed by Brigham during the last quarter of the period covered by this Annual Report on Form 10-K: Brigham filed a report on Form 8-K on October 19, 2001 to report Brigham had issued an operational press release announcing success in its South Texas drilling program and reaffirmed guidance for the third quarter 2001. Brigham filed a report on Form 8-K on November 6, 2001 to report Brigham announced that it would host a conference call to discuss Brigham's operational and financial results for the third quarter ended September 30, 2001 with investors, analyst and other interested parties on Wednesday, November 7, at 9:00 am Central time. Additionally, Brigham announced that it plans to issue a press release regarding its third quarter 2001 financial results after the close of market trading on Tuesday, November 06, 2001. Brigham filed a report on Form 8-K on November 12, 2001 to report Brigham announced its financial results for the third quarter ended September 30, 2001 and to provide guidance for fourth quarter financial results. Brigham filed a report on Form 8-K on November 15, 2001 to report Brigham announced the successful completion of its first two wells at the Triple Crown Field. </Table> 56 <Page> GLOSSARY OF OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. BCF. One billion cubic feet. BCFE. One billion cubic feet of natural gas equivalent. In reference to natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate of natural gas liquids. CAEX. Computer-aided exploration. COMPLETION. The installation of permanent equipment for the production of oil or natural gas. COMPLETION RATE. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled. DEVELOPED ACREAGE. The number of acres which are allocated or assignable to producing wells or wells capable of production. DEVELOPMENT WELL. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. DRILLING COSTS. The costs associated with drilling and completing a well (exclusive of seismic and land acquisition costs for that well and future development costs associated with proved undeveloped reserves added by the well) divided by total proved reserve additions. DRY WELL. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or gas well. EXPLORATORY WELL. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. FINDING AND DEVELOPMENT COSTS. Capital costs incurred in the acquisition, exploration and development of proved oil and natural gas reserves divided by total proved reserve additions. GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in which Brigham has a working interest. MBBL. One thousand barrels of oil or other liquid hydrocarbons. MCF. One thousand cubic feet of natural gas. MCFE. One thousand cubic feet of natural gas equivalents. MMBBL. One million barrels of oil or other liquid hydrocarbons. MMBTU. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. MMCF. One million cubic feet of natural gas. MMCFE. One million cubic feet of natural gas equivalents. 57 <Page> NET ACRES OR NET WELLS. Gross acres or wells multiplied, in each case, by the percentage working interest owned by Brigham. NET PRODUCTION. Production that is owned by Brigham less royalties and production due others. OIL. Crude oil, condensate or other liquid hydrocarbons. OPERATOR. The individual or company responsible for the exploration, development, and production of an oil or gas well or lease. PRESENT VALUE OF FUTURE NET REVENUES OR PV10%. The pretax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. PROVED RESERVES. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. PSI. Pounds per square inch. ROYALTY. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. SPUD. Start drilling a new well (or restart). STANDARDIZED MEASURE. The aftertax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. TCFE. One trillion cubic feet of natural gas equivalents. 2-D SEISMIC. The method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. 3-D SEISMIC. The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production. WORKING INTEREST. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. 58 <Page> SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunder duly authorized, as of March 29, 2002. <Table> BRIGHAM EXPLORATION COMPANY By: /s/ BEN M. BRIGHAM ----------------------------------------- Ben M. Brigham CHIEF EXECUTIVE OFFICER AND PRESIDENT </Table> Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of March 29, 2002, by the following persons on behalf of the Registrant and in the capacity indicated. <Table> /s/ BEN M. BRIGHAM ------------------------------------------- Ben M. Brigham CHIEF EXECUTIVE OFFICER, PRESIDENT AND CHAIRMAN OF THE BOARD /s/ CURTIS F. HARRELL ------------------------------------------- Curtis F. Harrell EXECUTIVE VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND DIRECTOR (PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER) /s/ ANNE L. BRIGHAM ------------------------------------------- Anne L. Brigham DIRECTOR /s/ HAROLD D. CARTER ------------------------------------------- Harold D. Carter DIRECTOR /s/ ALEXIS M. CRANBERG ------------------------------------------- Alexis M. Cranberg DIRECTOR </Table> 59 <Page> <Table> /s/ STEPHEN P. REYNOLDS ------------------------------------------- Stephen P. Reynolds DIRECTOR /s/ STEVEN A. WEBSTER ------------------------------------------- Steven A. Webster DIRECTOR /s/ R. GRAHAM WHALING ------------------------------------------- R. Graham Whaling DIRECTOR </Table> 60 <Page> BRIGHAM EXPLORATION COMPANY INDEX TO FINANCIAL STATEMENTS <Table> <Caption> PAGE -------- Report of Independent Accountants........................... F-2 Consolidated Balance Sheets as of December 31, 2001 and 2000...................................................... F-3 Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000 and 1999.......................... F-4 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2001, 2000 and 1999.............. F-5 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999.......................... F-6 Notes to the Consolidated Financial Statements.............. F-7 </Table> F-1 <Page> REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Brigham Exploration Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Brigham Exploration Company (the "Company") and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. PricewaterhouseCoopers LLP February 22, 2002 Houston, Texas F-2 <Page> BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) <Table> <Caption> DECEMBER 31, ------------------- 2001 2000 -------- -------- ASSETS Current assets: Cash and cash equivalents $ 5,112 $ 837 Accounts receivable 9,325 9,277 Other current assets 2,531 559 -------- -------- Total current assets 16,968 10,673 -------- -------- Oil and natural gas properties, using the full cost method of accounting Unproved 35,908 41,617 Proved 203,803 162,482 Accumulated depletion (87,820) (74,609) -------- -------- 151,891 129,490 -------- -------- Other property and equipment, net 1,331 1,341 Deferred loan fees 3,166 4,338 Other noncurrent assets 52 1,069 -------- -------- $173,408 $146,911 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 8,412 $ 9,211 Accrued drilling costs 1,969 792 Other current liabilities 4,885 7,896 -------- -------- Total current liabilities 15,266 17,899 -------- -------- Notes payable 75,000 75,000 Senior subordinated notes 16,721 7,000 Other noncurrent liabilities 206 3,697 Commitments and contingencies Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 1,630,692 and 1,000,000 shares issued and outstanding at December 31, 2001 and 2000, respectively 16,614 8,558 Stockholders' equity: Preferred stock, $.01 par value, 10 million shares authorized, of which 2,250,000 shares are designated as Series A -- -- Common stock, $.01 par value, 50 million shares authorized, 17,127,650 and 17,030,176 shares issued and 16,016,113 and 15,977,544 shares outstanding at December 31, 2001 and 2000, respectively 171 170 Additional paid-in capital 80,466 78,274 Treasury stock, at cost; 1,111,537 and 1,052,632 shares at December 31, 2001 and 2000, respectively (4,165) (3,950) Unearned stock compensation (494) (1,321) Accumulated other comprehensive income 351 -- Accumulated deficit (26,728) (38,416) -------- -------- Total stockholders' equity 49,601 34,757 -------- -------- $173,408 $146,911 ======== ======== </Table> The accompanying notes are an integral part of these consolidated financial statements. F-3 <Page> BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA) <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Revenues: Oil and natural gas sales $32,293 $ 19,143 $ 14,992 Other revenue 255 69 285 ------- -------- -------- 32,548 19,212 15,277 ------- -------- -------- Costs and expenses: Lease operating 3,486 2,139 2,259 Production taxes 1,511 1,786 968 General and administrative 3,638 3,100 3,481 Depletion of oil and natural gas properties 13,211 7,920 7,792 Depreciation and amortization 677 620 526 ------- -------- -------- 22,523 15,565 15,026 ------- -------- -------- Operating income 10,025 3,647 251 ------- -------- -------- Other income (expense): Interest income 264 108 176 Interest expense, net (6,681) (9,906) (9,697) Loss on sale of oil and natural gas properties -- -- (12,195) Other income (expense) 8,080 (9,504) (163) ------- -------- -------- 1,663 (19,302) (21,879) ------- -------- -------- Income (loss) before income taxes and extraordinary item 11,688 (15,655) (21,628) Income taxes -- -- -- ------- -------- -------- Income (loss) before extraordinary item 11,688 (15,655) (21,628) Extraordinary item--gain on refinancing of senior subordinated notes, net of $0 tax -- 32,267 -- ------- -------- -------- Net income (loss) 11,688 16,612 (21,628) Less accretion and dividends on redeemable preferred stock 2,450 275 -- ------- -------- -------- Net income (loss) available to common stockholders $ 9,238 $ 16,337 $(21,628) ======= ======== ======== Net income (loss) per share available to common stockholders: Basic Income (loss) before extraordinary item $ 0.58 $ (0.98) $ (1.53) Extraordinary item -- 1.99 -- ------- -------- -------- $ 0.58 $ 1.01 $ (1.53) ======= ======== ======== Diluted Income (loss) before extraordinary item $ 0.54 $ (0.98) $ (1.53) Extraordinary item -- 1.99 -- ------- -------- -------- $ 0.54 $ 1.01 $ (1.53) ======= ======== ======== </Table> The accompanying notes are an integral part of these consolidated financial statements. F-4 <Page> BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS) <Table> <Caption> ACCUMULATED COMMON STOCK ADDITIONAL UNEARNED OTHER ------------------- PAID IN TREASURY STOCK COMPREHENSIVE ACCUMULATED SHARES AMOUNTS CAPITAL STOCK COMPENSATION INCOME DEFICIT -------- -------- ---------- -------- ------------ ------------- ----------- Balance, December 31, 1998 13,306 $133 $58,838 $ -- $ (890) $ -- $(33,400) Net loss -- -- -- -- -- -- (21,628) Issuance of common stock 1,212 12 4,228 -- -- -- -- Forfeiture of stock options -- -- (602) -- 602 -- -- Revision in terms of warrants -- -- 479 -- -- -- -- Issuance of warrants -- -- 1,228 -- -- -- -- Amortization of unearned stock compensation -- -- -- -- (2) -- -- ------ ---- ------- ------- ------- -------- -------- Balance, December 31, 1999 14,518 145 64,171 -- (290) -- (55,028) Net income -- -- -- -- -- -- 16,612 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) -- -- -- Dividends on Series A Preferred Stock -- -- (267) -- -- -- -- Accretion on Series A Preferred Stock -- -- (8) -- -- -- -- ------ ---- ------- ------- ------- -------- -------- Balance, December 31, 2000 17,030 170 78,274 (3,950) (1,321) -- (38,416) Comprehensive income (loss): Net income -- -- -- -- -- -- 11,688 Cumulative effect (loss) on adoption of SFAS 133 -- -- -- -- -- (11,800) -- Unrealized gain on cash flow hedges -- -- -- -- -- 12,151 -- -------- Comprehensive income 351 -------- 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 -- -- -- -- Dividends on Series A Preferred Stock -- -- (2,347) -- -- -- -- Accretion on Series A Preferred Stock -- -- (103) -- -- -- -- Amortization of unearned stock compensation -- -- -- -- 675 -- -- ------ ---- ------- ------- ------- -------- -------- Balance, December 31, 2001 17,127 $171 $80,466 $(4,165) $ (494) $ 351 $(26,728) ====== ==== ======= ======= ======= ======== ======== <Caption> TOTAL STOCKHOLDERS' EQUITY ------------- Balance, December 31, 1998 $ 24,681 Net loss (21,628) Issuance of common stock 4,240 Forfeiture of stock options -- Revision in terms of warrants 479 Issuance of warrants 1,228 Amortization of unearned stock compensation (2) -------- Balance, December 31, 1999 8,998 Net income 16,612 Exercise of employee stock options 19 Issuance of common stock 4,188 Issuance of restricted stock -- Issuance of stock options -- Forfeiture of stock options (50) Issuance of warrants 13,910 Cancellation of warrants (4,979) Amortization of unearned stock compensation 284 Purchase of treasury stock (3,950) Dividends on Series A Preferred Stock (267) Accretion on Series A Preferred Stock (8) -------- Balance, December 31, 2000 34,757 Comprehensive income (loss): Net income 11,688 Cumulative effect (loss) on adoption of SFAS 133 (11,800) Unrealized gain on cash flow hedges 12,151 -------- Comprehensive income 12,039 -------- Exercise of employee stock options 252 Forfeitures of employee stock options (84) Forfeitures of restricted stock (21) Purchases of restricted stock (67) Issuance of warrants 4,500 Dividends on Series A Preferred Stock (2,347) Accretion on Series A Preferred Stock (103) Amortization of unearned stock compensation 675 -------- Balance, December 31, 2001 $ 49,601 ======== </Table> The accompanying notes are an integral part of these consolidated financial statements. F-5 <Page> BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Cash flows from operating activities: Net income (loss) $ 11,688 $ 16,612 $(21,628) Adjustments to reconcile net income (loss) to cash provided (used) by operating activities: Depletion of oil and natural gas properties 13,211 7,920 7,792 Depreciation and amortization 677 620 526 Interest paid through issuance of additional senior subordinated notes 721 4,575 5,459 Amortization of deferred loan fees and debt issuance costs 1,372 1,283 1,739 Amortization of discount on senior subordinated notes -- 673 575 Amortization of deferred loss on derivative instruments -- 280 759 Market value adjustment for derivative instruments (9,666) 8,885 115 Extraordinary gain on refinancing of senior subordinated notes -- (32,267) -- Loss on sale of oil and natural gas properties -- -- 12,195 Loss on investment in Brigham Duke LLC 94 -- -- Changes in working capital and other items: Accounts receivable (48) (4,332) 2,993 Other current assets (1,671) (262) (1,046) Accounts payable (799) (7,290) (1,136) Other current liabilities 3,400 (1,354) (29) Noncurrent assets 13 54 (151) Noncurrent liabilities (70) (32) (5,585) -------- -------- -------- Net cash provided (used) by operating activities 18,922 (4,635) 2,578 -------- -------- -------- Cash flows from investing activities: Additions to oil and natural gas properties (34,532) (28,910) (25,560) Proceeds from sale of oil and natural gas properties 397 3,938 27,143 Additions to other property and equipment (396) (162) (146) (Increase) decrease in drilling advances paid 960 (937) 207 -------- -------- -------- Net cash provided (used) by investing activities (33,571) (26,071) 1,644 -------- -------- -------- Cash flows from financing activities: Proceeds from issuance of common stock -- 4,188 -- Proceeds from issuance of preferred stock and warrants 9,838 20,060 -- Proceeds from issuance of senior subordinated notes and warrants 9,000 7,000 -- Proceeds from exercise of employee stock options 252 19 -- Repurchases of common stock (67) -- -- Increase in notes payable -- 19,000 13,750 Repayment of notes payable -- -- (16,750) Principal payments on senior subordinated notes -- (20,354) -- Principal payments on capital lease obligations (99) (210) (253) Deferred loan fees paid -- (902) (796) -------- -------- -------- Net cash provided (used) by financing activities 18,924 28,801 (4,049) -------- -------- -------- Net increase (decrease) in cash and cash equivalents 4,275 (1,905) 173 Cash and cash equivalents, beginning of year 837 2,742 2,569 -------- -------- -------- Cash and cash equivalents, end of year $ 5,112 $ 837 $ 2,742 ======== ======== ======== </Table> The accompanying notes are an integral part of these consolidated financial statements. F-6 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND NATURE OF OPERATIONS Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the "Partnership"). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as "Brigham." Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in West Texas, the Anadarko Basin and the onshore Gulf Coast. Pursuant to an exchange agreement dated February 26, 1997 (the "Exchange Agreement") and upon the initial filing on February 27, 1997 of a registration statement with the Securities and Exchange Commission (the "SEC") for the public offering of common stock (the "Offering"), the shareholders of Brigham, Inc. transferred all of the outstanding stock of Brigham, Inc. to Brigham in exchange for 3,859,821 shares of common stock of Brigham. Pursuant to the Exchange Agreement, the Partnership's other general partner and the limited partners also transferred all of their partnership interests to Brigham in exchange for 3,314,286 shares of common stock of Brigham. Furthermore, the holders of the Partnership's subordinated convertible notes transferred these notes to Brigham in exchange for 1,754,464 shares of common stock. These transactions are referred to as "the Exchange." In completing the Exchange, Brigham issued 8,928,571 shares of common stock to the stockholders of Brigham, Inc., the partners of the Partnership and the holder of the Partnership's subordinated notes payable. As a result of the Exchange, Brigham now owns all the partnership interests in the Partnership. In May 1997, Brigham sold 3,325,000 shares of its common stock in the Offering at a price of $8.00 per share. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes and the future development costs as well as estimates relating to certain oil and natural gas revenues and expenses. Actual results may differ from those estimates. PRINCIPLES OF CONSOLIDATION The accompanying financial statements include the accounts of Brigham and its wholly owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries has a participating interest. All significant intercompany accounts and transactions have been eliminated. CASH AND CASH EQUIVALENTS Brigham considers all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents. F-7 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) PROPERTY AND EQUIPMENT Brigham uses the full cost method of accounting for oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including payroll, other internal costs, and interest incurred for the purpose of finding oil and natural gas reserves are capitalized. Internal costs capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from the sale of oil and natural gas properties are applied to reduce the capitalized costs of oil and natural gas properties unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated costs of future development, dismantlement, restoration and abandonment costs, net of estimated salvage values, are amortized using the unit-of-production method based on proved reserves. Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the total of estimated future net cash flows from proved oil and natural gas reserves, discounted at ten percent, plus the cost of unevaluated properties. There are many factors, including global events that may influence the production, processing, marketing and valuation of oil and natural gas. A reduction in the valuation of oil and natural gas properties resulting from declining prices or production could adversely impact depletion rates and capitalized cost limitations. Capitalized costs associated with properties that have not been evaluated through drilling or seismic analysis are excluded from the unit-of-production amortization. Exclusions are adjusted annually based on drilling results and interpretative analysis. Other property and equipment, which primarily consists of 3-D seismic interpretation workstations, is depreciated on a straight-line basis over the estimated useful lives of the assets after considering salvage value. Estimated useful lives are as follows: <Table> Furniture and fixtures...................................... 10 years Machinery and equipment..................................... 5 years 3-D seismic interpretation workstations and software........ 3 years </Table> Betterments and major improvements that extend the useful lives are capitalized while expenditures for repairs and maintenance of a minor nature are expensed as incurred. REVENUE RECOGNITION Brigham recognizes crude oil revenues using the sales method of accounting. Under this method, Brigham recognizes revenues when oil is delivered and title transfers. Brigham recognizes natural gas revenues using the entitlements method of accounting. Under this method, revenues are recognized based on Brigham's entitled ownership percentage of sales of natural gas to purchasers. Gas imbalances occur when Brigham sells more or less than its entitled ownership percentage of total natural gas production. When Brigham receives less than its entitled share, a receivable is recorded. When Brigham receives more than its entitled share, a liability is recorded. At December 31, 2001, Brigham had recorded a receivable of approximately 441 MMcf and $1.7 million and a liability of approximately 758 MMcf and $2.9 million associated with gas imbalances. Gas balancing receivables and liabilities as of December 31, 2000 were not significant. F-8 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Brigham uses derivative instruments to manage market risks resulting from fluctuations in commodity prices of natural gas and crude oil. Brigham periodically enters into commodity contracts, including price swaps, caps and/or floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. Prior to January 1, 2001, in order for a derivative instrument to qualify for hedge accounting, there must have been clear correlation between the derivative instrument and the forecasted transaction. Correlation of the commodity contracts was determined by evaluating whether the contract gains and losses would substantially offset the effects of price changes on the underlying natural gas and crude oil sales volumes. To the extent that correlation existed between the contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the contracts were recognized as a component of oil and natural gas sales in the same period as the sale of the underlying volumes. To the extent that correlation did not exist between the contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the contracts were recognized in the period incurred as a component of other income or loss. The fair market value of any contract that does not meet the correlation test outlined above was recorded as a deferred gain or loss on the balance sheet and was adjusted to current market value at each balance sheet date with any deferred gains or losses recognized as a component of other income. On January 1, 2001, Brigham adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended. Effective with the adoption of SFAS 133, all derivatives are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. Brigham's derivatives consist primarily of cash flow hedge transactions in which Brigham is hedging the variability of cash flows related to a forecasted transaction. Changes in the fair value of these derivative instruments designated as cash flow hedges will be reported in other comprehensive income and will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of the cash flow hedges will be recognized in current period earnings. Gains and losses on derivative instruments that do not qualify for hedge accounting are included in other income (expense) in the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. The adoption of SFAS 133 resulted in a January 1, 2001 transition adjustment to record a net of tax cumulative effect of $11.8 million to other comprehensive income to recognize the fair value (liability) of all derivative instruments that qualify for hedge accounting treatment. Gains and losses on derivatives that were previously deferred as adjustments to the carrying amount of hedged items were not adjusted. At the inception of a derivative contract, Brigham may designate the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, Brigham formally documents the relationship between the derivative contract and the hedged items, as well as the risk management objective for entering into the derivative contract. To be designated as a cash flow hedge transaction, the relationship between the derivative and the hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. F-9 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Brigham measures hedge effectiveness on a quarterly basis and hedge accounting is discontinued prospectively if it is determined that the derivative is no longer effective in offsetting changes in the cash flows of the hedged item. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered. If Brigham determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. See Note 12 for a description of the derivative contracts in which Brigham participates. STOCK BASED COMPENSATION Brigham accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). See Note 15 for the pro forma disclosures of compensation expense determined under the fair-value provisions of SFAS 123. INCOME TAXES Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of the enacted rate change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. DEBT ISSUE COSTS Debt issue costs are incurred in connection with the issuance of debt and are recorded on the balance sheet as deferred assets. The debt issue costs are amortized to interest expense over the life of the debt using the straight-line method. The results obtained using the straight-line method are not materially different than those that would result from using the effective interest method. SEGMENT INFORMATION All of Brigham's oil and natural gas properties and related operations are located in the United States and management has determined that Brigham has one reportable segment. TREASURY STOCK Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. NEW PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board issued Statements of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", SFAS No. 142, "Goodwill and Other Intangible Assets", and SFAS No. 143, "Accounting for Asset Retirement Obligations". In F-10 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) August 2001, SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" was also issued. SFAS No. 141 requires the use of the purchase method of accounting for all business combinations, applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of" and is effective for fiscal years beginning after December 15, 2001. Brigham does not believe that the adoption of these statements will have a material effect on its financial position, results of operations or cash flows. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Brigham is currently assessing the impact of this statement and therefore, at this time, cannot reasonably estimate the effect of these statements on its consolidated financial position, results of operations or cash flows. RECLASSIFICATIONS Certain reclassifications have been made to the prior year balances to conform to current year presentation. 3. ASSET DISPOSITIONS In February 1999, Brigham entered into a project financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund the continued exploration of five projects covered by approximately 200 square miles of 3-D seismic data acquired in 1998. In this transaction, Brigham conveyed 100% of its working interest in land and seismic in these project areas to a newly formed limited liability company (the "Brigham-Duke LLC") for a total consideration of $10 million. Brigham is the managing member of the Brigham-Duke LLC with a 1% interest and Duke is the sole remaining member with a 99% interest. Pursuant to the terms of the Brigham-Duke LLC agreement, Brigham pays 100% of the drilling and completion costs for all wells drilled by the Brigham-Duke LLC in exchange for a 70% working interest in the wells and their associated drilling and spacing units and allocable seismic data. Upon 100% project payout, Brigham has certain rights to back-in for up to a 94% effective working interest in the Brigham-Duke LLC properties. In February 2001, Duke, as majority member of the Brigham-Duke LLC elected to dissolve the Brigham-Duke LLC. As a result of the dissolution of the Brigham-Duke LLC, the remaining undeveloped land and seismic data in the Brigham-Duke LLC project areas were unconditionally owned by Duke and, in December 2001, Brigham recorded a loss of approximately $94,000 on its investment in Brigham-Duke LLC. In June 1999, Brigham sold its entire interest in certain producing and non-producing oil and natural gas properties located in its Anadarko Basin province to two parties for a combined sales price of $17.1 million. Total proceeds, net of transaction costs, were $16.7 million and were used to repay a portion of Brigham's notes payable. Due to the magnitude of the reserve volumes that were attributable to these properties relative to Brigham's remaining net reserve volumes, Brigham F-11 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) recognized a loss of $12.2 million, which was the difference between the sales price received, after adjustment for transaction costs, and the $28.9 million basis allocated to the divested properties in accordance with the full-cost method of accounting for oil and natural gas properties. 4. PROPERTY AND EQUIPMENT Property and equipment, at cost, are summarized as follows (in thousands): <Table> <Caption> DECEMBER 31, ------------------- 2001 2000 -------- -------- Oil and natural gas properties.......................... $239,711 $204,099 Accumulated depletion................................... (87,820) (74,609) -------- -------- 151,891 129,490 -------- -------- Other property and equipment: 3-D seismic interpretation workstations and software............................................ 2,307 2,277 Office furniture and equipment........................ 2,225 2,015 Accumulated depreciation.............................. (3,201) (2,951) -------- -------- 1,331 1,341 -------- -------- $153,222 $130,831 ======== ======== </Table> Brigham capitalizes certain payroll and other internal costs directly attributable to acquisition, exploration and development activities as part of its investment in oil and natural gas properties over the periods benefited by these activities. During the years ended December 31, 2001, 2000 and 1999, these capitalized costs amounted to $3.9 million, $3.4 million and $3.3 million, respectively. Capitalized costs do not include any costs related to production, general corporate overhead, or similar activities. Interest costs of $1.8 million, $2.8 million and $3.0 million were capitalized in 2001, 2000 and 1999, respectively. 5. NOTES PAYABLE AND SENIOR SUBORDINATED NOTES PAYABLE NOTES PAYABLE In January 1998, Brigham entered into a reserve-based revolving credit facility (as amended the "Senior Credit Facility") that originally provided for initial borrowing availability of $75 million. Principal outstanding under the Senior Credit Facility was due at maturity on January 26, 2001 with interest due monthly for base rate tranches or periodically as LIBOR tranches mature. Amounts outstanding under the Senior Credit Facility accrued interest at either the lender's Base Rate or LIBOR plus 2.25%, at Brigham's option. In connection with the origination of the Senior Credit Facility, certain bank fees and other expenses totaling approximately $1.9 million were recorded as deferred costs and are amortized over the life of the loan. The Senior Credit Facility was amended in March 1999 to reduce the borrowing availability, extend the date of borrowing base redetermination, modify certain financial covenants, include certain additional covenants that place significant restrictions on Brigham's ability to make certain capital expenditures, and to change the interest rate on outstanding borrowings to either the lender's Base Rate or LIBOR plus 3.0%, at Brigham's option. Brigham incurred a $500,000 transaction fee due to the lender over a ten-month period. F-12 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) In July 1999, the Senior Credit Facility was amended to provide Brigham with borrowing availability of $56 million. As consideration for this amendment, Brigham issued to its senior lenders one million warrants to purchase Brigham's common stock at an exercise price of $2.25 per share. An estimated value of $1.2 million was attributed to these warrants by Brigham and was recognized as additional deferred loan fees to be amortized over the remaining period to maturity of the Senior Credit Facility. Brigham's obligations under the Senior Credit Facility are secured by substantially all of the oil and natural gas properties and other tangible assets of Brigham. In February 2000, Brigham entered into an amended and restated Senior Credit Facility with its existing senior lenders and a new lender. The Senior Credit Facility was further amended in October 2000 and December 2001. The amended and restated Senior Credit Facility provides Brigham with $75 million in borrowing availability with a maturity date of December 31, 2003. As a result of the February 2000 amendments, $30 million of the Senior Credit Facility held by one of the lenders is convertible into shares of Brigham common stock (the "Convertible Notes") in the following amounts and prices: (i) $10 million is convertible at $3.90 per share, (ii) $10 million is convertible at $6.00 per share and (iii) $10 million is convertible at $8.00 per share. In October 2000, the Senior Credit Facility was amended in connection with the refinancing of the subordinated notes. The Senior Credit Facility was amended to, among other things, permit the issuance of new subordinated notes and new preferred stock to provide funding for the repurchase of the subordinated notes and equity interests. In addition, the minimum interest coverage ratio test of the Senior Credit Facility was amended to reflect Brigham's expected cash flow and interest expense beginning in the fourth quarter of 2000 and Brigham conditionally waived certain rights to force conversion of the portion of the borrowings under the Senior Credit Facility that are convertible at $3.90 per share. The December 2001 amendment to the Senior Credit Facility extended the maturity date from December 31, 2002 to December 31, 2003. Brigham recognized $200,000 as additional deferred loan costs that will be amortized over the remaining period to maturity of the Senior Credit Facility. In addition, the unamortized deferred loan fees relating to the Senior Credit Facility as previously amended will be amortized over the remaining period to maturity of the Senior Credit Facility. If the Senior Credit Facility is repaid at maturity or is prepaid prior to maturity without payment of cash premiums, the warrants to purchase Brigham common stock issued to the new participant in the Senior Credit Facility become exercisable. Further, to the extent Brigham chooses to prepay any of the Convertible Notes without the warrants becoming exercisable, and also assuming the lender chooses not to convert to equity upon notice of such prepayment, Brigham will be required to pay a premium above the face value of the Convertible Notes to the lender. Such premium amounts would range from 150% to 110%, depending upon the timing of the prepayment. Such prepayment, however, would require prior approval of the original lenders to the Senior Credit Facility. In addition, certain financial covenants of the Senior Credit Facility were amended or added in the July 1999, February 2000 and October 2000 amendments. In connection with the February 2000 amendment, Brigham reset the price of the warrants previously issued to its existing senior lenders to purchase one million shares of Brigham common stock from the then current exercise price of $2.25 per share to $2.02 per share. As of December 31, 2001, Brigham had $75 million in borrowings outstanding under the Senior Credit Facility, of which the Convertible Notes are $30 million. Principal outstanding under the Senior Credit Facility is due at maturity with interest due monthly for base rate tranches or periodically as LIBOR tranches mature. The annual interest rate for borrowings under the Senior Credit Facility is either the lender's base rate or LIBOR (1.88% on December 31, 2001) plus 3.00%, at Brigham's F-13 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) option. Obligations under the Senior Credit Facility are secured by substantially all of Brigham's oil and natural gas properties and other tangible assets. The Senior Credit Facility contains various restrictive covenants and compliance requirements, which include minimum current ratio, interest coverage ratio, limitations on capital expenditures related to seismic and land activities, and various other financial covenants. At December 31, 2001 and for the year then ended, Brigham was in compliance with the covenants. SENIOR SUBORDINATED NOTES PAYABLE In August 1998, Brigham issued $50 million of debt and equity securities to two affiliated institutional investors. The financing transaction consisted of the issuance of $40 million of senior subordinated secured notes (the "Subordinated Notes") with warrants (the "Warrants") to purchase Brigham's common stock and the sale of $10 million of Brigham's common stock, or 1,052,632 shares at a price of $9.50 per share. The combined sale of the Subordinated Notes and common stock of Brigham generated proceeds, net of transaction costs, of approximately $47.5 million that was used to repay a portion of the then outstanding borrowings under the Senior Credit Facility. Principal outstanding under the Subordinated Notes was due at maturity on August 20, 2003. Interest on the Subordinated Notes was payable quarterly at rates that vary depending upon whether accrued interest was paid in cash or "in kind" through the issuance of additional Subordinated Notes. Interest was payable in cash at interest rates of 12%, 13%, and 14% during the years one through three, year four and year five, respectively, of the term of the Subordinated Notes; provided, however, that Brigham was permitted to pay interest in kind for a cumulative total of seven (or potentially eight) quarterly interest payments at interest rates of 13%, 14% and 15% during the years one through three, year four and year five, respectively, of the term of the Subordinated Notes. Brigham was permitted to repay the Subordinated Notes in full without premium at any time prior to maturity. The indenture governing the Subordinated Notes contained certain covenants including, but not limited to, limitations or restrictions on indebtedness, distributions, affiliate transactions, liens and sale and leaseback transactions. The indenture prohibited all dividends on Brigham's stock. Warrants to purchase 1 million shares of Brigham's common stock exercisable during a period of seven years at a price of $10.45 per share were issued in connection with the Subordinated Notes. Concurrent with the issuance of the Subordinated Notes, Brigham recorded a discount on the Subordinated Notes of $4.5 million to reflect the estimated value of the Warrants. Also, in connection with the issuance of the Subordinated Notes, certain fees and expenses totaling approximately $1.8 million were recorded as deferred costs. The Subordinated Note discount and deferred fees were amortized over the five-year term of the Subordinated Notes. In March 1999, the indenture governing the Subordinated Notes was amended to provide Brigham with the option to pay interest due on the Subordinated Notes in kind, for any reason, through the second quarter of 2000. The amendment also provided for a reduction in the exercise price per share of the Warrants from $10.45 per share to $3.50 per share. The discount on the Subordinated Notes was decreased by $479,000 to reflect the change in value attributed to the Warrants as a result of the revision in the terms of the Warrants. In February 2000, the indenture governing the Subordinated Notes was amended to, among other things, provide Brigham with an extension of its right to pay interest through the issuance of additional Subordinated Notes in lieu of cash (or "in kind") through the third quarter of 2000 and potentially through the fourth quarter of 2000 if certain conditions were met. In exchange for granting these amendments, Brigham (i) reset the price of the warrants previously issued to the holders of the F-14 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Subordinated Notes to purchase one million shares of Brigham's common stock from an exercise price of $3.50 per share to $2.43 per share and (ii) granted to the holders of the Subordinated Notes a term overriding royalty interest that provided for the limited right to receive 4%, or 3% if certain conditions were met, of Brigham's net production revenue to reduce any outstanding Subordinated Notes issued as interest paid in kind. As payments were made pursuant to the term overriding royalty interest, they were recorded by Brigham as a reduction of the balance payable pursuant to the Subordinated Notes. On November 1, 2000, the Subordinated Notes, the term overriding royalty interest and all of the equity securities of Brigham held by the holders of the Subordinated Notes were purchased by Brigham for $20 million cash resulting in an extraordinary gain of $32.3 million, net of transaction costs of $1.7 million. In October 2000, Brigham issued $20 million of new subordinated notes to Shell Capital Inc. (the "SCI Notes") and 1,250,000 warrants to purchase Brigham's common stock (the "SCI Warrants"). The SCI Notes are issued pursuant to a multi-draw facility at borrowing increments of at least $1 million, and such funds cannot be redrawn once they have been repaid. Principal is due at maturity in 2005 and interest at the rate of 10.75% per annum is payable quarterly on the last day of each January, April, July and October. At Brigham's option, up to 50% of the interest payments during the first two years can be satisfied by payment-in-kind ("PIK") through the issuance of additional SCI Notes in lieu of cash. The SCI Notes are secured obligations ranking junior to Brigham's existing $75 million Senior Credit Facility, are redeemable at Brigham's option for face value at anytime and have certain financial and other covenants. The SCI Warrants have a term of seven years, an exercise price of $3.00 per share and a cashless exercise feature. Brigham valued the SCI Warrants using the Black-Scholes valuation model and recorded the estimated value of $2.9 million as deferred loan costs which are being amortized over the five-year term of the SCI Notes. The outstanding balance of the SCI Notes totaled $16.7 and $7.0 million at December 31, 2001 and 2000, respectively. The SCI Notes contain various restrictive covenants and compliance requirements, which include minimum current ratio, interest coverage ratio, limitations on capital expenditures related to seismic and land activities, and various other financial covenants. At December 31, 2001 and for the year then ended, Brigham was in compliance with the covenants. 6. SERIES A PREFERRED STOCK In October 2000, Brigham designated 1.5 million shares of preferred stock as Series A Preferred Stock, which has a par value of $.01 per share and a stated value of $20 per share. The Series A Preferred Stock is cumulative and pays dividends quarterly at a rate of 6% per annum of the stated value if paid in cash or 8% per annum of the stated value if paid-in-kind ("PIK") through the issuance of additional Series A Preferred Stock in lieu of cash. At Brigham's option, up to 100% of the dividend payments on the Series A Preferred Stock can be paid by the issuance of PIK dividends for five years. The Series A Preferred Stock matures in ten years and is redeemable at Brigham's option at 100% or 101% of par value (depending upon certain conditions) at anytime prior to maturity. On November 1, 2000, Brigham issued one million shares of mandatorily redeemable preferred stock (the "Series A Preferred Stock") and 6,666,667 warrants to purchase Brigham's common stock (the "Series A Warrants") for net proceeds of $19.8 million. The proceeds from the issuance of the Series A Preferred Stock and Series A Warrants were used to purchase the Subordinated Notes, the term overriding royalty interest and all of the equity securities of Brigham held by the holder of the Subordinated Notes as described in Note 5. F-15 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The Series A Warrants have a term of ten years, an exercise price of $3.00 per share and must be exercised, if Brigham so requires, in the event Brigham's common stock trades at or above $5.00 per share for 60 consecutive trading days. The exercise price of the Series A Warrants is payable either in cash or in shares of the Series A Preferred Stock valued at liquidation value plus accrued dividends. If Brigham requires exercise of the Series A Warrants, proceeds will be used to fund the redemption of a similar value of then outstanding Series A Preferred Stock. The Series A Warrants were valued at $11.5 million using the Black-Scholes valuation model and were recorded as additional paid-in capital in 2000. In March 2001, Brigham designated an additional 750,000 shares of preferred stock as Series A and issued 500,000 shares of Series A Preferred Stock and 2,105,263 warrants to purchase Brigham's common stock (the "Additional Series A Warrants") for net proceeds of $9.8 million. The Additional Series A Warrants have terms similar to the Series A Warrants described above except the Additional Series A Warrants have an exercise price of $4.75 per share and must be exercised, if Brigham so requires, in the event that Brigham's common stock trades at an average of at least 150% of the exercise price (currently $7.125 per share) for 60 consecutive trading days. The Additional Series A Warrants were valued at approximately $4.5 million using the Black-Scholes valuation model and were recorded as additional paid-in capital in March 2001. Brigham had 1,630,692 and 1,000,000 shares of Series A Preferred Stock issued and outstanding with a redemption value of $32.6 million and $20.0 million at December 31, 2001 and 2000, respectively, 7. ISSUANCE OF COMMON STOCK In February 2000, Brigham issued 2,195,122 shares of common stock and 731,707 warrants to purchase Brigham's common stock for total net proceeds of approximately $4.2 million in a private placement to a group of institutional investors led by affiliates of two members of Brigham's board of directors. The equity sale consisted of units that included one share of common stock and one-third of a warrant to purchase Brigham's common stock at an exercise price of $2.5625 per share. 8. CAPITAL LEASE OBLIGATIONS Property under capital leases consists of the following (in thousands): <Table> <Caption> DECEMBER 31, ------------------- 2001 2000 -------- -------- 3-D seismic interpretation workstations and software........ $ 45 $ 601 Office furniture and equipment.............................. 167 167 ----- ----- 212 768 Accumulated depreciation and amortization................... (175) (587) ----- ----- $ 37 $ 181 ===== ===== </Table> The obligations under capital leases are at fixed interest rates ranging from 7.5% to 17.9% and are collateralized by property, plant and equipment. The future minimum lease payments under the capital F-16 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) leases and the present value of the net minimum lease payments at December 31, 2001 are as follows (in thousands): <Table> 2002........................................................ $ 30 2003........................................................ -- ---- Total minimum lease payments................................ 30 Estimated executory costs included in capital leases...... (1) ---- Net minimum lease payments.................................. 29 Amounts representing interest............................. (1) ---- Present value of net minimum lease payments................. 28 Less: current portion....................................... (28) ---- Noncurrent portion.......................................... $ -- ==== </Table> 9. INCOME TAXES The provision for income taxes consists of the following (in thousands): <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------------ 2001 2000 1999 -------- -------- -------- Current income taxes: Federal............................................. $ -- $ -- $ -- State............................................... -- -- -- Deferred income taxes: Federal............................................. -- -- -- State............................................... -- -- -- ---- ---- ---- $ -- $ -- $ -- ==== ==== ==== </Table> The difference in income taxes provided and the amounts determined by applying the federal statutory tax rate to income before income taxes result from the following (in thousands): <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Tax at statutory rate............................. $ 4,091 $ 5,814 $(7,570) Add the effect of: Nondeductible expenses.......................... 4 12 8 Deductible stock compensation................... (9) -- -- Valuation allowance............................. (4,087) (5,826) 7,562 ------- ------- ------- $ -- $ -- $ -- ======= ======= ======= </Table> F-17 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The components of deferred income tax assets and liabilities are as follows (in thousands): <Table> <Caption> DECEMBER 31, ------------------- 2001 2000 -------- -------- Deferred tax assets: Net operating loss carryforwards...................... $ 31,085 $ 26,329 Capital loss carryforwards............................ 438 -- Stock compensation.................................... 745 305 Derivative assets..................................... -- 3,434 Gas imbalances........................................ 445 -- Other................................................. 7 26 -------- -------- 32,720 30,094 -------- -------- Deferred tax liability: Depreciable and depletable property................... (24,058) (17,578) Derivative liabilities................................ (233) -- -------- -------- (24,291) (17,578) -------- -------- Net deferred tax asset................................ 8,429 12,516 Valuation allowance................................... (8,429) (12,516) -------- -------- $ -- $ -- ======== ======== </Table> Realization of deferred tax assets associated with net operating loss carryforwards ("NOLs") and other credit carryforwards is dependent upon generating sufficient taxable income prior to their expiration. At December 31, 2001, management believes it is more likely than not that these NOLs and other credit carryforwards may expire unused and, accordingly, has established a valuation allowance of $8.4 million against them. The valuation allowance was reduced by $4.1 million in 2001 due to an increase of $6.7 million in deferred tax liabilities, partially offset by a $2.4 million increase in carryforward amounts. At December 31, 2001, Brigham has regular tax net operating loss carryforwards of approximately $88.8 million of which $13.3 million expires in 2012, $26.4 million expires in 2018, $21.0 expires in 2019, $11.7 million expires in 2020 and $16.4 million expires in 2021. In addition, at December 31, 2001, Brigham has alternative minimum tax net operating loss carryforwards of approximately $74.5 million of which $8.7 million expires in 2012, $23.2 million expires in 2018, $20.4 million expires in 2019, $6.7 million expires in 2020 and $15.5 million expires in 2021. Also, at December 31, 2001, Brigham has capital loss carryforwards of approximately $1.3 million that expire in 2006. Brigham believes it has a limitation on its net operating losses under Internal Revenue Code Section 382 due to a potential 50% change in ownership among its 5% shareholders over a three-year period. This limitation is approximately $4.5 million per year. 10. NET INCOME (LOSS) PER SHARE Basic earnings per share are computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or F-18 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) resulted in the issuance of common stock that would then share in the earnings of Brigham. The number of common share equivalents outstanding is computed using the treasury stock method. <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Basic EPS: Income (loss) available to common stockholders before extraordinary item................................. $ 9,238 $(15,930) $(21,628) Extraordinary item................................... -- 32,267 -- ------- -------- -------- Income (loss) available to common stockholders..... $ 9,238 $ 16,337 $(21,628) ======= ======== ======== Common shares outstanding.......................... 15,988 16,241 14,152 ======= ======== ======== Basic EPS Income (loss) available to common stockholders before extraordinary item........................ $ 0.58 $ (0.98) $ (1.53) Extraordinary item................................. -- 1.99 -- ------- -------- -------- $ 0.58 $ 1.01 $ (1.53) ======= ======== ======== Diluted EPS: Income (loss) available to common stockholders before extraordinary item................................. $ 9,238 $(15,930) $(21,628) Extraordinary item................................... -- 32,267 -- ------- -------- -------- Income (loss) available to common stockholders..... $ 9,238 $ 16,337 $(21,628) Adjustments for assumed conversions: Amortization of compensation expense on stock options.......................................... 20 -- -- Income (loss) available to common stockholders before extraordinary item--diluted........................ $ 9,258 $(15,930) $(21,628) Extraordinary item................................... -- 32,267 -- ------- -------- -------- Income (loss) available to common stockholders--diluted............................ $ 9,258 $ 16,337 $(21,628) ======= ======== ======== Common shares outstanding............................ 15,988 16,241 14,152 Effect of dilutive securities: Warrants........................................... 926 -- -- Stock options...................................... 329 -- -- ------- -------- -------- Potentially dilutive common shares................... 1,255 -- -- ------- -------- -------- Adjusted common shares outstanding--diluted........ 17,243 16,241 14,152 ======= ======== ======== Diluted EPS Income (loss) available to common stockholders before extraordinary item........................ $ 0.54 $ (0.98) $ (1.53) Extraordinary item................................. -- 1.99 -- ------- -------- -------- $ 0.54 $ 1.01 $ (1.53) ======= ======== ======== </Table> F-19 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) At December 31, 2001, 2000, and 1999 options and warrants to purchase approximately 7.7 million, 11.1 million and 3.5 million shares of common stock, respectively, were outstanding but were not included in the computation of diluted income (loss) per share because the effect of including the options and warrants would have been anti-dilutive. 11. CONTINGENCIES, COMMITMENTS AND FACTORS WHICH MAY AFFECT FUTURE OPERATIONS LITIGATION Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of Brigham. On November 20, 2001, Brigham filed a lawsuit in the District Court of Travis County, Texas against Steve Massey Company, Inc. ("Massey") for breach of contract. The Petition claims Massey furnished defective casing to Brigham, which ultimately led to the casing failure of the Palmer "347" No. 5 well (the "Palmer #5") and the loss of the Palmer #5 as a producing well. Brigham believes the amount of damages incurred due to the loss of the Palmer #5 may exceed $5 million. Massey joined as additional defendants to the lawsuit other parties that had responsibility for the manufacture, importation or fabrication of the casing for its use in the Palmer #5. The case is currently in discovery. A trial has not been set. Brigham believes a trial will not take place before the first quarter of 2003. On February 20, 2002, Massey filed an Original Petition to Foreclose Lien in Brooks County, Texas. Massey's Petition claims Brigham breached its contract for failure to pay for the casing it furnished Brigham for the Palmer #5 (and that Brigham's claim is defective, forming the basis of the lawsuit described in the paragraph above). Massey's Petition claims Brigham owes Massey a total of $445,819. Brigham recently filed a Motion to Transfer Venue to Travis County, Texas, to join this case with Brigham's suit against Masses pending in Travis County. In the addition, Brigham has asked for a Plea in Abatement to place the case on hold until the Travis County suit has been resolved. If Massey is successful in its Brooks County case, Massey would have the right to foreclose its lien against the well, associated equipment and Brigham's leasehold interest. At this point in time, Brigham cannot predict the outcome of either the Travis County case or the Brooks County case. On June 1, 2001, Leonel Garcia, a landowner in Brooks County, Texas, filed suit against Brigham, claiming Brigham transported natural gas under his property through an existing pipeline, without his consent. Brigham is now using an alternate pipeline. Mr. Garcia is claiming $1.2 million in actual damages and $3 million in exemplary damages. Brigham is strenuously defending this lawsuit, believing there is no basis for the damages being claimed. The case has been set for mediation on May 2, 2002. At this point in time, Brigham cannot predict the outcome of this case. As of December 31, 2001, there were no known environmental or other regulatory matters related to Brigham's operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham's capital expenditures, earnings or competitive position. OPERATING LEASE COMMITMENTS Brigham leases office equipment and space under operating leases expiring at various dates. The noncancelable term of the lease for Brigham's office space expires in 2007 with an option to renew for F-20 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) an additional five years. The future minimum annual rental payments under the noncancelable terms of these leases at December 31, 2001 are as follows (in thousands): <Table> 2002........................................................ $ 864 2003........................................................ 881 2004........................................................ 881 2005........................................................ 881 2006........................................................ 881 Thereafter.................................................. 440 ------ $4,828 ====== </Table> Future minimum rental payments are not reduced by minimum sublease rental income of approximately $45,000 due in 2002 under noncancelable subleases. Rental expense for the years ended December 31, 2001, 2000 and 1999 was approximately $731,000, $805,000 and $938,000, respectively. MAJOR PURCHASERS The following purchasers accounted for 10% or more of Brigham's oil and natural gas sales for the years ended December 31, 2001, 2000 and 1999: <Table> <Caption> 2001 2000 1999 -------- -------- -------- Purchaser A............................................. 45% 36% 26% Purchaser B............................................. 15% 20% 16% Purchaser C............................................. -- -- 11% </Table> Brigham ended its existing relationship with Purchaser A effective March 1, 2002 and has given notice as required by contract of its intent to end its relationship with Purchaser B at the end of the notice period. Due to the availability of other purchasers, Brigham does not believe that the loss of either of these purchasers will adversely affect Brigham's result of operations. FACTORS WHICH MAY AFFECT FUTURE OPERATIONS Since Brigham's major products are commodities, significant changes in the prices of oil and natural gas could have a significant impact on Brigham's results of operations for any particular year. 12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of volatility in price changes on the oil and natural gas commodities it produces and sells, (ii) support its capital budgeting plans, and (iii) lock-in prices to protect the economics related to certain capital projects. As of December 31, 2001, Brigham has three fixed price swap derivative contracts that are designated as hedges and one fixed price cap derivative contract that is not designated as a hedge. The F-21 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) following table sets forth Brigham's outstanding natural gas derivative contracts as of December 31, 2001: NATURAL GAS DERIVATIVE CONTRACTS <Table> <Caption> 2002 2003 --------------------- -------------------- AVERAGE AVERAGE VOLUMES CONTRACT VOLUMES CONTRACT REMAINING HEDGED PRICE HEDGED PRICE PRICING BASIS CONTRACT TERM (MMBTU) ($/MMBTU) (MMBTU) ($/MMBTU) ------------- -------------- --------- --------- -------- --------- Fixed Price Swaps: Contract #1........... NYMEX January 2002 - June 2002 452,500 $2.8000 -- -- Contract #2........... NYMEX January 2002 - December 2002 912,500 $2.9000 -- -- Contract #3........... NYMEX January 2002 - June 2003 912,500 $3.0000 452,500 $3.0000 Fixed Price Cap......... ANR January 2002 - Oklahoma June 2002 1,810,000 $2.6326 -- -- </Table> There were no outstanding oil derivative contracts as of December 31, 2001. However, in February 2002, Brigham entered into a combination of crude oil cap and floor option contracts. Under these option contracts, which together form collars, Brigham will receive a maximum of $21.95 per Bbl and a minimum of $18.00 per Bbl for 250 Bbls per day for the period from February 2002 to June 2002, a maximum of $22.35 per Bbl and minimum of $18.00 per Bbl for 250 Bbls per day for the period from February 2002 to December 2002, and a maximum of $22.56 per Bbl and minimum of $18.00 per Bbl for 250 Bbls per day for the period from February 2002 to June 2003. These contracts settle based on the NYMEX price for West Texas Intermediate and are designated as cash flow hedges under SFAS 133. In March 2002, Brigham entered into six natural gas fixed price swap agreements whereby Brigham exchanged a floating market price for a fixed contract price of $3.20 per MMBtu for 2,500 MMBtu per day for the period from July 2002 to September 2002, $3.46 per MMBtu for 1,000 MMBtu per day for the period from October 2002 to December 2002, $3.70 per MMBtu for 2,500 MMBtu per day for the period from January 2003 to March 2003, $3.40 per MMBtu for 1,000 MMBtu per day for the period from April 2003 to June 2003, $3.45 per MMBtu for 2,500 MMBtu per day for the period from July 2003 to September 2003, and $3.67 per MMBtu for 1,000 MMBtu per day for the period from October 2003 to December 2003. These contracts settle based on the NYMEX price for natural gas and will be designated as cash flow hedges. Brigham also entered into six crude oil fixed price swap agreements in March 2002, whereby Brigham exchanged a floating market price for a fixed contract price of $25.06 per Bbl for 500 Bbl per day for the period from July 2002 to September 2002, $24.50 per Bbl for 250 Bbls per day for the period from October 2002 to December 2002, $23.92 per Bbl for 250 Bbls per day for the period from January 2003 to March 2003, $23.50 per Bbl for 250 Bbls per day for the period from April 2003 to June 2003, $23.15 per Bbl for 250 Bbls per day for the period from July 2003 to September 2003, and $22.90 per Bbl for 250 Bbls per day for the period from October 2003 to December 2003. These F-22 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) contracts settle based on the NYMEX price for West Texas Intermediate and will be designated as cash flow hedges. At December 31, 2001, the fair value of hedging contracts included in accumulated other comprehensive income and other current assets was approximately $351,000 of which approximately $50,000 was classified as noncurrent assets. 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 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, 2001: <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- NATURAL GAS Average price per Mcf as reported (including hedging results)................................................ $ 3.11 $ 1.94 $ 2.11 Average price per Mcf realized (excluding hedging results)................................................ $ 4.29 $ 4.06 $ 2.22 Decrease in revenue (in thousands)........................ $(8,001) $(9,400) $ (486) OIL Average price per Bbl as reported (including hedging results)................................................ $ 24.05 $ 29.17 $17.79 Average price per Bbl realized (excluding hedging results)................................................ $ 24.38 $ 29.47 $17.79 Decrease in revenue (in thousands)........................ $ (153) $ (107) $ -- </Table> Derivative instruments that do not qualify as hedging contracts are recorded at fair value on the balance sheet. At each balance sheet date, the value of these derivatives is adjusted to reflect current fair value and any gains or losses are recognized as other income or expense. At December 31, 2001 and 2000, the fair value of these derivatives included in other liabilities was $384,000 and $10.1 million, respectively. Brigham recognized $9.7 million, $(8.9) million and $(115,000) in non-cash gains (losses) related to changes in the fair values of these derivative contracts and $1.5 million, $620,000 and $48,000 in losses related to the cash settlement payments made by Brigham to the counterparty for the years ended December 31, 2001, 2000 and 1999, respectively. 13. FINANCIAL INSTRUMENTS Brigham's non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The carrying value of Brigham's Senior Credit Facility approximates its fair market value since it bears interest at floating market interest rates. The fair value of Brigham's SCI Notes at December 31, 2001 was $13.9 million. F-23 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Brigham's accounts receivable relate to oil and natural gas sold to various industry companies, and amounts due from industry participants for expenditures made by Brigham on their behalf. Credit terms, typical of industry standards, are of a short-term nature and Brigham does not require collateral. Brigham's accounts receivable at December 31, 2001 and 2000 do not represent significant credit risks as they are dispersed across many counterparties. Counterparties to the natural gas and crude oil price swaps are investment grade financial institutions. 14. EMPLOYEE BENEFIT PLANS Brigham has adopted a defined contribution 401(k) plan for substantially all of its employees. The plan provides for Brigham matching of employee contributions to the plan, at Brigham's discretion. During 2001, Brigham matched 25% of eligible employee contributions. Based on attainment of performance goals established at the beginning of 2001, Brigham matched an additional 17% of eligible employee contributions made during 2001. Brigham contributed $102,000 to the 401(k) plan for the year ended December 31, 2001 to match eligible contributions by employees. Prior to 2001, Brigham had not matched employee contributions. 15. STOCK BASED COMPENSATION Brigham adopted an incentive plan, effective upon completion of the Exchange (see Note 1), which provides for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to reward key employees whose performance may have a significant effect on the success of Brigham. An aggregate of 1,588,170 shares of Brigham's common stock was reserved for issuance pursuant to this plan. By resolution of the stockholders in May 2001, the number of shares of common stock available under the plan was amended to equal the lesser of 13% of the shares of common stock of Brigham issued and outstanding at any time or 2,077,335 shares. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham's common stock on the date of grant and generally vest over three to five years. Brigham also maintains a plan under which it offers stock compensation to non-employee directors. Pursuant to the terms of the plan, non-employee directors are entitled to annual grants. Options granted under this plan have an exercise price equal to the fair market value of Brigham's common stock on the date of grant and generally vest over five years. F-24 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table summarizes activity under the incentive plan for each of the three years ended December 31, 2001: <Table> <Caption> WEIGHTED AVERAGE SHARES EXERCISE PRICE --------- ---------------- Options outstanding December 31, 1998.............. 1,194,654 $ 5.63 Options granted................................ 650,000 2.43 Options forfeited or cancelled................. (324,761) (4.68) Options exercised.............................. (167) (7.46) --------- ------ Options outstanding December 31, 1999.............. 1,519,726 4.47 Options granted................................ 793,500 2.83 Options forfeited or cancelled................. (898,112) (5.57) Options exercised.............................. (8,000) (5.11) --------- ------ Options outstanding December 31, 2000.............. 1,407,114 2.89 Options granted................................ 546,500 3.44 Options forfeited or cancelled................. (239,369) (3.48) Options exercised.............................. (97,474) (2.59) --------- ------ Options outstanding December 31, 2001.............. 1,616,771 $ 3.00 ========= ====== </Table> Brigham is required to use variable accounting for 252,500 of the stock options granted during 2000. This method of accounting requires recognition of noncash compensation expense for the difference between the option exercise price and the market price of Brigham's stock at the end of the accounting period of vested options. Since the market price for Brigham's stock is a component of the variable cost accounting calculation, it is not possible to determine the total noncash compensation expense that will be recognized during the vesting period of these options. Exercise prices for options outstanding at December 31, 2001 and 2000 range from $1.5545 to $14.375 and have remaining contract lives of 1 to 7 years. Exercise prices for options outstanding at December 31, 1999 range from $1.5545 to $14.375 and remaining contractual lives range from 4.5 to 7 years. Options exercisable at December 31, 2001, 2000 and 1999 were 378,495, 247,450, and 291,242, respectively. The weighted average fair value per share of stock compensation issued during 2001, 2000 and 1999 was $2.19, $1.92, and $1.42, respectively. The fair value for these options was estimated using the Black-Scholes model with the following weighted average assumptions for grants made in 2001, 2000 and 1999; risk free interest rate of 4.9%, 6.2%, and 6.0%; volatility of the expected market prices of Brigham's common stock of 60%, 67% and 57%; expected dividend yield of zero and weighted average expected option lives of 7.0, 6.6, and 5.6 years, respectively. The Black-Scholes valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are transferable. Additionally, the assumptions required by the valuation model are highly subjective. Because Brigham's stock options have significantly different characteristics from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion the model does not necessarily provide a reliable single measure of the fair value of Brigham's stock options. Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123, F-25 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Brigham's net income (loss) and net income (loss) per share for the years ended December 31, 2001, 2000 and 1999 would have been the pro forma amounts indicated below: <Table> <Caption> 2001 2000 1999 -------- -------- -------- Net income (loss) available to common stockholders (in thousands): As reported............................................ $9,238 $16,337 $(21,628) Pro forma.............................................. 9,186 17,470 (21,605) Net income (loss) per share: Basic: As reported.......................................... $ 0.58 $ 1.01 $ (1.53) Pro forma............................................ 0.57 1.08 (1.53) Diluted: As reported.......................................... $ 0.54 $ 1.01 $ (1.53) Pro forma............................................ 0.53 1.08 (1.53) </Table> EXCHANGE OF CERTAIN OPTIONS FOR SHARES OF RESTRICTED STOCK On October 25, 2000, the compensation committee of the Board of Directors approved a proposal to give its employees a one-time right to elect to cancel all or half of their outstanding employee stock options which were previously granted with exercise prices of $5.00 per share (the "$5 Options") or $6.31 per share (the "$6.31 Options") and to receive in exchange shares of restricted stock under Brigham's 1997 Incentive Plan. The exchange ratios were .643 shares of restricted stock for each share of common stock underlying a $5 Option and .4 shares of restricted stock for each share of common stock underlying a $6.31 Option. Pursuant to the option exchange offer, on October 27, 2000, a total of 244,794 of the $5 Options were canceled in exchange for 157,401 shares of restricted stock, and a total of 379,665 of the $6.31 Options were canceled in exchange for 151,866 shares of restricted stock. Regardless of whether the canceled options were vested or unvested, the shares of restricted stock vest 25% per year beginning October 27, 2000. The restricted stock agreements contain provisions for accelerated vesting in some circumstances, which provisions are similar to those in the agreements covering the canceled options. This exchange resulted in noncash compensation expense of approximately $1.1 million that is being recognized over the vesting period of the restricted stock. 16. RELATED PARTY TRANSACTIONS During the years ended December 31, 2001, 2000 and 1999, Brigham incurred costs of approximately $355,000, $138,000 and $180,000, respectively, in fees for land acquisition services performed by a company owned by a brother of Brigham's President and Chief Executive Officer and its Senior Vice President--Land and Administration. Other participants in Brigham's 3-D seismic projects reimbursed Brigham for a portion of these amounts. At December 31, 2001 and 2000, Brigham had recorded a liability in accounts payable of approximately $30,000 and $19,000, respectively, related to services performed by this company. A director of Brigham served as a consultant to Brigham on various aspects of Brigham's business and strategic issues. Fees paid for these services by Brigham were approximately $44,000, $33,000 and $63,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Additional disbursements totaling approximately $6,000, $12,000 and $12,000 were made during 2001, 2000 and 1999, respectively, F-26 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) for the reimbursement of certain expenses. At December 31, 2001 and 2000, there were no payables related to these services recorded by Brigham. From time to time, in the normal course of business, Brigham has engaged a drilling company in which one of Brigham's current directors owns stock and serves on the board of directors. Total payments during 2001 and 2000 were $3.9 million and $2.4 million, respectively. At December 31, 2001 the drilling company was not performing work for Brigham and there were no amounts owed. In October 2001, Brigham entered into a Joint Exploration Agreement with Carrizo Oil & Gas, Inc. ("Carrizo"). Under the terms of this agreement the parties (1) blended their existing oil and gas leasehold positions covering a South Texas prospect, (2) identified five separate areas of mutual interest within the prospect, and (3) agreed upon procedures for the future exploration and development of the prospect. One of Brigham's current directors was a co-founder of Carrizo and is currently a member of Carrizo's board of directors. At December 31, 2001 Brigham was owed $158,000 by Carrizo for exploration and production activities. Brigham owed Carrizo $13,000 at December 31, 2001. During 2001, Brigham entered into three agreements with Aspect Resources, LLC ("Aspect"). These agreements included (1) a Joint Development Agreement extending the term of an area of mutual interest arrangement, and establishing cost sharing for potential expenditures within the project area; (2) an Agreement and Partial Assignment of Seismic Participation Agreement under which Aspect assigned Brigham an interest in an existing 3-D seismic project and Brigham must pay the assigned interest portion of future costs; (3) a Geophysical Exploration Agreement under which Brigham assigned Aspect an interest in an existing 3-D project area (with certain exclusion) and Aspect agreed to provide certain seismic data overlapping the project area and share in future costs. The President of Aspect is a current director of Brigham and a member of the Compensation Committee. Total amounts paid to Aspect during 2001 for exploration, development and production operations were $588,000. Total amounts paid to Brigham by Aspect during 2001 for exploration, development and production operations were $524,000. Brigham owed Aspect $174,000 at December 31, 2001 for various exploration and production activities. Aspect owed Brigham $291,000 and $41,000 at December 31, 2001 and 2000, respectively, for various oil and gas exploration and production activities. Brigham was also owed $20,000 by Aspect Management Corp., an affiliate of Aspect, at December 31, 2001 for joint venture operations. 17. SUPPLEMENTAL CASH FLOW INFORMATION <Table> <Caption> YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Cash paid for interest...................................... $4,257 $3,894 $1,960 Noncash investing and financing activities: Capital lease asset additions............................. -- -- 51 Decrease in accounts payable and other noncurrent liabilities in exchange for issuance of common stock.... -- -- 4,240 Increase in current liabilities for deferred loan fees to be paid in future....................................... 200 -- 50 Increase in deferred loan fees for issuance of warrants... -- 2,400 1,228 Dividends and accretion on mandatorily redeemable preferred stock......................................... 2,450 275 -- </Table> F-27 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 18. OTHER ASSETS AND LIABILITIES Other current assets consist of the following (in thousands): <Table> <Caption> DECEMBER 31, ------------------- 2001 2000 -------- -------- Gas imbalance receivables................................... $1,658 $ -- Other....................................................... 873 599 ------ ---- $2,531 $599 ====== ==== </Table> Other noncurrent liabilities consist of the following (in thousands): <Table> <Caption> DECEMBER 31, ------------------- 2001 2000 -------- -------- Gas imbalance liabilities................................... $2,929 $ -- Derivative liabilities...................................... 384 6,654 Other....................................................... 1,572 1,242 ------ ------ $4,885 $7,896 ====== ====== </Table> 19. OIL AND NATURAL GAS EXPLORATION AND PRODUCTION ACTIVITIES Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest and other contractual provisions. Lease operating expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration and development activities. Results of operations do not include interest expense and general corporate amounts. COSTS INCURRED AND CAPITALIZED COSTS The costs incurred in oil and natural gas acquisition, exploration and development activities follow (in thousands): <Table> <Caption> DECEMBER 31, ------------------------------ 2001 2000 1999 -------- -------- -------- Costs incurred for the year: Exploration.................................... $18,210 $14,238 $19,224 Property acquisition........................... 3,437 2,540 3,462 Development.................................... 14,353 12,555 4,632 Proceeds from participants..................... (135) (40) (2,439) ------- ------- ------- $35,865 $29,293 $24,879 ======= ======= ======= </Table> Costs incurred represent amounts incurred by Brigham for exploration, property acquisition and development activities. Periodically, Brigham will receive proceeds from participants subsequent to project initiation for an assignment of an interest in the project. These payments are represented by "Proceeds from participants" in the table above. F-28 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Following is a summary of costs (in thousands) excluded from depletion at December 31, 2001 by year incurred. At this time, Brigham is unable to predict either the timing of the inclusion of these costs and the related natural gas and oil reserves in its depletion computation or their potential future impact on depletion rates. <Table> <Caption> DECEMBER 31, ------------------------------ PRIOR 2001 2000 1999 YEARS TOTAL -------- -------- -------- -------- -------- Property acquisition....................... $ 644 $ 191 $ 703 $11,764 $13,302 Exploration................................ 487 77 603 18,976 20,143 Capitalized interest....................... 672 1,104 445 242 2,463 ------ ------ ------ ------- ------- Total.................................... $1,803 $1,372 $1,751 $30,982 $35,908 ====== ====== ====== ======= ======= </Table> 20. OIL AND NATURAL GAS RESERVES AND RELATED FINANCIAL DATA (UNAUDITED) Information with respect to Brigham's oil and natural gas producing activities is presented in the following tables. Reserve quantities as well as certain information regarding future production and discounted cash flows were determined by Brigham's independent petroleum consultants and internal petroleum reservoir engineer. OIL AND NATURAL GAS RESERVE DATA The following tables present Brigham's estimates of its proved oil and natural gas reserves. Brigham emphasizes reserves are approximates and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be F-29 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) developed within the periods anticipated. A substantial portion of the reserve balances was estimated utilizing the volumetric method, as opposed to the production performance method. <Table> <Caption> NATURAL GAS OIL (MMCF) (MBBLS) -------- -------- Proved reserves at December 31, 1998........................ 71,166 4,433 Revisions to previous estimates........................... (9,938) 214 Extensions, discoveries and other additions............... 30,428 1,156 Sales of minerals-in-place................................ (22,002) (2,430) Production................................................ (4,197) (346) ------- ------ Proved reserves at December 31, 1999........................ 65,457 3,027 Revisions to previous estimates........................... 83 (554) Extensions, discoveries and other additions............... 17,058 758 Production................................................ (4,431) (361) ------- ------ Proved reserves at December 31, 2000........................ 78,167 2,870 Revisions of previous estimates........................... (1,959) 351 Extensions, discoveries and other additions............... 22,554 1,101 Sales of minerals-in-place................................ (3,402) (106) Production................................................ (6,766) (468) ------- ------ Proved reserves at December 31, 2001........................ 88,594 3,748 ======= ====== Proved developed reserves at December 31: 1999...................................................... 28,594 1,873 2000...................................................... 39,271 1,802 2001...................................................... 38,633 2,609 </Table> Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN The following table presents a standardized measure of discounted future net cash inflows (in thousands) relating to proved oil and natural gas reserves. Future cash flows were computed by applying year-end prices of oil and natural gas relating to Brigham's proved reserves to the estimated year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual agreements in existence at year-end. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Actual future cash inflows F-30 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) may vary considerably and the standardized measure does not necessarily represent the fair value of Brigham's oil and natural gas reserves. <Table> <Caption> DECEMBER 31, ------------------------------- 2001 2000 1999 -------- --------- -------- Future cash inflows.................................. $301,201 $ 899,819 $228,429 Future development and production costs.............. (84,413) (154,295) (61,878) Future income taxes.................................. (34,062) (216,342) (12,406) -------- --------- -------- Future net cash inflows.............................. $182,726 $ 529,182 $154,145 ======== ========= ======== Future net cash inflow before income taxes, discounted at 10% per annum........................ $146,807 $ 497,666 $114,466 ======== ========= ======== Standardized measure of future net cash inflows discounted at 10% per annum........................ $120,924 $ 359,228 $113,546 ======== ========= ======== </Table> The base sales prices for Brigham's reserves were $2.57 per Mcf for natural gas and $19.84 per Bbl for oil as of December 31, 2001, $10.42 per Mcf for natural gas and $26.83 per Bbl for oil as of December 31, 2000, and $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31, 1999. These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate Brigham's reserves at these dates. Changes in the future net cash inflows discounted at 10% per annum follow (in thousands): <Table> <Caption> DECEMBER 31, ------------------------------- 2001 2000 1999 --------- -------- -------- Beginning of period......................................... $ 359,228 $113,546 $ 81,649 Sales of oil and natural gas produced, net of production costs................................................... (27,296) (15,218) (11,765) Development costs incurred................................ 8,310 5,308 4,413 Extensions and discoveries................................ 41,278 295,239 43,346 Sales of minerals-in-place................................ (22,476) -- (32,783) Net change of prices and production costs................. (322,047) 175,018 33,226 Change in future development costs........................ (15,956) 6,990 (555) Changes in production rates and other..................... (29,545) (83,322) 637 Revisions of quantity estimates........................... (22,676) (12,262) (11,969) Accretion of discount..................................... 49,766 11,447 8,174 Change in income taxes.................................... 102,338 (137,518) (827) --------- -------- -------- End of period............................................... $ 120,924 $359,228 $113,546 ========= ======== ======== </Table> F-31 <Page> BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 21. QUARTERLY FINANCIAL DATA (UNAUDITED) <Table> <Caption> YEAR ENDED DECEMBER 31, 2001 --------------------------------------------- QUARTER 1 QUARTER 2 QUARTER 3 QUARTER 4 --------- --------- --------- --------- Revenue............................................... $7,043 $10,504 $8,871 $ 6,130 Operating income (loss)............................... 2,425 4,876 3,296 (572) Net income (loss)..................................... 424 8,327 2,947 (2,460) Net income (loss) per share: Basic............................................... $ 0.03 $ 0.52 $ 0.18 $ (0.15) Diluted............................................. $ 0.02 $ 0.46 $ 0.17 $ (0.15) </Table> <Table> <Caption> YEAR ENDED DECEMBER 31, 2000 --------------------------------------------- QUARTER 1 QUARTER 2 QUARTER 3 QUARTER 4 --------- --------- --------- --------- Revenue............................................... $ 4,538 $ 4,651 $ 5,365 $ 4,642 Operating income...................................... 1,136 1,078 1,198 219 Net loss before extraordinary gain.................... (2,198) (4,328) (5,345) (3,784) Extraordinary gain.................................... -- -- -- 32,267 Net income (loss)..................................... (2,198) (4,328) (5,345) 28,208 Net loss per share: Basic/Diluted Net loss before extraordinary gain................ $ (0.14) $ (0.26) $ (0.32) $ (0.25) Extraordinary gain................................ -- -- -- 1.99 ------- ------- ------- ------- $ (0.14) $ (0.26) $ (0.32) $ 1.74 ======= ======= ======= ======= </Table> F-32 <Page> INDEX TO EXHIBITS The following documents are filed as exhibits to this report: <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 2.1 -- Exchange Agreement (filed as Exhibit 2.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 3.1 -- Certificate of Incorporation (filed as Exhibit 3.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 3.1.1 -- 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). 3.2 -- 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). 4.2.1 -- Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (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). 10.1 -- Agreement of Limited Partnership, dated May 1, 1992, between Brigham Exploration Company and General Atlantic Partners III, L.P. as general partners, and Harold D. Carter and GAP-Brigham Partners, L.P. as limited partners (filed as Exhibit 10.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.1.1 -- Amendment No. 1 to Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated May 1, 1992, by and among Brigham Exploration Company, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P. and Harold D. Carter (filed as Exhibit 10.1.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.1.2 -- Amendment No. 2 to Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated September 30, 1994, by and among Brigham Exploration Company, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., Harold D. Carter and the additional signatories thereto (filed as Exhibit 10.1.2 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.1.3 -- Amendment No. 3 to Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated August 24, 1995, by and among Brigham Exploration Company, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., Harold D. Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.1.3 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.1.4 -- Amended and Restated Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated December 30, 1997 by and among Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings II, L.L.C. (filed as Exhibit 10.1.4 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference) 10.2 -- Agreement of Limited Partnership of Venture Acquisitions, L.P., dated September 23, 1994, by and between Quest Resources, L.L.C. and RIMCO Energy, Inc. as general partners, and RIMCO Production Company, Inc., RIMCO Exploration Partners, L.P. I and RIMCO Exploration Partners, L.P. II, as limited partners (filed as Exhibit 10.2 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.3 -- Regulations of Quest Resources, L.L.C. (filed as Exhibit 10.3 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.4 -- Management and Ownership Agreement, dated September 23, 1994, by and among Brigham Oil & Gas, L.P., Brigham Exploration Company, General Atlantic Partners III, L.P., Harold D. Carter, Ben M. Brigham and GAP-Brigham Partners, L.P. (filed as Exhibit 10.4 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.5* -- Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit 10.4 to Brigham's Registration Statement on Form S-1 (Registration No. 33-53873), and incorporated herein by reference). 10.5.1* -- Letter agreement, dated as of March 20, 2000, setting forth amendments effective January 1, 2000, to the Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit 10.5.1 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). 10.6* -- Employment Agreement, by and between Brigham Exploration Company and Ben M. Brigham (filed as Exhibit 10.7 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.7* -- Form of Confidentiality and Noncompete Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.8 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.8* -- 1997 Incentive Plan of Brigham Exploration Company as amended 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). 10.8.1* -- 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). 10.8.2* -- 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). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 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). 10.10.1 -- First Amendment to Two Bridge Point Lease Agreement dated April 11, 1997 between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.10.2 -- Second Amendment to Two Bridge Point Lease Agreement dated October 13, 1997 between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.2 to Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.10.3 -- Letter dated April 17, 1998 exercising Right of First Refusal to Lease "3rd Option Space" (filed as Exhibit 10.9.3 to Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.10.4 -- Sublease agreement dated as of November 16, 1999, by and between Brigham Oil & Gas, L.P., and ShowSupport.com, Inc. (filed as Exhibit 10.10.4 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). 10.11 -- Anadarko Basin Seismic Operations Agreement, dated February 15, 1996, by and between Brigham Oil & Gas, L.P. and Veritas Geophysical, Ltd. (filed as Exhibit 10.15 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.11.1 -- Letter Amendment to Anadarko Basin Seismic Operations Agreement, dated June 10, 1996, between Brigham Oil & Gas, L.P. and Veritas Geophysical, Ltd. (filed as Exhibit 10.15.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.12 -- Expense Allocation and Participation Agreement, dated April 1, 1996, between Brigham Oil & Gas, L.P. and Gasco Limited Partnership. (filed as Exhibit 10.16 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.12.1 -- Amendment to Expense Allocation and Participation Agreement, dated October 21, 1996, between Brigham Oil & Gas, L.P. and Gasco Limited Partnership (filed as Exhibit 10.16.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.13 -- Expense Allocation and Participation Agreement, dated April 1, 1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.13.1 -- Amendment to Expense Allocation and Participation Agreement, dated September 26, 1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.13.2 -- Letter Amendment to Expense Allocation and Participation Agreement, dated May 20, 1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.2 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.14 -- Anadarko Basin Joint Participation Agreement, dated May 1, 1996, by and among Stephens Production Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.18 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.15 -- Anadarko Basin Joint Participation Agreement, dated May 1, 1996, by and between Vintage Petroleum, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.19 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.16 -- Processing Alliance Agreement, dated July 20, 1993, between Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.20 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.16.1 -- Letter Amendment to Processing Alliance Agreement, dated November 3, 1994, between Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.20.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.17 -- Agreement and Assignment of Interest, West Bradley Project, dated September 1, 1995, by and between Aspect Resources Limited Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.21 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.18 -- Agreement and Assignment of Interests in lands located in Grady County, Oklahoma, West Bradley Project, dated December 1, 1995, by and between Aspect Resources Limited Liability Company, Brigham Oil & Gas, L.P. and Venture Acquisitions, L.P. (filed as Exhibit 10.22 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.19 -- Agreement and Assignment of Interests, West Bradley Project, dated December 1, 1995, by and between Aspect Resources Limited Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.23 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.20 -- Geophysical Exploration Agreement, Hardeman Project, Hardeman and Wilbarger Counties, Texas and Jackson County, Oklahoma, dated March 15, 1993 by and among General Atlantic Resources, Inc., Maynard Oil Company, Ruja Muta Corporation, Tucker Scully Interests Ltd., JHJ Exploration, Ltd., Cheyenne Petroleum Company, Antrim Resources, Inc., and Brigham Oil & Gas, L.P. (filed as Exhibit 10.24 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.21 -- Agreement and Partial Assignment of Interests in OK13?P Prospect Area, Jackson County, Oklahoma (Hardeman Project), dated August 1, 1995, by and between Brigham Oil & Gas, L.P. and Aspect Resources Limited Liability Company (filed as Exhibit 10.25 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.22 -- Agreement and Partial Assignment of Interests in Q140?E Prospect Area, Hardeman County, Texas (Hardeman Project), dated August 1, 1995, by and between Brigham Oil & Gas, L.P. and Aspect Resources Limited Liability Company (filed as Exhibit 10.26 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.23 -- Agreement and Partial Assignment of Interests in Hankins #1 Chappel Prospect Agreement, Jackson County, Oklahoma (Hardeman Project), dated March 21, 1996, by and between Brigham Oil & Gas, L.P., NGR, Ltd. and Aspect Resources Limited Liability Company (filed as Exhibit 10.27 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.24 -- Form of Indemnity Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.28 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.25 -- Registration Rights Agreement dated February 26, 1997 by and among Brigham Exploration Company, General Atlantic Partners III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II, RIMCO Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M. Brigham, Anne L. Brigham, Harold D. Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.29 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.26 -- 1997 Director Stock Option Plan (filed as Exhibit 10.30 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.27 -- Form of Employee Stock Ownership Agreement (filed as Exhibit 10.31 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.28 -- Agreement and Assignment of Interest in Geophysical Exploration Agreement, Esperson Dome Project, dated November 1, 1994, by and between Brigham Oil & Gas, L.P. and Vaquero Gas Company (filed as Exhibit 10.33 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.29 -- Geophysical Exploration Agreement, Southwest Danbury Project, Brazoria County, Texas, dated as of July 1, 1996, by and among UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.34 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.30 -- Geophysical Exploration Agreement, Welder Project, Duval County, Texas, dated as of October 1, 1996, by and among UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.35 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.31 -- Proposed Trade Structure, RIMCO/Tigre Project, Vermillion Parish, Louisiana, among Brigham Oil & Gas, L.P., Tigre Energy Corporation and Resource Investors Management Company (filed as Exhibit 10.36 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.31.1 -- Letter relating to Proposed Trade Structure, RIMCO/Tigre Project, dated January 31, 1997, from Resource Investors Management Company to Brigham Oil & Gas, L.P. (filed as Exhibit 10.36 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.31.2 -- Agreement dated March 6, 2000 by and between RIMCO Production Co., Tigre Energy Corporation and Brigham Oil & Gas, L.P. regarding modifications to the Proposed Trade Structure, RIMCO/Tigre Project, dated January 31, 1997. </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.32 -- Anadarko Basin Seismic Operations Agreement II, dated as of April 1, 1997, by and between Brigham Oil & Gas, L.P. (filed as Exhibit 10.37 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.32.1 -- Letter Amendment to Anadarko Basin Seismic Operations Agreement II, dated March 20, 1997, between Brigham Oil & Gas, L.P. and Veritas DGC Land, Inc. (filed as Exhibit 10.37 to Brigham's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.33 -- Expense Allocation and Participation Agreement II, dated April 1, 1997, between Brigham Oil & Gas, L.P., and Gasco Limited Partnership (filed as Exhibit 10.31 to Brigham's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and incorporated herein by reference). 10.36 -- Credit Agreement dated as of January 26, 1998 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.36 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated herein by reference). 10.36.1 -- First Amendment to Credit Agreement dated as of August 20, 1998 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.36.1 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.36.2 -- Second Amendment to Credit Agreement dated as of March 26, 1999 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.36.2 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.37 -- Guaranty Agreement dated January 26, 1998 by Brigham Exploration Company in favor of Bank of Montreal, as Agent, and each of the Lenders party to the Credit Agreement (filed as Exhibit 10.33.1 to Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.37.1 -- First Amendment to Guaranty Agreement dated as of March 30, 1998 between Brigham Exploration Company and Bank of Montreal, as Agent for the Lenders party to the Credit Agreement (filed as Exhibit 10.33.2 to Brigham's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.37.2 -- Second Amendment to Guaranty Agreement dated as of August 20, 1998 between Brigham Exploration Company and Bank of Montreal, as Agent for the Lenders party to the Credit Agreement (filed as Exhibit 10.37.2 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.37.3 -- Third Amendment to Guaranty Agreement dated as of March 26, 1999 between Brigham Exploration Company and Bank of Montreal, as Agent for the Lenders party to the Credit Agreement (filed as Exhibit 10.37.3 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.38 -- Exchange Agreement dated as of March 30, 1999 by and between Brigham Exploration Company and Veritas DGC Land, Inc. (filed as Exhibit 10.41 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.39 -- Registration Rights Agreement dated as of March 30, 1999 by and between Brigham Exploration Company and Veritas DGC Land, Inc. (filed as Exhibit 10.42 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.40 -- Third Amendment to Credit Agreement dated as of July 19, 1999 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.1 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended July 31, 1999 and incorporated by reference herein). 10.41 -- Fourth Amendment to Guaranty Agreement dated as of July 19, 1999 between Brigham Exploration Company and Bank of Montreal, as Agent for the lenders party to the Credit Agreement (filed as Exhibit 10.2 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended July 31, 1999 and incorporated by reference herein). 10.42* -- Agreement dated as of August 16, 1999 between Brigham Exploration Company and Jon L. Glass for the amendment of an Employee Stock Ownership Agreement and Option Agreements (filed as Exhibit 10.1 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.43* -- Agreement dated as of August 16, 1999 between Brigham Exploration Company and Craig M. Fleming for the amendment of an Employee Stock Ownership Agreement and Option Agreement (filed as Exhibit 10.2 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.44 -- Form Change of Control Agreement dated as of September 20, 1999 between Brigham Exploration Company and certain Officers (filed as Exhibit 10.3 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.45 -- Warrant Agreement for the Purchase of Common Stock dated as of July 19, 1999 by and between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.4 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.46 -- Warrant Agreement for the Purchase of Common Stock dated as of July 19, 1999 by and between Brigham Exploration Company and Societe Generale, Southwest Agency (filed as Exhibit 10.5 to Brigham's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.47 -- Amended and Restated Credit Agreement dated as of February 17, 2000 among Brigham Oil & Gas, L.P., as Borrower, Bank of Montreal, as Agent, and the Lenders signatory thereto (filed as Exhibit 10.1 to Brigham's Current Report on Form 8-K filed February 29, 2000, and incorporated herein by reference). 10.48 -- Amended and Restated Guaranty Agreement dated as of February 17, 2000 by Brigham Exploration Company in favor of Bank of Montreal, as Agent, and each of the Lenders party to the Amended and Restated Credit Agreement (filed as Exhibit 10.2 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.49 -- Partial Assignment of Notes dated as of February 17, 2000 by and among (i) Bank of Montreal, (ii) Societe Generale, Southwest Agency, (iii) Shell Capital Inc,, and (iv) Brigham Oil & Gas, L.P. (filed as Exhibit 10.3 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.50 -- First Amendment to Warrant Agreement dated as of February 17, 2000 between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.4 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.51 -- First Amendment to Warrant Agreement dated as of February 17, 2000 between Brigham Exploration Company and Societe Generale, Southwest Agency (filed as Exhibit 10.5 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.52 -- Equity Conversion Agreement dated as of February 17, 2000 by and among Brigham Oil & Gas, L.P., Brigham Exploration Company and Shell Capital Inc. and its successors and assigns (filed as Exhibit 10.6 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.53 -- Warrant Agreement dated as of February 17, 2000 by and between Brigham Exploration Company and Shell Capital Inc. (filed as Exhibit 10.7 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.54 -- Registration Rights Agreement dated as of February 17, 2000 by and between Brigham Exploration Company and Shell Capital Inc. (filed as Exhibit 10.8 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.55 -- Letter dated as of February 17, 2000 regarding certain fees pursuant to Credit Agreement dated as of February 17, 2000, among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, Shell Capital Inc. and the lenders signatory thereto (filed as Exhibit 10.9 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.56 -- Securities Purchase and Registration Rights Agreement dated as of February 22, 2000 by and among Brigham Exploration Company and GAP Coinvestment Partners II, L.P., Special Situations Private Equity Fund, L.P., and Aspect Resources, L.L.C. (filed as Exhibit 10.15 to Brigham's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.57 -- Joint Development Agreement, dated as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. (filed as Exhibit 10.65 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). 10.57.1 -- First Amendment, dated as of May 10, 1999, to that certain Joint Development Agreement entered into effective as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. (filed as Exhibit 10.65.1 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). 10.57.2 -- Acquisition and Participation Agreement, dated October 21, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. (filed as Exhibit 10.65.2 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). 10.57.3 -- Letter agreement, dated as of December 30, 1999, regarding amendments to Joint Development Agreement, dated as of February 10, 1999, as amended, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. (filed as Exhibit 10.65.3 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.58 -- Letter agreement dated as of September 6, 1999 between Brigham Oil & Gas, L.P. and Brigham Land Management Company, Inc. regarding work to be performed within Brigham's Angelton Project. (filed as Exhibit 10.66 to Brigham's Annual Report on Form 10-K for the year ended December 31, 1999, and incorporated herein by reference). 10.59 -- Securities and Note Acquisition Agreement dated as of October 31, 2000 by and among Brigham Oil & Gas, L.P., Brigham, Inc., Brigham Exploration Company, Brigham Holdings I, LLC, Brigham Holdings II, LLC, ECT Merchant Investment Corp., and Joint Energy Development Investments II Limited Partnership (filed as Exhibit 10.1 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.60 -- Subordinated Credit Agreement dated as of October 31, 2000 among Brigham Oil & Gas, L.P., as Borrower, Shell Capital Inc., as Agent, and the Lenders signatory hereto (filed as Exhibit 10.2 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.60.1 -- First Amendment to Amended and Restated Guaranty Agreement dated as of October 31, 2000 between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.8 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference). 10.61 -- Subordinated Guaranty Agreement dated as of October 31, 2000 by Brigham Exploration Company in favor of Shell Capital Inc., as Agent, and each of the Lenders party to the Credit Agreement (filed as Exhibit 10.3 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.61.1 -- First Amendment to Amended and Restated Credit Agreement dated as of October 31, 2000 by and among Brigham Oil & Gas, L.P., Bank of Montreal, Societe Generale, Southwest Agency, and Shell Capital Inc.(filed as Exhibit 10.7 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference). 10.62 -- Ancillary Agreement dated as of October 31, 2000 by and among Brigham Oil & Gas, L.P. and Shell Capital Inc. (filed as Exhibit 10.4 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.63 -- Intercreditor and Subordination Agreement dated as of October 31, 2000 by and among Bank of Montreal, as Senior Agent and a Senior Lender, Societe Generale, Southwest Agency, as a Senior Lender, Shell Capital Inc., as a Senior Lender, Shell Capital Inc., both as a Subordinated Agent and a Subordinated Lender, Brigham Exploration Company, Brigham Oil & Gas, L.P., Brigham, Inc., Brigham Holdings I, LLC, and Brigham Holdings II, LLC. (filed as Exhibit 10.5 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.64 -- Warrant Agreement dated as of October 31, 2000 by and between Brigham Exploration Company and Shell Capital Inc.(filed as Exhibit 10.6 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.65 -- Securities Purchase Agreement dated as of November 1, 2000 between Brigham Exploration Company, DLJ MB Funding III, Inc., and DLJ ESC II, LP., (filed as Exhibit 10.9 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.66 -- Registration Rights Agreement dated November 1, 2000 by and between Brigham Exploration Company, DLJ MB Funding III, Inc., and DLJ ESC II, LP. (filed as Exhibit 10.10 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.67 -- Warrant Certificate dated as of November 1, 2000 by and between Brigham Exploration Company and DLJ MB Funding III, Inc. (filed as Exhibit 10.11 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.68 -- Warrant Certificate dated as of November 1, 2000 by and between Brigham Exploration Company and DLJ ESC II, LP. (filed as Exhibit 10.12 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.69 -- Stockholders Voting Agreement dated as of October 31, 2000 by and among Brigham Exploration Company, DLJ ESC II, L.P., DLJ MB Funding III, Inc., and certain shareholders of Brigham Exploration Company (filed as Exhibit 10.13 to Brigham's Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference). 10.70 -- Securities Purchase Agreement dated as of March 5, 2001 among Brigham Exploration Company, DLJ MB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP and DLJ Offshore Partners III, CV (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). 10.71 -- First Amendment to Registration Rights Agreement, dated March 5, 2001, by and among Brigham Exploration Company, DLJMB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP and DLJ Offshore Partners III, CV (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). 10.72 -- 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). 10.73 -- 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). 10.74 -- 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). 10.75 -- 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). </Table> <Page> <Table> <Caption> NUMBER DESCRIPTION - ------ ------------------------------------------------------------ 10.76 -- Stockholders Voting Agreement dated as of March 5, 2001 by and among Brigham Exploration Company, DLJMB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP, DLJ Offshore Partners III, CV and certain shareholders of Brigham Exploration Company(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). 21+ -- Subsidiaries of the Registrant. 23.1+ -- Consent of PricewaterhouseCoopers LLP, independent public accountants. 23.2+ -- Consent of Cawley, Gillespie & Associates, Inc., independent petroleum engineers. </Table> - ------------------------ * Management contract or compensatory plan. + Filed herewith.