-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HxoSp+1tdYiJH0H1r0qaF98FbwxLaWW44fEoCupFvdeO2gjyBj5y1jxOHr9jWfom Obw8nm7LintDbQtLLivZbg== 0001104659-00-000084.txt : 20000331 0001104659-00-000084.hdr.sgml : 20000331 ACCESSION NUMBER: 0001104659-00-000084 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BRIGHAM EXPLORATION CO CENTRAL INDEX KEY: 0001034755 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752692967 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-22433 FILM NUMBER: 584855 BUSINESS ADDRESS: STREET 1: 6300 BRIDGE POINT PARKWAY STREET 2: BLDG 2 SUITE 500 CITY: AUSTIN STATE: TX ZIP: 78730 BUSINESS PHONE: 5124273300 MAIL ADDRESS: STREET 1: 6300 BRIDGE POINT PARKWAY STREET 2: BLDG 2 SUITE 500 CITY: AUSTIN STATE: TX ZIP: 78730 10-K 1 ANNUAL REPORT UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------- FORM 10-K ------------------------- (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ____________________ to ____________________ Commission file number: 000-22433 BRIGHAM EXPLORATION COMPANY (Exact name of Registrant as Specified in its Charter) Delaware 75-2692967 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 6300 Bridge Point Parkway Building 2, Suite 500 78730 Austin, Texas (Zip Code) (Address of principal executive offices) (512) 427-3300 (Registrant's telephone number, including area code) --------------- Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Title of Each Class Which Registered None None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.01 par value (Title of Class) Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of March 23, 2000, the Registrant had 16,712,908 shares of common stock outstanding. The aggregate market value of the common stock held by non-affiliates of the Registrant, based upon the closing sale price of the common stock on March 23, 2000, as reported on The Nasdaq Stock Market(sm), was approximately $14 million. For purposes of determination of the foregoing amount, only directors, executive officers and 10% or greater stockholders have been deemed affiliates. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 2000 Annual Meeting of Stockholders to be held on May 18, 2000, are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 1999. TABLE OF CONTENTS PART I ITEM 1. BUSINESS.........................................................1 ITEM 2. PROPERTIES.......................................................9 ITEM 3. LEGAL PROCEEDINGS...............................................18 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS..............18 EXECUTIVE OFFICERS OF THE REGISTRANT..........................................19 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.................................20 ITEM 6. SELECTED FINANCIAL DATA.........................................21 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................22 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK......41 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.....................42 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..........................42 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..............42 ITEM 11. EXECUTIVE COMPENSATION..........................................42 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT................................42 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS............43 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.........................................43 GLOSSARY OF OIL AND GAS TERMS.................................................52 SIGNATURES....................................................................54 INDEX TO FINANCIAL STATEMENTS...............................................F1-1 BRIGHAM EXPLORATION COMPANY 1999 ANNUAL REPORT ON FORM 10-K ITEM 1. BUSINESS Overview Brigham Exploration Company ("Brigham" or the "Company") is an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore and develop onshore oil and natural gas provinces in the United States. The Company focuses its activity in provinces where it believes 3-D technology may be effectively applied to generate relatively large potential reserve volumes per well and per field, high potential production rates and multiple producing objectives. Brigham's exploration activities are concentrated primarily in three core provinces: o the Anadarko Basin of western Oklahoma and the Texas Panhandle; o the onshore Texas Gulf Coast; and o West Texas. The Company pioneered the acquisition of large scale onshore 3-D seismic surveys for exploration, obtaining extensive 3-D seismic data and experience in capturing undiscovered oil and natural gas reserves. As of December 31, 1999, Brigham has acquired 5,122 square miles (3.3 million acres) of 3-D seismic data and has identified approximately 1,050 potential drilling locations, of which the Company has drilled 469 through year-end 1999. The Company generates most of its exploratory projects and, therefore, has the ability to retain a sizeable working interest in these projects. From inception in 1990 through 1999, Brigham drilled 395 exploratory and 74 development wells on its 3-D generated prospects with an aggregate 64% completion rate and an average working interest of 29%. As of December 31, 1999, the Company has added 143 Bcfe of net proved reserves to its reserve base, approximately 121 net Bcfe of which were discovered by Brigham through its systematic 3-D exploration drilling activities at an average net drilling cost of $0.72 per Mcfe. In 1999, the Company's average net drilling cost was $0.37 per Mcfe and its all-in net finding and development cost was $0.52 per Mcfe, each of which represent the lowest annual finding costs achieved by Brigham to date. The Company's estimated net proved reserves as of December 31, 1999 were 84 Bcfe having an aggregate Present Value of Future Net Revenues of $115 million, compared to estimated net proved reserves as of December 31, 1996 of 22 Bcfe having an aggregate Present Value of Future Net Revenues of $45 million. The Company's net proved reserve volumes at December 31, 1999 are 78% natural gas and 48% proved developed. Business Strategy Brigham's principal objective and business strategy is to achieve superior growth in shareholder value through the application of its systematic exploration approach, which emphasizes the integrated use of 3-D seismic imaging and other advanced technologies to reduce drilling risks and finding costs. Since its inception in 1990, the Company has achieved rapid growth in its acquisition of 3-D seismic data, identification of potential drilling locations, discovery of proved reserves and production of oil and natural gas volumes. Having acquired in excess of 5,100 square miles of 3-D seismic data in proven producing trends, the Company's current activities are focused on generating tangible value from its high quality inventory of 3-D delineated prospect locations through disciplined exploration and development drilling activities and selective non-producing asset sales. 1 Brigham completed its initial public offering of common stock in May 1997, raising approximately $24 million to fund the Company's accelerated 3-D seismic acquisition and exploration drilling activities. Key elements of the Company's long-term growth strategy at its initial public offering included: o acquiring 3-D seismic data in proven producing trends to identify and capture potential drilling locations; o retaining significant working interests in its exploration projects to capture a greater share of the reserves that the Company discovers; o identifying higher potential, higher impact prospects; and o monetizing the value of its 3-D seismic investments by drilling its inventory of 3-D seismic delineated locations. During 1997 and 1998, the Company acquired 2,360 square miles of 3-D seismic data at an average working interest of 73%, which nearly doubled its inventory of gross onshore 3-D seismic data to 5,122 square miles as compared to year-end 1996 and increased its net onshore 3-D seismic data in inventory more than three-fold from 781 square miles at year-end 1996 to 2,507 square miles at year-end 1998. Brigham's overall level of 3-D seismic acquisition during 1997 and 1998 was the most active in the Company's history, and the vast majority of this newly acquired data was located in Brigham's higher potential Anadarko Basin and Gulf Coast provinces where it has achieved historically lower average finding costs for drilling than in its West Texas province. The majority of this data was processed in 1998 and 1999, and the interpretation and prospect generation is still underway. As a result of these significant investments in 3-D seismic acquisition and interpretation in proven natural gas producing trends, the Company believes it has assembled a significant competitive knowledge base and strategic position in each of its two active exploration provinces. Brigham further believes it has captured a high quality inventory of 3-D delineated potential drilling locations that can be monetized through the drill bit at attractive finding costs over the next several years, thereby providing opportunities for future reserve, production and cash flow growth. Brigham's current business strategy consists of the following key elements: o focus resources on drilling of its established 3-D delineated prospect inventory; o maintain a balanced risk-reward profile in its planned exploration and development program; o improve cash flow margins by continuing efforts to reduce per unit finding and operating cost components; and o selectively monetize non-producing assets to recoup capital investments and improve project rates of return. Focus on Drilling From 1990 to 1999, the Company directed a significant portion of its resources toward the establishment of a sizeable inventory of 3-D seismic projects within proven natural gas producing trends in the Anadarko Basin and Gulf Coast. As a result of these efforts, Brigham believes it has assembled a significant asset base within these two core exploration provinces that it has only begun to monetize through its drilling efforts to date. During 1999, Brigham began to focus the majority of its resources toward drilling activities within its established 3-D seismic projects to generate proved reserves, production volumes and cash flow from these investments. As a result, the Company achieved its lowest annual average drilling and finding and development costs in its history during 1999 at $0.37 per Mcfe and $0.52 per Mcfe, respectively. In addition, Brigham generated approximately $4 in net PV10% value of proved reserves for every dollar invested in drilling during 1999. 2 Continuing to benefit from its existing 3-D seismic project assets, Brigham's primary objective in 2000 is to drill the highest-grade locations within its inventory of identified drilling locations to generate continued growth in proved reserves and cash flow. Approximately 80% of the Company's planned $25 million capital expenditure budget for 2000 is targeted for drilling activities within its Anadarko Basin and Gulf Coast 3-D seismic projects. Through December 31, 1999, the Company has achieved historical average drilling costs of $0.56 and $0.62 per Mcfe in these two provinces, respectively. With the significant competitive advantages afforded by the Company's sizeable investments in 3-D seismic data within its core provinces, Brigham expects that drilling capital expenditures should represent at least 80% of its total annual capital expenditures for the foreseeable future. Execute Balanced Drilling Program The majority of the Company's historical drilling expenditures have been directed toward exploration-oriented projects. Leveraging numerous drilling discoveries during 1999, including the Company's potentially significant Home Run Field discovery, Brigham's planned 2000 drilling program consists of a balanced blend of exploration and development projects in trends where the Company has achieved historical drilling success. Of the Company's $20 million drilling budget planned for 2000, 54% of the expenditures relate to exploration projects and 46% are for development drilling projects that are either currently planned or contingent upon drilling success during the year. In addition, approximately 20% of Brigham's planned 2000 drilling program is directed toward continuing drilling activities in and adjacent to its Home Run Field discovery in its Diablo Project in South Texas, in which the Company maintains a 34% working interest. This planned activity consists of the drilling of three proved undeveloped locations within the Home Run Field and two exploratory tests of potentially significant Lower Vicksburg structures located in fault blocks that are adjacent to the Company's Home Run Field discovery. Drilling success from either of these two exploratory prospects would likely establish further development drilling locations, thereby further enhancing the overall economics from this project area. Improve Operating Margins Brigham seeks to improve its return on invested capital by achieving low finding and development costs and by reducing and controlling its per unit operating costs. The Company has achieved average drilling costs of $0.72 per Mcfe during the past five years. By focusing its drilling program within areas where the Company had previously experienced drilling success, Brigham achieved improved returns on its drilling investments during 1999 with average drilling costs of $0.37 per Mcfe. Importantly, the Company's all-in finding and development costs during 1999 were $0.52 per Mcfe, a substantial improvement from its most recent five-year average finding and development costs of $1.37 per Mcfe due to: o Brigham's considerable prior investments in 3-D seismic and land, principally during 1997 and 1998; o significantly lower non-drilling capital expenditures in 1999; o improved drilling returns achieved during 1999; and o sales of interests in certain 3-D seismic projects in 1999 which provided reimbursements of previously incurred expenditures. Brigham expects this trend toward convergence of its all-in finding and development costs and drilling costs to continue during the next few years as the Company continues to capitalize on its extensive inventory of 3-D delineated prospects by allocating a substantial majority of its capital expenditures to drilling within its existing 3-D seismic project areas. 3 During the past few years, Brigham's low per unit lease operating expenses can be attributed to: o the relatively new nature of many of the Company's producing wells; o focused operations in three core provinces; and o operating a greater percentage of the wells that it drills. Brigham intends to continue to maintain low per unit operating expenses by: o monitoring and controlling production efficiency from its existing producing wells; o adding new producing wells that typically cost less to operate than more mature wells; and o seeking to achieve operating cost efficiencies through increased economies of scale by greater concentration of its producing assets within its project areas. Additionally, Brigham undertook numerous measures to reduce and control its overhead expenses during 1999. These measures contributed to a 33% reduction in total general and administrative expenses (including amounts capitalized) in the fourth quarter of 1999 relative to the fourth quarter 1998, and a 43% reduction in net general and administrative expenses per Mcfe during the same periods. Through a continuation of overhead cost containment efforts and production volume growth anticipated from its planned drilling program, Brigham expects to achieve further improvements in per unit general and administrative expenses during 2000. Monetize Non-Producing Assets In addition to supporting a multi-year drilling program, Brigham believes that its substantial investments in 3-D seismic data and undeveloped acreage provide a significant competitive advantage to attract participants to invest in its projects, thereby recouping a portion of its initial capital investments typically on a promoted basis. Brigham has been effective at raising capital and attaining promoted working interests in its 3-D seismic projects throughout its history. During 1999, the Company raised approximately $13 million through the sales of interests in various 3-D seismic projects or individual drilling prospects to fund a portion of its capital expenditure program. Brigham expects to market interests in certain 3-D seismic projects or individual prospects during 2000 to provide incremental sources of capital for reinvestment in its drilling program and to improve its project economics. Exploration and Operating Approach The Company has acquired 3-D seismic data covering 5,122 square miles (3.3 million acres) in over 20 geologic trends in seven basins and seven states. Through this activity, the Company has developed expertise in the selection of geologic trends that are suitable for 3-D seismic exploration. Brigham uses experience that it gains within a trend to enhance the quality of subsequent projects in the same trend and other analogous trends, contributing to lower finding and development costs, compressed project cycle times and increased project rates of return. Brigham typically acquires 3-D seismic data in and around existing producing fields where the Company can benefit from the imaging of producing analogs. These 3-D defined analogs, combined with the Company's experience in drilling 469 wells, provide the Company with a knowledge base to evaluate other potential geologic trends, 3-D seismic projects within trends and 3-D delineated potential drilling locations. The Company's knowledge base assists in identifying geologic trends where Brigham believes it can find and develop economic volumes of oil and natural gas. 4 The Company has experience exploring with 3-D seismic in a wide range of reservoir types and geologic trapping styles, both stratigraphic and structural (including reefs, salt domes, channel sands, complex faulted and fractured reservoirs and pinchout plays). The Company seeks to supplement its knowledge base with the best local geologic expertise available for a particular geologic trend. In addition, the Company typically acquires digital data bases for integration on the Company's CAEX workstations, including digital land grids, well information, log curves, production information, geologic studies, geologic top data bases and existing 2-D seismic data. The Company uses its knowledge base, local geological expertise and digital data bases integrated with 3-D seismic to create maps of producing and potentially productive reservoirs. The Company believes its 3-D generated maps are more accurate than previous reservoir maps (which generally were based on subsurface geological information and 2-D seismic surveys), enabling the Company to more precisely evaluate recoverable reserves and the economic feasibility of projects and drilling locations. Brigham acquires most of its raw 3-D seismic data using seismic acquisition vendors on either a proprietary basis or through alliances affording the alliance members the exclusive right to interpret and use data for extended periods of time. In addition, the Company participates in non-proprietary group shoots of 3-D data when it believes the expected full cycle project economics are justified. In its proprietary acquisitions and alliances, Brigham selects the sites of projects, primarily guided by its knowledge and experience in the core provinces it explores; establishes and monitors the seismic parameters of each project for which data is shot; and typically selects the equipment that will be used. Data is generally priced on the basis of square miles shot. Brigham's operations staff includes four petroleum engineers that have an average of over thirteen years of reservoir and operations engineering experience, most of which was gained in the Company's primary areas of activity. The Company's engineers work closely with Brigham's explorationists and are integrally involved in all phases of the Company's exploration process, including preparation of pre- and post-drill reserve estimates, analysis of full cycle risked drilling economics, well design and production management. Brigham conducts field operations for its operated oil and natural gas properties through third party contract personnel. In an effort to retain better control of its project timing, operational costs and production volumes, Brigham has significantly increased the percentage of the wells that it operates during the past several years. Brigham operated 44% of the gross and 73% of the net wells it participated in during 1999, as compared with 10% and 17%, respectively, of its wells drilled during 1996. As a result of its increased operational control in recent years, Brigham-operated wells constituted 61% of the PV10% value of its proved developed producing reserves at year-end 1999, as compared with only 8% at year-end 1996. Technical Staff The Company's experienced technical staff includes seven geophysicists, seven geologists, four petroleum engineers, five computer applications specialists, four geophysical/geological/engineering technicians, three landmen and three lease and division order analysts. Brigham's geophysicists have different but complementary backgrounds, and their diversity of experience in varied geological and geophysical settings, combined with various technical specializations (from hardware and systems to software and seismic data processing), provide the Company with valuable technical intellectual resources. The Company's team of explorationists has over 245 years of exploration experience, or an average of almost 18 years per person, and more than 80 years of 3-D CAEX workstation experience, most of which was acquired at Brigham and various major and large independent oil companies. Brigham's team of technical specialists was assembled according to the expertise that these individuals have within producing basins where Brigham focuses its exploration and development activities. By integrating both geologic and geophysical expertise within its project teams, Brigham believes it possesses a competitive advantage in its exploration approach. Occasionally, the Company complements and leverages its exploration staff by seeking out alliances or retainer relationships with geologists and other technical professionals who have extensive experience in a particular area of interest. 5 3-D Seismic Technology The Company's strategy is to use 3-D seismic and other advanced technologies, including CAEX, to systematically explore and develop domestic onshore oil and natural gas provinces. In general, 3-D seismic is the process of acquiring seismic data along multiple lines and grids. The primary advantage of 3-D seismic over 2-D seismic is that it provides information with respect to multiple horizontal and vertical points within a geologic formation instead of information on a single vertical line or multiple vertical lines within the formation. Acquiring larger amounts of data relating to a geologic formation allows a user to better correlate the data and, in some cases, to obtain a greater understanding and image of the formation. Although it is impossible to predict with certainty the specific configuration or composition of any underground geologic formation, the use of 3-D seismic data provides clearer and more accurate projected images of complex geologic formations, which can assist a user in evaluating whether to drill for oil and natural gas reserves. If a decision to drill is made, 3-D seismic data can also help in determining the optimal location to drill. CAEX is the process of accumulating and analyzing the various seismic, production and other data obtained relating to a geographic area. In general, CAEX involves accumulating various 2-D and 3-D seismic data with respect to a potential drilling location, correlating that data with historical well control and production data from similar properties and analyzing the available data through computer programs and modeling techniques to project the likely geologic composition of a potential drilling location and potential locations of undiscovered oil and natural gas reserves. This process relies on a comparison of data with respect to the potential drilling location and historical data with respect to the density and sonic characteristics of different types of rock formations, hydrocarbons and other subsurface minerals, resulting in a projected three dimensional image of the subsurface. This modeling is performed through the use of advanced interactive computer workstations and various combinations of available computer programs that have been developed solely for this application. Brigham has invested extensively in the advanced computer hardware and software necessary for 3-D seismic exploration. The Company has both Landmark and Schlumberger Geoquest CAEX workstations. This workstation flexibility provides the Company the opportunity to interpret a project on the particular CAEX workstation that it believes is best suited for defining those particular geologic objectives. Brigham's explorationists can access a diverse software tool kit including SeisWorks, StratWorks, EarthCube, OpenVision, Open Explorer, ZAP, Zmap+, ARIES, SynTool, Poststack, TDQ, AutoPix, Seis3DV, Seis2D, BaseMap+, GeoViz, Voxels, SynView, Seisan, SeisTie, CSA (Computed Seismic Attributes), Surface Slice, Hampson Russell AVO Analysis and Modeling, ZEH Graphics Plotex, CGMage Builder (graphics montage tool), and Neuralog Inc. NDS/Log and NeuraSection. Natural Gas and Oil Marketing and Major Customers Most of the Company's natural gas and oil production is sold under price sensitive or spot market contracts. The revenues generated by the Company's operations are highly dependent upon the prices of and demand for natural gas and oil. The price received by the Company for its natural gas and oil production depends on numerous factors beyond the Company's control, including seasonality, competition, the condition of the United States economy, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries, and domestic government regulation, legislation and policies. Decreases in the prices of natural gas and oil could have an adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Although the Company is not currently experiencing any significant involuntary curtailment of its natural gas or oil production, market, economic and regulatory factors may in the future materially affect the Company's ability to sell its natural gas or oil production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", "-- Risk Factors - -- Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are Volatile" and "-- Risk Factors -- The Marketability Of Our Production Is Dependent On Facilities That We Typically Do Not Own Or Control." For the year ended December 31, 1999, sales to Highland Energy Company, Lantern Petroleum Corporation and Duke Energy Field Services, Inc., were approximately 26%, 16%, and 11%, respectively, of the Company's natural gas and oil revenues. Due to the availability of other markets and pipeline connections, the Company does not believe that the loss of any single natural gas or oil customer would have a material adverse effect on the Company's results of operations. 6 Competition The oil and gas industry is highly competitive in all of its phases. The Company encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of seismic and leasing options and oil and natural gas leases on properties. The Company's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of its competitors are large, well established companies with substantially larger operating staffs and greater capital resources than the Company's. Such companies may be able to pay more for seismic and lease options on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors -- We Face Significant Competition" and "-- Risk Factors -- We Have Substantial Capital Requirements." Operating Hazards and Uninsured Risks Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. The Company's future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on the Company's business, financial condition or results of operations. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors -- Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are Dependent On Exploratory Drilling Activities." In addition, use of 3-D seismic technology requires greater pre-drilling expenditures than traditional drilling strategies. Although the Company believes that its use of 3-D seismic technology will increase the probability of drilling success, some unsuccessful wells are likely, and there can be no assurance that unsuccessful drilling efforts will not have a material adverse effect on the Company's business, financial condition or results of operations. The Company's operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to properties of the Company and others. The Company maintains insurance against some but not all of the risks described above. In particular, the insurance maintained by the Company does not cover claims relating to failure of title to oil and natural gas leases, trespass during 3-D survey acquisition or surface change attributable to seismic operations, business interruption or loss of revenues due to well failure. In certain circumstances in which insurance is available the Company may not purchase it. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on the Company's business, financial condition and results of operations. Employees On March 23, 2000, the Company had 51 full-time employees. None is represented by any labor union. The Company believes its relations with its employees are good. The Company also relies on several regional consulting service companies to provide field landmen to support the Company on a project-by-project basis. One of these companies, Brigham Land Management, is owned by Vincent M. Brigham, who is the brother of Ben M. Brigham, the Company's Chief Executive Officer, President and Chairman of the Board. 7 Facilities The Company's principal executive offices are located in Austin, Texas, where it leases approximately 34,330 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730. As part of its efforts to reduce corporate overhead expenses, the Company agreed to sublease approximately 5,300 square feet of excess office space at its principal executive offices to a third party for a two-year term beginning in November 1999. In addition to its corporate headquarters location, the Company also leases a 4,100 square foot office at 450 Gears Road, Suite 240, Houston, Texas 77067. Title to Properties The Company believes it has satisfactory title, in all material respects, to substantially all of its producing properties in accordance with standards generally accepted in the oil and gas industry. The Company's properties are subject to royalty interests, standard liens incident to operating agreements, liens for current taxes and other inchoate burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. The Company's Credit Facility (as defined) is secured by a first lien against substantially all of the Company's oil and natural gas properties and other tangible assets, and the Company's Subordinated Notes (as defined) are secured by a second lien against all collateral pledged by the Company as security under its Credit Facility. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." Governmental Regulation The Company's oil and natural gas exploration, production and marketing activities are subject to extensive laws, rules and regulations promulgated by federal and state legislatures and agencies. Failure to comply with such laws, rules and regulations can result in substantial penalties. The legislative and regulatory burden on the oil and gas industry increases the Company's cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the Company is unable to predict the future cost or impact of complying with such laws and regulations because they are frequently amended, interpreted and reinterpreted. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. These states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. Environmental Matters The Company's operations and properties are, like the oil and gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from the Company's operations. The permits required for various of the Company's operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines or injunction, or both. In the opinion of management, the Company is in substantial compliance with current applicable environmental laws and regulations, and the Company has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on the Company, as well as the oil and gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict and arguably joint and several liability on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting the Company's operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. 8 Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on the Company. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. With respect to certain of its operations, the Company is required to maintain such permits or meet general permit requirements. The Environmental Protection Agency ("EPA") recently adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. The Company believes that it will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on the Company. The Company has acquired leasehold interests in numerous properties that for many years have produced natural gas and oil. Although the Company believes that the previous owners of these interests have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties. In addition, some of the Company's properties are operated by third parties over whom the Company has little control. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Matters" and "-- Risk Factors -- We Are Subject To Various Governmental Regulations And Environmental Risks." ITEM 2. PROPERTIES Primary Exploration Provinces Brigham focuses its 3-D seismic exploration efforts in natural gas and oil producing provinces where it believes 3-D technology may be effectively applied to generate relatively large potential reserve volumes per well and per field, high potential production rates and multiple producing objectives. Brigham's exploration activities are concentrated primarily in three core provinces: the Anadarko Basin of western Oklahoma and the Texas Panhandle; the onshore Texas Gulf Coast; and West Texas. During the past three years, Brigham has concentrated the majority of its 3-D seismic and drilling activities on natural gas projects in its Anadarko Basin and Gulf Coast provinces primarily due to the higher expected rates of return provided by these opportunities relative to its more mature West Texas oil projects. In 1997 and 1998, Brigham made significant investments in the acquisition of 3-D seismic and prospective acreage in its Anadarko Basin and Gulf Coast provinces. Through these investments, the Company believes it has assembled an inventory of potential drilling locations that will support a multi-year drilling program, thereby providing attractive opportunities for long-term growth. Based upon the interpreted portion of its 3-D seismic data as of December 31, 1999, the Company estimates that it has identified approximately 580 potential undrilled locations within its three core exploration provinces. From inception in 1990 through 1999, Brigham achieved net drilling costs of $0.72 per Mcfe added through its 3-D seismic exploration efforts. In addition, over 400 of Brigham's estimated potential drilling locations are in its currently active Anadarko Basin and Gulf Coast provinces where the Company has achieved inception-to-date average net drilling costs of $0.56 and $0.62 per Mcfe, respectively. 9 Continuing its strategy implemented during 1999, Brigham intends to focus substantially all of its efforts and available capital resources in 2000 to the drilling and monetization of its highest grade prospects within its over 5,000 square mile inventory of 3-D seismic data. Employing this emphasis during 1999, the Company achieved its lowest annual average drilling and finding and development costs of $0.37 per Mcfe and $0.52 per Mcfe, respectively. In addition, Brigham's average net drilling cost for proved developed reserve additions during 1999 was $0.63 per Mcfe. The Company's current 2000 capital expenditure budget is estimated to be $25 million, which includes approximately $20 million to drill an estimated 30 to 40 gross wells. Brigham's planned 2000 drilling program is comprised of a balanced blend of exploration and development drilling projects with approximately 54% of budgeted drilling expenditures targeted for exploratory prospects, 28% for development locations and the remaining 18% for development locations that are contingent upon drilling success during the year. In addition, the Company's 2000 budgeted drilling expenditures have been allocated approximately 75% to its Gulf Coast province and 25% to its Anadarko Basin province, concentrated within trends where the Company has experienced exploration success historically. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." The Company's actual capital expenditures in 2000 may differ from the estimates discussed herein based upon cash flow and capital availability during the year. There can be no assurance that any potential drilling locations identified by the Company will be drilled at all or within the expected time frame. The final determination with respect to the drilling of any well, including those currently budgeted, will depend on a number of factors, including: o the results of exploration and development efforts and the continuing review and analysis of the seismic data; o the availability of sufficient capital resources by the Company and other participants for drilling prospects; o economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews; o the financial resources and results of the Company; and o the availability of leases on reasonable terms and permitting for the potential drilling location. In addition, there can be no assurance that the budgeted wells will, if drilled, encounter reservoirs of commercial quantities of natural gas or oil. Gulf Coast The onshore Texas Gulf Coast region is a high potential, multi-pay province that lends itself to 3-D seismic exploration due to its substantial structural and stratigraphic complexity. Brigham was attracted to the Gulf Coast province because of the opportunity to apply the Company's established 3-D seismic exploration approach and its staff's extensive Gulf Coast experience to a prolific, highly complex structural province with potential to discover significant natural gas reserves and production. The Company has assembled a digital data base including geographical, production, geophysical and geological information that the Company evaluates on its CAEX workstations. Brigham's team of explorationists has assembled projects in the Expanded Wilcox and Expanded Vicksburg trends in South Texas, and the Miocene and Upper, Middle, and Lower Frio trends of the mid-to-southern regions of the Texas Gulf Coast, each of which are active 3-D seismic exploration trends. 10 A portion of Brigham's 3-D seismic data acquisition in the Gulf Coast has been accomplished by the Company's participation in certain non-proprietary, or speculative, seismic programs. By converting certain of the Company's proprietary seismic projects in core exploration areas to speculative data, the Company was able to leverage these proprietary projects for access to substantially larger non-proprietary speculative data for minimal or no additional cost to the Company. The Company believes this 3-D seismic acquisition strategy in the Gulf Coast, in certain circumstances, can accelerate the addition of attractive potential drilling locations in targeted trends at costs that are considerably less than those associated with proprietary 3-D seismic programs, thereby enhancing expected project rates of return. As of December 31, 1999, the Company had acquired 1,096 square miles (701,440 acres) of 3-D seismic data in its Gulf Coast province. Through its drilling efforts in this region from 1996 through 1999, Brigham had completed 32 wells in 44 attempts (73% completion rate) in the Gulf Coast and had found cumulative net proved reserves of approximately 36 Bcfe at an average net drilling cost of $0.62 per Mcfe. In its Gulf Coast drilling program in 1999, the Company completed 7 wells in 12 attempts (58% completion rate) with an average working interest of 22% that contributed to the addition of approximately 12 net Bcfe of proved reserves (including revisions to previous estimates) at an average net drilling cost of $0.66 per Mcfe during the year. As of December 31, 1999, Brigham had identified approximately 210 3-D delineated potential drilling locations in the Gulf Coast province, of which the Company intends to drill 20 to 25 gross wells in 2000 with an estimated average working interest of approximately 45%. Brigham intends to focus its exploration and development drilling activities in its Gulf Coast province in the following key project areas during 2000: Diablo Project Brigham's Diablo Project covers 57 square miles in Brooks County, Texas, and targets shallow Frio and deep Vicksburg producing horizons. The Company is involved in a joint venture with a major integrated oil company that controls adjoining acreage to explore on the combined acreage for potential below 10,000 feet in the Vicksburg formation in this project area. Brigham has retained a 34% working interest in this joint exploration project in which the Company and its participant currently control approximately 10,000 gross and net acres of leasehold. However, in prospective zones above 10,000 feet, primarily the Frio, Brigham has retained a 100% working interest in its original 4,000 acre lease block. The Company initially acquired 25 square miles of proprietary 3-D seismic in this project in 1997, and acquired an additional 33 square miles in 1998. In the fourth quarter of 1999, Brigham confirmed a major Lower Vicksburg field discovery, the Home Run Field, in its Diablo Project with the completion of the Brigham-operated Palmer State #2 well (Brigham 34% working interest). The Palmer State #2 encountered productive reservoirs in four Lower Vicksburg intervals with 210 feet of potential pay. After completion of successive operations to fracture stimulate each of these intervals during January and February 2000, the well was successfully commingled to produce simultaneously from all four Lower Vicksburg intervals. The Palmer State #2 began flowing to sales as a commingled producer in late February 2000 at average net daily production rates of 10.1 MMcf of natural gas and 650 Bbls of condensate, or approximately 14.1 MMcfe in total. Brigham's net cost to drill, complete and fracture stimulate the Palmer State #2 was approximately $0.24 per proved developed producing Mcfe discovered, and the net PV10% of the proved producing reserves attributable to the well were more than nine times the Company's net drilling investment. Brigham's 3-D interpretative mapping indicates that the Home Run Field reservoirs have over 500 feet of relief and cover approximately 1,100 acres with estimated potential gross reserves ranging from a minimum of 80 Bcfe to over 200 Bcfe (or 23 Bcfe to 58 Bcfe net), approximately 19 net Bcfe of which were booked as proved reserves as of December 31, 1999. The Company and its project participant have established a multi-well drilling plan for the development of the Home Run Field that includes the planned drilling of a minimum of three field delineation wells and two exploratory wells in adjacent fault blocks during 2000. The 1,100 acre Home Run Field is located upthrown from two large, untested 3-D delineated Vicksburg structures (Mariposa and Floyd) in adjacent fault blocks that cover approximately 1,200 acres. Brigham currently plans to spud an exploratory test of the estimated 1,000 acre Mariposa structure in the fourth quarter of 2000. This 3-D delineated Vicksburg feature is located beneath the shallower Mariposa Field which has produced in excess of 187 Bcf of natural gas from the Frio. The estimated 200 acre Floyd feature is an apparent four-way Lower Vicksburg closure that Brigham plans to test with an exploratory well in the third quarter of 2000. The Company believes that its Home Run Field discovery has significantly enhanced the prospectiveness of each of these large structural closures. 11 Southwest Danbury Project Located in Brazoria County, Texas, Brigham's Southwest Danbury Project is an approximate 29 square mile 3-D project targeting a series of geo-pressured Lower Frio sands at depths ranging from 12,000 to 13,000 feet. The project area was well suited to 3-D seismic imaging due to the significant structural geologic complexity associated with Danbury Salt Dome that provides multiple prospective pay intervals. Since commencement of drilling operations in early 1998, Brigham has completed three wells in three attempts in this project area. The Company's two 1999 completions in this project, the Renn Gas Unit #1 (Brigham working interest 84%) and the Sebestia Gas Unit #1 (Brigham working interest 56%), discovered gross proved reserves in the Frio interval estimated at 12.4 Bcfe as of December 31, 1999, or 6.6 net Bcfe to the Company's revenue interests. Brigham has identified several additional 3-D seismic amplitude-supported prospects in the Upper and Lower Frio sections in its Southwest Danbury Project, three of which are expected to be tested in its 2000 drilling program, including one that may be an offset to its most recent discovery well in this project. Hawkins Ranch and Millenium Projects Brigham's Hawkins Ranch and Millenium Projects consist of 344 square miles of contiguous non-proprietary 3-D seismic data in the prolific Miocene/Frio trend in Matagorda County, Texas. Identified prospects in these project areas target potential in the shallow, nonpressured Miocene and Frio sands as well as the deeper, pressured Frio sands. Operators have been actively leasing and drilling within this acreage during the past two years. This activity has resulted in the completion of nine wells in twelve attempts, including the discovery of a 3-D delineated field that is estimated to contain gross reserves of approximately 40 Bcfe in three wells that have produced at rates in excess of 30 MMcfe of natural gas per day per well. Sustaining these high production rates, these three wells have produced in excess of 37 Bcfe in less than eighteen months. The Company's 2000 drilling program includes five 3-D seismic amplitude-supported prospects in its Hawkins Ranch and Millenium Projects that target combined gross unrisked reserve potential of 112 Bcfe. Three of these five planned exploratory wells are expected to spud during the first half of 2000. Brigham expects to retain working interests ranging from 30% to 75% in its wells planned for drilling in these project areas in 2000. El Sauz Project In May 1997, Brigham initiated its El Sauz Project with a seismic option covering approximately 94,000 acres in Willacy and Kennedy Counties, Texas. In 1998, the Company acquired approximately 200 square miles of 3-D seismic data over this acreage and sold a 45% working interest in the project to two industry participants which provided the Company with a significant carry on the pre-seismic land and seismic acquisition costs of the project. The El Sauz Project is an underexplored area that is bordered on three sides by Miocene and Frio fields which have in aggregate produced over 740 Bcf of natural gas and 94 MMBbls of oil. Primary targets in the El Sauz Project are the Miocene and Frio sands at depths of 4,500 to 10,000 feet, with additional potential as deep as 18,000 feet in the Lower Frio. Reserve targets range from 5 to 20 Bcf per well. Three prospects are planned for drilling in 2000, including a shallow Miocene 3-D seismic amplitude-supported four-way closure, an Upper Frio structural test and a deep multi-target Miocene and amplitude-supported Middle Frio test. In addition to these planned wells, the Company has identified nine additional potential drilling opportunities in its continuing interpretation of the 3-D seismic data within this project area. Brigham currently retains a 55% working interest in its El Sauz Project. Caliente Project Brigham's Caliente Project consists of 350 square miles of contiguous non-proprietary 3-D seismic data in the prolific Wilcox and Queen City trend in Duval and Webb counties of Texas. Primary targets in this project include shallow, non-pressured Queen City sands at depths ranging from 6,000 to 7,000 feet, and deeper, geo-pressured Expanded Upper Wilcox sands at depths ranging from 10,000 to 18,000 feet. Brigham has identified 35 prospects within its Caliente Project, including four prospects planned for drilling in 2000. The first of these planned wells is expected to spud during the second quarter of 2000 and will test multiple pay objectives in a fault block located updip from a well with pay on water. The Company estimates gross unrisked reserve potential attributable to this Wilcox prospect of 25 Bcfe and it expects to retain a 50% working interest in the well. During the second half of 2000, Brigham currently plans to test an additional high potential Wilcox prospect in which it expects retain a working interest of 37.5% to 50%. This prospect targets an analogous fault block to a recent discovery that encountered over 300 feet of gross pay in the target Wilcox objective. The Company estimates gross unrisked reserve potential of 37 Bcfe related to this prospect. 12 Anadarko Basin The Anadarko Basin is a prolific natural gas province that the Company believes offers a combination of lower risk exploration and development opportunities in shallower horizons and deeper, higher potential objectives that have been relatively under explored. This province has produced in excess of 90 Tcfe to date from numerous, historically elusive stratigraphic targets, such as the Red Fork, Upper Morrow and Springer channel sands, as well as from deeper, higher potential structural objectives, such the Lower Morrow sandstones and the Hunton and Arbuckle carbonates. In some cases, these objectives have produced in excess of 30 Bcf of natural gas from a single well at rates of up to 30 MMcf of natural gas per day. In addition, drilling economics in the Anadarko Basin are enhanced by the multi-pay nature of many of the prospects in this province, with secondary or tertiary targets serving as either incremental value or bailout potential relative to the primary target zone. Each of the stratigraphic and structural objectives in the Anadarko Basin can provide excellent targets for 3-D seismic imaging. The Company has assembled an extensive digital data base in this province, including geologic studies, basin wide geologic tops, production data, well data, geographic data and over 8,400 miles of 2-D seismic data. Brigham's explorationists integrate this data with their extensive expertise and knowledge base to generate 3-D projects in the Anadarko Basin. As of December 31, 1999, the Company had acquired 2,062 square miles (1.3 million acres) of 3-D seismic data in the Anadarko Basin. Through its drilling efforts in this region from 1994 through 1999, Brigham had completed 83 wells in 109 attempts (76% completion rate) in the Anadarko Basin and had found cumulative net proved reserves of 63 Bcfe at an average net drilling cost of $0.56 per Mcfe. In its Anadarko Basin drilling program in 1999, the Company completed 12 wells in 14 attempts (86% completion rate) with an average working interest of 40% that contributed to the addition of 15 net Bcfe of proved reserves (including revisions to previous estimates) at an average net drilling cost of $0.17 per Mcfe during the year. As of December 31, 1999, the Company had identified approximately 210 3-D delineated potential drilling locations in the Anadarko Basin, of which the Company intends to drill 10 to 15 gross wells in 2000 with an estimated average working interest of 45%. As part of its strategic initiatives to improve its capital resources and liquidity during 1999, Brigham sold certain producing and non-producing oil and natural gas properties located in its Anadarko Basin province to two separate parties for a total of $17.1 million in June 1999. The divested properties were located in two fields operated by third parties - the Chitwood Field in Grady County, Oklahoma, and the Red Deer Creek Field in Roberts County, Texas. Brigham's independent reservoir engineers estimated net proved reserve volumes attributable to the properties as of June 1, 1999 of approximately 36 Bcfe, of which 33% were classified as proved developed producing reserves and 59% were natural gas. Brigham estimated net daily production volumes from the divested properties to be approximately 2.8 MMcfe per day at the time these sales were consummated. Net proceeds from these transactions were used by the Company to reduce borrowings under its bank credit facility and to fund working capital needs and capital expenditures during the second half of 1999. The effective date of each transaction was June 30, 1999. 13 Brigham intends to focus its exploration and development drilling activities in its Anadarko Basin province in the following key project areas during 2000: Arnett Project Brigham's Arnett Project covers approximately 81,920 acres in Ellis County, Oklahoma, and targets Morrow and Hunton producing horizons at depths of 10,000 to 14,000 feet. In 1997 and 1998, the Company acquired 128 square miles of 3-D seismic in the three phases of this project. Following the sale of a portion of its interest in this project in early 1999, Brigham retains a 70% effective working interest in its Arnett Project. During 1999, Brigham completed all five wells drilled in its Arnett Project, resulting in the discovery of 11.3 gross Bcfe of proved developed reserves in Morrow sandstone objectives, or 5.4 Bcfe net to the Company's interests. Capitalizing on these discoveries, the Company plans to drill three offset Morrow locations during the first half of 2000. Each of these Morrow prospects will test natural gas reserve targets estimated at approximately 2 Bcf per well on a gross unrisked basis with dry hole costs estimated to be approximately $400,000 per well. Huskie and Boilermaker Projects Brigham's Huskie and Boilermaker Projects consist of 103 and 96 square miles, respectively, of continuous 3-D seismic data covering approximately 127,000 acres in Blaine County, Oklahoma. These projects target stratigraphic sand channels in the Springer-aged Old Woman and Britt intervals. Brigham initiated acquisition of data in its Huskie Project in 1996 where it retained a 37.5% working interest and, based upon the prospect density and reserve potential interpreted from this initial data set, the Company subsequently acquired data in its adjacent Boilermaker Project in 1998 where it retained a 100% working interest. The Company has assembled acreage over a number of potential drilling locations in these project areas and has at least one exploratory well planned for its Huskie Project in 2000. This well was spud during the first quarter 2000 and will test a prospect with approximately 20 Bcfe of gross unrisked reserve potential which is an extension to a prolific Springer channel that has produced over 128 Bcfe. Success from this initial exploratory well would likely establish several development locations. The Company retains a 71% working interest in this exploratory well. Wildcat and Panther Projects The Company's Wildcat and Panther Projects consist of 47 and 99 square miles, respectively, of continuous 3-D seismic data covering approximately 93,440 acres in the southern portion of the Texas Panhandle in Wheeler County, Texas and Beckham County, Oklahoma. The primary exploration targets within these projects are high potential, structural features at depths ranging from 7,500 to 21,000 feet. Brigham initiated acquisition of data in its Wildcat Project in 1997 where it retained a 37.5% working interest. Based upon the interpretation of this initial data set, the Company subsequently acquired data in its adjacent Panther Project in 1998 where it retained a 100% working interest. In its Wildcat Project, the Company has a deep 21,000 foot exploratory well planned for the first half of 2000 to drill an updip location to a Hunton well that has produced over 15 Bcfe since 1981 and was still producing in February 2000. The Company believes successful completion of this exploratory test could prove up an additional 55 Bcfe of remaining gross unrisked reserves in this producing structure and set up several development locations. Bearcat Project Brigham's Bearcat Project consists of approximately 59 square miles of 3-D seismic data covering approximately 37,760 acres in the prolific Carter Knox anticline in Grady County, Oklahoma. This project targets 3-D seismic amplitude-related shallow Pennsylvanian-aged channel sands and deep bar sands in the Springer section. In early 2000, the Company drilled its first well in its Bearcat Project, which was a 13,000 foot test of a potentially significant 3-D delineated Springer bar feature with gross unrisked reserve potential of 100 Bcfe. The well encountered a significant thickness of Springer-aged sand which confirmed Brigham's 3-D seismic interpretation of this feature. The well was being tested in late March 2000, and a successful completion would establish multiple offset development drilling opportunities. 14 West Texas The Company's drilling activity in its West Texas province has been focused in the Horseshoe Atoll, the Midland Basin and the Eastern Shelf of the Permian Basin and in the Hardeman Basin. In response to reduced market prices for oil and comparatively higher potential natural gas projects in its Anadarko Basin and Gulf Coast provinces, the Company substantially reduced its 3-D seismic and drilling activities in its West Texas during 1998 and 1999. Based on the recent recovery in oil prices, the Company intends to undertake a comprehensive analysis of its proved and unproved West Texas assets to evaluate opportunities to generate value either through the drilling of identified 3-D prospects, the sale of promoted interests in drillable 3-D prospects or the sale of all or a portion of its proved reserves and 3-D prospect inventory. As of December 31, 1999, Brigham had acquired 1,689 square miles (1.1 million acres) in the West Texas region. Through its drilling efforts in this region from 1990 through 1999, Brigham had completed 185 wells in 299 attempts (62% completion rate) in its West Texas province with an average working interest of 23% and had found cumulative net proved reserves of 21 Bcfe at an average net drilling cost of $1.31 per Mcfe. The Company participated in the drilling of one well with a 35% working interest in its West Texas province during 1999 which was unsuccessful. As of December 31, 1999, the Company had identified approximately 165 3-D delineated potential drilling locations in its West Texas projects. While the Company's 2000 drilling program does not currently include any wells in its West Texas province, Brigham may participate in the drilling of several of its highest quality West Texas prospects this year to capitalize on high current oil prices. Natural Gas and Oil Reserves The Company's estimated total net proved reserves of natural gas and oil as of December 31, 1997, 1998 and 1999 and the present values attributable to these reserves as of those dates were as follows: As of December 31, ------------------------------- 1997 1998 1999 ---------- -------- --------- Estimated net proved reserves: Natural gas (MMcf) ........................ 53,230 71,166 65,457 Oil (MBbls) ............................... 3,181 4,433 3,027 Natural gas equivalent (MMcfe) ............ 72,316 97,764 83,618 Proved developed reserves as a percentage of proved reserves ........................ 65% 57% 48% Present Value of Future Net Revenues (in thousands)............................. $ 69,249 $ 81,741 $ 114,466 Standardized Measure (in thousands).......... $ 64,274 $ 81,649 $ 113,546 The reserve estimates reflected above were prepared by Cawley, Gillespie & Associates, Inc. ("Cawley Gillespie"), the Company's petroleum consultants, and are part of reports on the Company's oil and natural gas properties prepared by Cawley Gillespie. The base sales prices for the Company's reserves were $2.27 per Mcf for natural gas and $15.50 per Bbl for oil as of December 31, 1997, $2.12 per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31, 1999. These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company's reserves at these dates. In accordance with applicable requirements of the SEC, estimates of the Company's proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the Company. The reserve data set forth in this Form 10-K represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. The Company's estimated proved reserves have not been filed with or included in reports to any federal agency. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Risk Factors -- We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows." 15 Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the estimated reserves that may be substantial. Drilling Activities The Company drilled, or participated in the drilling of, the following number of wells during the periods indicated:
Year Ended December 31, --------------------------------------------------------- 1997 1998 1999 ---------------- ----------------- ------------------ Gross Net Gross Net Gross Net ------- ------- ------- -------- -------- -------- Exploratory Wells (1): Natural gas..................... 15 6.5 30 15.6 8 3.4 Oil............................. 21 7.9 7 2.5 2 0.1 Non-productive ................. 26 9.8 17 8.0 7 2.4 -- --- -- --- -- --- Total....................... 62 24.2 54 26.1 17 5.9 == ==== == ==== == === Development Wells (2): Natural gas..................... 4 1.6 10 6.6 8 2.3 Oil............................. 5 1.6 3 1.5 1 0.5 Non-productive ................. 2 0.9 5 3.4 1 0.6 -- --- -- ---- -- --- Total....................... 11 4.1 18 11.5 10 3.4 == === == ==== == ===
- ---------------- (1) From January 1, 2000 through March 23, 2000, the Company drilled, or participated in the drilling of, two gross (0.19 net) exploratory wells, of which one gross (0.17 net) was completed as a natural gas well and one gross (0.02 net) was completed as an oil well. (2) From January 1, 2000 through March 23, 2000, the Company drilled, or participated in the drilling of, five gross (2.1 net) development wells, of which one gross (1.0 net) was completed as a natural gas well, two gross (0.03 net) were completed as oil wells and two gross (1.1 net) in the process of drilling at March 23, 2000. The Company does not own any drilling rigs, and the majority of its drilling activities have been conducted by industry participant operators or independent contractors under standard drilling contracts. Consistent with its business strategy, the Company has continued to retain operations of an increasing number of the wells it drills. Brigham operated 44% of the gross and 73% of the net wells it participated in during 1999. 16 Productive Wells and Acreage Productive Wells The following table sets forth the Company's ownership interest as of December 31, 1999 in productive natural gas and oil wells in the areas indicated.
Natural Gas Oil Total -------------- ---------------- ----------------- Gross Net Gross Net Gross Net ------- ----- --------- ------ -------- ------ Province: Anadarko Basin...... 88 32.1 12 3.7 100 35.8 Gulf Coast.......... 32 13.6 15 2.3 47 15.9 West Texas ......... 9 2.8 88 26.3 97 29.1 Other............... -- -- 2 0.7 2 0.7 --- ---- --- ---- --- ---- Total........... 129 48.5 117 33.0 246 81.5 === ==== === ==== === ====
Productive wells consist of producing wells and wells capable of production, including wells waiting on pipeline connection. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, none had multiple completions. Acreage Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof. The following table sets forth the approximate developed and undeveloped acreage in which the Company held a leasehold, mineral or other interest at December 31, 1999:
Developed Undeveloped Total ---------------- -------------------- ------------------- Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- Province: Anadarko Basin................... 29,540 12,112 85,625 46,759 115,165 58,871 Gulf Coast....................... 2,626 1,237 23,249 14,762 25,875 15,999 West Texas ...................... 6,861 2,013 15,370 5,331 22,231 7,344 Other............................ 480 148 16,646 5,412 17,126 5,560 ------ ------ ------- ------ ------- ------ Total........................ 39,507 15,510 140,890 72,264 180,397 87,774 ====== ====== ======= ====== ======= ======
All the leases for the undeveloped acreage summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed, production has been obtained from the acreage subject to the lease prior to that date, or some other "savings clause" is implicated. The following table sets forth the minimum remaining terms of leases for the gross and net undeveloped acreage: Acres Expiring -------------------- Gross Net ------- ------ Twelve Months Ending: December 31, 2000................... 47,537 22,409 December 31, 2001................... 64,153 33,711 December 31, 2002................... 7,215 3,992 Thereafter.......................... 21,985 12,152 ------- ------ Total........................... 140,890 72,264 ======= ====== 17 In addition, the Company had lease options as of December 31, 1999 to acquire an additional 109,374 gross (67,119 net) acres, substantially all of which expire before June 30, 2000. Volumes, Prices and Production Costs The following table sets forth the production volumes, average prices received and average production costs associated with the Company's sale of oil and natural gas for the periods indicated.
Year Ended December 31, -------------------------- 1997 1998 1999 -------- -------- -------- Production: Natural gas (MMcf).............................. 1,382 4,269 4,197 Oil (MBbls)..................................... 291 396 346 Natural gas equivalent (MMcfe).................. 3,126 6,644 6,270 Average sales price: Natural gas (per Mcf)........................... $ 2.56 $ 2.04 $ 2.11 Oil (per Bbl) .................................. 19.40 12.85 17.79 Average production expenses and taxes (per Mcfe) .. $ 0.55 $ 0.46 $ 0.51
Costs Incurred and Capitalized Costs The costs incurred in oil and natural gas acquisition, exploration and development activities are as follows (in thousands): Year Ended December 31, ------------------------------------ 1997 1998 1999 ---------- ---------- ------------ Cost incurred for the year: Exploration....................... $ 29,516 $ 68,214 $ 19,224 Property acquisition.............. 26,956 16,245 3,462 Development....................... 2,953 10,475 4,632 Proceeds from participants........ (319) (10,502) (29,582) ----------- ----------- ---------- $ 59,106 $ 84,432 $ (2,264) =========== ========== ========== Costs incurred represent amounts incurred by the Company for exploration, property acquisition and development activities. Periodically, the Company will receive reimbursement of certain costs from participants in its projects subsequent to project initiation in return for an interest in the project. These payments are described as "Proceeds from participants" in the table above. ITEM 3. LEGAL PROCEEDINGS The Company is not a party to any material legal proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS No matter was submitted to a vote of the Company's securityholders during the fourth quarter of 1999. 18 EXECUTIVE OFFICERS OF THE REGISTRANT Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this report. The following table sets forth certain information concerning the executive officers of the Company as of March 23, 2000:
Name Age Position - ---------------------- ----- --------------------------------------------------- Ben M. Brigham 40 Chief Executive Officer, President and Chairman Curtis F. Harrell 36 Chief Financial Officer and Director David T. Brigham 39 Vice President - Land and Administration, Corporate Secretary A. Lance Langford 37 Vice President - Operations Jeffery E. Larson 41 Vice President - Exploration Karen E. Lynch 38 Vice President - Legal and General Counsel Christopher A. Phelps 29 Vice President - Finance and Strategic Planning
Set forth below is a description of the backgrounds of the executive officers of the Company. Ben M. "Bud" Brigham has served as Chief Executive Officer, President and Chairman of the Board of the Company since founding the Company in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas. Mr. Brigham is the husband of Anne L. Brigham, Director, and the brother of David T. Brigham, Vice President-- Land and Administration and Corporate Secretary. Curtis F. Harrell has served as Chief Financial Officer and Director of the Company since August 1999. From 1997 to August 1999, he was Executive Vice President and Partner at R. Chaney & Company, Inc., an equity investment firm focused on the energy industry, where he managed the firm's investment origination efforts in the U.S., focusing on investments in corporate equity securities of energy companies in the exploration and production and oilfield service industry segments. From 1995 to 1997, Mr. Harrell was a Director of Domestic Corporate Finance for Enron Capital & Trade Resources, Inc., where he was responsible for initiating and executing a variety of debt and equity financing transactions for independent exploration and production companies. Before joining Enron Capital & Trade Resources, Mr. Harrell spent eight years working in corporate finance and reservoir engineering positions for two public independent exploration and production companies, Kelley Oil & Gas Corporation and Pacific Enterprises Oil Company, Inc. He has a B.S. in Petroleum Engineering from the University of Texas at Austin and an M.B.A. from Southern Methodist University. David T. Brigham joined the Company in 1992 and has served as Vice President-- Land and Administration and Corporate Secretary of the Company since February 1998. Mr. Brigham served as Vice President-- Legal of the Company from 1994 until February 1998. From 1987 to 1992, Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending law school, Mr. Brigham was a landman for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board. A. Lance Langford joined the Company as Manager of Operations in 1995 and has served as Vice President-- Operations since January 1997. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University. 19 Jeffery E. Larson joined the Company in 1997 and has served as Vice President -- Exploration since August 1999. Mr. Larson joined Brigham in October 1997 as Gulf Coast Exploration Manager in its Houston office where he co-managed the Company's successful expansion into the onshore Gulf Coast province through the initiation and assemblage of 3-D seismic projects and drilling opportunities. In November 1998, Mr. Larson relocated to Brigham's corporate office in Austin where he assumed an expanded role in directing the Company's exploration activities in the Anadarko Basin, in addition to the further advancement of its Gulf Coast activities. Prior to joining Brigham, Mr. Larson was an explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities. Mr. Larson worked at Burlington for seven years in various roles of increasing responsibility within its exploration department. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and Research Scientist. He has a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana. Karen E. Lynch joined the Company in October 1997 as General Counsel and has served as Vice President-- Legal and General Counsel of the Company since February 1998. Prior to joining the Company, Ms. Lynch was a shareholder in the Dallas-based law firm of Thompson & Knight, P.C., where she practiced in the energy area since joining the firm in 1987. Ms. Lynch holds a B.B.A. in Petroleum Land Management from the University of Texas and a J.D. from the University of Oklahoma. Christopher A. Phelps joined the Company as Manager of Finance and Investor Relations in January 1998 and has served as Vice President -- Finance and Strategic Planning since August 1999. Prior to joining the Company, Mr. Phelps was a Vice President in the Investment Banking Department of Bear, Stearns & Co. Inc., a major international securities brokerage and investment banking firm, where he spent over five years executing a variety of capital raising and mergers and acquisition transactions principally for independent exploration and production companies. He holds a B.B.A. in Finance from the University of Texas at Austin. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock has been publicly traded on The Nasdaq Stock Market(sm) under the symbol "BEXP" since the Company's initial public offering effective May 8, 1997. The following table summarizes the high and low last reported sales prices of the Company's common stock on Nasdaq for each quarterly period during the past two fiscal years: 1998 1999 ------------------ ------------------ High Low High Low ------ ------ ----- ------ First Quarter........... $14.00 $10.50 $6.00 $2.75 Second Quarter.......... $15.50 $8.75 $3.25 $0.88 Third Quarter........... $10.25 $5.13 $3.31 $1.94 Fourth Quarter.......... $9.50 $4.75 $2.72 $1.00 The closing market price of the Company's common stock on March 23, 2000 was $2.13 per share. As of March 23, 2000, the Company estimates that there were 82 record owners of the Company's common stock. No dividends have been declared or paid on the Company's common stock to date. The Company intends to retain all future earnings for the development of its business. In addition, the Credit Facility (as defined) and the Indenture (as defined) restrict the Company's ability to pay dividends on the Company's common stock. 20 ITEM 6. SELECTED FINANCIAL DATA The following selected consolidated financial data should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's consolidated financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data."
Year Ended December 31, --------------------------------------------------- 1995 1996 1997 1998 1999 --------- -------- ------- --------- -------- Statement of Operations Data: Revenues: Natural gas and oil sales............................... $ 3,578 $ 6,141 $ 9,184 $ 13,799 $ 14,992 Workstation revenue..................................... 635 627 637 390 285 -------- ------- -------- -------- -------- Total revenues..................................... 4,213 6,768 9,821 14,189 15,277 Costs and expenses: Lease operating......................................... 761 726 1,151 2,172 2,259 Production taxes........................................ 165 362 549 850 968 General and administrative.............................. 1,897 2,199 3,570 4,672 3,481 Depletion of natural gas and oil properties............. 1,626 2,323 2,743 8,483 7,792 Depreciation and amortization........................... 533 487 306 413 525 Capitalized ceiling impairment.......................... - - - 25,926 - Amortization of stock compensation...................... - - 388 372 1 -------- ------- -------- -------- -------- Total costs and expenses........................... 4,982 6,097 8,707 42,888 15,026 -------- ------- -------- -------- -------- Operating income (loss)................................. (769) 671 1,114 (28,699) 251 Other income (expense): Interest expense, net................................... (936) (1,173) (1,190) (5,968) (9,697) Interest income......................................... 128 52 145 136 176 Other expense........................................... - - - - (163) Loss on sale of natural gas and oil properties.......... - - - - (12,195) -------- ------- -------- -------- -------- Total other income (expense)....................... (808) (1,121) (1,045) (5,832) (21,879) -------- ------- -------- -------- -------- Net income (loss) before income taxes................... (1,577) (450) 69 (34,531) (21,628) Income tax benefit (expense)............................ - - (1,186) 1,186 - -------- ------- -------- -------- -------- Net loss................................................ $ (1,577) $ (450) $ (1,117) $(33,345) $(21,628) ======== ======= ======== ======== ======== Net loss per share - basic and diluted.................. $ (0.18) $ (0.05) $ (0.10) $ (2.64) $ (1.53) Weighted average shares outstanding - basic and diluted. 8,929 8,929 11,081 12,626 14,152 Statement of Cash Flows Data: Net cash provided by operating activities............... $ 1,383 $ 3,710 $ 9,806 $ 14,774 $ 2,578 Net cash provided (used) by investing activities........ (8,005) (11,796) (57,300) (86,227) 1,644 Net cash provided (used) by financing activities........ 7,724 7,731 47,748 72,321 (4,049) Other Financial Data: Capital expenditures.................................... $ 7,935 $13,612 $ 57,170 $ 85,207 $ 25,560 As of December 31, -------------------------------------------------- 1995 1996 1997 1998 1999 --------- -------- ------- --------- -------- Balance Sheet Data: Cash and cash equivalents............................... $ 1,802 $ 1,447 $ 1,701 $ 2,569 $ 2,742 Oil and natural gas properties, net..................... 18,538 28,005 84,294 134,317 112,066 Total assets............................................ 22,916 33,614 92,519 150,516 125,683 Long-term debt, net..................................... 16,000 24,000 32,000 94,786 97,341 Total stockholders' equity.............................. 3,694 3,244 43,313 24,681 8,998
21 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview The Company is an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore and develop onshore oil and natural gas provinces in the United States. From inception in 1990 through December 31, 1999, Brigham acquired 5,122 square miles of 3-D seismic data, identified approximately 1,050 potential drilling locations and drilled 469 wells delineated by 3-D seismic analysis. Through its 3-D seismic-based drilling efforts, the Company had discovered an aggregate of 121 Bcfe of net proved reserves as of December 31, 1999. The Company believes this performance demonstrates a systematic methodology for finding oil and natural gas in onshore domestic hydrocarbon producing provinces. Combining its geologic and geophysical expertise with a sophisticated land effort, the Company manages the majority of its projects from conception through 3-D acquisition, processing and interpretation and leasing. In addition, the Company manages the negotiation and drafting of most of its geophysical exploration agreements, resulting in reduced contract risk and more consistent deal terms. Because it generates most of its projects, the Company can control the size of the working interest that it retains as well as the selection of the operator and the non-operating participants. Consistent with its business strategy, Brigham has increased the working interest it retained in its projects, based on capital availability and perceived risk. The Company's average working interest in its 3-D seismic projects acquired during 1996, 1997 and 1998 was 37%, 66% and 81%, respectively, while its average working interest in its wells drilled during this period was 24%, 39% and 52%, respectively. The Company did not acquire any new 3-D seismic in 1999, and its average working interest in its wells drilled during 1999 was 34%. Beginning in 1995, the Company has managed operations through the drilling and production phases on an increasing portion of its 3-D seismic projects. Brigham operated 44% of its gross wells and 73% of its net wells drilled in 1999 as compared with 10% of its gross wells and 17% of its net wells drilled in 1996. Expenditures made in oil and natural gas exploration vary from project to project depending primarily on the costs related to seismic acquisition, land and drilling, and the working interest retained by the Company. Prior to 1997, the Company's participants typically bore a disproportionate share of the costs of optioning available acreage and acquiring, processing and interpreting the 3-D seismic data, and the Company and its participants each typically incurred leasing, drilling and completion costs in proportion to their ownership interests. In 1997 and 1998, Brigham retained majority working interests in its new 3-D seismic projects, and thereby reduced the financial leverage it historically received on the costs of optioning available acreage and acquiring, processing and interpreting the 3-D seismic data on its projects. From inception through 1996, the Company acquired 2,762 gross (781 net) square miles of 3-D seismic data. Initially, the Company focused its efforts in West Texas. In 1995, the Company began to devote substantial attention to the Anadarko Basin, and since 1996 the Company has devoted the majority of its resources to the Anadarko Basin and Gulf Coast. With this shift in regional focus, the majority of the Company's production volumes has shifted from oil to natural gas. To finance these project generation and drilling activities, the Company supplemented cash flow from operations with private placements of debt and equity, commercial bank credit facilities and placements of working interests in projects with industry participants. As the Company's cash flows from operations and other sources of capital have increased during this period, it retained larger average working interests in its projects. In 1997 and 1998, the Company acquired 2,360 gross (1,727 net) square miles of 3-D seismic and continued to focus the majority of its 3-D exploration efforts in the Anadarko Basin and the Gulf Coast. During these two years, the Company acquired 1,196 square miles (51%) of 3-D seismic in the Anadarko Basin, making this basin the most active 3-D seismic acquisition province for the Company. Brigham also significantly increased its Gulf Coast activity, acquiring 942 square miles (40%) of 3-D seismic during this period. During 1997 and 1998, the Company drilled 145 gross (65.9 net) wells based on its 3-D seismic data analysis. In addition to its drilling activities, the Company acquired 21.3 net Bcfe of proved reserves and an interest in undeveloped acreage (the "Chitwood Acquisition") at the northern end of the Carter Knox anticline in Grady County, Oklahoma for $13.4 million in November 1997. As a result of these activities, the Company's net natural gas and oil production increased from 2.1 Bcfe in 1996 to 6.6 Bcfe in 1998. The Company's net production volumes consisted of 79% natural gas on an equivalent basis during the fourth quarter 1998 as compared with 36% during the fourth quarter 1996. The Company supplemented cash flow from operations in 1997 and 1998 with borrowings under commercial bank credit facilities, $24 million raised in its initial public offering of common stock in May 1997, $47.5 million raised through the placement of debt and equity securities in August 1998 and the placement of working interests in projects to industry participants to finance its project generation, property acquisition and drilling activities. 22 As a result of lower commodity prices and reduced access to the capital markets in late 1998 and 1999, the Company implemented a number of strategic initiatives during 1999 to improve its capital liquidity to fund its continuing exploration program in the difficult industry environment. These objectives and results accomplished for each include: o Focusing All Planned Exploration Efforts in 1999 Toward Drilling of Highest-Grade 3-D Prospects in its Anadarko Basin and Gulf Coast Projects. Operating under a reduced drilling budget in 1999 as compared with 1998, Brigham directed its resources toward the drilling of identified prospects within trends where it had achieved historical drilling success. This focused drilling emphasis contributed to substantially improved returns on the Company's drilling investments during 1999, with average drilling costs of $0.37 per Mcfe and average all-in finding costs of $0.52 per Mcfe for the year. o Eliminating Substantially All Seismic and Land Expenditures for New Projects. In an effort to devote the majority of its capital resources to the drilling of its identified prospect locations, Brigham did not acquire any new 3-D seismic data in 1999. In addition to executing the Company's high-graded drilling program, Brigham's staff of explorationists continued to interpret previously acquired 3-D seismic data within existing projects to further delineate and refine pre-drill analysis of potential drilling locations. o Seeking to Divest Certain Producing Natural Gas and Oil Properties. In June 1999, Brigham sold interests in certain non-operated properties in two project areas in its Anadarko Basin province for a total of $17.1 million. These properties had estimated net proved reserves of 36 Bcfe as of June 1, 1999, of which approximately 67% were non-producing, and were producing an estimated 2.8 net MMcfe per day at the time of the sales. After application of the net proceeds received from these sales to the repayment of a portion of its outstanding borrowings under its bank credit facility, Brigham was able to increase its available borrowings under its bank credit facility by $8 million. The increase in bank borrowing capacity resulting primarily from these property sales was utilized to fund a substantial portion of the Company's capital expenditures during the second half of 1999. o Restructuring its Senior and Subordinated Debt Agreements. Working closely with its senior and subordinated lenders in 1999 and early 2000, Brigham was able to amend its senior credit facility and the indenture for its subordinated notes due 2003 to provide the Company with increased borrowing availability and financial flexibility to preserve cash flow to fund its exploration activities. See "-- Liquidity and Capital Resources." o Implementing an Overhead Reduction Plan. Brigham implemented several initiatives during 1999 that were designed to reduce general and administrative expenses and thereby increase cash flow from operations. These cost reduction initiatives included a Company-wide salary reduction effective in May 1999, the elimination of employee bonuses for 1999, subleasing a portion of the Company's headquarters space effective in November 1999, certain personnel reductions and the elimination or reduction of various other discretionary expenses. As a result of these actions, Brigham's total general and administrative expenses (including amounts capitalized) were reduced 33% from the fourth quarter 1998 to the fourth quarter 1999, while the Company's per unit net general and administrative expenses decreased 43% from $0.92 per Mcfe to $0.52 per Mcfe during these same periods. o Raising Equity Capital. During 1999, Brigham raised approximately $13 million in capital through the sale of interests in non-producing assets, primarily project and prospect equity sales to industry participants. In addition, Brigham issued $4.2 million of common stock to Veritas DGC Land, Inc. ("Veritas") to satisfy payment obligations due to Veritas for seismic acquisition and processing services performed prior to 1999 and certain seismic processing services performed during 1999. In connection with its series of financing transactions effected in February 2000 to fund its planned exploration and development program for 2000, Brigham raised $4.5 million through the issuance of common stock and warrants in a private equity placement. See "--Liquidity and Capital Resources." 23 The Company uses the full-cost method of accounting for its natural gas and oil properties. Under this method, all acquisition, exploration and development costs, including certain internal costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in the amortizable base of the "full-cost pool" as incurred. Upon the interpretation by the Company of the 3-D seismic associated with unproved properties, the geological and geophysical costs of acreage that is not specifically identified as prospective are transferred to the amortizable base of the full-cost pool. Geological and geophysical costs associated with prospective acreage, as well as leasehold costs, are transferred to the amortizable base of the full-cost pool when the prospects are drilled. The Company records depletion of its full-cost pool using the unit of production method. To the extent that the costs capitalized in the full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate and based on period-end natural gas and oil prices) of estimated future net after-tax cash flows from proved natural gas and oil reserves plus the capitalized cost of unproved properties, such costs are charged to operations as a writedown of the carrying value of natural gas and oil properties, or a "capitalized ceiling impairment" charge. The risk that the Company will be required to write down the carrying value of its oil and gas properties increases when oil and gas prices are depressed, even if such prices are temporary. In addition, capitalized ceiling impairment charges may occur if the Company experiences poor drilling results or has substantial downward revisions in its estimated proved reserves. A capitalized ceiling impairment is a charge to earnings that does not impact cash flows, but does impact operating income and stockholders' equity. Once incurred, a capitalized ceiling impairment charge to natural gas and oil properties cannot be reversed at a later date. Primarily as a result of the significant declines in both oil and natural gas prices at December 31, 1998 and disappointing drilling results on several of the Company's high working interest wells in 1998, the Company recorded a capitalized ceiling impairment charge at December 31, 1998 of $25.9 million (see Note 4 of Notes to the Consolidated Financial Statements). No assurance can be given that the Company will not experience a capitalized ceiling impairment charge in future periods. See "-- Risk Factors -- Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are Dependent On Exploratory Drilling Activities"; "-- Risk Factors -- Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are Volatile"; and " - -- Risk Factors -- We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows." In connection with the exchange of interests in the Company's predecessor partnership with shares of the Company's common stock (the "Exchange") prior to the Company's initial public offering in 1997, the Company issued options to purchase 644,097 shares of common stock to certain of its officers and employees. The Company recorded an unearned stock compensation balance of $2.5 million in the first quarter 1997, of which approximately one-half will be added to the amortizable base of the full-cost pool over the vesting period of the options and the balance will be recorded as a non-cash compensation expense over the vesting period of the options. As a result, the Company expects to incur unearned stock compensation amortization expenses of approximately $64,000 in 2000, $33,000 in 2001 and an aggregate of $41,000 in the two years thereafter. The Company's predecessor was classified as a partnership for federal income tax purposes. Therefore, no income taxes were paid or provided for by the Company prior to the Exchange. The Company is a taxable entity. In connection with the Exchange on February 27, 1997, the Company incurred a $5 million charge to record a deferred income tax liability to recognize the differences between the financial statement basis and tax basis of the Company's predecessor partnership's natural gas and oil properties at the Exchange date, given the provisions of enacted tax laws. During the fourth quarter 1997, the Company elected to record a step-up in the basis of its assets for tax purposes as a result of the Exchange. Due to this election, the Company recorded a $3.8 million non-cash deferred income tax benefit during the fourth quarter 1997, which resulted in a net $1.2 million ($0.10 per diluted share) non-cash deferred income tax charge for the year ended December 31, 1997. 24 Results of Operations The following table sets forth certain operating data for the periods presented.
Year Ended December 31, ------------------------------------ 1997 998 1999 ---------- ---------- ------------ Production: Natural gas (MMcf)............................................. 1,382 4,269 4,197 Oil (MBbls).................................................... 291 396 346 Natural gas equivalent (MMcfe) ................................ 3,126 6,644 6,270 % Natural gas.................................................. 44% 64% 67% Average sales prices per unit (1): Natural gas (per Mcf).......................................... $ 2.56 $ 2.04 $ 2.11 Oil (per Bbl).................................................. 19.40 12.85 17.79 Natural gas equivalent (per Mcfe).............................. 2.94 2.08 2.39 Costs and expenses per Mcfe: Lease operating................................................ $ 0.37 $ 0.33 $ 0.36 Production taxes............................................... 0.18 0.13 0.15 General and administrative..................................... 1.14 0.70 0.56 Depletion of natural gas and oil properties.................... 0.88 1.28 1.24
- ------------------- (1) Reflects the effects of the Company's hedging activities. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-- Other Matters-- Hedging Activities." Year Ended December 31, 1999 Compared to Year Ended December 31, 1998 Natural gas and oil sales. Natural gas and oil sales increased 9% from $13.8 million in 1998 to $15 million in 1999. An increase in the average sales price received for natural gas and oil sales accounted for $2 million of this increase and was offset by $797,000 from a decrease in net production volumes. Production volumes for natural gas decreased 2% from 4,269 MMcf in 1998 to 4,197 MMcf in 1999, while the average price received for natural gas increased 3% from $2.04 per Mcf in 1998 to $2.11 per Mcf in 1999. Production volumes for oil decreased 13% from 396 MBbls in 1998 to 346 MBbls in 1999, while the average price received for oil increased 38% from $12.85 per Bbl in 1998 to $17.79 per Bbl in 1999. Natural gas and oil sales in 1999 were increased by higher realized natural gas and oil prices and production from wells completed during 1999, offset partially by the natural decline of existing production and from the sale of certain producing wells in the Company's mid-1999 property divestitures. See "-- Overview." As a result of hedging activities, natural gas revenues were reduced by $486,000 ($0.12 per Mcf) in 1999, compared to an increase in natural gas revenues of $555,000 ($0.13 per Mcf) in 1998. See "-- Other Matters -- Hedging Activities." Workstation revenue. Workstation revenue decreased 27% from $390,000 in 1998 to $285,000 in 1999. Brigham recognizes workstation revenue as industry participants in its seismic programs are charged an hourly rate for the work performed by the Company on its 3-D seismic interpretation workstations. This decrease in 1999 is primarily attributable to the Company's increased working interests in its 3-D seismic projects in 1997 and 1998, which reduces the amount of workstation interpretation costs billable to the Company's project participants. Brigham expects workstation revenue to continue to decline in 2000 due to the Company's increased working interests in the square miles of 3-D seismic it acquired in 1997 and 1998. Lease operating expenses. Lease operating expenses increased 4% from $2.2 million ($0.33 per Mcfe) in 1998 to $2.3 million ($0.36 per Mcfe) in 1999. This increase was primarily due to higher average working interests in its producing wells and increased well repair and workover activity in 1999 as compared with 1998, offset in part by the elimination of lease operating expenses related to wells sold by the Company in its mid-1999 property divestitures. See "-- Overview." 25 Production taxes. Production taxes increased 14% from $850,000 ($0.13 per Mcfe) in 1998 to $968,000 ($0.15 per Mcfe) in 1999 primarily due to higher average natural gas and oil sales prices and revenues. The effective average production tax rate increased from 6.2% of natural gas and oil sales revenues in 1998 to 6.5% in 1999 resulting from changes in the geographic distribution of the Company's producing wells. General and administrative expenses. General and administrative expenses decreased 25% from $4.7 million ($0.70 per Mcfe) in 1998 to $3.5 million ($0.56 per Mcfe) in 1999. This decrease was primarily attributable to a series of cost reduction initiatives implemented by Brigham during 1999 to reduce overhead expense levels. These initiatives included a Company-wide salary reduction effective in May 1999, the elimination of employee bonuses for 1999, a sublease of a portion of the Company's headquarters space effective in November 1999, certain personnel reductions and the elimination or reduction of various other discretionary expenses. The Company plans to continue certain of these cost reduction initiatives in an effort to further reduce net general and administrative expenses per unit in 2000. Depletion of natural gas and oil properties. Depletion of natural gas and oil properties decreased 8% from $8.5 million ($1.28 per Mcfe) in 1998 to $7.8 million ($1.24 per Mcfe) in 1999. Of this decrease, $464,000 was attributable to the lower production volumes during the period and $227,000 was due to the reduction in the depletion rate per unit of production. The decrease in depletion rate per unit of production was primarily the result of the addition of natural gas and oil reserves at lower average capital costs due to improved average finding costs during 1999, partially offset by an increase in the percentage of the Company's total full cost pool subject to depletion attributable to an increase in the estimate of the evaluated portion of the Company's natural gas and oil properties. Interest expense. Interest expense increased from $6 million in 1998 to $9.7 million in 1999 due to higher outstanding debt balances in 1999 at higher effective interest rates. The Company's weighted average outstanding debt balance increased 51% from $66 million in 1998 to $99.5 million in 1999. This increase in debt was incurred primarily to fund the Company's increased capital expenditures and working capital needs, net of operating cash flow, during 1998 and 1999. The effective annual interest rate on the Company's outstanding indebtedness increased from 10.6% in 1998 to 12.6% in 1999, primarily due to the Company's issuance of $40 million of senior subordinated secured notes due 2003 (the "Subordinated Notes") in August 1998, which bore interest at an annual rate of 12% when paid in cash and 13% when paid "in kind" through the issuance of additional Subordinated Notes. In addition, interest expense in 1999 included (i) $5.5 million of interest expenses related to the Subordinated Notes that was paid in kind through the issuance of additional Subordinated Notes in lieu of cash, and (ii) $2.3 million of non-cash charges related to the amortization of deferred loan fees and the amortization of discount on the Subordinated Notes. Pursuant to the recently amended terms of the Company's senior credit facility and the Subordinated Notes, Brigham expects to pay its interest obligations related to the Subordinated Notes through the issuance of additional Subordinated Notes in lieu of cash during the first three quarters of 2000 (and potentially during the fourth quarter 2000, if certain conditions are met) in an effort to preserve cash flow to fund capital expenditures. Borrowings under the Company's credit facility had an effective annual interest rate of 9.5% at December 31, 1999. See "-- Liquidity and Capital Resources." Loss on sale of natural gas and oil properties. In June 1999, the Company sold all of its interests in certain producing and non-producing natural gas and oil properties for a total sales price of $17.1 million. Due to the magnitude of the reserve volumes that were attributable to these properties relative to the Company's remaining net reserve volumes, the Company recognized a $12.2 million non-cash loss to reflect the difference between the sales price received (after adjustment for transaction costs) and the $28.9 million basis allocated to the divested properties in accordance with the full-cost method of accounting for oil and gas properties. No property divestitures occurred during 1998 for which recognition of gain or loss was appropriate. Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 Natural gas and oil sales. Natural gas and oil sales increased 50% from $9.2 million in 1997 to $13.8 million in 1998. Production volume increases accounted for $9.4 million of this increase and were offset by $4.8 million from a decrease in the average sales price received for natural gas and oil sales. Production volumes for natural gas increased 209% from 1,382 MMcf in 1997 to 4,269 MMcf in 1998. The average price received for natural gas decreased 20% from $2.56 per Mcf in 1997 to $2.04 per Mcf in 1998. Production volumes for oil increased 36% from 291 MBbls in 1997 to 396 MBbls in 1998. The average price received for oil decreased 34% from $19.40 per Bbl in 1997 to $12.85 per Bbl in 1998. Natural gas and oil sales in 1998 were increased by production from wells completed and flowing to sales since December 31, 1997, offset partially by the natural decline of existing production, and from certain wells acquired in the Chitwood Acquisition which were included in the Company's results of operations effective September 1, 1997. See "-- Overview." As a result of hedging activities, natural gas revenues increased by $555,000 ($0.13 per Mcf) in 1998, compared to a decrease in oil revenues of $6,200 ($0.02 per Bbl) in 1997. See "-- Other Matters -- Hedging Activities." 26 Workstation revenue. Workstation revenue decreased 39% from $637,000 in 1997 to $390,000 in 1998. This decrease is primarily attributable to the Company's increased working interests in its recently acquired 3-D seismic data, which reduced the amount of workstation interpretation costs billable to the Company's project participants. Lease operating expenses. Lease operating expenses increased 89% from $1.2 million ($0.37 per Mcfe) in 1997 to $2.2 million ($0.33 per Mcfe) in 1998. This increase was primarily due to an increase in the number of producing wells during 1998 from those in 1997. The decrease in the per unit amount was primarily due to an increase in natural gas production as a percentage of total equivalent production (44% in 1997 and 64% in 1998) since a typical natural gas well produces with lower average lease operating costs per unit of production than a typical oil well. Production taxes. Production taxes increased 55% from $549,000 ($0.18 per Mcfe) in 1997 to $850,000 ($0.13 per Mcfe) in 1998 as a direct result of increased production volumes. The effective average production tax rate increased from 6% of natural gas and oil sales revenues in 1997 to 6.2% in 1998 due to the increase in natural gas production as a percentage of total equivalent production as natural gas is typically burdened with higher production tax rates than oil. The decrease in the per unit amount was primarily attributable to the decline in natural gas and oil sales prices in 1998 as compared with 1997. General and administrative expenses. General and administrative expenses increased 31% from $3.6 million ($1.14 per Mcfe) in 1997 to $4.7 million ($0.70 per Mcfe) in 1998. This increase was primarily attributable to the hiring of additional personnel and related expenses necessary to manage the Company's growing operations. The decrease in the per unit rate was a result of a greater increase in natural gas and oil production volumes than general and administrative expenses from 1997 to 1998 due to the aforementioned factors. Depletion of natural gas and oil properties. Depletion of natural gas and oil properties increased 209% from $2.7 million ($0.88 per Mcfe) in 1997 to $8.5 million ($1.28 per Mcfe) in 1998. Of this increase, $4.5 million was attributable to the increase in production volumes during the period and $1.3 million was due to the increase in the depletion rate per unit of production. The increase in depletion rate per unit of production was primarily the result of the addition of natural gas and oil reserves at higher average capital costs due to a reduction in drilling performance and downward revisions to previous reserve estimates. Interest expense. Interest expense increased from $1.2 million in 1997 to $6 million in 1998 due to higher outstanding debt balances in 1998 at higher effective interest rates. The Company's weighted average outstanding debt balance increased 450% from $12 million in 1997 to $66 million in 1998. This increase in debt was incurred primarily to fund the Company's increased capital expenditures and working capital needs, net of operating cash flow, during 1998. The effective annual interest rate on the Company's outstanding indebtedness increased from 9.4% in 1997 to 10.6% in 1998, primarily due to the Company's issuance of Subordinated Notes in August 1998. In addition, interest expense in 1998 included (i) approximately $1 million of non-cash charges related to the amortization of deferred loan fees and the amortization of discount on the Subordinated Notes, and (ii) $507,000 of interest expenses related to the Subordinated Notes that was paid in kind through the issuance of additional Subordinated Notes in lieu of cash in February 1999. Borrowings under the Company's senior credit facility had an effective annual interest rate of 7.2% at December 31, 1998. 27 Liquidity and Capital Resources The Company's primary sources of capital have been credit facility and other debt borrowings, public and private equity financings, the sale of interests in projects and properties and funds generated by operations. The Company's primary capital requirements are 3-D seismic acquisition, processing and interpretation costs, land acquisition costs and drilling expenditures. In January 1998, the Company entered into a new bank credit facility that provided for borrowing availability of $75 million that was used to repay its then outstanding borrowings under its previous credit facility and to fund capital expenditures. This credit facility has been subsequently amended, including (i) an amendment in July 1999 in connection with the Company's mid-1999 sales of natural gas and oil properties to provide for borrowing availability of $56 million, and (ii) an amendment in February 2000 to provide for borrowing availability of $70 million that would be increased to $75 million under certain circumstances. In August 1998, the Company issued $50 million of debt and equity securities, including the $40 million of Subordinated Notes, that generated proceeds of approximately $47.5 million, net of offering costs, that were used to repay a portion of then outstanding borrowings under the Company's credit facility, thereby increasing the Company's borrowing availability under its credit facility to fund capital expenditures. During 1999, Brigham issued $4.2 million of common stock to Veritas DGC Land, Inc., to satisfy payment obligations due to Veritas for seismic acquisition and processing services. In June 1999, the Company received $17.1 million ($16.7 million after transaction costs and post-closing adjustments) from the sale of its interests in producing and non-producing natural gas and oil properties located in two non-operated fields in its Anadarko Basin province. In February 2000, Brigham raised $4.5 million through the issuance of common stock and warrants to purchase common stock in a private equity placement to three institutional investors. Credit Facility In January 1998, the Company entered into a revolving credit agreement (the "Credit Facility"), which provided for an initial borrowing availability of $75 million. The Credit Facility was amended in March 1999 to reduce the borrowing availability, extend the date of borrowing base redetermination, modify certain financial covenants, include certain additional covenants that place significant restrictions on the Company's ability to incur certain capital expenditures, and to increase the interest rate on outstanding borrowings. As a result of the completion of the majority of the Company's strategic initiatives to improve its capital resources, including the June 1999 property divestitures and the application of the net sales proceeds to reduce borrowings outstanding under the Credit Facility, the Company and its senior lenders entered into an amendment to the Credit Facility in July 1999. This amendment provided the Company with borrowing availability of $56 million principally to fund its planned drilling activities and anticipated working capital requirements through the end of 1999. As consideration for this amendment to the Credit Facility, in July 1999 the Company issued to its senior lenders one million warrants to purchase the Company's common stock at an exercise price of $2.25 per share. The warrants have a seven-year term from the date of issuance and are exercisable at the holders' option at any time. An estimated value of $1.2 million was attributed to these warrants by the Company and was recognized as additional deferred loan fees that will be amortized over the remaining period to maturity of the Credit Facility. In February 2000, Brigham entered into an amended and restated Credit Facility with its existing lenders and a new lender. This amended and restated Credit Facility provides the Company with $70 million in borrowing availability for a three-year term, an increase from the $56 million previously available. If Brigham exceeds certain asset value and interest coverage tests in the second or third quarters of 2000, the total borrowing availability under the Credit Facility will increase to $75 million. The Company's lenders have indicated that the borrowing availability provided under the amended Credit Facility exceeded that which would otherwise have been made available under a more traditional conforming borrowing base calculation based on the estimated value of the Company's current net proved reserves and its cash flow. Borrowings under the Credit Facility in excess of $45 million are convertible into shares of Brigham common stock in the following amounts: (i) the first $10 million of borrowings is convertible at $3.90 per share, (ii) the second $10 million is convertible at $6.00 per share and (iii) the final $10 million is convertible at $8.00 per share. If the Credit Facility is repaid at maturity or is prepaid prior to maturity without payment of cash premiums, the warrants issued to the new lender of the Credit Facility to purchase Brigham common stock become exercisable. In addition, certain financial covenants of the Credit Facility have been amended or added. In connection with this most recent amendment, the Company reset the price of the warrants previously issued to its existing senior lenders to purchase one million shares of Brigham common stock from the then current exercise price of $2.25 per share to $2.02 per share. 28 Principal outstanding under the Credit Facility is due at maturity on December 31, 2002, with interest due monthly for base rate tranches or periodically as LIBOR tranches mature. The annual interest rate for borrowings under the Credit Facility is either the lender's base rate or LIBOR plus 3.00%, at the Company's option. The Company's obligations under the Credit Facility are secured by substantially all of the natural gas and oil properties and other tangible assets of the Company. At March 23, 2000, the Company had $58 million in borrowings outstanding under the Credit Facility, which bear interest at an annual rate of approximately 9.1%. See Note 5 of Notes to the Consolidated Financial Statements. The Credit Facility has certain financial covenants, including current and interest coverage ratios, as defined. The Company and its lenders effected the amendments to the Credit Facility in March 1999, July 1999 and February 2000, in part, to enable the Company to comply with certain financial covenants of the Credit Facility, including the minimum current ratio (as defined), minimum interest coverage ratio (as defined) and the limitation on capital expenditures related to seismic and land activities. Should the Company be unable to comply with certain of the financial or other covenants, its senior lenders may be unwilling to waive compliance or amend the covenants in the future. In such instance, the Company's liquidity may be adversely affected, which could in turn have an adverse impact on the Company's future financial position and results of operations. Subordinated Notes In August 1998, the Company issued $50 million of debt and equity securities to affiliates of Enron Corp. Securities issued by the Company in connection with this financing transaction included: (i) $40 million of Subordinated Notes, (ii) warrants to purchase one million shares of the Company's common stock at a price of $10.45 per share (the "Subordinated Note Warrants"), and (iii) 1,052,632 shares of the Company's common stock at a price of $9.50 per share. The approximate $47.5 million in net proceeds received by the Company from this financing transaction were used to repay a portion of outstanding borrowings under its senior credit facility, which at the time increased the Company's borrowing availability under its credit facility to fund capital expenditures. Principal outstanding under the Subordinated Notes is due at maturity on August 20, 2003. Interest on the Subordinated Notes is payable quarterly at rates that vary depending upon whether accrued interest is paid in cash or "in kind" through the issuance of additional Subordinated Notes. Interest is payable in cash at interest rates of 12%, 13% and 14% per annum during years one through three, year four and year five, respectively, of the term of the Subordinated Notes; provided, however, that the Company may pay interest in kind for a cumulative total of seven quarterly interest payments (potentially increasing to eight if certain conditions are met) at interest rates of 13%, 14% and 15% per annum during years one through three, year four and year five, respectively, of the term of the Subordinated Notes. As of March 23, 2000, the Company had made a cumulative total of five quarterly interest payments in kind and expects to make at least the next two quarterly interest payments (due May 2000 and August 2000) in kind. The Subordinated Notes rank subordinate in right of payment to Senior Indebtedness (as defined) and senior to all other financings (other than any allowed capital leases and purchase money financings) of the Company. The Subordinated Notes are secured by a second lien against substantially all of the natural gas and oil properties and other tangible assets of the Company. The Subordinated Notes may be prepaid at any time, in whole or in part, without premium or penalty, provided that all partial prepayments must be pro rata to the various holders of the Subordinated Notes. The Subordinated Notes were issued pursuant to an indenture (the "Indenture") that contains certain covenants that, among other things, limit the ability of the Company and its subsidiaries to incur additional indebtedness, pay dividends, make distributions, enter into certain sale and leaseback transactions, enter into certain transactions with affiliates, dispose of certain assets, incur liens, reborrow funds utilized to prepay the Senior Indebtedness and engage in most types of mergers and consolidations. In March 1999, the Company and Chase Bank of Texas, National Association, as trustee (the "Trustee") for the holders of the Subordinated Notes, entered into an amendment to the Indenture. This amendment provided the Company with the option to pay interest due on the Subordinated Notes in kind, for any reason, through the second quarter of 2000. In addition, certain financial and other covenants were amended. The amendment also provided for a reduction in the exercise price per share of the Subordinated Note Warrants from $10.45 per share to $3.50 per share and extended the term of the Subordinated Note Warrants from seven to ten years. 29 In February 2000, Brigham entered into another amendment to the terms of the Indenture. In this amendment, the holders of the Subordinated Notes agreed to waive the minimum consolidated interest coverage ratio covenant through June 30, 2000 and to adjust subsequent levels under this test. In addition, the amendment provides the Company with an extension of its right to pay interest in kind through the issuance of additional Subordinated Notes in lieu of cash through the third quarter of 2000 and potentially through the fourth quarter of 2000 if certain conditions are met. In exchange for granting these amendments, the Company has (i) reset the price of the Subordinated Note Warrants from a then current exercise price of $3.50 per share to $2.43 per share, and (ii) granted to the holders of the Subordinated Notes a term overriding royalty interest that provides for the limited right to receive 4%, or 3% if certain conditions are met, of the Company's net production revenue to reduce any outstanding Subordinated Notes issued as interest paid in-kind. The Indenture governing the Subordinated Notes has certain financial covenants, including current and interest coverage ratios, as defined. The Company and the holders of the Subordinated Notes effected the March 1999 and February 2000 amendments to the Indenture to enable the Company to comply with certain financial covenants of the Indenture, including the minimum current ratio and the minimum interest coverage ratio, as defined. Should the Company be unable to comply with certain of the financial covenants, the holders of the Subordinated Notes may be unwilling to waive compliance or amend the covenants in the future. In such instance, the Company's liquidity may be adversely affected, which could in turn have an adverse impact on the Company's future financial position and results of operations. At December 31, 1999 and March 23, 2000, the Company had $45.5 million and $46.9 million, respectively, principal amount of Subordinated Notes outstanding. Sales of Interests in Projects and Natural Gas and Oil Properties Duke Project Financing. In February 1999, the Company entered into a project financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund the continued exploration of five Anadarko Basin projects covered by approximately 200 square miles of 3-D seismic data acquired in 1998. In this transaction, the Company conveyed 100% of its working interest (land and seismic) in these project areas to a newly formed limited liability company (the "Duke LLC") for total consideration of $10 million. The Company is the managing member of the Duke LLC with a 1% interest, and Duke is the sole remaining member with a 99% interest. Pursuant to the terms of the Duke LLC agreement, Brigham pays 100% of the drilling and completion costs for all wells drilled by the Duke LLC within the designated project areas in exchange for a 70% working interest in the wells (and their allocable drilling and spacing units), with the remaining 30% working interest remaining in the Duke LLC, subject in each instance to proportionate reduction by any ownership rights held by third parties. Upon 100% project payout, the Company has the right to back-in for 80% of the Duke LLC's working interest in all of the then producing wells (and their allocable drilling and spacing units) and a 94% working interest in any wells (and their allocable drilling and spacing units) drilled after payout within the designated project areas governed by the Duke LLC agreement, thereby increasing the Company's effective working interest in the Duke LLC wells from 70% to 94%. The Company believes this project financing arrangement to be beneficial as it enabled Brigham to recoup substantially all of its pre-seismic land and seismic data acquisition costs incurred in these project areas and provided capital to fund the drilling of the first six wells within these projects. Mid-1999 Property Sales. In June 1999, Brigham sold certain producing and non-producing natural gas and oil properties located in its Anadarko Basin province to two separate parties for a total of $17.1 million. The divested properties were located in two fields operated by third parties - the Chitwood Field in Grady County, Oklahoma (originally acquired by the Company for $13.4 million in the Chitwood Acquisition in November 1997), and the Red Deer Creek Field in Roberts County, Texas. Brigham's independent reservoir engineers estimated net proved reserve volumes attributable to the properties as of June 1, 1999 of approximately 36 Bcfe, of which 33% were classified as proved developed producing reserves and 59% were natural gas. The Company estimated that net production volumes from the divested properties were 2.8 MMcfe per day at the time of the sales. The Company used the proceeds from these transactions to reduce borrowings under its credit facility, which contributed to provide the Company with $8 million in borrowing availability under its then existing credit facility that was used to fund working capital needs and capital expenditures during the second half of 1999. The effective date of each transaction was June 30, 1999. 30 Equity Placements Veritas Equity Issuances. On March 30, 1999, the Company entered into an agreement with Veritas DGC Land, Inc. to exchange 1,002,865 shares of newly issued Brigham common stock valued at $3.50 per share for approximately $3.5 million of payment obligations due to Veritas in 1999 for certain seismic acquisition and processing services previously performed. In addition, this agreement provided for the payment by Brigham of up to $1 million in future seismic processing services to be performed by Veritas in newly issued shares of Brigham common stock valued at $3.50 per share, in the event that the Company did not elect to pay for such services in cash. The settlement of these future seismic processing services was determined on a quarterly basis through September 30, 1999. Pursuant to this agreement, Brigham issued a total of 1,211,580 shares of common stock to Veritas to satisfy $4.2 million in aggregate payment obligations due to Veritas for seismic acquisition and processing services performed prior to 1999 and certain seismic processing services performed during 1999. Private Equity Placement. On February 22, 2000, Brigham entered into an agreement to issue 2,195,122 shares of common stock and 731,707 warrants to purchase common stock for total consideration of $4.5 million in a private placement to a group of institutional investors led by affiliates of two members of the Company's board of directors. The equity sale consisted of units that include one share of common stock priced at $2.0525 per share and one-third of a warrant to purchase Brigham common stock at an exercise price of $2.5625 per share with a three-year term. Pricing of this private equity placement was based on the average market price of Brigham common stock during a twenty trading day period prior to issuance. Net proceeds from this equity placement will be used to fund a portion of the Company's planned 2000 capital expenditures and working capital obligations. Cash Flow Analysis Cash Flows from Operating Activities. Cash flows provided by operating activities were $2.6 million in 1999, $14.8 million in 1998 and $9.8 million in 1997. The decrease in cash flows for 1999 compared to 1998 was primarily attributable to changes in working capital (a $5 million reduction in cash flow from working capital items in 1999 compared to an $11.9 million increase in cash flow from working capital items in 1998). The increase in cash flows for 1998 compared to 1997 was due primarily to an increase in natural gas and oil revenues, net of lease operating expenses, production taxes and general and administrative expenses, and net changes in working capital items. Cash Flows from Investing Activities. Cash flows provided by investing activities in 1999 were $1.6 million as compared to cash flows used by investing activities of $86.2 million in 1998 and $57.3 million in 1997. The increase in net cash flow from investing activities in 1999 was due to the combined effects of significantly reduced net capital expenditures and a total of $27.1 million of proceeds received from the sales of natural gas and oil properties, which consisted principally of the Company's mid-1999 producing property divestitures and its sales of promoted interests in certain 3-D seismic projects and drilling prospects in its Anadarko Basin and Gulf Coast regions. The decrease in cash flow from investing activities in 1998 were the direct result of an increase in capital expenditures related to the Company's exploration and development activities. Capital expenditures (before the application of net proceeds received from the sales of interests in projects) were $25.6 million in 1999, $85.2 million in 1998 and $57.2 million in 1997. After acquiring 1,227 gross (807 net) square miles of 3-D seismic in 1997 and 1,134 gross (920 net) square miles of 3-D seismic in 1998, the Company did not acquire any new 3-D seismic data during 1999. The Company's drilling efforts during the past three years resulted in the completion of 19 (6.3 net) wells in 1999, 50 (26.3 net) wells in 1998, and 45 (17.6 net) wells in 1997, which contributed to aggregate net increases in proved reserve volumes (net of revisions to previous estimates) of 28.7 Bcfe in 1999, 31.2 Bcfe in 1998 and 32.4 Bcfe in 1997. In addition, the Company sold interests in certain producing and non-producing properties in 1999 for a total of $27.1 million, and it acquired certain producing properties and related interests for $1 million in 1998 and $13.5 million in 1997. 31 Cash Flows from Financing Activities. Cash flows used by financing activities in 1999 were $4.1 million, principally due to the net repayment of borrowings outstanding under the Company's credit facility and the payment of deferred loan fees. Cash flows provided by financing activities in 1998 were $72.3 million, primarily as a result of borrowings under the Company's credit facility, the issuance of the Subordinated Notes and the sale of $10 million of common stock. Cash flows from financing activities for 1997 were $47.7 million, primarily as a result of borrowings under the Company's credit facility and proceeds from the common stock sold in the Company's initial public offering. Capital Expenditures Continuing its strategy implemented during 1999, Brigham intends to focus substantially all of its efforts and available capital resources in 2000 to the drilling and monetization of its highest grade prospects within its over 5,000 square mile inventory of 3-D seismic data. The Company's current 2000 capital expenditure budget is estimated to be $25 million, which includes approximately $20 million for drilling projects and $5 million for non-drilling activities (primarily acreage acquisition and capitalized overhead costs). Brigham's planned 2000 drilling program consists of a balanced blend of exploration and development drilling projects with approximately 54% of budgeted drilling expenditures targeted for exploratory prospects, 28% for development locations and the remaining 18% for development locations that are contingent upon drilling success during the year. In addition, the Company's 2000 budgeted drilling expenditures have been allocated approximately 75% to its Gulf Coast province and 25% to its Anadarko Basin province, concentrated within trends where the Company has experienced exploration success to date. The Company intends to fund these budgeted capital expenditures through a combination of cash flow from operations, available borrowings under its senior credit facility and the proceeds from its February 2000 private equity placement. Additionally, the Company intends to supplement its available capital resources through selective sales of interests in non-producing assets, including interests in its 3-D seismic projects and promoted interests in future drilling prospects or locations. See "Item 2. Properties -- Primary Exploration Provinces." Due to the Company's active exploration and development activities, Brigham has experienced and expects to continue to experience substantial working capital requirements. While the Company believes that cash flow from operations and borrowings under its senior credit facility should allow the Company to finance its planned operations through 2000 based on current conditions and expectations, additional financing will be required in the future to fund the Company's exploration and development activities. In the event additional financing is not available, the Company may be required to curtail or delay its planned activities. Other Matters Hedging Activities The Company believes that hedging, although not free of risk, allows the Company to reduce its exposure to natural gas and oil sales price fluctuations and thereby to achieve more predictable cash flows. However, hedging arrangements, when utilized, limit the benefit to the Company of increases in the prices of the hedged commodity. Moreover, the Company's hedging arrangements apply only to a portion of its production and provide only partial price protection against declines in commodity prices. The Company expects that the amount of its hedges will vary from time to time. See "-- Risk Factors -- Our Hedging Transactions May Not Prevent Losses" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." In 1998, Brigham began using natural gas swap arrangements in an attempt to reduce its sensitivity to volatile commodity prices as its production base became increasingly weighted toward natural gas. Pursuant to these arrangements the Company exchanges a floating market price for a fixed contract price. Payments are made by the Company when the floating price exceeds the fixed price for a contract month and payments are received by the Company when the fixed price exceeds the floating price. Settlements of these swaps are based on the difference between regional market index prices for a contract month and the fixed contract price for the same month. Total natural gas purchased and sold subject to swap arrangements entered into by the Company was 2,750,000 MMBtu in 1998 and 5,025,000 MMBtu in 1999. The Company accounted for substantially all of these transactions as hedging activities and, accordingly, adjusted the price received for natural gas and oil production during the period the hedged transactions occurred. Adjustments to the price received for natural gas under these swap arrangements resulted in an increase in natural gas revenues of $555,000 in 1998 and a decrease in natural gas revenues of $486,000 in 1999. 32 In September 1999, Brigham sold call options on a portion of its future oil and natural gas production. The Company applied the proceeds from the sale of these call options to increase the effective fixed swap price on its then existing natural gas hedging contracts during the months of October 1999 through January 2000 by an average of $0.57 per MMBtu. For accounting purposes, the improvement in the Company's fixed natural gas swap price attributable to these transactions is not reflected in reported revenues. Rather, it is reflected in (i) other income (expense) on the income statement, and (ii) amortization of deferred loss on derivatives instruments and market value adjustment for derivatives instruments on the cash flow statement. The following tables summarize the Company's outstanding natural gas and oil hedging arrangements as of March 23, 2000: Natural Gas Hedges
2000 2001 2002 ------------------------ --------------------- --------------------- Average Average Average Volumes Contract Volumes Contract Volumes Contract Monthly Hedged Price Hedged Price Hedged Price Pricing Basis Contract Term (MMBtu) ($/MMBtu) (MMBtu) ($/MMBtu) (MMBtu) ($/MMBtu) ------------- ------------- ------- --------- ------- --------- ------- --------- Fixed Price Swaps: Contract #1 ANR November 1999 - 2,740,000 $2.1690 600,000 $2.0650 -- -- Oklahoma April 2001 Contract #2 Houston April 2000 - 1,375,000 $2.1500 600,000 $2.1500 -- -- Ship Channel April 2001 Contract #3 TETCO April 2000 - 1,375,000 $2.0575 600,000 $2.0575 -- -- South Texas April 2001 Fixed Price Cap ANR May 2001 - -- -- 2,450,000 $2.5498 1,810,000 $2.6326 Oklahoma June 2002 Fixed Price Floor ANR May 2001 - -- -- 765,000 $1.8000 -- -- Oklahoma December 2001
Crude Oil Hedges
2000 2001 2002 ---------------------- ---------------------- -------------------- Average Average Average Volumes Contract Volumes Contract Volumes Contract Monthly Hedged Price Hedged Price Hedged Price Pricing Basis Contract Term (Bbls) ($/Bbl) (Bbls) ($/Bbl) (Bbls) ($/Bbl) ------------- ------------- ------ ------- ------ ------- ------ ------- Fixed Price Cap NYMEX October 1999 - 219,600 $27.40 109,200 $26.15 -- -- December 2001 Fixed Price Floor NYMEX March 2000 - 183,600 $18.00 109,200 $17.36 -- -- December 2001
33 Effects of Inflation and Changes in Prices The Company's results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that the Company is required to bear for operations. Inflation has had a minimal effect on the Company. Environmental and Other Regulatory Matters The Company's business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of natural gas and oil, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect the Company's financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to the Company, compliance has not had a material adverse effect on the earnings or competitive position of the Company. Future regulations may add to the cost of, or significantly limit, drilling activity. See "-- Risk Factors - -- We Are Subject To Various Governmental Regulations And Environmental Risks," "Item 1. Business -- Governmental Regulation" and "Item 1. Business -- Environmental Matters." Year 2000 Issue The Company has initially incurred no significant problems related to the Year 2000 issue. However, the Company has not yet fully utilized all functions and processes of its systems and accordingly cannot be sure that all its systems will be free of Year 2000 issues. Also, the Company has no assurance that its critical business partners, governmental agencies or other key third parties have not incurred Year 2000 issues that may affect the Company. Recent Accounting Pronouncements In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Company must adopt SFAS No. 133, as amended by SFAS No. 137, effective January 1, 2001. The Company is currently assessing the impact adoption of this standard will have on its financial statement presentation. Forward Looking Information Brigham or its representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and gas production, the number of wells the Company anticipates drilling through 2000 and the Company's financial position, business strategy and other plans and objectives for future operations. Although the Company believes that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by the Company will be realized or, even if substantially realized, that they will have the expected effects on its business or operations. Among the factors that could cause actual results to differ materially from the Company's expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and gas prices, availability of sufficient capital resources to the Company and its project participants, government regulations and other factors set forth among the risk factors noted below or in the description of the Company's business in Item 1 of this report. All subsequent oral and written forward looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these factors. The Company assumes no obligation to update any of these statements. 34 Risk Factors We Are Substantially Leveraged Our outstanding long-term debt was $101.5 million (principal amount) as of December 31, 1999. The indenture governing our senior subordinated secured notes limits the amounts of additional debt borrowings, including borrowings under our senior credit facility or other senior indebtedness. However, the indenture permits us to borrow under our senior credit facility up to the lesser of $75 million or the loan commitments under the facility ($70 million as of March 23, 2000). We had $58 million of borrowings outstanding under our senior credit facility as of March 23, 2000. Our level of indebtedness will have several important effects on our operations, including those listed below. o We will dedicate a substantial portion of our cash flow from operations to the payment of interest on our indebtedness and will not have these cash flows available for other purposes. o The covenants in our senior credit facility and the indenture limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions. o Our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. We may also be required to alter our capitalization significantly to accommodate future exploration, development or acquisition activities. These changes in capitalization may significantly alter our leverage and dilute the equity interests of existing stockholders. Our ability to meet our debt service obligations and to reduce our total indebtedness will be dependent upon our future performance, which will be subject to general economic conditions and to financial, business and other factors affecting our operations, many of which are beyond our control. We cannot assure you that our future performance will not be harmed by such economic conditions and financial, business and other factors. See " -- Liquidity and Capital Resources." We Have Substantial Capital Requirements We make and will continue to make substantial capital expenditures in our exploration and development projects. While we believe that our cash flow from operations and borrowings under our credit facility should allow us to finance our planned operations through 2000 based on current conditions and expectations, additional financing will be required in the future to fund our exploration and development activities. We cannot assure you that we will be able to secure additional financing on reasonable terms or at all, or that financing will continue to be available to us under our existing or new financing arrangements. Without additional capital resources, our drilling and other activities may be limited and our business, financial condition and results of operations may suffer. See " -- Liquidity and Capital Resources." Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are Volatile Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our oil and natural gas production. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Market prices of oil and natural gas depend on many factors beyond our control, including: o worldwide and domestic supplies of oil and natural gas; o the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; o political instability or armed conflict in oil-producing regions; o the price and level of foreign imports; 35 o the level of consumer demand; o the price and availability of alternative fuels; o the availability of pipeline capacity; o weather conditions; o domestic and foreign governmental regulations and taxes; and o the overall economic environment. We cannot predict future oil and natural gas price movements with certainty. During 1999, the high and low prices for oil on the NYMEX were $27.07 per Bbl and $11.37 per Bbl, and the high and low prices for natural gas on the NYMEX were $3.09 per MMBtu and $1.63 per MMBtu. Significant declines in oil and natural gas prices for an extended period may have the following effects on our business: o limit our financial condition, liquidity, ability to finance planned capital expenditures and results of operations; o reduce the amount of oil and natural gas that we can produce economically; o cause us to delay or postpone some of our capital projects; o reduce our revenues, operating income and cash flow; and o reduce the carrying value of our oil and natural gas properties. Our Hedging Transactions May Not Prevent Losses In an attempt to reduce our sensitivity to energy price volatility, we use swap and collar hedging arrangements that generally result in a fixed price or a range of minimum and maximum price limits over a specified monthly time period. If we do not produce our oil and natural gas reserves at rates equivalent to our hedged position, we would be required to satisfy our obligations under hedging contracts on potentially unfavorable terms without the ability to hedge that risk through sales of comparable quantities of our own production. Because the terms of our hedging contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation and marketing costs to delivery points, substantial differences between the hedged prices and actual results could harm our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and natural gas prices. Hedging contracts limit the benefits we will realize if actual prices rise above the contract prices. We could be financially harmed if the other party to the hedging contracts proves unable or unwilling to perform its obligations under such contracts. See " -- Other Matters -- Hedging Activities" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." 36 Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are Dependent On Exploratory Drilling Activities Our revenues, operating results and future rate of growth depend highly upon the success of our exploratory drilling program. Exploratory drilling involves numerous risks, including the risk that we will not encounter commercially productive natural gas or oil reservoirs. We cannot always predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: o unexpected drilling conditions; o pressure or irregularities in formations; o equipment failures or accidents; o adverse weather conditions; o compliance with governmental requirements; and o shortages or delays in the availability of drilling rigs and the delivery of equipment. We may not be successful in our future drilling activities because even with the use of 3-D seismic and other advanced technologies, exploratory drilling is a speculative activity. We could incur losses because our use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies. Even when fully utilized and properly interpreted, our 3-D seismic data and other advanced technologies only assist us in identifying subsurface structures and do not indicate whether hydrocarbons are in fact present in those structures. Because we interpret the areas desirable for drilling from 3-D seismic data gathered over large areas, we may not acquire option and lease rights until after the seismic data is available and, in some cases, until the drilling locations are also identified. Although we have identified numerous potential drilling locations, we cannot assure you that we will ever lease, drill or produce oil or natural gas oil from these or any other potential drilling locations. We cannot assure you that we will be successful in our drilling activities, that our overall drilling success rate for activity within a particular province will not decline, or that our completed wells will ultimately produce our estimated economically recoverable reserves. Unsuccessful drilling activities could materially harm our operations and financial condition. We Are Subject To Various Casualty Risks Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as: o fires; o natural disasters; o formations with abnormal pressures; o blowouts, cratering and explosions; and o pipeline ruptures and spills. Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. See "Item 1. Business -- Operating Hazards and Uninsured Risks." 37 We May Not Have Enough Insurance To Cover Some Operating Risks We maintain insurance coverage against some, but not all, potential losses in order to protect against operating hazards. We may elect to self-insure if our management believes that the cost of insurance, although available, is excessive relative to the risks presented. We generally maintain insurance for the hazards and risks inherent in drilling for and producing and transporting oil and natural gas and believe this insurance is adequate. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition and results of operations. In addition, we cannot fully insure against pollution and environmental risks. The Marketability Of Our Production Is Dependent On Facilities That We Typically Do Not Own Or Control The marketability of our production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own. Our ability to produce and market oil and natural gas could be harmed by any dramatic change in market factors or by: o federal and state regulation of oil and natural gas production and transportation; o tax and energy policies; o changes in supply and demand; and o general economic conditions. We Have Historical Operating Losses And Our Future Results May Vary; We Have Incurred Net Losses In Each Year Of Operation We cannot assure you that we will be profitable in the future. At December 31, 1999, we had an accumulated deficit of $55 million and total stockholders' equity of $9 million. We have recognized the following annual net losses since 1995: $1.6 million in 1995, $450,000 in 1996, $1.1 million (including a net $1.2 million non-cash deferred income tax charge incurred in connection with our conversion from a partnership to a corporation) in 1997, $33.3 million (including a $25.9 million non-cash writedown in the carrying value of our natural gas and oil properties) in 1998, and $21.6 million (including a $12.2 million non-cash loss on the sale of natural gas and oil properties) in 1999. See "Item 6. Selected Financial Data." Our Future Operating Results May Fluctuate Our future operating results may fluctuate significantly depending upon a number of factors, including: o industry conditions; o prices of oil and natural gas; o rates of drilling success; o capital availability; o rates of production from completed wells; and o the timing and amount of capital expenditures. This variability could cause our business, financial condition and results of operations to suffer. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our ability to invest and participate in economically attractive projects. 38 Maintaining Reserves And Revenues In The Future Depends On Successful Exploration And Development In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production depends highly upon our ability to economically find, develop or acquire reserves in commercial quantities. The business of exploring for or developing reserves is capital intensive. Reductions in our cash flow from operations and limitations on or unavailability of external sources of capital may impair our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves. In addition, we cannot be certain that our future exploration and development activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Furthermore, although significant increases in prevailing prices for oil and natural gas could cause increases in our revenues, our finding and development costs could also increase. Finally, we participate in a percentage of our wells as a non-operator. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could harm us. We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows There is substantial uncertainty in estimating quantities of proved reserves and projecting future production rates and the timing of development expenditures. No one can measure underground accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve engineering requires subjective estimations of those accumulations. Estimates of other engineers might differ widely from those of our independent petroleum engineers. Accuracy of reserve estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Our independent petroleum engineers may make material changes to reserve estimates based on the results of actual drilling, testing, and production. As a result, our reserve estimates often differ from the quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. See "Item 2. Properties -- Natural Gas and Oil Reserves." Actual future net cash flows from our oil and natural gas properties also will be affected by factors such as: o the amount and timing of actual production; o supply and demand for oil and natural gas; o limits or increases in consumption by gas purchasers; and o changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the SEC reporting requirements may not necessarily be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. 39 We Face Significant Competition We operate in the highly competitive areas of oil and natural gas exploration, exploitation, acquisition and production with other companies. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent oil and natural gas companies in a number of areas such as: o seeking to acquire desirable producing properties or new leases for future exploration; o marketing our oil and natural gas production; and o seeking to acquire the equipment and expertise necessary to operate and develop those properties. Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could harm our business. See "Item 1. Business-- Competition." We Are Subject To Various Governmental Regulations And Environmental Risks Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Although we believe we are in substantial compliance with all applicable laws and regulations, legal requirements are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. Our operations are subject to complex environmental laws and regulations adopted by federal, state and local governmental authorities. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm us. The discharge of natural gas, oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation. We cannot be certain that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our results of operations and financial condition. See "Item 1. Business -- Governmental Regulation; and -- Environmental Matters." Our Business May Suffer If We Lose Key Personnel We have assembled a team of geologists, geophysicists and engineers who have considerable experience in applying 3-D imaging technology to explore for and to develop oil and natural gas. We depend upon the knowledge, skills and experience of these experts to provide 3-D imaging and to assist us in reducing the risks associated with our participation in oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management, particularly Ben M. Brigham, our Chief Executive Officer, President and Chairman of the Board. We have an employment agreement with Ben M. Brigham, but do not have an employment agreement with any of our other employees. We have key man life insurance on Mr. Brigham in the amount of $2 million. If we lose the services of our key management personnel or technical experts, or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We cannot assure you that we will be successful in attracting and retaining such executives, geophysicists, geologists and engineers. See "Item 1. Business -- Technical Staff" and "Executive Officers of the Registrant." Control By Certain Stockholders And Certain Anti-Takeover Provisions May Affect You; Certain Of Our Affiliates Control A Majority Of The Outstanding Common Stock As of March 23, 2000, our directors, executive officers and principal stockholders, and certain of their affiliates, beneficially owned approximately 53% of our outstanding common stock. Accordingly, these stockholders, as a group, will be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws, and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership concentrated in a few persons makes it unlikely that any other holder of common stock will be able to affect our management or direction. These factors may also have the effect of delaying or preventing a change in our management or voting control. 40 Certain Anti-Takeover Provisions May Affect Your Rights As A Stockholder Our certificate of incorporation authorizes our Board of Directors to issue up to 10 million shares of preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights, of those shares as the Board of Directors may determine. These provisions, alone or in combination with the other matters described in the preceding paragraph may discourage transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock. We are also subject to provisions of the Delaware General Corporation Law that may make some business combinations more difficult. The Market Price Of Our Stock Price Is Volatile The trading price of our common stock and the price at which we may sell securities in the future is subject to large fluctuations in response to any of the following: limited trading volume in our stock, changes in government regulations, quarterly variations in operating results, our involvement in litigation, general market conditions, the prices of oil and natural gas, announcements by us and our competitors, our liquidity, our ability to raise additional funds and other events. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Management Opinion Concerning Derivative Instruments The Company limits its use of derivative instruments principally to commodity price hedging activities, whereby gains and losses are generally offset by price changes in the underlying commodity. As a result, management believes that its use of derivative instruments does not expose the Company to material risk. The Company's use of derivative instruments for hedging activities could materially affect the Company's results of operations in particular quarterly or annual periods since such instruments can limit the Company's ability to benefit from favorable oil and natural gas price movements. However, management believes that use of these instruments will not have a material adverse effect on the Company's financial position or liquidity. Commodity Price Risk The Company's primary commodity market risk exposure is to changes in the prices related to the sale of its oil and natural gas production. The market prices for oil and natural gas have been volatile and are likely to continue to be volatile in the future. As such, the Company employs established policies and procedures to manage its exposure to fluctuations in the sales prices it receives for its oil and natural gas production through hedging activities. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Matters -- Hedging Activities." The Company believes that hedging, although not free of risk, allows the Company to reduce its exposure to oil and natural gas sales price fluctuations and thereby to achieve more predictable cash flows. However, hedging arrangements, when utilized, limit the benefit to the Company of increases in the prices of the hedged commodity. Moreover, the Company's hedging arrangements apply only to a portion of its production and provide only partial price protection against declines in commodity prices. The Company expects that the amount of its hedges will vary from time to time. Based on the Company's oil and natural gas hedging arrangements outstanding at March 23, 2000, an adverse change (defined as a hypothetical 10% and 25% increase in underlying commodity prices for open positions) would reduce cash flow by approximately $3.3 million and $8.8 million, respectively, from currently projected levels. Additionally, as the Company utilizes swap and collar arrangements to hedge anticipated and firmly committed transactions, a loss in fair value for those instruments is generally offset by price changes in the underlying commodity. The impact of these price changes is not reflected in this sensitivity analysis. 41 Interest Rate Risk The Company is subject to interest rate risk as borrowings under its senior credit facility ($58 million outstanding as of March 23, 2000) accrue interest at floating rates based on the lender's base rate or LIBOR. The Company does not utilize derivative instruments to protect against changes in interest rates on debt borrowings. See Note 9 of Notes to Consolidated Financial Statements for a description of the Company's financial instruments at December 31, 1999. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Company's Consolidated Financial Statements and the Financial Statements of Certain of the Company's Subsidiaries required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F1-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to information under the caption "Proposal 1 - Election of Directors" and to the information under the caption "Compliance with Section 16(a) of the Securities Exchange Act of 1934" in the Company's definitive Proxy Statement (the "2000 Proxy Statement") for its annual meeting of stockholders to be held on May 18, 2000. The 2000 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 1999. Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to executive officers of the Company is set forth in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to the 2000 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1999. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 2000 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1999. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to the 2000 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1999. 42 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Consolidated Financial Statements: See Index to Financial Statements on page F1-1. 2. Financial Statement Schedules: See Index to Financial Statements on page F1-1. 3. Exhibits: The following documents are filed as exhibits to this report: Number Description - ------ ----------- 2.1 Exchange Agreement (filed as Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 3.1 Certificate of Incorporation (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 3.2 Bylaws (filed as Exhibit 3.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 4.1 Form of Common Stock Certificate (filed as Exhibit 4.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 4.2 Indenture dated as of August 20, 1998 between Brigham Exploration Company and Chase Bank of Texas, National Association, as Trustee (filed as Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 4.2.1 Supplemental Indenture dated as of March 26, 1999 between Brigham Exploration Company and Chase Bank of Texas, National Association, as Trustee (filed as Exhibit 4.2.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 4.3 Form of Warrant Certificate (filed as Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 4.4 Form of Senior Subordinated Secured Note due 2003 (filed as Exhibit 4.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.1 Agreement of Limited Partnership, dated May 1, 1992, between Brigham Exploration Company and General Atlantic Partners III, L.P. as general partners, and Harold D. Carter and GAP-Brigham Partners, L.P. as limited partners (filed as Exhibit 10.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.1.1 Amendment No. 1 to Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated May 1, 1992, by and among Brigham Exploration Company, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P. and Harold D. Carter (filed as Exhibit 10.1.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.1.2 Amendment No. 2 to Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated September 30, 1994, by and among Brigham Exploration Company, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., Harold D. Carter and the additional signatories thereto (filed as Exhibit 10.1.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 43 10.1.3 Amendment No. 3 to Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated August 24, 1995, by and among Brigham Exploration Company, General Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., Harold D. Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.1.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.1.4 Amended and Restated Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated December 30, 1997 by and among Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings II, L.L.C. (filed as Exhibit 10.1.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference) 10.2 Agreement of Limited Partnership of Venture Acquisitions, L.P., dated September 23, 1994, by and between Quest Resources, L.L.C. and RIMCO Energy, Inc. as general partners, and RIMCO Production Company, Inc., RIMCO Exploration Partners, L.P. I and RIMCO Exploration Partners, L.P. II, as limited partners (filed as Exhibit 10.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.3 Regulations of Quest Resources, L.L.C. (filed as Exhibit 10.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.4 Management and Ownership Agreement, dated September 23, 1994, by and among Brigham Oil & Gas, L.P., Brigham Exploration Company, General Atlantic Partners III, L.P., Harold D. Carter, Ben M. Brigham and GAP-Brigham Partners, L.P. (filed as Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.5* Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit 10.4 to the Company's Registration Statement on Form S-1 (Registration No. 33-53873), and incorporated herein by reference). 10.5.1*+Letter agreement, dated as of March 20, 2000, setting forth amendments effective January 1, 2000, to the Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter. 10.6* Employment Agreement, by and between Brigham Exploration Company and Ben M. Brigham (filed as Exhibit 10.7 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.7* Form of Confidentiality and Noncompete Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.8 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.8* 1997 Incentive Plan of Brigham Exploration Company (filed as Exhibit 10.9 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.8.1* Form of Option Agreement for certain executive officers (filed as Exhibit 10.9.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.8.2* Option Agreement dated as of March 4, 1997, by and between Brigham Exploration Company and Jon L. Glass (filed as Exhibit 10.9.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.9* Incentive Bonus Plan dated as of February 28, 1997 of Brigham, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.10 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 44 10.10 Two Bridgepoint Lease Agreement, dated September 30, 1996, by and between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.10.1 First Amendment to Two Bridge Point Lease Agreement dated April 11, 1997 between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.10.2 Second Amendment to Two Bridge Point Lease Agreement dated October 13, 1997 between Investors Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.10.3 Letter dated April 17, 1998 exercising Right of First Refusal to Lease "3rd Option Space" (filed as Exhibit 10.9.3 to the Company's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.10.4+Sublease agreement dated as of November 16, 1999, by and between Brigham Oil & Gas, L.P., and ShowSupport.com, Inc. 10.11 Anadarko Basin Seismic Operations Agreement, dated February 15, 1996, by and between Brigham Oil & Gas, L.P. and Veritas Geophysical, Ltd. (filed as Exhibit 10.15 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.11.1 Letter Amendment to Anadarko Basin Seismic Operations Agreement, dated June 10, 1996, between Brigham Oil & Gas, L.P. and Veritas Geophysical, Ltd. (filed as Exhibit 10.15.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.12 Expense Allocation and Participation Agreement, dated April 1, 1996, between Brigham Oil & Gas, L.P. and Gasco Limited Partnership. (filed as Exhibit 10.16 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.12.1 Amendment to Expense Allocation and Participation Agreement, dated October 21, 1996, between Brigham Oil & Gas, L.P. and Gasco Limited Partnership (filed as Exhibit 10.16.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.13 Expense Allocation and Participation Agreement, dated April 1, 1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.13.1 Amendment to Expense Allocation and Participation Agreement, dated September 26, 1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.13.2 Letter Amendment to Expense Allocation and Participation Agreement, dated May 20, 1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.14 Anadarko Basin Joint Participation Agreement, dated May 1, 1996, by and among Stephens Production Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.18 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.15 Anadarko Basin Joint Participation Agreement, dated May 1, 1996, by and between Vintage Petroleum, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.19 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 45 10.16 Processing Alliance Agreement, dated July 20, 1993, between Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.20 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.16.1 Letter Amendment to Processing Alliance Agreement, dated November 3, 1994, between Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.20.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.17 Agreement and Assignment of Interest, West Bradley Project, dated September 1, 1995, by and between Aspect Resources Limited Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.21 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.18 Agreement and Assignment of Interests in lands located in Grady County, Oklahoma, West Bradley Project, dated December 1, 1995, by and between Aspect Resources Limited Liability Company, Brigham Oil & Gas, L.P. and Venture Acquisitions, L.P. (filed as Exhibit 10.22 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.19 Agreement and Assignment of Interests, West Bradley Project, dated December 1, 1995, by and between Aspect Resources Limited Liability Company and Brigham Oil & Gas, L.P. (filed as Exhibit 10.23 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.20 Geophysical Exploration Agreement, Hardeman Project, Hardeman and Wilbarger Counties, Texas and Jackson County, Oklahoma, dated March 15, 1993 by and among General Atlantic Resources, Inc., Maynard Oil Company, Ruja Muta Corporation, Tucker Scully Interests Ltd., JHJ Exploration, Ltd., Cheyenne Petroleum Company, Antrim Resources, Inc., and Brigham Oil & Gas, L.P. (filed as Exhibit 10.24 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.21 Agreement and Partial Assignment of Interests in OK13-P Prospect Area, Jackson County, Oklahoma (Hardeman Project), dated August 1, 1995, by and between Brigham Oil & Gas, L.P. and Aspect Resources Limited Liability Company (filed as Exhibit 10.25 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.22 Agreement and Partial Assignment of Interests in Q140-E Prospect Area, Hardeman County, Texas (Hardeman Project), dated August 1, 1995, by and between Brigham Oil & Gas, L.P. and Aspect Resources Limited Liability Company (filed as Exhibit 10.26 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.23 Agreement and Partial Assignment of Interests in Hankins #1 Chappel Prospect Agreement, Jackson County, Oklahoma (Hardeman Project), dated March 21, 1996, by and between Brigham Oil & Gas, L.P., NGR, Ltd. and Aspect Resources Limited Liability Company (filed as Exhibit 10.27 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.24 Form of Indemnity Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.28 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.25 Registration Rights Agreement dated February 26, 1997 by and among Brigham Exploration Company, General Atlantic Partners III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II, RIMCO Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M. Brigham, Anne L. Brigham, Harold D. Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.29 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 46 10.26 1997 Director Stock Option Plan (filed as Exhibit 10.30 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.27 Form of Employee Stock Ownership Agreement (filed as Exhibit 10.31 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.28 Agreement and Assignment of Interest in Geophysical Exploration Agreement, Esperson Dome Project, dated November 1, 1994, by and between Brigham Oil & Gas, L.P. and Vaquero Gas Company (filed as Exhibit 10.33 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.29 Geophysical Exploration Agreement, Southwest Danbury Project, Brazoria County, Texas, dated as of July 1, 1996, by and among UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.34 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.30 Geophysical Exploration Agreement, Welder Project, Duval County, Texas, dated as of October 1, 1996, by and among UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.35 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.31 Proposed Trade Structure, RIMCO/Tigre Project, Vermillion Parish, Louisiana, among Brigham Oil & Gas, L.P., Tigre Energy Corporation and Resource Investors Management Company (filed as Exhibit 10.36 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.31.1 Letter relating to Proposed Trade Structure, RIMCO/Tigre Project, dated January 31, 1997, from Resource Investors Management Company to Brigham Oil & Gas, L.P. (filed as Exhibit 10.36 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.31.2+Agreement dated March 6, 2000 by and between RIMCO Production Co., Tigre Energy Corporation and Brigham Oil & Gas, L.P. regarding modifications to the Proposed Trade Structure, RIMCO/Tigre Project, dated January 31, 1997. 10.32 Anadarko Basin Seismic Operations Agreement II, dated as of April 1, 1997, by and between Brigham Oil & Gas, L.P. (filed as Exhibit 10.37 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.32.1 Letter Amendment to Anadarko Basin Seismic Operations Agreement II, dated March 20, 1997, between Brigham Oil & Gas, L.P. and Veritas DGC Land, Inc. (filed as Exhibit 10.37 to the Company's Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference). 10.33 Expense Allocation and Participation Agreement II, dated April 1, 1997, between Brigham Oil & Gas, L.P., and Gasco Limited Partnership (filed as Exhibit 10.31 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and incorporated herein by reference). 10.36 Credit Agreement dated as of January 26, 1998 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated herein by reference). 10.36.1 First Amendment to Credit Agreement dated as of August 20, 1998 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.36.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.36.2 Second Amendment to Credit Agreement dated as of March 26, 1999 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.36.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 47 10.37 Guaranty Agreement dated January 26, 1998 by Brigham Exploration Company in favor of Bank of Montreal, as Agent, and each of the Lenders party to the Credit Agreement (filed as Exhibit 10.33.1 to the Company's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.37.1 First Amendment to Guaranty Agreement dated as of March 30, 1998 between Brigham Exploration Company and Bank of Montreal, as Agent for the Lenders party to the Credit Agreement (filed as Exhibit 10.33.2 to the Company's Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by reference). 10.37.2 Second Amendment to Guaranty Agreement dated as of August 20, 1998 between Brigham Exploration Company and Bank of Montreal, as Agent for the Lenders party to the Credit Agreement (filed as Exhibit 10.37.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.37.3 Third Amendment to Guaranty Agreement dated as of March 26, 1999 between Brigham Exploration Company and Bank of Montreal, as Agent for the Lenders party to the Credit Agreement (filed as Exhibit 10.37.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.38 Securities Purchase Agreement dated as of August 20, 1998 among Brigham Exploration Company, Enron Capital & Trade Resources Corp. and Joint Energy Development Investments II Limited Partnership (filed as Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.39 Registration Rights Agreement dated as of August 20, 1998, by and among Brigham Exploration Company, Enron Capital & Trade Resources Corp. and Joint Energy Development Investments II Limited Partnership (filed as Exhibit 10.39 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.39.1 Amendment to Registration Rights Agreement dated as of March 26, 1999, by and among Brigham Exploration Company, Enron Capital & Trade Resources Corp., ECT Merchant Investments Corp. and Joint Energy Development Investments II Limited Partnership (filed as Exhibit 10.39.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.40 Form of Guaranty for subsidiaries (filed as Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.41 Exchange Agreement dated as of March 30, 1999 by and between Brigham Exploration Company and Veritas DGC Land, Inc. (filed as Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.42 Registration Rights Agreement dated as of March 30, 1999 by and between Brigham Exploration Company and Veritas DGC Land, Inc. (filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, and incorporated herein by reference). 10.43 Third Amendment to Credit Agreement dated as of July 19, 1999 among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders signatory thereto (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended July 31, 1999 and incorporated by reference herein). 48 10.44 Fourth Amendment to Guaranty Agreement dated as of July 19, 1999 between Brigham Exploration Company and Bank of Montreal, as Agent for the lenders party to the Credit Agreement (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended July 31, 1999 and incorporated by reference herein). 10.45* Agreement dated as of August 16, 1999 between Brigham Exploration Company and Jon L. Glass for the amendment of an Employee Stock Ownership Agreement and Option Agreements (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.46* Agreement dated as of August 16, 1999 between Brigham Exploration Company and Craig M. Fleming for the amendment of an Employee Stock Ownership Agreement and Option Agreement (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.47 Form Change of Control Agreement dated as of September 20, 1999 between Brigham Exploration Company and certain Officers (filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.48 Warrant Agreement for the Purchase of Common Stock dated as of July 19, 1999 by and between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.49 Warrant Agreement for the Purchase of Common Stock dated as of July 19, 1999 by and between Brigham Exploration Company and Societe Generale, Southwest Agency (filed as Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and incorporated by reference herein). 10.50 Amended and Restated Credit Agreement dated as of February 17, 2000 among Brigham Oil & Gas, L.P., as Borrower, Bank of Montreal, as Agent, and the Lenders signatory thereto (filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed February 29, 2000, and incorporated herein by reference). 10.51 Amended and Restated Guaranty Agreement dated as of February 17, 2000 by Brigham Exploration Company in favor of Bank of Montreal, as Agent, and each of the Lenders party to the Amended and Restated Credit Agreement (filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.52 Partial Assignment of Notes dated as of February 17, 2000 by and among (i) Bank of Montreal, (ii) Societe Generale, Southwest Agency, (iii) Shell Capital Inc., and (iv) Brigham Oil & Gas, L.P. (filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.53 First Amendment to Warrant Agreement dated as of February 17, 2000 between Brigham Exploration Company and Bank of Montreal (filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.54 First Amendment to Warrant Agreement dated as of February 17, 2000 between Brigham Exploration Company and Societe Generale, Southwest Agency (filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.55 Equity Conversion Agreement dated as of February 17, 2000 by and among Brigham Oil & Gas, L.P., Brigham Exploration Company and Shell Capital Inc. and its successors and assigns (filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.56 Warrant Agreement dated as of February 17, 2000 by and between Brigham Exploration Company and Shell Capital Inc. (filed as Exhibit 10.7 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 49 10.57 Registration Rights Agreement dated as of February 17, 2000 by and between Brigham Exploration Company and Shell Capital Inc. (filed as Exhibit 10.8 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.58 Letter dated as of February 17, 2000 regarding certain fees pursuant to Credit Agreement dated as of February 17, 2000, among Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, Shell Capital Inc. and the lenders signatory thereto (filed as Exhibit 10.9 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.59 Second Amendment to Intercreditor and Subordination Agreement dated as of February 17, 2000 by and among ECT Merchant Investments Corp., Joint Energy Development Investments II Limited Partnership and Bank of Montreal, as agent for each of the lenders that is a signatory to, or which becomes a signatory to, the Senior Credit Agreement (filed as Exhibit 10.10 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.60 Second Amendment to Indenture dated as of February 17, 2000 among Brigham Exploration Company and Chase Bank of Texas, National Association (filed as Exhibit 10.11 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.61 Conveyance of Adjustable Term Overriding Royalty Interest dated as of February 17, 2000 by and between Brigham Oil & Gas, L.P., and ECT Merchant Investments Corp. and Joint Energy Development Investments II Limited Partnership (filed as Exhibit 10.12 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.62 Warrant Certificate dated as of February 17, 2000 by and between Brigham Exploration Company and Joint Energy Development Investments II Limited Partnership (filed as Exhibit 10.13 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.63 Warrant Certificate dated as of February 17, 2000 by and between Brigham Exploration Company and ECT Merchant Investments Corp. (filed as Exhibit 10.14 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.64 Securities Purchase and Registration Rights Agreement dated as of February 22, 2000 by and among Brigham Exploration Company and GAP Coinvestment Partners II, L.P., Special Situations Private Equity Fund, L.P., and Aspect Resources, L.L.C. (filed as Exhibit 10.15 to the Company's Current Report on Form 8-K filed February 29, 2000 and incorporated herein by reference). 10.65+ Joint Development Agreement, dated as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. 10.65.1+First Amendment, dated as of May 10, 1999, to that certain Joint Development Agreement entered into effective as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. 10.65.2+Acquisition and Participation Agreement, dated October 21, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. 10.65.3+Letter agreement, dated as of December 30, 1999, regarding amendments to Joint Development Agreement, dated as of February 10, 1999, as amended, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC. 10.66+ Letter agreement dated as of September 6, 1999 between Brigham Oil & Gas, L.P. and Brigham Land Management Company, Inc. regarding work to be performed within Brigham's Angelton Project. 50 21+ Subsidiaries of the Registrant. 23.1+ Consent of PricewaterhouseCoopers LLP, independent public accountants. 23.2+ Consent of Cawley, Gillespie & Associates, Inc., independent petroleum engineers. 27+ Financial Data Schedule. * Management contract or compensatory plan. + Filed herewith. (b) The following reports on Form 8-K were filed by the Company during the last quarter of the period covered by this Annual Report on Form 10-K: None. 51 GLOSSARY OF OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. Bcf. One billion cubic feet. Bcfe. One billion cubic feet of natural gas equivalent. In reference to natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate of natural gas liquids. CAEX. Computer-aided exploration. Completion. The installation of permanent equipment for the production of oil or natural gas. Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled. Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production. Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Drilling Costs. The costs associated with drilling and completing a well (exclusive of seismic and land acquisition costs for that well and future development costs associated with proved undeveloped reserves added by the well) divided by total proved reserve additions. Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or gas well. Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Finding and Development Costs. Capital costs incurred in the acquisition, exploration and development of proved oil and natural gas reserves divided by total proved reserve additions. Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which the Company has a working interest. MBbl. One thousand barrels of oil or other liquid hydrocarbons. Mcf. One thousand cubic feet of natural gas. Mcfe. One thousand cubic feet of natural gas equivalents. MMBbl. One million barrels of oil or other liquid hydrocarbons. MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. MMcf. One million cubic feet of natural gas. MMcfe. One million cubic feet of natural gas equivalents. Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company. Net Production. Production that is owned by the Company less royalties and production due others. Oil. Crude oil, condensate or other liquid hydrocarbons. Operator. The individual or company responsible for the exploration, development, and production of an oil or gas well or lease. Present Value of Future Net Revenues or PV10%. The pretax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. 52 Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. Spud. Start drilling a new well (or restart). Standardized Measure. The aftertax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. 2-D Seismic. The method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. 3-D Seismic. The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production. Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. 53 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunder duly authorized, as of March 24, 2000. BRIGHAM EXPLORATION COMPANY By: /s/ Ben M. Brigham ------------------------------------- Ben M. Brigham Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of March 24, 2000, by the following persons on behalf of the Registrant and in the capacity indicated. /s/ Ben M. Brigham - ------------------------------------------------------------ Ben M. Brigham Chief Executive Officer, President and Chairman of the Board /s/ Curtis F. Harrell - ------------------------------------------------------------ Curtis F. Harrell Chief Financial Officer and Director (principal financial and accounting officer) /s/ Anne L. Brigham - ------------------------------------------------------------ Anne L. Brigham Director /s/ Harold D. Carter - ------------------------------------------------------------ Harold D. Carter Director /s/ Alexis M. Cranberg - ------------------------------------------------------------ Alexis M. Cranberg Director /s/ Stephen P. Reynolds - ------------------------------------------------------------ Stephen P. Reynolds Director 54 INDEX TO FINANCIAL STATEMENTS Page ---- Financial Statements of Brigham Exploration Company Report of Independent Accountants.................................... F1-2 Consolidated Balance Sheets as of December 31, 1999 and 1998......... F1-3 Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998, and 1997................................. F1-4 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1999, 1998, and 1997................................. F1-5 Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998, and 1997................................. F1-6 Notes to the Consolidated Financial Statements....................... F1-7 Financial Statements of Certain Brigham Exploration Company Subsidiaries Report of Independent Accountants.................................... F2-1 Balance Sheets as of December 31, 1999............................... F2-2 Balance Sheets as of December 31, 1998............................... F2-3 Statements of Operations for the Year Ended December 31, 1999........ F2-4 Statements of Operations for the Year Ended December 31, 1998........ F2-5 Statements of Operations for the Year Ended December 31, 1997........ F2-6 Statements of Equity for the Year Ended December 31, 1999............ F2-7 Statements of Equity for the Year Ended December 31, 1998............ F2-8 Statements of Equity for the Year Ended December 31, 1997............ F2-9 Statements of Cash Flows for the Year Ended December 31, 1999........ F2-10 Statements of Cash Flows for the Year Ended December 31, 1998........ F2-11 Statements of Cash Flows for the Year Ended December 31, 1997........ F2-12 Notes to the Financial Statements.................................... F2-13 As all Brigham Exploration Company significant subsidiaries fully and unconditionally guarantee the Senior Subordinated Secured Notes and the Company has no significant assets other than its investments in its subsidiaries, the consolidated financial statements are substantially the same as the financial statements of the subsidiary guarantors and separate financial statements have been omitted as they would not be meaningful to investors. Financial statements for the wholly owned subsidiaries whose securities are pledged as collateral for the Senior Subordinated Notes are included in the separate financial statements. F1-1 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Brigham Exploration Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Brigham Exploration Company at December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Dallas, Texas March 7, 2000 F1-2 BRIGHAM EXPLORATION COMPANY CONSOLIDATED BALANCE SHEETS (in thousands)
December 31, --------------------------------------- 1999 1998 ------------------ --------------- ASSETS Current assets: Cash and cash equivalents $ 2,742 $ 2,569 Accounts receivable 4,945 7,938 Other current assets 577 290 ------------------ --------------- Total current assets 8,264 10,797 ------------------ --------------- Natural gas and oil properties, at cost, net 112,066 134,317 Other property and equipment, at cost, net 1,686 2,014 Drilling advances paid 23 230 Deferred loan fees 3,481 3,146 Other noncurrent assets 163 12 ------------------ --------------- $ 125,683 $ 150,516 ================== =============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 14,851 $ 19,883 Accrued drilling costs 541 1,219 Participant advances received 850 764 Other current liabilities 1,502 1,647 ------------------ --------------- Total current liabilities 17,744 23,513 ------------------ --------------- Notes payable 56,000 59,000 Senior subordinated notes, net 41,341 35,786 Other noncurrent liabilities 1,600 7,536 Commitments and contingencies Stockholders' equity: Preferred stock, $.01 par value, 10 million shares authorized, none issued and outstanding - - Common stock, $.01 par value, 30 million shares authorized, 14,517,786 and 13,306,206 issued and outstanding at December 31, 1999 and 1998, respectively 145 133 Additional paid-in capital 64,171 58,838 Unearned stock compensation (290) (890) Accumulated deficit (55,028) (33,400) ------------------ --------------- Total stockholders' equity 8,998 24,681 ------------------ --------------- $ 125,683 $ 150,516 ================== ===============
Natural gas and oil properties are accounted for using the full cost method. See accompanying notes to the consolidated financial statements. F1-3 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data)
Year Ended December 31, --------------------------------------------------------------- 1999 1998 1997 ------------------ ----------------- ------------------ Revenues: Natural gas and oil sales $ 14,992 $ 13,799 $ 9,184 Workstation revenue 285 390 637 ------------------ ----------------- ------------------ 15,277 14,189 9,821 ------------------ ----------------- ------------------ Costs and expenses: Lease operating 2,259 2,172 1,151 Production taxes 968 850 549 General and administrative 3,481 4,672 3,570 Depletion of natural gas and oil properties 7,792 8,483 2,743 Depreciation and amortization 525 413 306 Capitalized ceiling impairment - 25,926 - Amortization of stock compensation 1 372 388 ------------------ ----------------- ------------------ 15,026 42,888 8,707 ------------------ ----------------- ------------------ Operating income (loss) 251 (28,699) 1,114 ------------------ ----------------- ------------------ Other income (expense): Interest income 176 136 145 Interest expense, net (9,697) (5,968) (1,017) Interest expense - related party - - (173) Loss on sale of natural gas and oil propertieS (12,195) - - Other expense (163) - - ------------------ ----------------- ------------------ (21,879) (5,832) (1,045) ------------------ ----------------- ------------------ Net income (loss) before income taxes (21,628) (34,531) 69 Income tax benefit (expense) - 1,186 (1,186) ------------------ ----------------- ------------------ Net loss $ (21,628) $ (33,345) $ (1,117) ================== ================= ================== Net loss per share: Basic/Diluted $ (1.53) $ (2.64) $ (0.10) Weighted average common shares outstanding: Basic/Diluted 14,152 12,626 11,081
See accompanying notes to the consolidated financial statements. F1-4 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (in thousands)
Additional Unearned Common Stock Paid-in Stock Accumulated Predecessor ------------------------------ Shares Amounts Capital Compensation Deficit Capital Total -------------- ------------ ----------- -------------- ------------ --------------- ------- Balance, December 31, 1996 - $ - $ - $ - $ - $ 3,244 $ 3,244 Consummation of the Exchange 8,928,574 90 19,580 - - (3,244) 16,426 Issuance of stock options - - 2,576 (2,576) - - - Forfeiture of stock options - - (69) 69 - - - Issuance of common stock 3,325,000 33 23,894 - - - 23,927 Net loss for period ended February 27, 1997 - - (4,869) - - - (4,869) Net income for period from February 27, 1997 to Dec. 31, 1997 - - 3,807 - (55) - 3,752 Amortization of unearned stock compensation - - - 833 - - 833 ----------------- ---------- ---------------- ------------ -------------- -------------- ----------- Balance, December 31, 1997 12,253,574 123 44,919 (1,674) (55) - 43,313 Net loss - - - - (33,345) - (33,345) Issuance of common stock 1,052,632 10 9,419 - - - 9,429 Issuance of warrants - - 4,500 - - - 4,500 Amortization of unearned stock compensation - - - 784 - - 784 ----------------- ---------- ---------------- ------------ -------------- -------------- ---------- Balance, December 31, 1998 13,306,206 133 58,838 (890) (33,400) - 24,681 Net loss - - - - (21,628) - (21,628) Issuance of common stock 1,211,580 12 4,228 - - - 4,240 Forfeiture of stock options - - (602) 602 - - - Revision in terms of warrants - - 479 - - - 479 Issuance of warrants - - 1,228 - - - 1,228 Amortization of unearned stock compensation - - - (2) - - (2) ----------------- ---------- ---------------- ------------ -------------- -------------- ---------- Balance, December 31, 1999 14,517,786 $ 145 $ 64,171 $ (290) $ (55,028) $ - $ 8,998 ================= ========== ================ ============ ============== ============== ==========
See accompanying notes to the financial statements. F1-5 BRIGHAM EXPLORATION COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Year ended December 31, ------------------------------------------ 1999 1998 1997 ----------- ------------ ------------ Cash flows from operating activities: Net loss $ (21,628) $ (33,345) $ (1,117) Adjustments to reconcile net loss to cash provided by operating activities: Depletion of natural gas and oil properties 7,792 8,483 2,743 Depreciation and amortization 525 413 306 Capitalized ceiling impairment - 25,926 - Amortization of stock compensation 1 372 388 Interest paid through issuance of additional senior subordinated notes 5,459 - - Amortization of deferred loan fees and debt issuance costs 1,739 726 - Amortization of discount on senior subordinated notes 575 286 - Amortization of deferred loss on derivatives instruments 759 - - Market value adjustment for derivatives instruments 115 - - Loss on sale of natural gas and oil properties 12,195 - - Changes in working capital and other items: (Increase) decrease in accounts receivable 2,993 (3,029) (2,213) Increase in other current assets (1,046) (10) (128) Increase (decrease) in accounts payable (1,136) 7,991 8,955 Increase (decrease) in participant advances received 86 275 (648) Increase (decrease) in other current liabilities (115) 862 50 Increase in deferred interest payable - related party - - 53 Increase (decrease) in deferred income tax liability - (1,186) 1,186 Other noncurrent assets (151) 6 281 Other noncurrent liabilities (5,585) 7,004 (50) ----------- ------------ ------------ Net cash provided by operating activities 2,578 14,774 9,806 ----------- ------------ ------------ Cash flows from investing activities: Additions to natural gas and oil properties (25,560) (85,207) (57,170) Proceeds from sale of natural gas and oil properties 27,143 - 74 Additions to other property and equipment (146) (868) (545) (Increase) decrease in drilling advances paid 207 (152) 341 ----------- ------------ ------------ Net cash provided (used) by investing activities 1,644 (86,227) (57,300) ----------- ------------ ------------ Cash flows from financing activities: Proceeds from issuance of common stock - 9,429 23,927 Proceeds from issuance of sr. subordinated notes payable and warrants - 40,000 - Increase in notes payable 13,750 105,800 37,250 Repayment of notes payable (16,750) (78,800) (13,250) Principal payments on capital lease obligations (253) (236) (179) Deferred loan fees paid (796) (3,872) - ----------- ------------ ------------ Net cash provided (used) by financing activities (4,049) 72,321 47,748 ----------- ------------ ------------ Net increase in cash and cash equivalents 173 868 254 Cash and cash equivalents, beginning of period 2,569 1,701 1,447 ----------- ------------ ------------ Cash and cash equivalents, end of period $ 2,742 $ 2,569 $ 1,701 =========== ============ ============ Supplemental disclosure of cash flow information: Cash paid during the period for interest $ 1,960 $ 5,490 $ 1,679 =========== ============ ============ Supplemental disclosure of noncash investing and financing activities: Capital lease asset additions $ 51 $ 320 $ 403 =========== ============ ============ Decrease in accounts payable and other noncurrent liabilities in exchange for issuance of common stock $ 4,240 =========== Increase in accounts payable for deferred loan fees to be paid in future periods $ 50 =========== Increase in deferred loan fees for issuance of warrants $ 1,228 ===========
See accompanying notes to the consolidated financial statements. F1-6 BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Nature of Operations Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the "Partnership"). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as "the Company." Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic natural gas and oil properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of natural gas and oil properties primarily in West Texas, the Anadarko Basin and the onshore Gulf Coast. Pursuant to an exchange agreement dated February 26, 1997 (the "Exchange Agreement") and upon the initial filing on February 27, 1997 of a registration statement with the Securities and Exchange Commission (the "SEC") for the public offering of common stock (the "Offering"), the shareholders of Brigham, Inc. transferred all of the outstanding stock of Brigham, Inc. to the Company in exchange for 3,859,821 shares of common stock of the Company. Pursuant to the Exchange Agreement, the Partnership's other general partner and the limited partners also transferred all of their partnership interests to the Company in exchange for 3,314,286 shares of common stock of the Company. Furthermore, the holders of the Partnership's subordinated convertible notes transferred these notes to the Company in exchange for 1,754,464 shares of common stock. These transactions are referred to as "the Exchange." In completing the Exchange, the Company issued 8,928,571 shares of common stock to the stockholders of Brigham, Inc., the partners of the Partnership and the holder of the Partnership's subordinated notes payable. As a result of the Exchange, the Company now owns all the partnership interests in the Partnership. In May 1997, the Company sold 3,325,000 shares of its common stock in the Offering at a price of $8.00 per share. 2. Summary of Significant Accounting Policies Basis of Accounting The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. Principles of Consolidation The accompanying financial statements include the accounts of the Company and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which the Company, or any of its subsidiaries has a participating interest. All significant intercompany accounts and transactions have been eliminated. Cash and Cash Equivalents The Company considers all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents. Property and Equipment The Company uses the full cost method of accounting for its investment in natural gas and oil properties. Under this method, all acquisition, exploration and development costs, including certain payroll and other internal costs, incurred for the purpose of finding natural gas and oil reserves are capitalized. Internal costs capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. F1-7 The capitalized costs of the Company's natural gas and oil properties plus future development, dismantlement, restoration and abandonment costs (the "Amortizable Base"), net of estimated salvage values, are amortized using the unit-of-production method based upon estimates of total proved reserve quantities. The Company's capitalized costs of its natural gas and oil properties, net of accumulated amortization, are limited to the total of estimated future net cash flows from proved natural gas and oil reserves, discounted at ten percent, plus the cost of unevaluated properties. There are many factors, including global events, that may influence the production, processing, marketing and valuation of natural gas and oil. A reduction in the valuation of natural gas and oil properties resulting from declining prices or production could adversely impact depletion rates and capitalized cost limitations. All costs directly associated with the acquisition and evaluation of unproved properties are initially excluded from the Amortizable Base. Upon the interpretation by the Company of the 3-D seismic data associated with unproved properties, the geological and geophysical costs related to acreage that is not specifically identified as prospective are added to the Amortizable Base. Geological and geophysical costs associated with prospective acreage, as well as leasehold costs, are added to the Amortizable Base when the prospects are drilled. Costs of prospective acreage are reviewed annually for impairment on a property-by-property basis. Other property and equipment, which primarily consists of 3-D seismic interpretation workstations, are depreciated on a straight-line basis over the estimated useful lives of the assets after considering salvage value. Estimated useful lives are as follows: Furniture and fixtures................................ 10 years Machinery and equipment............................... 5 years 3-D seismic interpretation workstations and software.. 3 years Betterments and major improvements that extend the useful lives are capitalized, while expenditures for repairs and maintenance of a minor nature are expensed as incurred. Revenue Recognition The Company recognizes natural gas and oil sales from its interests in producing wells under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Gas balancing obligations as of December 31, 1999, 1998 and 1997 were not significant. Interest is capitalized on significant unevaluated natural gas and oil properties that are not subject to amortization. Industry participants in the Company's seismic programs are charged on an hourly basis for the work performed by the Company on its 3-D seismic interpretation workstations. The Company recognizes workstation revenue as service is provided. Derivative Instruments The Company periodically enters into commodity hedge contracts, including price swaps, caps and/or floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of underlying volumes. The notional amounts of these derivative financial instruments are based on expected production from existing wells. The Company uses these derivative financial instruments to manage market risks resulting from fluctuations in commodity prices. F1-8 Correlation of the hedge contracts is determined by evaluating whether hedge contract gains and losses will substantially offset the effects of price changes on the underlying natural gas and crude oil sales volumes. To the extent that correlation exists between the hedge contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the hedge contracts are recognized as a component of natural gas and oil sales in the same period as the sale of the underlying volumes. To the extent that correlation does not exist between the hedge contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the hedge contracts are recognized in the period incurred as a component of other income. The fair market value of any hedge contract that does not meet the correlation test outlined above is recorded as a deferred gain or loss on the balance sheet and is adjusted to current market value at each balance sheet date with any deferred gains or losses recognized as a component of other income. In the event that management decides to terminate a hedge contract, generally accepted accounting principles require that any gains or losses upon termination be carried forward and recognized as a component of natural gas and oil sales in the period in which the underlying volumes are sold. Stock Based Compensation The Company measures compensation expense for its stock based incentive plan using the intrinsic value method and has provided in Note 11 the pro forma disclosure of the effect on net loss and net loss per common share as if the fair value based method prescribed by Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock Based Compensation," had been applied in measuring compensation expense. Federal and State Income Taxes Prior to the consummation of the Exchange, there was no income tax provision included in the financial statements as the Partnership was not a taxpaying entity. Income and losses were passed through to its partners on the basis of the allocation provisions established by the partnership agreement. Upon consummation of the Exchange, the Partnership became subject to federal income taxes through its ownership by the Company. In conjunction with the Exchange, the Company recorded a deferred income tax liability of $5 million to recognize the temporary differences between the financial statement and tax bases of the assets and liabilities of the Partnership at the Exchange date, February 27, 1997, given the provisions of enacted tax laws. Subsequent to this date, the Company elected to record a step-up in basis of its assets for tax purposes as a result of the Exchange. Related to this election, the Company recorded a $3.8 million deferred income tax benefit, resulting in a net $1.2 million deferred income tax charge for the year ended December 31, 1997. Segment Information All of the Company's natural gas and oil properties and related operations are located in the United States and management has determined that the Company has one reportable segment. F1-9 New Pronouncements In June 1998, the Financial Accounting Standards Board (the "FASB") issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that all derivative instruments be recorded on the balance sheet at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. For fair value hedge transactions in which the Company is hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions in which the Company is hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in current period earnings. The Company must adopt SFAS No. 133, as amended by SFAS No. 137, effective January 1, 2001. The Company is in the process of analyzing the potential impact of this standard on its financial statement presentations. 3. Asset Dispositions In February 1999, the Company entered into a project financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund the continued exploration of five projects covered by approximately 200 square miles of 3-D seismic data acquired in 1998. In this transaction, the Company conveyed 100% of its working interest in land and seismic in these project areas to a newly formed limited liability company (the "Duke LLC") for a total consideration of $10 million. The Company is the managing member of the Duke LLC with a 1% interest, and Duke is the sole remaining member with a 99% interest. Pursuant to the terms of the Duke LLC agreement, the Company pays 100% of the drilling and completion costs for all wells drilled by the Duke LLC in exchange for a 70% working interest in the wells and their associated drilling and spacing units and allocable seismic data. Upon 100% project payout, the Company has certain rights to back-in for up to a 94% effective working interest in the Duke LLC properties. In June 1999, the Company sold its entire interest in certain producing and non-producing natural gas and oil properties located in its Anadarko Basin province to two parties for a combined sales price of $17.1 million. Total proceeds, net of transaction costs, were $16.7 million and were used to repay a portion of the Company's notes payable. Due to the magnitude of the reserve volumes that were attributable to these properties relative to the Company's remaining net reserve volumes, the Company recognized a loss of $12.2 million, which was difference between the sales price received, after adjustment for transaction costs, and the $28.9 million basis allocated to the divested properties in accordance with the full-cost method of accounting for oil and gas properties. F1-10 4. Property and Equipment Property and equipment, at cost, are summarized as follows (in thousands):
December 31, ------------------------------ 1999 1998 ------------- -------------- Natural gas and oil properties....................... $ 178,755 181,019 Accumulated depletion................................ (66,689) (46,702) ------------- -------------- 112,066 134,317 ------------- -------------- Other property and equipment: 3-D seismic interpretation workstations and software.................................... 2,248 2,186 Office furniture and equipment.................... 1,909 1,774 Accumulated depreciation.......................... (2,471) (1,946) ------------- -------------- 1,686 2,014 ------------- -------------- $ 113,752 $ 136,331 ============= ==============
At December 31, 1998, a capitalized ceiling impairment of $25.9 million was recognized and is included above in the accumulated depletion balances for natural gas and oil properties. The write down was calculated based on the estimated discounted present value of future net cash flows from proved natural gas and oil reserves using prices in effect at December 31, 1998. The Company capitalizes certain payroll and other internal costs directly attributable to acquisition, exploration and development activities as part of its investment in natural gas and oil properties over the periods benefited by these activities. During the years ended December 31, 1999, 1998 and 1997, these capitalized costs amounted to $3.3 million, $4.6 million and $3.5 million, respectively. Capitalized costs do not include any costs related to production, general corporate overhead, or similar activities. Interest costs of $3.0 million and $1.2 million were capitalized in 1999 and 1998, respectively. 5. Notes Payable and Senior Subordinated Notes Payable In January 1998, the Company entered into a reserve-based revolving credit facility (the "Credit Facility") which originally provided for initial borrowing availability of $75 million. Principal outstanding under the Credit Facility is due at maturity on January 26, 2001 with interest due monthly for base rate tranches or periodically as LIBOR tranches mature. Amounts outstanding under the Credit Facility accrued interest at either the lender's Base Rate or LIBOR plus 2.25%, at the Company's option. The Credit Facility contains covenants restricting the Company's ability to declare or pay dividends on its stock. In connection with the origination of the Credit Facility, certain bank fees and other expenses totaling approximately $1.9 million were recorded as deferred costs and are amortized over the life of the loan. The Credit Facility was amended in March 1999 to reduce the borrowing availability, extend the date of borrowing base redetermination, modify certain financial covenants, include certain additional covenants that place significant restrictions on the Company's ability to make certain capital expenditures, and to change the interest rate on outstanding borrowings to either the lender's Base Rate or LIBOR plus 3.0%, at the Company's option. The Company incurred a $500,000 transaction fee due to the lender over a ten month period. In July 1999, the Credit Facility was amended to provide the Company with borrowing availability of $56 million. As consideration for this amendment, in July 1999 the Company issued to its senior lenders one million warrants to purchase the Company's common stock at an exercise price of $2.25 per share. An estimated value of $1.2 million was attributed to these warrants by the Company and was recognized as additional deferred loan fees to be amortized over the remaining period to maturity of the Credit Facility. The Company's obligations under the Credit Facility are secured by substantially all of the natural gas and oil properties and other tangible assets of the Company. F1-11 In August 1998, upon the filing of a registration statement with the SEC, the Company issued $50 million of debt and equity securities to two affiliated institutional investors. The financing transaction consisted of the issuance of $40 million of senior subordinated secured notes (the "Notes") with warrants (the "Warrants") to purchase the Company's common stock and the sale of $10 million of the Company's common stock, or 1,052,632 shares at a price of $9.50 per share. The combined sale of the Notes and common stock of the Company generated proceeds, net of offering costs, of approximately $47.5 million that was used to repay a portion of the then outstanding borrowings under the Company's Credit Facility. Principal outstanding under the Notes is due at maturity on August 20, 2003. Interest on the Notes is payable quarterly at rates that vary depending upon whether accrued interest is paid in cash or "in kind" through the issuance of additional Notes. Interest is payable in cash at interest rates of 12%, 13%, and 14% during the years one through three, year four and year five, respectively, of the term of the Notes; provided, however, that the Company may pay interest in kind for a cumulative total of seven (or potentially eight) quarterly interest payments at interest rates of 13%, 14% and 15% during the years one through three, year four and year five, respectively, of the term of the Notes. The Company may repay the Notes in full without premium at any time prior to maturity. The indenture governing the Notes contains certain covenants including, but not limited to, limitations or restrictions on indebtedness, distributions, affiliate transactions, liens and sale and leaseback transactions. The indenture prohibits all dividends on the Company's stock. Warrants to purchase 1 million shares of the Company's common stock exercisable during a period of seven years at a price of $10.45 per share were issued in connection with the Notes. The Notes are fully and unconditionally guaranteed, on a joint and several basis, by each of the Company's subsidiaries (the "Subsidiary Guarantors"), all of which are directly or indirectly wholly-owned by the Company. Additionally, the stock of certain subsidiaries has also been pledged as collateral for the Notes. The obligations of the Subsidiary Guarantors under the subsidiary guaranty agreements are subordinated to the senior indebtedness of the Subsidiary Guarantors. The assets of the parent, Brigham Exploration Company, consist solely of investments in its subsidiaries. Concurrent with the issuance of the Notes, the Company recorded a discount on the Notes of $4.5 million to reflect the estimated value of the Warrants. Also in connection with the issuance of the Notes, certain fees and expenses totaling approximately $1.8 million were recorded as deferred costs. The Note discount and deferred fees are amortized over the five year term of the Notes. In March 1999, the indenture governing the Notes was amended to provide the Company with the option to pay interest due on the Notes in kind, for any reason, through the second quarter of 2000. In addition, certain financial and other covenants were amended. The amendment also provides for a reduction in the exercise price per share of the Warrants from $10.45 per share to $3.50 per share. The discount on the Notes was decreased by $479,000 to reflect the change in value attributed to the Warrants as a result of the revision in the terms of the Warrants. F1-12 6. Capital Lease Obligations Property under capital leases consists of the following (in thousands):
December 31, ------------------------------ 1999 1998 ------------- -------------- 3-D seismic interpretation workstations and software....................... $ 607 $ 620 Office furniture and equipment............................................. 167 167 ------------- -------------- 774 787 Accumulated depreciation and amortization.................................. (410) (276) ------------- -------------- $ 364 $ 511 ============= ==============
The obligations under capital leases are at fixed interest rates ranging from 7.5% to 17.9% and are collateralized by property, plant and equipment. The future minimum lease payments under the capital leases and the present value of the net minimum lease payments at December 31, 1999 are as follows (in thousands): 2000...................................................... $ 258 2001...................................................... 115 2002...................................................... 27 ------------- Total minimum lease payments.............................. 400 Estimated executory costs included in capital leases... (25) ------------- Net minimum lease payments................................ 375 Amounts representing interest.......................... (38) ------------- Present value of net minimum lease payments............... 337 Less: current portion.................................... (210) ------------- Noncurrent portion........................................ $ 127 ============= 7. Income Taxes The provision for income taxes consists of the following (in thousands): Year ended December 31, ------------------------------ 1999 1998 ------------- -------------- Current income taxes: Federal............................... $ - $ - State................................. - - Deferred income taxes: Federal............................... - (1,186) State................................. - - ------------- -------------- $ - $ (1,186) ============= ============== F1-13 The difference in income taxes provided and the amounts determined by applying the federal statutory tax rate to income before income taxes result from the following (in thousands): Year ended December 31, ------------------------------ 1999 1998 ------------- -------------- Tax at statutory rate................... $ (7,570) $ (11,740) Add the effect of: Nondeductible expenses............... 8 10 Valuation reserve.................... 7,562 10,544 ------------- -------------- $ - $ (1,186) ============= ============== The components of deferred income tax assets and liabilities are as follows (in thousands): December 31, ----------------------------- 1999 1998 ------------ -------------- Deferred tax assets: Net operating loss carryforwards........ $ 18,796 $ 11,219 Amortization of stock compensation...... 266 258 Other................................... 27 3 ------------ -------------- 19,089 11,480 Deferred tax liability: Depreciable and depletable property..... (484) (936) Valuation reserve....................... (18,605) (10,544) ------------ -------------- $ - $ - ============ ============== At December 31, 1999, the Company had regular and alternative minimum tax net operating loss carryforwards of approximately $53.7 million and $45.2 million, respectively, which expire by December 31, 2019. 8. Net Income (Loss) Per Share Net loss per share is presented in the consolidated financial statements based on a basic loss per share calculation as well as a diluted loss per share calculation. Basic loss per share is computed by dividing net loss applicable to common shareholders by the weighted average number of common shares outstanding during each period. Diluted loss per share is computed by dividing net loss applicable to common shareholders by the weighted average number of common shares and common share equivalents outstanding (if dilutive) during each period. The number of common share equivalents outstanding is computed using the treasury stock method. Net loss per share for 1997 is presented giving effect to the shares issued pursuant to the Exchange as well as shares issued in the initial public offering. At December 31, 1999 and 1998, options and warrants to purchase 3,519,726 and 2,194,654 shares of common stock, respectively, were outstanding but were not included in the computation of diluted loss per share because they were anti-dilutive. 9. Contingencies, Commitments and Factors Which May Affect Future Operations Litigation The Company is, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of the Company. F1-14 As of December 31, 1999, there were no known environmental or other regulatory matters related to the Company's operations which are reasonably expected to result in a material liability to the Company. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company's capital expenditures, earnings or competitive position. Lease Commitments The Company leases office equipment and space under operating leases expiring at various dates through 2002. The future minimum annual rental payments under the noncancelable terms of these leases at December 31, 1999, are as follows (in thousands): 2000....................................................... $ 795 2001....................................................... 790 2002....................................................... 395 ------------- $ 1,980 ============= Rental expense for the years ended December 31, 1999, 1998 and 1997 was $937,669, $875,150 and $606,173, respectively. Major Customers During 1999, approximately 26%, 16% and 11% of the Company's natural gas and oil production was sold to three separate customers. During 1998, approximately 25%, 15%, 11% and 11% of the Company's natural gas and oil production was sold to four separate customers. During 1997, approximately 14% and 12% of the Company's natural gas and oil production was sold to two separate customers. However, due to the availability of other customers, the Company does not believe that the loss of any one of these individual customers would adversely affect the Company's result of operations. Factors Which May Affect Future Operations Since the Company's major products are commodities, significant changes in the prices of natural gas and oil could have a significant impact on the Company's results of operations for any particular year. 10. Financial Instruments The Company periodically enters into commodity price swap agreements which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of the underlying volumes. The notional amounts of these derivative financial instruments are based on planned production from existing wells. The Company uses these derivative financial instruments to manage market risks resulting from fluctuations in commodity prices. Commodity price swaps are effective in minimizing these risks by creating essentially equal and offsetting market exposures. In 1997, the Company was a party to a crude oil swap arrangement resulting in a fixed price over a period of time for a specified volume of crude oil. In February 1998, the Company entered into a hedging contract whereby 10,000 MMBtu per day of natural gas is purchased and sold subject to a fixed price swap agreement for monthly periods from April 1998 through October 1999. Pursuant to these arrangements the Company exchanges a floating market price for a contract month and payments are received when the fixed price exceeds the floating price. Total natural gas subject to this hedging contract is 2,750,000 MMBtu in 1998 and 3,040,000 MMBtu in 1999. F1-15 In August 1998, the Company entered into a hedging contract whereby 5,000 MMBtu per day of natural gas is purchased and sold subject to a fixed price swap agreement for monthly periods from April 1999 through October 1999. Pursuant to these arrangements the Company exchanges a floating market price for a fixed contract price of $2.015 per MMBtu. Payments are made by the Company when the floating price exceeds the fixed price for a contract month and payments are received when the fixed price exceeds the floating price. Total natural gas subject to this hedging contract is 1,070,000 MMBtu in 1999. In January 1999, the Company entered into a swap agreement with terms similar to existing agreements which relates to production for monthly periods from November 1999 through April 2001. Pursuant to these arrangements, 15,000 MMBtu per day of natural gas is purchased and sold subject to a fixed price swap agreement, and the Company exchanges a floating market price for a fixed contract price of $2.065 per MMBtu. Total natural gas volumes subject to this agreement are 915,000 MMBtu, 5,490,000 MMBtu and 1,800,000 MMBtu in 1999, 2000 and 2001, respectively. As a result of these arrangements, the Company realized an increase (decrease) in natural gas and oil revenues of approximately $(486,000), $555,000 and $(6,200) during 1999, 1998 and 1997, respectively. To the extent that notional amounts covered by these arrangements exceed actual production quantities, a corresponding portion of the contracts has been recorded on the balance sheet at fair value, which approximated $291,000 as of December 31, 1999. Additionally, the mark-to-market adjustments and related cash flows associated with this portion of these contracts of approximately $(429,000) have been recorded as a component of other income (expense) on the 1999 statement of operations. In September 1999, the Company amended the fixed contract price from $2.065 per MMBtu to a range from $2.509 to $2.678 per MMBtu for natural gas volumes for the months of October 1999 through January 2000 under the then outstanding swap agreement. This resulted in a deferred loss of $1.1 million to be amortized to natural gas and oil revenues over the original contract period of October 1999 through January 2000. During 1999, approximately $645,000 was amortized to natural gas and oil revenues. Concurrently, in September 1999 the Company entered into natural gas and crude oil cap contracts. The natural gas cap contract provides the counterparty with a call option on 10,000 MMBtu per day of natural gas production for the monthly periods from May 2001 through June 2002. Payments are made by the Company to the counterparty when the floating price exceeds the fixed price of $2.50 per MMBtu for the periods May 2001 through October 2001 and May 2002 through June 2002, and $2.70 per MMBtu for the period November 2001 through April 2002. These instruments do not qualify for hedge accounting and accordingly were recorded on the date of the transaction at their fair value of $1.1 million as a deferred credit on the balance sheet. As of December 31, 1999, the fair value of the remaining contracts approximated $875,000 million with the corresponding mark-to-market adjustments and related cash flows recorded as a component of other income (expense) on the statement of operations. The Company's non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short maturities. The carrying value of the Company's revolving credit facility approximates its fair market value since it bears interest at floating market interest rates. The Company's accounts receivable relate to natural gas and oil sales to various industry companies, amounts due from industry participants for expenditures made by the Company on their behalf and workstation revenues. Credit terms, typical of industry standards, are of a short-term nature and the Company does not require collateral. The Company's accounts receivable at December 31, 1999 do not represent significant credit risks as they are dispersed across many counterparties. Counterparties to the natural gas and crude oil price swaps are investment grade financial institutions. F1-16 11. Employee Benefit Plans Retirement Savings Plan The Company has adopted a defined contribution 401(k) plan for substantially all of its employees. Eligible employees may contribute up to 15% of their compensation to this plan. The 401(k) plan provides that the Company may, at its discretion, match employee contributions. The Company has not matched employee contributions in any plan year. Stock Compensation In 1994 three employees were granted restricted interests in the Company which vest in increments through July 1999. At the date of grant, the value of these interests was immaterial. On February 26, 1997, in connection with the Exchange (see Note 1), the three employees transferred these interests to the Company in exchange for 156,250 shares of restricted common stock of the Company. The terms of the restricted stock and the restricted Company interests are substantially the same. No compensation expense resulted from this exchange. The Company adopted an incentive plan, effective upon completion of the Exchange (see Note 1), which provides for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to reward key employees whose performance may have a significant effect on the success of the Company. An aggregate of 1,588,170 shares of the Company's common stock was reserved for issuance pursuant to this plan. The Compensation Committee of the Board of Directors will determine the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of the Company's common stock on the date of grant and generally vest over three to five years. The Company also maintains a plan under which it offers stock compensation to non-employee directors. Pursuant to the terms of the plan, non-employee directors are entitled to annual grants. Options granted under this plan have an exercise price equal to the fair market value of the Company's common stock on the date of grant and generally vest over five years. F1-17 The following table summarizes activity under the incentive plan for each of the three years ended December 31, 1999: Weighted Average Exercise Shares Price ------------- ------------ Options outstanding December 31, 1996....... - $ - Options granted........................ 646,097 5.03 Options forfeited or cancelled......... (17,360) 5.00 Options exercised...................... - - ------------- ------------ Options outstanding December 31, 1997....... 628,737 5.03 Options granted........................ 873,500 8.62 Options forfeited or cancelled......... (307,583) (12.88) Options exercised...................... - - ------------- ------------ Options outstanding December 31, 1998....... 1,194,654 5.63 Options granted........................ 650,000 2.43 Options forfeited or cancelled......... (324,928) (4.68) Options exercised...................... - - ------------- ------------ Options outstanding December 31, 1999....... 1,519,726 $ 4.47 ============= ============ On December 14, 1998, the Board of Directors approved a proposal to cancel and reissue outstanding employee stock options which were granted in January 1998 with an exercise price of $12.88. A total of 305,250 options with an exercise price of $12.88 per share were cancelled and reissued with an exercise price of $6.31 per share, the fair market value of the Company's stock at the date of reissuance. Vesting schedules remained unchanged by the reissuance. Exercise prices for options outstanding at December 31, 1999 range from $1.5545 to $14.375 and remaining contractual lives range from 4.5 to 7 years. Exercise prices for options outstanding at December 31, 1998 range from $5.00 to $14.375 and remaining contractual lives range from 5.5 years to 7 years. Exercise prices for options outstanding at December 31, 1997 range from $5.00 to $14.375 and remaining contractual lives range from 5.5 years to 6 years. Options exercisable at December 31, 1999, 1998 and 1997 were 291,242, 145,740 and zero, respectively. The weighted average fair value per share of stock compensation issued during 1999, 1998 and 1997 was $1.42, $5.40 and $6.24, respectively. The fair value for these options was estimated using the Black-Scholes model with the following weighted average assumptions for grants made in 1999, 1998 and 1997: risk free interest rate of 6.0%, 4.7% and 6.2%; volatility of the expected market prices of the Company's common stock of 57%, 77% and 38%; expected dividend yield of zero and weighted average expected option lives of 5.6, 5.0 and 7.3 years, respectively. The Black-Scholes valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are transferable. Additionally, the assumptions required by the valuation model are highly subjective. Because the Company's stock options have significantly different characteristics from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion the model does not necessarily provide a reliable single measure of the fair value of the Company's stock options. Had compensation cost for the Company's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS No. 123 the Company's net loss and net loss per share for 1999, 1998 and 1997 would have been the pro forma amounts indicated below: F1-18 1999 1998 1997 ------------ ------------ ---------- Net loss (in thousands): As reported.................. $ (21,628) $ (33,345) $ (1,117) Pro forma.................... (21,605) (33,591) (1,314) Net loss per share: As reported.................. (1.53) (2.64) (0.10) Pro forma.................... (1.53) (2.66) (0.12) The Company granted 644,097 stock options as of March 4, 1997. These options have an exercise price of $5.00 compared to an originally determined estimated fair market value of the Company's common stock at date of grant of $8.00. This grant resulted in noncash compensation expense which is being recognized over the related vesting period of the options. In January 1998, the Company revised the fair market value of its common stock at the date these options were granted from $8.00 to $9.00. The result of this revision was an increase in the 1997 net loss of approximately $81,000, or $0.01 per share. 12. Related Party Transactions During the years ended December 31, 1999, 1998 and 1997, the Company incurred costs of approximately $180,000, $851,000 and $837,000 respectively, for fees for land acquisition services performed by a company owned by a brother of the Company's President and Chief Executive Officer. Other participants in the Company's 3-D seismic projects reimbursed the Company for a portion of these amounts. In 1997, the Company paid $18,000 for working interests in natural gas and oil properties owned by affiliates of a member of the Company's board of directors/management committee. A Director of the Company served as a consultant to the Company on various aspects of the Company's business and strategic issues. Fees paid for these services by the Company were $62,874, $100,539 and $86,580 for the years ended December 31, 1999, 1998 and 1997, respectively. Additional disbursements totaling approximately $12,000, $12,000 and $13,000 were made during 1999, 1998 and 1997, respectively, for the reimbursement of certain expenses. 13. Subsequent Event In February 2000, the Company entered into an amended and restated Credit Facility with its existing lenders and a new lender. This amended and restated Credit Facility provides the Company with an increase to $70 million in borrowing availability for a three-year term. If the Company exceeds certain asset value and interest coverage tests in the second or third quarters of 2000, the total borrowing availability under the Credit Facility will increase to $75 million. Borrowings under the Credit Facility in excess of $45 million are convertible into shares of the Company's common stock in the following amounts: (i) the first $10 million of borrowings is convertible at $3.90 per share, (ii) the second $10 million is convertible at $6.00 per share, and (iii) the final $10 million is convertible at $8.00 per share. If the Credit Facility is repaid at maturity or is prepaid prior to maturity without payment of cash premiums, the Company must issue to a new lender of the Credit Facility warrants to purchase shares of the Company's common stock. In addition, certain financial covenants of the Credit Facility have been amended or added. In connection with this most recent amendment, the Company reset the price of the warrants previously issued to its existing senior lenders to purchase one million shares of the Company's common stock from an exercise price of $2.25 per share to $2.02 per share. In February 2000, the indenture governing the Notes was amended. The holders of the Notes waived the minimum consolidated interest coverage ratio covenant through June 30, 2000 and adjusted subsequent levels under this test. In addition, an amendment to the Notes provides the Company with an extension of its right to pay interest through the issuance of additional Notes in lieu of cash (or "in kind") through the third quarter of 2000 and potentially through the fourth quarter of 2000 if certain conditions are met. In exchange for granting these amendments, the Company has (i) reset the price of the warrants previously issued to the holders of the Notes to purchase one million shares of the Company's common stock from an exercise price of $3.50 per share to $2.43 per share and (ii) granted to the holders of the Notes a term overriding royalty interest that provides for the limited right to receive 4%, or 3% if certain conditions are met, of the Company's net production revenue to reduce any outstanding Notes issued as interest paid in kind. F1-19 14. Natural Gas and Oil Exploration and Production Activities The tables presented below provide supplemental information about natural gas and oil exploration and production activities as defined by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Results of Operations for Natural Gas and Oil Producing Activities (in thousands)
Year ended December 31, ------------------------------------- 1999 1998 1997 ----------- ------------ ---------- Natural gas and oil sales......................... $ 14,992 $ 13,799 $ 9,184 Costs and expenses: Lease operating................................ 2,259 2,172 1,151 Production taxes............................... 968 850 549 Depletion of natural gas and oil properties.... 7,792 8,483 2,743 Capitalized ceiling impairment................. - 25,926 - Income tax expense (benefit) (a)............... 1,391 (8,271) 1,318 ----------- ------------ ---------- Total costs and expenses.......................... 12,410 29,160 5,761 ----------- ------------ ---------- $ 2,582 $ (15,361) $ 3,423 =========== ============ ========== Depletion per physical unit of production (equivalent Mcf of gas)........................ $ 1.24 $ 1.27 $ 0.88 =========== ============ ==========
- ------------ (a) The income tax expense (benefit) is calculated at the statutory rate and determined without regard to the Company's deduction for general and administrative expenses, interest costs and other income tax deductions and credits. Natural gas and oil sales reflect the market prices of net production sold or transferred, with appropriate adjustments for royalties, net profits interest and other contractual provisions. Lease operating expenses include lifting costs incurred to operate and maintain productive wells and related equipment, including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of natural gas and oil properties relates to capitalized costs incurred in acquisition, exploration and development activities. Results of operations do not include interest expense and general corporate amounts. F1-20 Costs Incurred and Capitalized Costs The costs incurred in natural gas and oil acquisition, exploration and development activities follow (in thousands): December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Costs incurred for the year: Exploration................. $ 19,224 $ 68,214 $ 29,516 Property acquisition........ 3,462 16,245 26,956 Development................. 4,632 10,475 2,953 Proceeds from participants.. (2,439) (10,502) (319) ------------ ------------ ------------ $ 24,879 $ 84,432 $ 59,106 ============ ============ ============ Costs incurred represent amounts incurred by the Company for exploration, property acquisition and development activities. Periodically, the Company will receive proceeds from participants subsequent to project initiation for an assignment of an interest in the project. These payments are represented by "Proceeds from participants" in the table above. Capitalized costs related to natural gas and oil acquisition, exploration and development activities follow (in thousands): December 31, ------------------------------ 1999 1998 ------------- -------------- Cost of natural gas and oil properties at year-end: Proved................................. $ 140,757 $ 128,643 Unproved............................... 37,998 52,376 ------------- -------------- Total capitalized costs................ 178,755 181,019 Accumulated depletion.................. (66,689) (46,702) ------------- -------------- $ 112,066 $ 134,317 ============= ============== Following is a summary of costs (in thousands) excluded from depletion at December 31, 1999, by year incurred. At this time, the Company is unable to predict either the timing of the inclusion of these costs and the related natural gas and oil reserves in its depletion computation or their potential future impact on depletion rates.
December 31, Prior ------------------------------------ 1999 1998 1997 Years Total ----------- ----------- ---------- ---------- ---------- Property acquisition... $ 1,079 $ 6,414 $ 5,558 $ 1,921 $ 14,972 Exploration............ 1,174 12,876 7,404 1,572 23,026 ----------- ----------- ---------- ---------- ---------- Total.................. $ 2,253 $ 19,290 $ 12,962 $ 3,493 $ 37,998 =========== =========== ========== ========== ==========
15. Natural Gas and Oil Reserves and Related Financial Data (Unaudited) Information with respect to the Company's natural gas and oil producing activities is presented in the following tables. Reserve quantities as well as certain information regarding future production and discounted cash flows were determined by the Company's independent petroleum consultants and internal petroleum reservoir engineer. F1-21 Natural Gas and Oil Reserve Data The following tables present the Company's estimates of its proved natural gas and oil reserves. The Company emphasizes that reserve estimates are approximates and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. A substantial portion of the reserve balances were estimated utilizing the volumetric method, as opposed to the production performance method.
Natural Gas Oil (MMcf) (MBbls) ------------- -------------- Proved reserves at December 31, 1996............. 10,257 1,940 Revisions to previous estimates............... (3,044) (447) Extensions, discoveries and other additions... 33,721 735 Purchase of minerals-in-place................. 13,718 1,244 Sales of minerals-in-place.................... (40) - Production.................................... (1,382) (291) ------------- -------------- Proved reserves at December 31, 1997............. 53,230 3,181 Revisions to previous estimates............... (26,696) (115) Extensions, discoveries and other additions... 48,050 1,752 Purchase of minerals-in-place................. 851 11 Production.................................... (4,269) (396) ------------- -------------- Proved reserves at December 31, 1998............. 71,166 4,433 Revisions of previous estimates............... (9,938) 214 Extensions, discoveries and other additions... 30,428 1,156 Sales of minerals-in-place.................... (22,002) (2,430) Production.................................... (4,197) (346) ------------- -------------- Proved reserves at December 31, 1999............. 65,457 3,027 ============= ============== Proved developed reserves at December 31: 1997.......................................... 30,677 2,665 1998.......................................... 38,571 2,935 1999.......................................... 28,594 1,873
Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash inflows (in thousands) relating to proved natural gas and oil reserves. Future cash flows were computed by applying year end prices of natural gas and oil relating to the Company's proved reserves to the estimated year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual agreements in existence at year-end. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved natural gas and oil reserves at the end of the year, based on year-end costs. Actual future cash inflows may vary considerably and the standardized measure does not necessarily represent the fair value of the Company's natural gas and oil reserves. F1-22
December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Future cash inflows.......................................... $ 228,429 $ 198,082 $ 165,156 Future development and production costs...................... (61,878) (61,064) (40,923) Future income taxes.......................................... (12,406) (6,972) (22,919) ------------ ------------ ------------ Future net cash inflows...................................... $ 154,145 $ 130,046 $ 101,314 ============ ============ ============ Future net cash inflow before income taxes, discounted at 10% per annum.......................................... $ 114,466 $ 81,741 $ 69,249 ============ ============ ============ Standardized measure of future net cash inflows discounted at 10% per annum.......................................... $ 113,546 $ 81,649 $ 44,506 ============ ============ ============
The base sales prices for the Company's reserves were $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31, 1999, $2.12 per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.27 per Mcf for natural gas and $15.50 per Bbl for oil as of December 31, 1997. These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company's reserves at these dates. Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Beginning of period............................................. $ 81,649 $ 64,274 $ 44,506 Sales of natural gas and oil produced, net of production costs................................................... (11,765) (10,776) (7,484) Development costs incurred................................... 4,413 5,423 1,955 Extensions and discoveries................................... 43,346 52,389 38,016 Purchases of minerals-in-place............................... - 687 16,965 Sales of minerals-in-place................................... (32,783) - (94) Net change of prices and production costs.................... 33,226 (11,921) (20,466) Change in future development costs........................... (555) (656) 319 Changes in production rates and other........................ 637 (6,109) (1,954) Revisions of quantity estimates.............................. (11,969) (23,470) (6,964) Accretion of discount........................................ 8,174 6,925 4,450 Change in income taxes....................................... (827) 4,883 (4,975) ------------ ------------ ------------ End of period................................................... $ 113,546 $ 81,649 $ 64,274 ============ ============ ============
F1-23 16. Quarterly Financial Data (Unaudited) The Company has restated previously reported quarterly financial results for the nine months ended September 30, 1999 and the year ended December 31, 1998 to give effect to the capitalization of interest for significant acquisition, exploration and development activities in progress. There was no effect on the year ended December 31, 1998 net loss or on the 1997 financial results. The effect of this restatement on the statement of operations is as follows (in thousands, except per share amounts):
Year Ended December 31, 1999 ------------------------------------------------------------------------------------ Quarter 1 Quarter 2 Quarter 3 Quarter 4 ------------------------ ---------------------- ------------------------ ----------- Previously As Previously As Previously As Reported Restated Reported Restated Reported Restated ------------- ----------- ----------- ---------- ----------- ----------- Revenue........................... $ 3,281 $ 3,281 $ 3,626 $ 3,624 $ 4,195 $ 4,238 $ 4,134 Operating income (loss)........... 124 113 245 190 (379) (432) 380 Net loss.......................... (2,669) (1,944) (15,034) (14,839) (3,589) (2,651) (2,194) Net loss per share: Basic/Diluted................ (0.20) (0.15) (1.05) (1.04) (0.25) (0.18) (0.15)
Year Ended December 31, 1998 ----------------------------------------------------------------------------------------------- Quarter 1 Quarter 2 Quarter 3 Quarter 4 ----------------------------------------------------------------------------------------------- Previously As Previously As Previously As Previously As Reported Restated Reported Restated Reported Restated Reported Restated ------------- ---------- ----------- ----------- ----------- ---------- ----------- ----------- Revenue.................. $ 3,257 $ 3,257 $ 4,120 $ 4,120 $ 4,237 $ 4,237 $ 2,575 $ 2,575 Operating income (loss).. 31 27 427 413 481 466 (28,486) (29,605) Net loss................. (632) (460) (627) (461) (964) (777) (31,122) (31,647) Net loss per share: Basic/Diluted....... (0.05) (0.04) (0.05) (0.04) (0.08) (0.06) (2.34) (2.34)
F1-24 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Brigham Exploration Company In our opinion, the accompanying balance sheets and the related statements of operations, of changes in equity and of cash flows, present fairly in all material respects, the financial position of Brigham Oil & Gas, L.P., and Brigham, Inc. at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Additionally, in our opinion, the accompanying balance sheets and the related statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Brigham Holdings I, LLC and Brigham Holdings II, LLC at December 31, 1999 and 1998 and for the two years then ended, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Dallas, Texas March 7, 2000 F2-1 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES BALANCE SHEETS As of December 31, 1999 (in thousands)
Brigham Brigham Brigham Oil & Brigham, Holdings Holdings Gas, L.P. Inc. I, LLC II, LLC ASSETS Current assets: Cash and cash equivalents $ 2,718 $ 2,736 $ 6 $ 6 Accounts receivable 4,945 4,945 - - Other current assets 577 577 - - ---------------- ---------------- -------------- --------------- Total current assets 8,240 8,258 6 6 ---------------- ---------------- -------------- --------------- Natural gas and oil properties, at cost, net 112,066 112,066 - - Other property and equipment, at cost, net 1,686 1,686 - - Investment in subsidiaries and intercompany advances 130 26 1,299 47,802 Drilling advances paid 23 23 - - Deferred loan fees 2,108 2,108 - - Other noncurrent assets 164 164 - - ---------------- ---------------- -------------- --------------- $ 124,417 $ 124,331 $ 1,305 $ 47,808 ================ ================ ============== =============== LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 14,851 $ 14,851 $ - $ - Accrued drilling costs 541 541 - - Participant advances received 850 850 - - Other current liabilities 1,429 1,429 - - ---------------- ---------------- -------------- --------------- Total current liabilities 17,671 17,671 - - ---------------- ---------------- -------------- --------------- Notes payable 56,000 56,000 - - Other noncurrent liabilities 1,600 1,600 - - Intercompany accounts payable 1,752 1,687 - 1,779 Intercompany notes payable 45,459 45,459 - 45,459 Commitments and contingencies Minority interest - 1,325 - - Equity Partners' capital 1,935 - 1,305 570 Common stock, $1.00 par value, 1,000 shares authorized, issued and outstanding - 1 - - Additional paid-in capital - 17,832 - - Accumulated deficit - (17,244) - - ---------------- ---------------- -------------- --------------- Total equity 1,935 589 1,305 570 ---------------- ---------------- -------------- --------------- $ 124,417 $ 124,331 $ 1,305 $ 47,808 ================ ================ ============== ===============
Natural gas and oil properties are accounted for using the full cost method. See accompanying notes to the financial statements. F2-2 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES BALANCE SHEETS As of December 31, 1998 (in thousands)
Brigham Brigham Brigham Oil & Brigham, Holdings Holdings Gas, L.P. Inc. I, LLC II, LLC ASSETS Current assets: Cash and cash equivalents $ 2,549 $ 2,563 $ 5 $ 6 Accounts receivable 7,938 7,938 - - Other current assets 290 290 - - ---------------- ---------------- ------------- --------------- Total current assets 10,777 10,791 5 6 ---------------- ---------------- ------------- --------------- Natural gas and oil properties, at cost, net 134,317 134,317 - - Other property and equipment, at cost, net 2,014 2,014 - - Investment in subsidiaries and intercompany advances 115 16 11,714 46,913 Drilling advances paid 231 231 - - Deferred loan fees 1,397 1,397 - - Other noncurrent assets 12 12 - - ---------------- ---------------- ------------- --------------- $ 148,863 $ 148,778 $ 11,719 $ 46,919 ================ ================ ============= =============== LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 19,883 $ 19,883 $ - $ - Accrued drilling costs 1,219 1,219 - - Participant advances received 764 764 - - Other current liabilities 1,647 1,647 - - ---------------- ---------------- ------------- --------------- Total current liabilities 23,513 23,513 - - ---------------- ---------------- ------------- --------------- Notes payable 59,000 59,000 - - Other noncurrent liabilities 7,536 7,536 - - Intercompany accounts payable 1,690 1,616 - 1,707 Intercompany notes payable 40,000 40,000 - 40,000 Commitments and contingencies Minority interest - 11,730 - - Equity Partners' capital 17,124 - 11,719 5,212 Common stock, $1.00 par value, 1,000 shares authorized, issued and outstanding - 1 - - Additional paid-in capital - 16,109 - - Accumulated deficit - (10,727) - - ---------------- ---------------- -------------- --------------- Total equity 17,124 5,383 11,719 5,212 ---------------- ---------------- -------------- --------------- $ 148,863 $ 148,778 $ 11,719 $ 46,919 ================ ================ ============== ===============
Natural gas and oil properties are accounted for using the full cost method. See accompanying notes to the financial statements. F2-3 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF OPERATIONS For the Year Ended December 31, 1999 (in thousands)
Brigham Brigham Brigham Oil & Brigham, Holdings Holdings Gas, L.P. Inc. I, LLC II, LLC Revenues: Natural gas and oil sales $ 14,992 $ 14,992 $ - $ - Workstation revenue 285 285 - - ------------- ------------- -------------- -------------- 15,277 15,277 - - ------------- ------------- -------------- -------------- Costs and expenses: Lease operating 2,259 2,259 - - Production taxes 968 968 - - General and administrative 3,462 3,472 9 9 Depletion of natural gas and oil properties 7,792 7,792 - - Depreciation and amortization 525 525 - - Amortization of stock compensation 1 1 - - ------------- ------------- -------------- -------------- 15,007 15,017 9 9 ------------- ------------- -------------- -------------- Operating income (loss) 270 260 (9) (9) ------------- ------------- -------------- -------------- Other income (expense): Interest income 176 176 - - Interest expense, net (3,214) (3,214) - - Interest expense - intercompany (5,532) (5,532) - (5,532) Loss on sale of natural gas and oil properties (12,195) (12,195) - - Other expense (163) (163) - - ------------- ------------- -------------- -------------- (20,928) (20,928) - (5,532) ------------- ------------- -------------- -------------- Minority interest in net loss - (14,151) - - ------------- ------------- -------------- -------------- Net loss before income taxes (20,658) (6,517) (9) (5,541) Income tax benefit - - - - Equity in net loss of investee - - (14,151) (769) ------------- ------------- -------------- -------------- Net loss $ (20,658) $ (6,517) $ (14,160) $ (6,310) ============= ============= ============== ==============
See accompanying notes to the financial statements. F2-4 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF OPERATIONS For the Year Ended December 31, 1998 (in thousands)
Brigham Brigham Brigham Oil & Brigham, Holdings Holdings Gas, L.P. Inc. I, LLC II, LLC Revenues: Natural gas and oil sales $ 13,799 $ 13,799 $ - $ - Workstation revenue 390 390 - - ------------- ------------- -------------- -------------- 14,189 14,189 - - ------------- ------------- -------------- -------------- Costs and expenses: Lease operating 2,172 2,172 - - Production taxes 850 850 - - General and administrative 4,650 4,661 11 11 Depletion of natural gas and oil properties 8,483 8,483 - - Depreciation and amortization 413 413 - - Capitalized ceiling impairment 25,926 25,926 - - Amortization of stock compensation 372 372 - - ------------- ------------- -------------- -------------- 42,866 42,877 11 11 ------------- ------------- -------------- -------------- Operating loss (28,677) (28,688) (11) (11) ------------- ------------- -------------- -------------- Other income (expense): Interest income 136 136 - - Interest expense, net (3,841) (3,841) - - Interest expense - intercompany (1,707) (1,707) - (1,707) ------------- ------------- -------------- -------------- (5,412) (5,412) - (1,707) ------------- ------------- -------------- -------------- Minority interest in net loss - (23,351) - - ------------- ------------- -------------- -------------- Net loss before income taxes (34,089) (10,749) (11) (1,718) Income tax benefit - 5,088 - - Equity in net loss of investee - - (23,351) (8,690) ------------- ------------- -------------- -------------- Net loss $ (34,089) $ (5,661) $ (23,362) $ (10,408) ============= ============= ============== ==============
See accompanying notes to the financial statements. F2-5 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF OPERATIONS For the Year Ended December 31, 1997 (in thousands)
Brigham Oil & Brigham, Gas, L.P. Inc. Revenues: Natural gas and oil sales $ 9,184 $ 9,184 Workstation revenue 637 637 -------------- --------------- 9,821 9,821 -------------- --------------- Costs and expenses: Lease operating 1,151 1,151 Production taxes 549 549 General and administrative 3,570 3,570 Depletion of natural gas and oil properties 2,743 2,743 Depreciation and amortization 306 306 Amortization of stock compensation 388 388 -------------- --------------- 8,707 8,707 -------------- --------------- Operating income 1,114 1,114 -------------- --------------- Other income (expense): Interest income 145 145 Interest expense, net (1,017) (1,017) Interest expense - related party (173) (173) -------------- --------------- (1,045) (1,045) -------------- --------------- Minority interest in net income - 47 -------------- --------------- Net income before income taxes 69 22 Income tax expense - (5,088) -------------- --------------- Net income (loss) $ 69 $ (5,066) ============== ==============
See accompanying notes to the financial statements. F2-6 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF CHANGES IN EQUITY (in thousands, except shares)
Retained Additional Earnings/ Common Stock Paid-in Accumulated Partners' --------------------- Shares Amounts Capital Deficit Capital Total --------- ---------------------- -------------- -------------- -------------- Brigham Oil & Gas, L.P. Balance, December 31, 1998 - $ - $ - $ - $ 17,124 $ 17,124 Capital contribution - - - - 5,469 5,469 Net loss - - - (20,658) (20,658) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1999 - $ - $ - $ - $ 1,935 $ 1,935 ========= ========== ============ ============== ============== ============== Brigham Inc. Balance, December 31, 1998 1,000 $ 1 $ 16,109 $ (10,727) $ - $ 5,383 Capital contribution - - 1,723 - - 1,723 Net loss - - - (6,517) - (6,517) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1999 1,000 $ 1 $ 17,832 $ (17,244) $ - $ 589 ========= ========== ============ ============== ============== ============== Brigham Holding I, LLC Balance, December 31, 1998 - $ - $ - $ - $ 11,719 $ 11,719 Capital contribution - - - - 3,746 3,746 Net loss - - - - (14,160) (14,160) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1999 - $ - $ - $ - $ 1,305 $ 1,305 ========= ========== ============ ============== ============== ============== Brigham Holdings II, LLC Balance, December 31, 1998 - $ - $ - $ - $ 5,212 $ 5,212 Capital contribution - - - - 1,668 1,668 Net loss - - - - (6,310) (6,310) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1999 - $ - $ - $ - $ 570 $ 570 ========= ========== ============ ============== ============== ==============
See accompanying notes to the financial statements. F2-7 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF CHANGES IN EQUITY (in thousands, except shares)
Retained Additional Earnings/ Common Stock Paid-in Accumulated Partners' --------------------- Shares Amounts Capital Deficit Capital Total --------- ---------------------- -------------- -------------- -------------- Brigham Oil & Gas, L.P. Balance, December 31, 1997 - $ - $ - $ - $ 43,665 $ 43,665 Capital contribution - - - - 7,548 7,548 Net loss - - - (34,089) (34,089) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1998 - $ - $ - $ - $ 17,124 $ 17,124 ========= ========== ============ ============== ============== ============== Brigham Inc. Balance, December 31, 1997 1,000 $ 1 $ 13,732 $ (5,066) $ - $ 8,667 Capital contribution - - 2,377 - - 2,377 Net loss - - - (5,661) - (5,661) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1998 1,000 $ 1 $ 16,109 $ (10,727) $ - $ 5,383 ========= ========== ============ ============== ============== ============== Brigham Holding I, LLC Balance, December 31, 1997 - $ - $ - $ - $ - $ - Partnership interest contributed - - - - 29,911 29,911 Capital contribution - - - - 5,170 5,170 Net loss - - - - (23,362) (23,362) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1998 - $ - $ - $ - $ 11,719 $ 11,719 ========= ========== ============ ============== ============== ============== Brigham Holdings II, LLC Balance, December 31, 1997 - $ - $ - $ - $ - $ - Partnership interest contributed - - - - 13,318 13,318 Capital contribution - - - - 2,302 2,302 Net loss - - - - (10,408) (10,408) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1998 - $ - $ - $ - $ 5,212 $ 5,212 ========= ========== ============ ============== ============== ==============
See accompanying notes to the financial statements. F2-8 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF CHANGES IN EQUITY (in thousands)
Retained Additional Earnings/ Common Stock Paid-in Accumulated Partners' --------------------- Shares Amounts Capital Deficit Capital Total --------- ---------------------- -------------- -------------- -------------- Brigham Oil & Gas, L.P. Balance, December 31, 1996 - $ - $ - $ - $ 3,244 $ 3,244 Capital contribution from Brigham Exploration Company at consummation of Exchange - - - - 16,425 16,425 Capital contribution from Brigham Exploration Company of proceeds from Offering - - - - 23,927 23,927 Net income - - - - 69 69 --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1997 - $ - $ - $ - $ 43,665 $ 43,665 ========= ========== ============ ============== ============== ============== Brigham Inc. Balance, December 31, 1996 1,000 $ 1 $ 29 $ - $ - $ 30 Increase in equity due to change in ownership in the Partnership resulting from the Exchange and the Offering - - 13,703 - - 13,703 Net loss - - - (5,066) - (5,066) --------- ---------- ------------ -------------- -------------- -------------- Balance, December 31, 1997 1,000 $ 1 $ 13,732 $ (5,066) $ - $ 8,667 ========= ========== ============ ============== ============== ==============
See accompanying notes to the financial statements. F2-9 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF CASH FLOWS For the Year Ended December 31, 1999 (in thousands)
Brigham Brigham Brigham Oil & Brigham, Holdings Holdings Gas, L.P. Inc. I, LLC II, LLC Cash flows from operating activities: Net loss $ (20,658) $ (6,517) $ (14,160) $ (6,310) Adjustments to reconcile net loss to cash provided by operating activities: Depletion of natural gas and oil properties 7,792 7,792 - - Depreciation and amortization 525 525 - - Amortization of stock compensation 1 1 - - Amortization of deferred loan fees and debt issuance costs 1,363 1,363 - - Amortization of deferred loss on derivatives instruments 759 759 - - Market value adjustment for derivatives instruments 115 115 - - Loss on sale of natural gas and oil properties 12,195 12,195 - - Minority interest in net loss - (14,151) - - Equity in net loss of investee - - 14,151 769 Changes in working capital and other items: Decrease in accounts receivable 2,993 2,993 - - Increase in other current assets (1,046) (1,046) - - Decrease in accounts payable (1,136) (1,136) - - Increase in participant advances received 86 86 - - Decrease in other current liabilities (188) (188) - - Increase in intercompany accounts payable 65 74 - 72 Other noncurrent assets (151) (151) - - Other noncurrent liabilities (5,585) (5,585) - - ------------ ------------- ------------- --------------- (2,870) (2,871) (9) (5,469) ------------ ------------- ------------- --------------- Cash flows from investing activities: Natural gas and oil properties (25,560) (25,560) - - Proceeds from sale of natural gas and oil properties 27,143 27,143 - - Other property and equipment (146) (146) - - Investment in subsidiaries and intercompany advances (15) (10) 10 10 Change in drilling advances paid 207 207 - - ------------ ------------- ------------- --------------- 1,629 1,634 10 10 ------------ ------------- ------------- --------------- Cash flows from financing activities: Increase in notes payable 13,750 13,750 - - Repayment of notes payable (16,750) (16,750) - - Increase in intercompany notes payable 5,459 5,459 - 5,459 Principal payments on capital lease obligations (253) (253) - - Deferred loan fees paid (796) (796) - - ------------ ------------- ------------- --------------- 1,410 1,410 - 5,459 ------------ ------------- ------------- --------------- Net increase in cash and cash equivalents 169 173 1 - Cash and cash equivalents, beginning of year 2,549 2,563 5 6 ------------ ------------- ------------- --------------- Cash and cash equivalents, end of year $ 2,718 $ 2,736 $ 6 $ 6 ============ ============= ============= =============== Supplemental disclosure of cash flow information: Cash paid during the year for interest $ 1,960 $ 1,960 $ - $ - Supplemental disclosure of noncash investing and financing activities: Capital lease asset additions $ 51 $ 51 $ - $ - Increase in accounts payable for deferred loan fees to be paid on future periods $ 50 $ 50 $ - $ - Capital contributions received in exchange for accounts payable and other noncurrent liabilities $ 5,469 $ - $ - $ - Intercompany capital contributions $ - $ 1,723 $ 3,746 $ 1,668 See accompanying notes to the financial statements.
F2-10 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF CASH FLOWS For the Year Ended December 31, 1998 (in thousands)
Brigham Brigham Brigham Oil & Brigham, Holdings Holdings Gas, L.P. Inc. I, LLC II, LLC Cash flows from operating activities: Net loss $ (34,089) $ (5,661) $ (23,362) $ (10,408) Adjustments to reconcile net loss to cash provided by operating activities: Depletion of natural gas and oil properties 8,483 8,483 - - Depreciation and amortization 413 413 - - Capitalized ceiling impairment 25,926 25,926 - - Amortization of stock compensation 372 372 - - Amortization of deferred loan fees and debt issuance costs 593 593 - - Minority interest in net loss - (23,351) - - Equity in net loss of investee - - 23,351 8,690 Changes in working capital and other items: Increase in accounts receivable (3,029) (3,029) - - Increase in prepaid expenses (10) (10) - - Increase in accounts payable 7,991 7,991 - - Increase in participant advances received 275 275 - - Increase in other current liabilities 862 862 - - Decrease in deferred income tax liability - (5,088) - - Increase in intercompany accounts payable - - - 1,707 Other noncurrent assets 6 6 - - Other noncurrent liabilities 7,004 7,004 - - ------------- ------------- --------------- ------------ 14,797 14,786 (11) (11) ------------- ------------- --------------- ------------ Cash flows from investing activities: Natural gas and oil properties (85,208) (85,208) - - Other property and equipment (868) (868) - - Investment in subsidiaries and intercompany advances (42) (17) (5,154) (42,285) Change in drilling advances paid (153) (153) - - ------------- ------------- --------------- ------------ (86,271) (86,246) (5,154) (42,285) ------------- ------------- --------------- ------------ Cash flows from financing activities: Capital contribution received 7,548 7,548 5,170 2,302 Increase in intercompany notes payable 40,000 40,000 - 40,000 Increase in notes payable 105,800 105,800 - - Repayment of notes payable (78,800) (78,800) - - Principal payments on capital lease obligations (236) (236) - - Deferred loan fees (1,990) (1,990) - - ------------- ------------- --------------- ------------ 72,322 72,322 5,170 42,302 ------------- ------------- --------------- ------------ Net increase in cash and cash equivalents 848 862 5 6 Cash and cash equivalents, beginning of year 1,701 1,701 - - ------------- ------------- --------------- ------------ Cash and cash equivalents, end of year $ 2,549 $ 2,563 $ 5 $ 6 ============= ============= =============== ============ Supplemental disclosure of cash flow information: Cash paid during the year for interest $ 4,878 $ 4,878 $ - $ - Supplemental disclosure of noncash investing and financing activities: Capital lease asset additions $ 320 $ 320 $ - $ - Intercompany capital contributions $ - $ - $ 29,911 $ 13,318
See accompanying notes to the financial statements. F2-11 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES STATEMENTS OF CASH FLOWS For the Year Ended December 31, 1997 (in thousands)
Brigham Oil & Brigham, Gas, L.P. Inc. Cash flows from operating activities: Net income (loss) $ 69 $ (5,066) Adjustments to reconcile net income (loss) to cash provided by operating activities: Depletion of natural gas and oil properties 2,743 2,743 Depreciation and amortization 306 306 Amortization of stock compensation 388 388 Minority interest in net income - 47 Changes in working capital and other items: Increase in accounts receivable (2,213) (2,213) Increase in prepaid expenses (128) (128) Increase in accounts payable 8,955 8,955 Decrease in participant advances received (648) (648) Increase in other current liabilities 50 50 Increase in deferred interest payable - related party 53 53 Increase in deferred income tax liability - 5,088 Other noncurrent assets 281 281 Other noncurrent liabilities (50) (50) ----------- -------------- 9,806 9,806 ----------- -------------- Cash flows from investing activities: Natural gas and oil properties (57,170) (57,170) Proceeds from the sale of natural gas and oil properties 74 74 Other property and equipment (545) (545) Change in drilling advances paid 341 341 ----------- -------------- (57,300) (57,300) ----------- -------------- Cash flows from financing activities: Capital contribution received 23,927 23,927 Increase in notes payable 37,250 37,250 Repayment of notes payable (13,250) (13,250) Principal payments on capital lease obligations (179) (179) ----------- -------------- 47,748 47,748 ----------- -------------- Net increase in cash and cash equivalents 254 254 Cash and cash equivalents, beginning of year 1,447 1,447 ----------- -------------- Cash and cash equivalents, end of year $ 1,701 $ 1,701 =========== ============== Supplemental disclosure of cash flow information: Cash paid during the year for interest $ 1,679 $ 1,679 Supplemental disclosure of noncash investing and financing activities: Capital lease asset additions $ 403 $ 403 Intercompany capital contributions $ 16,425 $ - Increase resulting from the Exchange and the Offering in ownership interest in the Partnership $ - $ 13,703
See accompanying notes to the financial statements. F2-12 BRIGHAM EXPLORATION COMPANY SUBSIDIARIES NOTES TO THE FINANCIAL STATEMENTS 1. Organization and Background In August 1998, upon the filing of a registration statement with the SEC, Brigham Exploration Company, a Delaware corporation, (the "Company") issued $50 million of debt and equity securities to two affiliated institutional investors. The financing transaction consisted of the issuance of $40 million of senior subordinated secured notes (the "Notes"). The Notes are fully and unconditionally guaranteed, on a joint and several basis, by each of the Company's directly or indirectly wholly-owned subsidiaries which are Brigham Oil & Gas, L.P. (the "Partnership"), Brigham Inc., Brigham Holdings I LLC ("Holdings I"), and Brigham Holdings II LLC ("Holdings II"). Furthermore, these subsidiaries have pledged their respective stock and partnership interests as collateral for the Notes. These financial statements include the financial statements for the wholly owned subsidiaries whose securities and partnership interests comprise substantially all of the collateral pledged for the Notes. The Partnership was formed in May 1992 to explore and develop onshore domestic natural gas and oil properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of natural gas and oil properties primarily in West Texas, the Anadarko Basin and the onshore Gulf Coast. Brigham, Inc. is a Nevada corporation whose only asset prior to the Exchange was its less than 1% ownership interest in the Partnership. Brigham, Inc. is the managing general partner of the Partnership. On February 25, 1997, the Company was formed for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of the Partnership. Pursuant to an exchange agreement dated February 26, 1997 (the "Exchange Agreement") and upon the initial filing on February 27, 1997 of a registration statement with the Securities and Exchange Commission (the "SEC") for the public offering of common stock (the "Offering"), the shareholders of Brigham, Inc. transferred all of the outstanding stock of Brigham, Inc. to the Company in exchange for 3,859,821 shares of common stock of the Company. Pursuant to the Exchange Agreement, the Partnership's other general partner and the limited partners also transferred all of their partnership interests to the Company in exchange for 3,314,286 shares of common stock of the Company. Furthermore, the holders of the Partnership's subordinated convertible notes transferred these notes to the Company in exchange for 1,754,464 shares of common stock. These transactions are referred to as "the Exchange." In completing the Exchange, the Company issued 8,928,571 shares of common stock to the stockholders of Brigham, Inc., the partners of the Partnership and the holder of the Partnership's subordinated notes payable. In May 1997, the Company sold 3,325,000 shares of its common stock in the Offering at a price of $8.00 per share. As a result of the Exchange and the Offering, the Company owns a 68.5% partnership interest in the Partnership and all of the outstanding shares of Brigham, Inc. Brigham, Inc. owns the remainder of the Partnership interest in the Partnership. The proceeds of the Offering were contributed to the Partnership by the Company. Subsequent to the Exchange and the Offering, the Company owned a 68.5% interest in the Partnership and Brigham, Inc. owned a 31.50% interest in the Partnership. Effective January 1, 1998, Brigham, Inc. contributed 30.5% of its 31.5% interest in the Partnership to Holdings II, a newly formed Nevada LLC and wholly owned subsidiary of Brigham, Inc., whose only asset is its investment in the Partnership. Also effective January 1, 1998 the Company contributed its 68.5% interest in the Partnership to Brigham Holdings I, a newly formed Nevada LLC and wholly owned subsidiary of the Company whose only asset is its investment in the Partnership. F2-13 2. Summary of Significant Accounting Policies Basis of Accounting The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. Principles of Consolidation The accompanying financial statements include the accounts of the Partnership, Brigham, Inc., Holdings I and Holdings II (collectively referred to as the "Subsidiaries"). Holdings II accounts for its interest in the Partnership under the equity method. Brigham, Inc. consolidates its interests in the Partnership and Holdings II as a result of its general partner interest in the Partnership and its 100% ownership of Holdings II. Holdings I accounts for its 68.5% investment in the Partnership under the equity method and its ownership in the Partnership is reflected as the minority interest in the consolidated results of Brigham, Inc. All entities are either directly or indirectly wholly-owned subsidiaries of the Company. All significant intercompany accounts and transactions have been eliminated. Substantially all of the Subsidiaries' assets are held by and all operations conducted through the Partnership and its subsidiaries. All references in these financial statements to assets held by the Partnership and transactions entered into by the Partnership are applicable to Brigham, Inc. through its consolidation of the Partnership. Cash and Cash Equivalents The Subsidiaries consider all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents. Property and Equipment All natural gas and oil properties are held by the Partnership which uses the full cost method of accounting for its investment in natural gas and oil properties. Under this method, all acquisition, exploration and development costs, including certain payroll and other internal costs, incurred for the purpose of finding natural gas and oil reserves are capitalized. Internal costs capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities. Costs associated with production and general and administrative activities are expensed in the period incurred. The capitalized costs of the Partnership's natural gas and oil properties plus future development, dismantlement, restoration and abandonment costs (the "Amortizable Base"), net of estimated of salvage values, are amortized using the unit-of-production method based upon estimates of total proved reserve quantities. The Partnership's capitalized costs of its natural gas and oil properties, net of accumulated amortization, are limited to the total of estimated future net cash flows from proved natural gas and oil reserves, discounted at ten percent, plus the cost of unevaluated properties. There are many factors, including global events, that may influence the production, processing, marketing and valuation of natural gas and oil. A reduction in the valuation of natural gas and oil properties resulting from declining prices or production could adversely impact depletion rates and capitalized cost limitations. All costs directly associated with the acquisition and evaluation of unproved properties are initially excluded from the Amortizable Base. Upon the interpretation by the Partnership of the 3-D seismic data associated with unproved properties, the geological and geophysical costs related to acreage that is not specifically identified as prospective are added to the Amortizable Base. Geological and geophysical costs associated with prospective acreage, as well as leasehold costs, are added to the Amortizable Base when the prospects are drilled. Costs of prospective acreage are reviewed annually for impairment on a property-by-property basis. F2-14 Other property and equipment, which primarily consists of 3-D seismic interpretation workstations, are depreciated on a straight-line basis over the estimated useful lives of the assets after considering salvage value. Estimated useful lives are as follows: Furniture and fixtures........................................ 10 years Machinery and equipment....................................... 5 years 3-D seismic interpretation workstations and software.......... 3 years Betterments and major improvements that extend the useful lives are capitalized, while expenditures for repairs and maintenance of a minor nature are expensed as incurred. Revenue Recognition The Partnership recognizes natural gas and oil sales from its interests in producing wells under the sales method of accounting. Under the sales method, the Partnership recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Partnership is entitled based on its interest in the properties. Gas balancing obligations as of December 31, 1999, 1998 and 1997 were not significant. Interest is capitalized on significant unevaluated natural gas and oil properties that are not subject to amortization. Industry participants in the Partnership's seismic programs are charged on an hourly basis for the work performed by the Partnership on its 3-D seismic interpretation workstations. The Partnership recognizes workstation revenue as service is provided. Derivative Instruments The Partnership periodically enters into commodity hedge contracts, including price swaps, caps and/or floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of underlying volumes. The notional amounts of these derivative financial instruments are based on expected production from existing wells. The Partnership uses these derivative financial instruments to manage market risks resulting from fluctuations in commodity prices. Correlation of the hedge contracts is determined by evaluating whether hedge contract gains and losses will substantially offset the effects of price changes on the underlying natural gas and crude oil sales volumes. To the extent that correlation exists between the hedge contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the hedge contracts are recognized as a component of natural gas and oil sales in the same period as the sale of the underlying volumes. To the extent that correlation does not exist between the hedge contracts and the underlying natural gas and crude oil sales volumes, realized gains or losses and related cash flows arising from the hedge contracts are recognized in the period incurred as a component of other income. The fair market value of any hedge contract that does not meet the correlation test outlined above is recorded as a deferred gain or loss on the balance sheet and is adjusted to current market value at each balance sheet date with any deferred gains or losses recognized as a component of other income. F2-15 In the event that management decides to terminate a hedge contract, generally accepted accounting principles require that any gains or losses upon termination be carried forward and recognized as a component of natural gas and oil sales in the period in which the underlying volumes are sold. Federal and State Income Taxes The Subsidiaries other than Brigham, Inc. are not taxable entities and as a result, no income tax provision has been recorded. However, the taxable income or loss resulting from their operations will ultimately be included in the federal and state income tax returns of the Company and may vary substantially from the income or loss reported for financial reporting purposes. Brigham, Inc., which is included in the Company's consolidated income tax return, is subject to federal corporate income taxation and utilizes an asset and liability approach for accounting for income taxes that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and tax bases of assets and liabilities. Resulting tax liabilities, if any, are borne by the Company. Segment Information All of the Partnership's natural gas and oil properties and related operations are located in the United States and management has determined that the Subsidiaries have one reportable segment. Recent Pronouncements In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that all derivative instruments be recorded on the balance sheet at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. For fair value hedge transactions in which the Partnership is hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions in which the Partnership is hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in current period earnings. The Partnership must adopt SFAS No. 133 effective January 1, 2000. The Partnership is in the process of analyzing the potential impact of this standard on its financial statement presentation. F2-16 3. Asset Dispositions In February 1999, the Partnership entered into a project financing arrangement with Duke Energy Financial Services, Inc. ("Duke") to fund the continued exploration of five projects covered by approximately 200 square miles of 3-D seismic data acquired in 1998. In this transaction, the Partnership conveyed 100% of its working interest in land and seismic in these project areas to a newly formed limited liability company (the "Duke LLC") for a total consideration of $10 million. The Partnership is the managing member of the Duke LLC with a 1% interest, and Duke is the sole remaining member with a 99% interest. Pursuant to the terms of the Duke LLC agreement, the Partnership pays 100% of the drilling and completion costs for all wells drilled by the Duke LLC in exchange for a 70% working interest in the wells and their associated drilling and spacing units and allocable seismic data. Upon 100% project payout, the Partnership has certain rights to back-in for up to a 94% effective working interest in the Duke LLC properties. In June 1999, the Partnership sold its entire interest in certain producing and non-producing natural gas and oil properties located in its Anadarko Basin province to two parties for a combined sales price of $17.1 million. Total proceeds, net of transaction costs, were $16.7 million and were used to repay a portion of the Partnership's notes payable. Due to the magnitude of the reserve volumes that were attributable to these properties relative to the Partnership's remaining net reserve volumes, the Partnership recognized a loss of $12.2 million, which was difference between the sales price received, after adjustment for transaction costs, and the $28.9 million basis allocated to the divested properties in accordance with the full-cost method of accounting for oil and gas properties. 4. Property and Equipment Property and equipment (held by the Partnership), at cost, are summarized as follows (in thousands):
December 31, ------------------------------ 1999 1998 ------------- -------------- Natural gas and oil properties.......................... $ 178,755 $ 181,019 Accumulated depletion................................... (66,689) (46,702) ------------- -------------- 112,066 134,317 ------------- -------------- Other property and equipment: 3-D seismic interpretation workstations and software. 2,248 2,186 Office furniture and equipment....................... 1,909 1,774 Accumulated depreciation............................. (2,471) (1,946) ------------- -------------- 1,686 2,014 ------------- -------------- $ 113,752 $ 136,331 ============= ==============
At December 31, 1998, a capitalized ceiling impairment of $25.9 million was recognized by the Partnership and is included above in the accumulated depletion balances for natural gas and oil properties. The write down was calculated based on the estimated discounted present value of future net cash flows from proved natural gas and oil reserves using prices in effect at December 31, 1998. The Partnership capitalizes certain payroll and other internal costs directly attributable to acquisition, exploration and development activities as part of its investment in natural gas and oil properties over the periods benefited by these activities. During the years ended December 31, 1999, 1998 and 1997, these capitalized costs amounted to $3.3 million, $4.6 million and $3.5 million, respectively. Capitalized costs do not include any costs related to production, general corporate overhead, or similar activities. Interest costs of $3.0 million and $1.2 million were capitalized in 1999 and 1998, respectively. F2-17 5. Notes Payable and Senior Subordinated Notes Payable In January 1998, the Partnership entered into a reserve-based revolving credit facility (the "Credit Facility") which originally provided for initial borrowing availability of $75 million. Principal outstanding under the Credit Facility is due at maturity on January 26, 2001 with interest due monthly for base rate tranches or periodically as LIBOR tranches mature. Amounts outstanding under the Credit Facility accrued interest at either the lender's Base Rate or LIBOR plus 2.25%, at the Partnership's option. The Credit Facility contains covenants restricting the Company's ability to declare or pay dividends on its stock. In connection with the origination of the Credit Facility, certain bank fees and other expenses totaling approximately $1.9 million were recorded as deferred costs and are amortized over the life of the loan. The Credit Facility was amended in March 1999 to reduce the borrowing availability, extend the date of borrowing base redetermination, modify certain financial covenants, include certain additional covenants that place significant restrictions on the Partnership's ability to make certain capital expenditures, and to change the interest rate on outstanding borrowings to either the lender's Base Rate or LIBOR plus 3.0%, at the Partnership's option. The Partnership incurred a $500,000 transaction fee due to the lender over a ten month period. In July 1999, the Credit Facility was amended to provide the Partnership with borrowing availability of $56 million. As consideration for this amendment, in July 1999 the Company issued to its senior lenders one million warrants to purchase the Company's common stock at an exercise price of $2.25 per share. An estimated value of $1.2 million was attributed to these warrants by the Partnership and was recognized as additional deferred loan fees to be amortized over the remaining period to maturity of the Credit Facility. The Partnership's obligations under the Credit Facility are secured by substantially all of the natural gas and oil properties and other tangible assets of the Partnership. In August 1998, upon the filing of a registration statement with the SEC, the Company issued $50 million of debt and equity securities to two affiliated institutional investors. The financing transaction consisted of the issuance of $40 million of senior subordinated secured notes (the "Notes") with warrants (the "Warrants") to purchase the Company's common stock and the sale of $10 million of the Company's common stock, or 1,052,632 shares at a price of $9.50 per share. The combined sale of the Notes and common stock of the Company generated proceeds, net of offering costs, of approximately $47.5 million that was used to repay a portion of the then outstanding borrowings under the Company's Credit Facility. Principal outstanding under the Notes is due at maturity on August 20, 2003. Interest on the Notes is payable quarterly at rates that vary depending upon whether accrued interest is paid in cash or "in kind" through the issuance of additional Notes. Interest is payable in cash at interest rates of 12%, 13%, and 14% during the years one through three, year four and year five, respectively, of the term of the Notes; provided, however, that the Company may pay interest in kind for a cumulative total of seven (or potentially eight) quarterly interest payments at interest rates of 13%, 14% and 15% during the years one through three, year four and year five, respectively, of the term of the Notes. The Company may repay the Notes in full without premium at any time prior to maturity. The indenture governing the Notes contains certain covenants including, but not limited to, limitations or restrictions on indebtedness, distributions, affiliate transactions, liens and sale and leaseback transactions. The indenture prohibits all dividends on the Company's stock. Warrants to purchase 1 million shares of the Company's common stock exercisable during a period of seven years at a price of $10.45 per share were issued in connection with the Notes. The Notes are fully and unconditionally guaranteed, on a joint and several basis, by each of the Subsidiaries, all of which are directly or indirectly wholly-owned by the Company. The obligations of the Subsidiaries under the subsidiary guaranty agreements are subordinated to the senior indebtedness of the Partnership. Furthermore, all Subsidiaries have pledged their respective stock and Partnership interests as collateral for the Notes. F2-18 Concurrent with the issuance of the Notes, the Company recorded a discount on the Notes of $4.5 million to reflect the estimated value of the Warrants. Also in connection with the issuance of the Notes, certain fees and expenses totaling approximately $1.8 million were recorded as deferred costs. The Note discount and deferred fees are amortized over the five year term of the Notes. The $40 million in proceeds from the Notes and Warrants, and subsequent changes to the Note balance due to interest paid in kind were transferred through a series of intercompany notes from the Company to Brigham Inc.; from Brigham, Inc. to Holdings II; and from Holdings II to the Partnership. Principal on the intercompany notes is due at the maturity of the Notes and intercompany interest accrues at rates corresponding to those applicable to the Notes. In 1998, approximately $7.6 million of the proceeds from the common stock was transferred through a series of intercompany capital contributions from the Company to Holdings I ($5.2 million) and Brigham, Inc. ($2.4 million); from Holdings I to the Partnership ($5.2 million); from Brigham, Inc. to Holdings II ($2.3 million) and the Partnership ($75,000); and from Holdings II to the Partnership ($2.3 million). In March 1999, the indenture governing the Notes was amended to provide the Company with the option to pay interest due on the Notes in kind, for any reason, through the second quarter of 2000. In addition, certain financial and other covenants were amended. The amendment also provides for a reduction in the exercise price per share of the Warrants from $10.45 per share to $3.50 per share. The discount on the Notes was decreased by $479,000 to reflect the change in value attributed to the Warrants as a result of the revision in the terms of the Warrants. 6. Capital Lease Obligations Property under capital leases held by the Partnership consists of the following (in thousands):
December 31, ------------------------------ 1999 1998 ------------- -------------- 3-D seismic interpretation workstations and software... $ 607 $ 620 Office furniture and equipment......................... 167 167 ------------- -------------- 774 787 Accumulated depreciation and amortization.............. (410) (276) ------------- -------------- $ 364 $ 511 ============= ==============
F2-19 The obligations under capital leases are at fixed interest rates ranging from 7.5% to 17.9% and are collateralized by property, plant and equipment. The future minimum lease payments under the capital leases and the present value of the net minimum lease payments at December 31, 1999 are as follows (in thousands): 2000..................................................... $ 258 2001..................................................... 115 2002..................................................... 27 -------------- Total minimum lease payments............................. 400 Estimated executory costs included in capital leases.. (25) -------------- Net minimum lease payments............................... 375 Amounts representing interest......................... (38) -------------- Present value of net minimum lease payments.............. 337 Less: current portion................................... (210) -------------- Noncurrent portion....................................... $ 127 ============== 7. Income Taxes The provision for income taxes consists of the following (in thousands): Year ended December 31, ---------------------------- 1999 1998 ------------ ------------ Current income taxes: Federal.................... $ - $ - State...................... - - Deferred income taxes: Federal.................... - (5,088) State...................... - - ------------ ------------ $ - $ (5,088) ============ ============ The difference in income taxes provided and the amounts determined by applying the federal statutory tax rate to income before income taxes result from the following (in thousands): Year ended December 31, ---------------------------- 1999 1998 ------------ ------------ Tax at statutory rate........... $ (2,281) $ (3,655) Add (deduct) the effect of: Tax effect of Exchange...... - (1,433) Valuation reserve........... 2,281 - ------------ ------------ $ - $ (5,088) ============ ============ F2-20 The components of deferred income tax assets and liabilities are as follows (in thousands): December 31, ----------------------------- 1999 1998 ------------- ------------- Deferred tax assets: Net operating loss carryforwards..... $ 8,119 $ 4,767 Deferred tax liability: Depreciable and depletable property.. (7,158) (4,767) Valuation reserve.................... (961) - ------------- ------------- $ - $ - ============= ============= At December 31, 1999, Brigham, Inc. had regular and alternative minimum tax net operating loss carryforwards of approximately $23.2 million and $20.4 million, respectively, which expire by December 31, 2019. 8. Contingencies, Commitments and Factors Which May Affect Future Operations Litigation The Subsidiaries are, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of the Subsidiaries. As of December 31, 1999, there were no known environmental or other regulatory matters related to the Subsidiaries' operations which are reasonably expected to result in a material liability to the Subsidiaries. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on their capital expenditures, earnings or competitive position. Lease Commitments The Partnership leases office equipment and space under operating leases expiring at various dates through 2002. The future minimum annual rental payments under the noncancelable terms of these leases at December 31, 1999, are as follows (in thousands): 2000...................................................... $ 795 2001...................................................... 790 2002...................................................... 395 ------------- $ 1,980 ============= Rental expense for the years ended December 31, 1999, 1998 and 1997 was $937,669, $875,150 and $606,173, respectively. Major Customers During 1999, approximately 26%, 16% and 11% of the Partnership's natural gas and oil production was sold to three separate customers. During 1998, approximately 25%, 15%, 11% and 11% of the Partnership's natural gas and oil production was sold to four separate customers. During 1997, approximately 14% and 12% of the Partnership's natural gas and oil production was sold to two separate customers. However, due to the availability of other customers, the Partnership does not believe that the loss of any one of these individual customers would adversely affect the Partnership's result of operations. F2-21 Factors Which May Affect Future Operations Since the Partnership's major products are commodities, significant changes in the prices of natural gas and oil could have a significant impact on the Partnership's results of operations for any particular year. 9. Financial Instruments The Partnership periodically enters into commodity price swap agreements which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of natural gas or crude oil without the exchange of the underlying volumes. The notional amounts of these derivative financial instruments are based on planned production from existing wells. The Partnership uses these derivative financial instruments to manage market risks resulting from fluctuations in commodity prices. Commodity price swaps are effective in minimizing these risks by creating essentially equal and offsetting market exposures. In 1997, the Partnership was a party to a crude oil swap arrangement resulting in a fixed price over a period of time for a specified volume of crude oil. In February 1998, the Partnership entered into a hedging contract whereby 10,000 MMBtu per day of natural gas is purchased and sold subject to a fixed price swap agreement for monthly periods from April 1998 through October 1999. Pursuant to these arrangements the Partnership exchanges a floating market price for a contract month and payments are received when the fixed price exceeds the floating price. Total natural gas subject to this hedging contract is 2,750,000 MMBtu in 1998 and 3,040,000 MMBtu in 1999. In August 1998, the Partnership entered into a hedging contract whereby 5,000 MMBtu per day of natural gas is purchased and sold subject to a fixed price swap agreement for monthly periods from April 1999 through October 1999. Pursuant to these arrangements the Partnership exchanges a floating market price for a fixed contract price of $2.015 per MMBtu. Payments are made by the Partnership when the floating price exceeds the fixed price for a contract month and payments are received when the fixed price exceeds the floating price. Total natural gas subject to this hedging contract is 1,070,000 MMBtu in 1999. In January 1999, the Partnership entered into a swap agreement with terms similar to existing agreements which relates to production for monthly periods from November 1999 through April 2001. Pursuant to these arrangements, 15,000 MMBtu per day of natural gas is purchased and sold subject to a fixed price swap agreement, and the Partnership exchanges a floating market price for a fixed contract price of $2.065 per MMBtu. Total natural gas volumes subject to this agreement are 915,000 MMBtu, 5,490,000 MMBtu and 1,800,000 MMBtu in 1999, 2000 and 2001, respectively. As a result of these arrangements, the Partnership realized an increase (decrease) in natural gas and oil revenues of approximately $(486,000), $555,000 and $(6,200) during 1999, 1998 and 1997, respectively. To the extent that notional amounts covered by these arrangements exceed actual production quantities, a corresponding portion of the contracts has been recorded on the balance sheet at fair value, which approximated $291,000 as of December 31, 1999. Additionally, the mark-to-market adjustments and related cash flows associated with this portion of the contract of approximately $(429,000) have been recorded as a component of other income (expense) on the 1999 statement of operations. F2-22 In September 1999, the Partnership amended the fixed contract price from $2.065 per MMBtu to a range from $2.509 to $2.678 per MMBtu for natural gas volumes for the months of October 1999 through January 2000 under the then outstanding swap agreement. This resulted in a deferred loss of $1.1 million to be amortized to natural gas and oil revenues over the original contract period of October 1999 through January 2000. During 1999, approximately $645,000 was amortized to natural gas and oil revenues. Concurrently, in September 1999 the Partnership entered into natural gas and crude oil cap contracts. The natural gas cap contract provides the counterparty with a call option on 10,000 MMBtu per day of natural gas production for the monthly periods from May 2001 through June 2002. Payments are made by the Partnership to the counterparty when the floating price exceeds the fixed price of $2.50 per MMBtu for the periods May 2001 through October 2001 and May 2002 through June 2002, and $2.70 per MMBtu for the period November 2001 through April 2002. These instruments do not qualify for hedge accounting and accordingly were recorded on the date of the transaction at their fair value of $1.1 million as a deferred credit on the balance sheet. As of December 31, 1999, the fair value of the remaining contracts approximated $875,000 million with the corresponding mark-to-market adjustments and related cash flows recorded as a component of other income (expense) on the statement of operations. The Partnership's non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short maturities. The carrying value of the Partnership's revolving credit facility approximates its fair market value since it bears interest at floating market interest rates. The Partnership's accounts receivable relate to natural gas and oil sales to various industry companies, amounts due from industry participants for expenditures made by the Partnership on their behalf and workstation revenues. Credit terms, typical of industry standards, are of a short-term nature and the Partnership does not require collateral. The Partnership's accounts receivable at December 31, 1999 do not represent significant credit risks as they are dispersed across many counterparties. Counterparties to the natural gas and crude oil price swaps are investment grade financial institutions. 10. Employee Benefit Plans Retirement Savings Plan The Partnership has adopted a defined contribution 401(k) plan for substantially all of its employees. In 1997 Brigham, Inc. succeeded to the 401(k) plan when the employees of the Partnership became employees of Brigham, Inc. Eligible employees may contribute up to 15% of their compensation to this plan. The 401(k) plan provides that the employer may, at its discretion, match employee contributions. The employer has not matched employee contributions in any plan year. F2-23 Stock Compensation In 1994 three employees were granted restricted interests in the Partnership which vest in increments through July 1999. At the date of grant, the value of these interests was immaterial. On February 26, 1997, in connection with the Exchange (see Note 1), the three employees transferred these interests to the Company in exchange for 156,250 shares of restricted common stock of the Company. The terms of the restricted stock and the restricted Company interests are substantially the same. No compensation expense will result from this exchange. The Company adopted an incentive plan, effective upon completion of the Exchange (see Note 1), which provides for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to reward key employees whose performance may have a significant effect on the success of the Company. Non-cash compensation expense related to certain stock options granted under the incentive plan by the Company on behalf of the Partnership has been allocated to the Partnerships's results of operations. Compensation expense allocated to the Partnership totaled $600,506, $782,544 and $833,710 in 1999, 1998 and 1997, respectively. 11. Subsequent Event In February 2000, the Partnership entered into an amended and restated Credit Facility with its existing lenders and a new lender. This amended and restated Credit Facility provides the Partnership with an increase to $70 million in borrowing availability for a three-year term. If the Partnership exceeds certain asset value and interest coverage tests in the second or third quarters of 2000, the total borrowing availability under the Credit Facility will increase to $75 million. Borrowings under the Credit Facility in excess of $45 million are convertible into shares of the Company's common stock in the following amounts: (i) the first $10 million of borrowings is convertible at $3.90 per share, (ii) the second $10 million is convertible at $6.00 per share, and (iii) the final $10 million is convertible at $8.00 per share. If the Credit Facility is repaid at maturity or is prepaid prior to maturity without payment of cash premiums, the Company must issue to a new lender of the Credit Facility warrants to purchase shares of the Company's common stock. In addition, certain financial covenants of the Credit Facility have been amended or added. In connection with this most recent amendment, the Company reset the price of the warrants previously issued to its existing senior lenders to purchase one million shares of the Company's common stock from an exercise price of $2.25 per share to $2.02 per share. In February 2000, the indenture governing the Notes was amended. The holders of the Notes waived the minimum consolidated interest coverage ratio covenant through June 30, 2000 and adjusted subsequent levels under this test. In addition, an amendment to the Notes provides the Company with an extension of its right to pay interest through the issuance of additional Notes in lieu of cash (or "in kind") through the third quarter of 2000 and potentially through the fourth quarter of 2000 if certain conditions are met. In exchange for granting these amendments, the Company has (i) reset the price of the warrants previously issued to the holders of the Notes to purchase one million shares of the Company's common stock from an exercise price of $3.50 per share to $2.43 per share and (ii) granted to the holders of the Notes a term overriding royalty interest that provides for the limited right to receive 4%, or 3% if certain conditions are met, of the Company's net production revenue to reduce any outstanding Notes issued as interest paid in kind. F2-24 12. Natural Gas and Oil Exploration and Production Activities The tables presented below provide supplemental information about natural gas and oil exploration and production activities as defined by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." All natural gas and oil properties are held by the Partnership. The Partnership's natural gas and oil properties are included in the consolidated results of Brigham, Inc., subject to the minority interest of 68.5% held by the Company in 1997 and by Holdings I in 1999 and 1998. Results of Operations for Natural Gas and Oil Producing Activities (in thousands)
Year ended December 31, ------------------------------------- 1999(a) 1998(a) 1997(a) ----------- ------------ ---------- Natural gas and oil sales........................................... $ 14,992 $ 13,799 $ 9,184 Costs and expenses: Lease operating................................................. 2,259 2,172 1,151 Production taxes................................................ 968 850 549 Depletion of natural gas and oil properties..................... 7,792 8,483 2,743 Capitalized ceiling impairment.................................. - 25,926 - ----------- ------------ ---------- Total costs and expenses........................................... 11,019 37,431 4,443 ----------- ------------ ---------- $ 3,973 $ (23,632) $ 4,741 =========== ============ ========== Depletion per physical unit of production (equivalent Mcf of gas).. $ 1.24 $ 1.27 $ 0.88 =========== ============ ==========
- ----------------- (a) The income tax expense (benefit) related to Brigham, Inc. for 1998, 1998 and 1997 is calculated at the statutory rate and determined without regard to deduction for general and administrative expenses, interest costs and other income tax deductions and credits. Upon consolidation of the Partnership interest into Brigham, Inc. for 1999, 1998 and 1997, the income tax expense (benefit) related to results of operations for natural gas and oil producing activities for Brigham, Inc. would be $438, $(2,605) and $523, respectively. Natural gas and oil sales reflect the market prices of net production sold or transferred, with appropriate adjustments for royalties, net profits interest and other contractual provisions. Lease operating expenses include lifting costs incurred to operate and maintain productive wells and related equipment, including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of natural gas and oil properties relates to capitalized costs incurred in acquisition, exploration and development activities. Results of operations do not include interest expense and general corporate amounts. F2-25 Costs Incurred and Capitalized Costs The costs incurred in natural gas and oil acquisition, exploration and development activities follow (in thousands): December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Costs incurred for the year: Exploration................. $ 19,224 $ 68,214 $ 29,516 Property acquisition........ 3,462 16,245 26,956 Development................. 4,632 10,475 2,953 Proceeds from participants.. (2,439) (10,502) (319) ------------ ------------ ------------ $ 24,879 $ 84,432 $ 59,106 ============ ============ ============ Costs incurred represent amounts incurred by the Partnership for exploration, property acquisition and development activities. Periodically, the Partnership will receive proceeds from participants subsequent to project initiation for an assignment of an interest in the project. These payments are represented by "Proceeds from participants" in the table above. Capitalized costs related to natural gas and oil acquisition, exploration and development activities follow (in thousands):
December 31, ------------------------------ 1999 1998 ------------- -------------- Cost of natural gas and oil properties at year-end: Proved............................................. $ 140,757 $ 128,643 Unproved........................................... 37,998 52,376 ------------- -------------- Total capitalized costs............................ 178,755 181,019 Accumulated depletion.............................. (66,689) (46,702) ------------- -------------- $ 112,066 $ 134,317 ============= ==============
Following is a summary of costs (in thousands) excluded from depletion at December 31, 1999, by year incurred. At this time, the Partnership is unable to predict either the timing of the inclusion of these costs and the related natural gas and oil reserves in its depletion computation or their potential future impact on depletion rates.
December 31, Prior ------------------------------------ 1999 1998 1997 Years Total ----------- ----------- ---------- ---------- ---------- Property acquisition........................ $ 1,079 $ 6,414 $ 5,558 $ 1,921 $ 14,972 Exploration................................. 1,174 12,876 7,404 1,572 23,026 ----------- ----------- ---------- ---------- ---------- Total....................................... $ 2,253 $ 19,290 $ 12,962 $ 3,493 $ 37,998 =========== =========== ========== ========== ==========
13. Natural Gas and Oil Reserves and Related Financial Data (Unaudited) Information with respect to the Partnership's natural gas and oil producing activities is presented in the following tables. Reserve quantities as well as certain information regarding future production and discounted cash flows were determined by the Partnership's independent petroleum consultants and internal petroleum reservoir engineer. F2-26 Natural Gas and Oil Reserve Data The following tables present the Partnership's estimates of its proved natural gas and oil reserves. The Partnership emphasizes that reserve estimates are approximates and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. A substantial portion of the reserve balances were estimated utilizing the volumetric method, as opposed to the production performance method.
Natural Gas Oil (MMcf) (MBbls) ------------- -------------- Proved reserves at December 31, 1996.................. 10,257 1,940 Revisions to previous estimates.................... (3,044) (447) Extensions, discoveries and other additions........ 33,721 735 Purchase of minerals-in-place...................... 13,718 1,244 Sales of minerals-in-place......................... (40) - Production......................................... (1,382) (291) ------------- -------------- Proved reserves at December 31, 1997.................. 53,230 3,181 Revisions to previous estimates.................... (26,696) (115) Extensions, discoveries and other additions........ 48,050 1,752 Purchase of minerals-in-place...................... 851 11 Production......................................... (4,269) (396) ------------- -------------- Proved reserves at December 31, 1998.................. 71,166 4,433 Revisions of previous estimates.................... (9,938) 214 Extensions, discoveries and other additions........ 30,428 1,156 Sales of minerals-in-place......................... (22,002) (2,430) Production......................................... (4,197) (346) ------------- -------------- Proved reserves at December 31, 1999.................. 65,457 3,027 ============= ============== Proved developed reserves at December 31: 1997............................................... 30,677 2,665 1998............................................... 38,571 2,935 1999............................................... 28,594 1,873
Proved reserves are estimated quantities of crude natural gas and oil which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. F2-27 Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash inflows (in thousands) relating to proved natural gas and oil reserves. Future cash flows were computed by applying year end prices of natural gas and oil relating to the Partnership's proved reserves to the estimated year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual agreements in existence at year-end. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved natural gas and oil reserves at the end of the year, based on year-end costs. Actual future cash inflows may vary considerably and the standardized measure does not necessarily represent the fair value of the Partnership's natural gas and oil reserves.
December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Future cash inflows............................................. $ 228,429 $ 198,082 $ 165,156 Future development and production costs......................... (61,878) (61,064) (40,923) ------------ ------------ ------------ Future net cash inflows......................................... $ 166,551 $ 137,018 $ 124,233 ============ ============ ============ Standardized measure of future net cash inflows discounted at 10% per annum............................................. $ 114,466 $ 81,741 $ 69,249 ============ ============ ============
Estimated future income tax expense as of December 31, 1999, 1998 and 1997 attributable to Brigham, Inc.'s interest in the Partnership was $3.9 million, $2.2 million and $7.2 million, respectively. The standardized measure of future net cash inflows discounted at 10% per annum as of December 31, 1999, 1998 and 1997 after estimated income taxes attributable to Brigham, Inc.'s interest in the Partnership was $114.2 million, $81.7 million and $67.7 million, respectively. The base sales prices for the Partnership's reserves were $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31, 1999, $2.12 per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.27 per Mcf for natural gas and $15.50 per Bbl for oil as of December 31, 1997. These base prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Partnership's reserves at these dates. F2-28 Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Beginning of period ....................................... $ 81,741 $ 69,249 $ 44,506 Sales of natural gas and oil produced, net of production costs ............................................. (11,765) (10,776) (7,484) Development costs incurred ............................. 4,413 5,423 1,955 Extensions and discoveries ............................. 43,346 52,389 38,016 Purchases of minerals-in-place ......................... -- 687 16,965 Sales of minerals-in-place ............................. (32,783) -- (94) Net change of prices and production costs .............. 33,226 (11,921) (20,466) Change in future development costs ..................... (555) (656) 319 Changes in production rates and other .................. 637 (6,109) (1,954) Revisions of quantity estimates ........................ (11,969) (23,470) (6,964) Accretion of discount .................................. 8,174 6,925 4,450 --------- --------- --------- End of period ............................................. $ 114,465 $ 81,741 $ 69,249 ========= ========= =========
The estimated change in future net cash inflows discounted at 10% per annum attributable to income taxes for the years ended December 31, 1999, 1998 and 1997 attributable to Brigham, Inc.'s interest in the Partnership was $(261,000), $1.5 million and $(1.6) million, respectively. 14. Quarterly Financial Data (Unaudited) The Subsidiaries have restated previously reported quarterly financial results for the nine months ended September 30, 1999 and the year ended December 31, 1998 to give effect to the capitalization of interest for significant acquisition, exploration and development activities in progress. There was no effect on the year ended December 31, 1998 net loss or on the 1997 financial results. The effect of this restatement on the statement of operations is as follows (in thousands):
Year Ended December 31, 1999 ------------------------------------------------------------------------------------ Quarter 1 Quarter 2 Quarter 3 Quarter 4 ------------------------ ---------------------- ----------------------- ------------ Previously As Previously As Previously As Reported Restated Reported Restated Reported Restated ------------- ---------- ------------ --------- ------------ ---------- Brigham Oil and Gas, L.P. Revenue........................... $ 3,281 $ 3,281 $ 3,626 $ 3,624 $ 4,195 $ 4,238 $ 4,134 Operating income (loss)........... 124 113 255 200 (379) (432) 389 Net loss.......................... (2,484) (1,759) (14,794) (14,599) (3,329) (2,391) (1,909) Brigham, Inc. Revenue........................... $ 3,281 $ 3,281 $ 3,626 $ 3,624 $ 4,195 $ 4,238 $ 4,134 Operating income (loss)........... 124 113 250 195 (379) (432) 384 Net loss.......................... (783) (554) (4,664) (4,604) (1,049) (753) (606) Brigham Holdings I, LLC Revenue........................... $ - $ - $ - $ - $ - $ - $ - Operating income (loss)........... - - (5) (5) - - (4) Net loss.......................... (1,701) (1,205) (10,140) (10,005) (2,280) (1,638) (1,312) Brigham Holdings II, LLC Revenue........................... $ - $ - $ - $ - $ - $ - $ - Operating income (loss)........... - - (5) (5) - - (4) Net loss.......................... (758) (537) (4,517) (4,457) (1,015) (729) (587)
F2-29
Year Ended December 31, 1998 ----------------------------------------------------------------------------------------------- Quarter 1 Quarter 2 Quarter 3 Quarter 4 ------------------------ ---------------------- ---------------------- ------------------------ Previously As Previously As Previously As Previously As Reported Restated Reported Restated Reported Restated Reported Restated ------------- ---------- ----------- ---------- ----------- --------- ---------- -------------- Brigham Oil & Gas, L.P. Revenue.................$ 3,257 $ 3,257 $ 4,120 $ 4,120 $ 4,237 $ 4,237 $ 2,575 $ 2,575 Operating income (loss). 31 27 438 424 481 466 (28,475) (29,594) Net loss................ (954) (692) (932) (682) (1,348) (1,064) (30,855) (31,651) Brigham, Inc. Revenue.................$ 3,257 $ 3,257 $ 4,120 $ 4,120 $ 4,237 $ 4,237 $ 2,575 $ 2,575 Operating income (loss). 31 27 432 418 481 466 (28,480) (29,599) Net loss................ (207) (152) (201) (150) (280) (221) (4,973) (5,138) Brigham Holdings I, LLC Revenue.................$ - $ - $ - $ - $ - $ - $ - $ - Operating income (loss). - - (6) (6) - - (5) (5) Net loss................ (653) (474) (645) (473) (923) (729) (21,141) (21,686) Brigham Holdings II, LLC Revenue.................$ - $ - $ - $ - $ - $ - $ - $ - Operating income (loss). - - (6) (6) - - (5) (5) Net loss................ (291) (211) (290) (214) (411) (325) (9,416) (9,658)
F2-30 EX-10.5.1 2 LETTER AGREEMENT EXHIBIT 10.5.1 March 20, 2000 Via Facsimile and Regular Mail - ------------------------------ Mr. Harold D. Carter 5949 Sherry Lane, Suite 620 Dallas, Texas 75225 Phone (214) 692-7785 Fax (214) 692-7820 Re: Amendment to Consulting Agreement by and between Harold D. Carter ("Consultant") and Brigham Oil & Gas, L.P. (the "Company") Dear Harold: This letter agreement shall set forth the agreement by and between Consultant and the Company to amend the above referenced Consulting Agreement, effective as of January 1, 2000, as follows: (1) Section 3 of the Consulting Agreement is hereby deleted in its entirety and replaced with the following Section 3: 3. Compensation. The Company shall pay Consultant for his services under this Agreement a consulting fee of $2,500 per month during the term of this Agreement. All federal withholding and other employment and income related taxes shall be the responsibility of Consultant. (2) Section 6 of the Consulting Agreement is hereby deleted in its entirety and replaced with the following Section 6: 6. Term. The term of this Agreement shall commence on the date hereof and terminate on December 31, 2000. All of the other terms and provisions of the Consulting Agreement shall continue in force and effect. If this letter amendment correctly reflects your agreement and understanding, we ask that you execute the duplicate originals of same and return one of the duplicate originals to us for our records. Sincerely, BRIGHAM OIL & GAS, L.P. By Brigham, Inc. Its Managing General Partner /s/ David T. Brigham David T. Brigham Vice President AGREED AND ACCEPTED: /s/ Harold D. Carter - -------------------- HAROLD D. CARTER EX-10.10.4 3 SUBLEASE AGREEMENT EXHIBIT 10.10.4 SUBLEASE THIS SUBLEASE is made as of November 16, 1999, by and between Brigham Oil & Gas, L.P., a Delaware limited partnership ("Sublandlord"), and ShowSupport.com, Inc., a Delaware corporation ("Subtenant"). RECITALS: A. Sublandlord leases certain office space in the office building known as Two Bridge Point, located at 6300 Bridge Point Parkway, Austin, Texas (the "Building"), pursuant to the Two Bridge Point Lease Agreement dated as of September 20, 1996, attached hereto as Exhibit A (the "Original Lease"), between Investors Life Insurance Company of North America, a Washington corporation, as landlord, and Sublandlord, as tenant, as amended by (i) First Amendment to Two Bridge Point Lease Agreement dated as of April 11, 1997, attached hereto as Exhibit B, (ii) Second Amendment to Two Bridge Point Lease Agreement dated as of October 13, 1997, attached hereto as Exhibit C, and (iii) Third Amendment to Two Bridge Point Lease Agreement dated November, 1998, attached hereto as Exhibit D (the Original Lease, as so modified, is herein called the "Base Lease"). The Building is now owned by HUB Properties Trust, a Maryland real estate investment trust ("Owner"). B. Subtenant desires to sublease certain space within the 34,327 Rentable Square Feet of space leased to Sublandlord as the "Premises" under the Base Lease. Sublandlord is willing to sublet such space to Subtenant upon the terms and conditions hereinafter set forth. NOW, THEREFORE, Sublandlord, in consideration of the rent to be paid and the covenants and agreements to be performed by Subtenant as set forth below, hereby subleases and demises to Subtenant, and Subtenant takes and accepts, the following premises on the fourth floor of the Building (the "Subleased Premises"): (a) 5,296.11 Rentable Square Feet of space within the Premises shown as the "Lease Space" on the floor plan attached hereto as Exhibit E (the "Floor Plan"); and (b) An undivided one-half interest in the space within the Premises shown as the "Shared Corridor Space" (herein so called) on the Floor Plan, which interest shall be deemed a sublease of 97.48 Rentable Square Feet of space, but shall entitle Subtenant to use the entirety of the Shared Corridor Space, in common with Sublandlord, for access to and from the Subleased Premises. The Subleased Premises are leased by Sublandlord to Subtenant and are accepted and are to be used and possessed by Subtenant upon the following terms and conditions: 1 1. Definitions. Capitalized terms used in this Sublease without definitions have the respective meanings assigned to them in the Base Lease. 2. Term. The term of this Sublease shall commence on the date hereof and shall end November 30, 2001 (the "Expiration Date"). 3. Base Rent. Subtenant shall pay to Sublandlord during the term hereof, without demand and without any setoff or deduction, minimum rental ("Base Rent") of (i) $11,798.48 per month from the date hereof through and including November 30, 2000, and (ii) $12,697.41 per month from December 1, 2000 through and including the Expiration Date. Base Rent shall be payable monthly in advance beginning on the first day of the term hereof and continuing thereafter on the first day of each calendar month. Should the term of this Sublease commence on a day other than the first day of a calendar month or terminate on a day other than the last day of a calendar month, the Base Rent for such partial month shall be prorated. Each installment of Base Rent shall be paid to Sublandlord at the address specified in this Sublease or elsewhere as designated from time to time by written notice from Sublandlord to Subtenant; provided, however, if Owner wishes to collect Base Rent directly from Subtenant and credit Sublandlord therefor under the Base Lease, then Subtenant will pay Base Rent directly to Owner at the address of Owner specified in the Base Lease and will simultaneously send evidence of such payment to Sublandlord. Owner will not be considered to have assumed Sublandlord's obligations hereunder by reason of the acceptance of any payment directly from Subtenant. 4. Additional Rent. (a) The Base Rent payable by Subtenant shall be increased by an amount ("Additional Rent") equal to Subtenant's Pro Rata Share of the Base Lease Obligations. For purposes of this Sublease, "Base Lease Obligations" shall mean the share of Operating Expenses and all other amounts that Sublandlord is obligated to pay under the Base Lease for the term of this Sublease, except for Sublandlord's obligation to pay "Base Rent" as specified in Section 3.01 of the Base Lease. "Subtenant's Pro Rata Share" shall mean (i) 15.71% with respect to all Base Lease Obligations except for charges for off-hour and nonstandard air conditioning, heating and electricity used in the Subleased Premises, and except for Base Lease Obligations that become due because of a default by Sublandlord under the Base Lease, (ii) 100% with respect to any Base Lease Obligations that become due because of the use of off-hour and nonstandard air conditioning, heating and electricity in the Subleased Premises, it being understood that such charges are made according to Building zones as provided in Article 5 of the Base Lease, and that the Subleased Premises, except for Offices 447 and 448 as shown on the Floor Plan, exclusively comprise "Zone 4B" of the Building's HVAC system, (iii) 100% with respect to any Base Lease Obligations that become due because of a default by Sublandlord under the Base Lease if such default is caused by Subtenant's failure to abide by the terms of this Sublease, and (iv) 0% with respect to any Base Lease Obligations that become due because of a default by Sublandlord under the Base Lease, if such default is not caused by Subtenant's failure to abide by the terms of this Sublease. Sublandlord's failure to pay any amount due under the Base Lease after Subtenant has failed to pay a corresponding amount under this Sublease will be considered a default caused by Subtenant's failure to abide by the terms of this Sublease. 2 (b) Payments of Additional Rent which are attributable to Operating Expenses shall be made by Subtenant to Sublandlord on the first day of the term hereof and on the first day of each succeeding month throughout the term, simultaneously with the payment of Base Rent, according to the most current, Estimated Operating Expenses then payable by Sublandlord to Owner. Payments of any and all other Additional Rent owing hereunder shall be made by Subtenant to Sublandlord within 10 days after Subtenant receives an invoice therefor, provided that Subtenant shall not be required to make any payment of Additional Rent more than 10 days prior to the date Sublandlord is required to pay the underlying Base Lease Obligation. Should the term of this Sublease commence on a day other than the first day of a calendar month or terminate on a day other than the last day of a calendar month, the Additional Rent for such partial month shall be prorated. If Owner wishes to collect Additional Rent directly from Subtenant and credit such Additional Rent against the underlying Base Lease Obligations owed by Sublandlord, then Subtenant will pay Additional Rent directly to Owner within the time periods set out in the Base Lease for payment of such underlying obligations and will simultaneously send evidence of such payment to Sublandlord. (c) Sublandlord shall provide Subtenant with copies of all information concerning Additional Rent within a reasonable time after it receives such information from Owner. In the absence of manifest error, any such information from Owner shall be presumed to be correct as between Sublandlord and Subtenant. To the extent that Sublandlord makes or is credited for payments of Base Lease Obligations on the basis of estimates by Owner (e.g., a payment on the basis of Estimated Operating Expenses), and Sublandlord shall be required to make an additional payment of Base Lease Obligations because Owner's estimates are determined to be understated, then Subtenant shall pay to Sublandlord, within 10 days after Subtenant receives an invoice therefor, Subtenant's Pro Rata Share of the excess payment required to be made by Sublandlord. If Sublandlord receives a refund of or credit for any part of its payments of Base Lease Obligations because Owner's estimates are determined to have been overstated, then Subtenant shall receive a refund of or credit for any Additional Rent paid on account of the previous overpayment of such Base Lease Obligations. 3 5. Security Deposit. Subtenant will pay Sublandlord on the date of this Sublease a security deposit of $35,395.00 (the "Security Deposit") as security for the performance of the terms hereof by Subtenant. Subtenant shall not be entitled to interest thereon and Sublandlord may commingle such Security Deposit with any other funds of Sublandlord. The Security Deposit shall not be considered an advance payment of rent or a measure of Sublandlord's damages in case of default by Subtenant. If a default by Subtenant shall occur under this Sublease, Sublandlord may, but shall not be required to, from time to time, without prejudice to any other remedy, use, apply, or retain all or any part of the Security Deposit for the payment of any rent or any other sum in default or for the payment of any other amount which Sublandlord may spend or become obligated to spend by reason of Subtenant's default or to compensate Sublandlord for any other loss or damage which Sublandlord may suffer by reason of Subtenant's default, including, without limitation, costs and attorneys' fees incurred by Sublandlord to recover possession of the Subleased Premises. If Subtenant shall fully and faithfully perform every provision of this Sublease to be performed by it, the Security Deposit shall be returned to Subtenant within 30 days after the Expiration Date. Subtenant agrees that it will not assign or encumber or attempt to assign or encumber the monies deposited herein as the Security Deposit, and that Sublandlord and its successors and assigns shall not be bound by any such actual or attempted assignment or encumbrance. Regardless of any assignment of this Sublease by Subtenant, if Subtenant and its assignee fail to provide evidence satisfactory to Sublandlord of an assignment of the right to receive the Security Deposit or any part of the balance thereof, Sublandlord may return the Security Deposit either to the original Subtenant or to the assignee, without any liability to the other. Following the execution of this Sublease, Sublandlord and Subtenant shall attempt to agree upon the terms and conditions of a letter of credit to replace the Security Deposit described in this Section 5. In the event that Sublandlord and Subtenant are able to agree upon the terms and conditions of a letter of credit as aforesaid, Sublandlord shall reimburse Subtenant the full amount of the cash Security Deposit described in this Section 5 within fifteen (15) days of Sublandlord's receipt of the fully executed and binding letter of credit. Subtenant shall reimburse Sublandlord for the reasonable attorneys' fees incurred by Sublandlord to negotiate and review all drafts of the letter of intent within fifteen (15) days of Subtenant's receipt of Sublandlord's invoice for any such attorneys' fees. 6. Finish Work. Sublandlord shall perform (or cause to be performed) the following work (the "Finish Work") as soon as racticable following the date of this Sublease: (a) Construct a temporary construction wall in the location shown on the Floor Plan; (b) Re-key the entry doors providing access to the Subleased Premises; and (c) Construct a common exit corridor within the Shared Corridor Space, which Sublandlord and Subtenant may use in common for access to and from the Premises and the Subleased Premises, respectively. Included in the construction of the Shared Corridor Space shall be the relocation of an entry door from the Shared Corridor Space to an area that will be outside of the Shared Corridor Space, the installation of an additional sprinkler outside of the Shared Corridor Space and the relocation of a security panel to Sublandlord's new access door. In the event that Subtenant believes that the bid received by Sublandlord to construct the common exit corridor is excessive, Subtenant shall have the right to have other contractors bid to perform substantially the same work and in the event that Subtenant is able to obtain a bid that is significantly less than that received by Sublandlord, and the contractor which provided such bid is reasonably acceptable to Sublandlord (and Owner to the extent required by the Lease), Sublandlord shall utilize the contractor obtained by Subtenant to construct the common exit corridor. Upon completion of such exit corridor, Sublandlord shall remove the temporary construction wall. 4 All Finish Work shall be designed and constructed at Subtenant's expense. Contemporaneously with the execution of this Sublease, Subtenant shall deposit with Sublandlord (in addition to the Security Deposit) the cash sum of $10,000. Sublandlord may draw against such deposit to pay the design and construction costs of the Finish Work. Sublandlord shall provide to Subtenant copies of all invoices submitted for the Finish Work for which draws are made against the deposit. If the deposit shall be insufficient to pay all design and construction costs of the Finish Work, then upon demand from Sublandlord, Subtenant shall deposit with Sublandlord such additional funds as may be necessary to pay the excess costs. If the deposit shall exceed the total design and construction costs of the Finish Work, as calculated upon the completion of the Finish Work, then Sublandlord shall promptly return the excess to Subtenant. Subtenant acknowledges that the temporary construction wall will prevent Subtenant's access to Offices 447 and 448 within the Subleased Premises, as shown on the Floor Plan. Subtenant agrees that while the temporary construction wall is in place, Subtenant will access Offices 447 and 448 only under the supervision of an employee of Sublandlord. As soon as practicable following the date of this Sublease, Subtenant shall, at its expense, construct a wiring closet for the Subleased Premises and install new telecommunications wiring within the Subleased Premises for Subtenant's telephone and computer systems in accordance with a wiring diagram that must be pre-approved by Sublandlord. Subtenant shall cause such work to be performed in a good and workmanlike manner, free of liens, according to all Building rules and regulations applicable to the work, and utilizing procedures approved by Sublandlord which will minimize the disturbance of Sublandlord's operations in the Premises. Subtenant shall reimburse Sublandlord and Owner on demand for any damage caused to any property of Sublandlord or Owner by such work, and Subtenant shall indemnify Sublandlord and Owner against any third party claims arising out of the work. Sublandlord and Owner may each have a representative present throughout performance of the work. Upon termination of this Sublease, Sublandlord may elect to restore the Shared Corridor Space to its condition existing prior to this Sublease and/or remove from the Subleased Premises the wiring closet and telecommunications wiring installed hereunder. In such event, Subtenant shall pay to Sublandlord the cost of such restoration and/or removal within 10 days after receiving an invoice therefor. 7. Telephone System. (a) Sublandlord shall allow Subtenant to temporarily utilize Sublandlord's telephone system until Subtenant establishes its own phone system as provided in subparagraph (b) below. Throughout the period of such temporary use, Subtenant will reimburse Sublandlord for all long distance charges incurred by Subtenant, and will pay to Sublandlord Subtenant's Pro Rata Share of the telephone charges (other than long distance charges) billed to Sublandlord by the telephone utility for the operation of the system. 5 (b) No later than December 1, 1999, Subtenant shall establish its own phone system and account with the telephone utility. If Sublandlord can do so without interfering with or hampering Sublandlord's existing or future phone system (the "PBX System"), Sublandlord will allow Subtenant to install separate trunking cards and/or digital line cards into Sublandlord's PBX System, in order to set up Subtenant's own phone system. During the term hereof, Subtenant shall pay Sublandlord a monthly fee equal to $10.20 per port accessed or installed into or from Sublandlord's PBX System, as independent consideration for the installation right, in recognition of costs incurred by Sublandlord to install and maintain the PBX System. Subtenant shall establish an account directly with the telephone utility for the payment of Subtenant's phone charges. All installations that may in any way impact or affect Sublandlord's PBX System must be pre-approved by Sublandlord and Sublandlord shall have the right and adequate opportunity to have a representative present during any such installations. Subtenant shall be solely responsible for all of the costs associated with the creation or installation of its phone system. No use by Subtenant of Sublandlord's PBX System shall make Sublandlord a "provider" of telephone service or otherwise impose any responsibility on Sublandlord for the quality or continuity of phone service provided to Subtenant, it being agreed that Subtenant shall look directly to the telephone utility for resolution of all such issues. (c) Sublandlord shall allow Subtenant to temporarily utilize up to 10 phone sets while Subtenant is in the process of obtaining its own phone sets. Subtenant may not utilize Sublandlord's phone sets after December 30, 1999 and shall return to Sublandlord all of such phone sets in the same condition in which they were received on or before December 30, 1999. (d) Subtenant shall pay all charges owing by Subtenant to Sublandlord under this Section 7 within 10 days after receiving an invoice therefor. 8. Acceptance of Subleased Premises. Prior to Subtenant's occupancy of the Subleased Premises, Sublandlord shall clean the Subleased Premises in accordance with its customary cleaning procedures for the Premises. Otherwise, Subtenant hereby (i) accepts the Subleased Premises as suitable for the purposes for which same are leased, without the need for any additional improvements to be constructed therein other than the Finish Work; (ii) accepts the Subleased Premises and each and every part and appurtenance thereof as being in a good and satisfactory condition, subject to completion of the Finish Work; and (iii) waives any defects in the Subleased Premises and its appurtenances, other than defects discovered in the Finish Work. Sublandlord shall not be liable to Subtenant or any of its agents, employees, licensees, servants, or invitees for any injury or damage to person or property caused in whole or in part by the condition or design or by any defect in the Subleased Premises or its systems and equipment, and Subtenant, with respect to itself and its agents, employees, licensees, servants, and invitees, hereby expressly assumes all risks of injury or damage to person or property, either proximate or remote, by reason of the condition of the Subleased Premises. Notwithstanding any provision in the Base Lease to the contrary, neither Sublandlord nor Owner shall have any obligation to construct any leasehold improvements to the Subleased Premises other than the Finish Work. Subtenant may not make or allow to be made any alterations, installations, additions or improvements in or to the Subleased Premises, or place safes, vaults or other heavy furniture or equipment within the Leased Premises, without the prior written consent of Sublandlord and Owner. 6 9. Parking. Subtenant may use the parking facilities of the Building, subject to Owner's rules and regulations therefor, at a ratio not to exceed one parking space per [279] Rentable Square Feet within the Subleased Premises. Subtenant shall not have the right to lease any executive parking spaces beneath the Building, notwithstanding Section 15.19 of the Base Lease, it being understood that any such arrangement shall be negotiated directly between Subtenant and Owner. 10. After-Hours Service. Subtenant acknowledges that Offices 447 and 448 within the Subleased Premises (as shown on the Floor Plan) fall outside the Building zone applicable to the remainder of the Subleased Premises for air conditioning and heating service (as set forth in Section 4(a) above). Without Sublandlord's prior, written consent, Subtenant shall not attempt to secure air conditioning or heating for Office 447 or 448 before or after normal Building hours. 11. Security. Sublandlord shall program its security system to allow Subtenant's employees to separately access the Subleased Space with security cards issued by Sublandlord. Subtenant shall reimburse Sublandlord for Subtenant's Pro Rata Share of the costs incurred by Sublandlord to maintain and operate the security system. Such reimbursement shall be paid to Sublandlord from time to time within 10 days after Subtenant's receipt of an invoice therefor. 12. Compliance with Base Lease. Subtenant agrees to comply with and abide by all terms and provisions of the Base Lease (except for the payment of rent), and to perform and assume all of Sublandlord's obligations under the Base Lease, insofar (but only insofar) as such terms, provisions and obligations relate to the Subleased Premises and to the term of this Sublease. Subtenant shall not commit any act that would constitute a default under the Base Lease. Subtenant's obligation under this paragraph shall be enforceable both by Owner and Sublandlord. Subtenant agrees that with respect to the Subleased Premises, Sublandlord shall have all rights as against Subtenant that Owner has as against Sublandlord under the Base Lease. Such rights of Sublandlord include (but are not limited to) (i) the right to receive any notices that Owner is entitled to receive under the Base Lease, (ii) the right to require that Subtenant obtain Sublandlord's consent in any and all circumstances that require the consent of Owner under the Base Lease, including without limitation consent to any assignment of this Sublease by Subtenant or any further sublease of the Subleased Premises, and (iii) the right to be indemnified by Subtenant against certain damages, costs and expenses as if the indemnity provisions under the Base Lease applied to Subtenant and Sublandlord instead of Sublandlord and Owner, respectively, and to the Subleased Premises instead of the entire Premises covered by the Base Lease. Such rights also include the right to act upon a default hereunder by Subtenant in the same manner that Owner might act upon a comparable default by Sublandlord under the Base Lease, it being agreed that Subtenant shall be in default under this Sublease if Subtenant acts or fails to act in a manner which would constitute a "Default" under the Base Lease were Sublandlord to have engaged in a comparable act or failure under the Base Lease. In addition, if Subtenant should fail to fully perform its obligations hereunder, Sublandlord shall have the right to perform such obligations on behalf of Subtenant and to charge Subtenant all costs thereof, whether or not Owner could similarly perform such obligations on behalf of Sublandlord under the Base Lease. Subtenant agrees to notify Sublandlord immediately of any claim by Owner that the Base Lease has been breached with respect to the Subleased Premises. The rights of Sublandlord and obligations of Subtenant set out in the other provisions of this Sublease shall supplement, not be in lieu of, the rights of Sublandlord and obligations of Subtenant under this paragraph. 7 13. Services. Subtenant acknowledges and agrees that the only services, amenities and rights to which Subtenant is entitled under this Sublease are those to which Sublandlord is entitled under the Base Lease (subject to the restrictions and conditions imposed under the Base Lease). Sublandlord shall not be liable to Subtenant for Owner's failure to provide any such services, amenities or rights, nor shall such failure be construed as a breach hereof by Sublandlord or an eviction of Subtenant or entitle Subtenant to an abatement of any of the rent under this Sublease, except to the extent that Sublandlord is entitled to treat the failure as an eviction or to receive an abatement under the Base Lease with respect thereto. Paragraph 7 of the Consent to Sublease referred to in Section 26 below authorizes Subtenant to obtain "services and materials" related to the Subleased Premises. Subtenant agrees it has no need to acquire services or materials from Sublandlord or Owner beyond those expressly set forth in this Lease. Subtenant will not seek to acquire any such services or materials from Owner without the prior, written consent of Sublandlord, and Sublandlord may condition its consent on the deposit by Subtenant with Sublandlord (for payment to Owner) of all costs of the services or materials. 14. No Implied Waiver. The failure of Sublandlord to insist at any time upon the strict performance of any covenant or agreement or to exercise any option, right, power or remedy contained in this Sublease shall not be construed as a waiver thereof. The waiver of any violation of any term, covenant, agreement or condition contained in this Sublease shall not prevent a subsequent act, which would have originally constituted a violation, from having all the force and effect of an original violation. No express waiver shall affect any condition other than the one specified in such waiver and that one only for the time and in the manner specifically stated. A receipt by Sublandlord of any rent with knowledge of the breach of any covenant or agreement contained in this Sublease shall not be deemed a waiver of such breach, and no waiver by Sublandlord of any provision of this Sublease shall be deemed to have been made unless expressed in writing and signed by Sublandlord. 15. Attorneys' Fees and Legal Expenses. Should either party hereto institute any action or proceeding in court to enforce any provision hereof or for damages by reason of any alleged breach of any provision of this Sublease or for any other judicial remedy, the prevailing party shall be entitled to receive from the losing party all reasonable attorneys' fees and all court costs in connection with such proceeding. 16. Subordination. This Sublease and all rights of Subtenant hereunder are subject and subordinate to (i) the Base Lease, and (ii) any mortgage or deed of trust, blanket or otherwise, which now or may hereafter affect the Subleased Premises. 8 17. Quiet Enjoyment. Provided Subtenant pays the rent payable under this Sublease as and when due and payable and keeps and fulfills all of the terms, covenants, agreements and conditions to be performed by Subtenant hereunder, neither Sublandlord nor any person lawfully claiming by, through or under Sublandlord shall disturb Subtenant's peaceable and quiet enjoyment of the Subleased Premises during the term of this Sublease, but Subtenant's right to such enjoyment is expressly subject and subordinate to the restrictions, requirements, and conditions of the Base Lease and of any deeds of trust or mortgages which are superior to this Sublease, as hereinabove set forth. No warranties, express or implied, are made by Sublandlord as to title to the Subleased Premises except as expressly set out in this paragraph. 18. Notices. Each provision of this Sublease, or of any applicable governmental laws, ordinances, regulations, and other requirements with reference to the sending, mailing, or delivery of any notice or with reference to the making of any payment by Subtenant to Sublandlord, shall be deemed to be complied with when and if the following instructions are complied with: (a) All rent and other payments required to be made by Subtenant to Sublandlord hereunder shall be payable to Sublandlord at the address set forth below, or at such other address as Sublandlord may specify from time to time by written notice delivered in accordance herewith. (b) Any notice or communication required or permitted hereunder shall be given in writing, sent by (i) personal delivery, or (ii) expedited delivery service with proof of delivery, or (iii) prepaid facsimile or (iv) United States mail, postage prepaid, registered or certified mail, addressed as follows: To Sublandlord: Brigham Oil & Gas, L.P. 6300 Bridgepoint Parkway Building 2, Suite 500 Austin, Texas 78730 Attn: David Brigham Fax: (512) 427-3393 To Subtenant: ShowSupport.com, Inc. 6300 Bridge Point Parkway Building 2, Suite 450 Austin, Texas 78730 Attn: Mr. Vinay Bhagat Fax:_____________________ 9 or to such other address or to the attention of such other person as hereafter shall be designated in writing by the applicable party sent in accordance herewith. Any such notice or communication shall be deemed to have been given either at the time of personal delivery or, in the case of delivery service or mail, as of the date of first attempted delivery at the address and in the manner provided herein or, in the case of facsimile, upon receipt. 19. Real Estate Commissions. Sublandlord has agreed to pay to Colliers Oxford Commercial, Inc. ("Agent") a commission for negotiating this Sublease pursuant to a separate agreement with the Agent. Under that agreement, the Agent will share the commission with CB Richard Ellis, Inc., as cooperating agent. Except as set forth in the preceding two sentences, each party represents that it has not authorized any broker or finder to act on its behalf in connection with this Sublease and that it has not dealt with any broker or finder purporting to act on behalf of any other party. Each party agrees to defend, indemnify and hold harmless the other from and against any and all claims, losses, damages, costs or expenses (including reasonable attorney's fees) arising out of or resulting from any agreement, arrangement or understanding alleged to have been made by such party or on its behalf with any broker or finder in connection with this Sublease or the transaction contemplated hereby. 20. Severability. If any term or provision of this Sublease or the application thereof to any person or circumstances shall be to any extent invalid and unenforceable, the remainder of this Sublease, or the application of such term or provision to persons or circumstances other than those as to which it is invalid or unenforceable, shall not be affected thereby. 21. No Representations. Sublandlord and Sublandlord's agents have made no representations or promises with respect to the Subleased Premises except as herein expressly set forth and no rights, easements, or licenses are acquired by Subtenant by implication or otherwise except as expressly set forth in the provisions of this Sublease. 22. Entire Agreement. This Sublease sets forth the entire agreement between the parties and no amendment or modification of this Sublease shall be binding or valid unless expressed in a writing executed by both parties hereto. Any and all agreements, written or oral, entered by the parties prior to the date of this Sublease are merged into, and superseded by, this Sublease. 23. Paragraph Headings. The paragraph headings contained in this Sublease are for convenience only and shall in no way enlarge or limit the scope or meaning of the various paragraphs hereof. 24. Binding Effect. All of the covenants, agreements, terms, and conditions to be observed and performed by the parties hereto shall be applicable to and binding upon their respective heirs, personal representatives, successors and, to the extent assignment is permitted hereunder, their respective assigns. 10 25. Options. Notwithstanding any provision in the Base Lease to the contrary, Subtenant shall have no right to exercise any renewal, extension, expansion, right of first refusal, cancellation or other similar option or right afforded to Sublandlord under the Base Lease. 26. Contingency. This Sublease is contingent upon Owner's consent and approval, which is to be evidenced by the signature of Owner to a Consent to Sublease on a form prepared by Owner and reasonably acceptable to Sublandlord and Subtenant. Contemporaneously with the execution of this Sublease, Sublandlord and Subtenant shall execute such Consent to Sublease. IN WITNESS WHEREOF, Sublandlord and Subtenant have executed this Sublease as of the date first above written. BRIGHAM OIL & GAS, L.P. By: Brigham, Inc., a Texas corporation, Managing General Partner By: /s/ David T. Brigham Name: David T. Brigham Title: Vice President SHOWSUPPORT.COM, INC. By: /s/ Vinay Bhagat Name: Vinay Bhagat Title: President & CEO 11 EX-10.31.2 4 AGREEMENT AGREEMENT AREA OF MUTUAL INTEREST TIGRE POINT AND ROB-L PROSPECTS VERMILION PARISH, LOUISIANA Special Note: Tigre Enery Corporation must receive a signed copy of this Agreement by Fax @ (713) 468-1352 no later than 5:00 p.m., Monday, March 6, 2000 (Tigre and its partner will not bid at the Sale unless these requirements are met) When executed by all parties hereto and a faxed copy has been received by Tigre Energy Corporation on or before 5:00 p.m., Monday, March 6, 2000, this Agreement (the "Agreement") between Tigre Energy Corporation ("TEC"), Brigham Oil & Gas, L.P. ("BOG"), Resource Investors Management Company ("RIMCO") will be deemed to be in effect at 5:00 p.m., Monday, March 6, 2000 and will modify the original agreement executed by the parties on or about January 24, 1997, with respect to their exploration efforts in the RIMCO/Tigre Project (being ownership interest in all leasehold and other property of every kind located within the lands described on Exhibit A hereto). NOW, THEREFORE, in consideration of good and valuable considerations, the receipt and sufficiency of which is hereby acknowledged, and the premises, mutual covenants and agreements contained herein TEC, BOG, and RIMCO agree as follows: 1. Distribution of Interests - If the requirement for prompt response from BOG and RIMCO is met (as set oiut in the "Special Note" above), TEC and its partner, acting through Cypress Energy, the lease broker, will provide funds to bid in an attempt to acquire all or part of the nominated acreage located within the above defined AMI at the State Lease Sale scheduled for 9:00 AM, Wednesday, March 8, 2000. TEC, the TEC Partner, Huerfano Corporation, BOG and RIMCO will each hold the following estimated interests, and no other, in the RIMCO/Tigre Project: Before Project Payout After Project Payout - ----------------------------------------------------------------------- W.I% R.I% W.I% R.I% ---- ---- ---- ---- Drilling Participant(s) 100.00 75.00 80.00 60.000 TEC 0.00 0.50 7.50 6.125 TEC Partner 0.00 0.50 7.50 6.125 BOG 0.00 0.50 2.50 2.375 RIMCO 0.00 0.50 2.50 2.375 Huerfano 0.00 3.00 0.00 3.000 State of Louisiana 0.00 20.00 0.00 20.000 - ----------------------------------------------------------------------- TOTAL(%) 100.00 100.00 100.00 100.00 2. Availability of 3-D Seismic data - Subject to the terms and the applicable license agreements, BOG will make available all seismic data, along with interpretations which BOG has within its possession or control related to the RIMCO/Tigre Project (the "3-D Data"). Further, for a period of two years from the date hereof, subject to the terms of the applicable seismic license agreements, BOG will provide prospective drilling participants the opportunity to review the 3-D Data and TEC, or its designee, will be responsible for marketing the RIMCO/Tigre Project. BOG will also make available all computer equipment necessary to review and analyze the 3-D Data to prospective drilling participants. 3. UNOCAL/AMOCO Farmout. BOG will provide limited assistance to TEC, or its designee, in obtaining a farm-out agreement with UNOCAL/AMOCO for leasehold rights in Vermillion Block 14, which is contained within the AMI. 4. Terms of the Trade - TEC will provide the Terms of the Trade in marketing the project to prospective Drilling Participants. Distribution of interests will be similar to those set out in Paragraph 1 above and reimbursement of sunk costs will be limited to actual lease acquisition cost, brokerage fees and miscellaneous expenses to TEC and its partner for lease(s) acquired after March 6, 2000. Terms of the Trade could vary depending on the market for prospects during the coming year(s). The final terms of trade shall remain within the sole discretion of TEC and the parties acknowledge that (i) before-payout revenue-interests and (ii) after-payout revenue-interests and working-interests may have to be adjusted in order to successfully market the Project. Any such adjustments will be made proportionately to all those interests described in the table set forth in Paragraph 1 above, with the exception of the State of Louisiana and the Drilling Participants. 5. Drilling Obligations. This Agreement eliminates any and all obligations of BOG to perform any drilling within the AMI. Time is the essence of this Agreement. IN WITNESS HEREOF, the parties hereto have executed this Agreement as of and effective on the 6th DAY of MARCH, 2000 RIMCO PRODUCTION CO. TIGRE ENERGY CORPORATION /s/ A.L. Jordan /s/ Jeffrey W. Wheelock _________________________________ _________________________________ By: A.L. Jordan Jeffrey W. Wheelock, President Title: President BRIGHAM OIL & GAS, L.P. /s/ Ben M. Brigham _________________________________ By: Ben M. Brigham Title: President EX-10.65 5 JOINT DEVELOPMENT AGREEMENT EXHIBIT 10.65 JOINT DEVELOPMENT AGREEMENT This Joint Development Agreement (the "Agreement") is entered into effective as of February 10, 1999, by and between BRIGHAM OIL & GAS, L.P. ("Brigham") and ASPECT RESOURCES LLC ("Aspect") (Brigham and Aspect being sometimes referred to herein individually as a "Party" and collectively as the "Parties"). I. FUNDING LEASE, MINERAL AND ROYALTY ACQUISITIONS Concurrent with its execution of this Agreement Aspect shall forward to Brigham two hundred thousand dollars (the "Initial Deposit") to be utilized by Brigham after the effective date of this Agreement exclusively for the purpose of acquiring interests in oil and gas leases ("Leasehold Interests") and/or mineral or royalty interests (collectively referred to as "Royalty Interests") within the lands which are described in Exhibit A which is attached hereto and incorporated herein for all purposes (the "Subject Lands") within two years from the date hereof (the "AMI Term") within the limitations contained below. In the event that it appears to Brigham that it will spend more than the Initial Deposit in acquiring Leasehold Interests and/or Royalty Interests within the Subject Lands during the AMI Term, Brigham shall provide Aspect with copies of the instruments evidencing the Leasehold Interests and Royalty Interests acquired to date (the "Acquired Interests"), lease purchase reports related to the Acquired Interests, and seismic interpretations covering the lands that are the subject of the Leasehold Interests and/or Royalty Interests acquired to date ("Back-Up Materials"). In the event that Aspect desires to review materials in addition to the Back-Up Materials, Aspect shall have the right to come into Brigham's offices at reasonable times prior to the expiration of the Election Period (as defined below) in order to view a reasonable amount of additional information and data with respect to the Prospect Areas within which the Acquired Interests are located, subject to any third-party limitations which are placed upon such materials. Within three business days of Aspect's receipt of the Back-Up Materials (the "Election Period") Aspect shall have the election to either: (i) fund an additional two hundred thousand dollars (a "Subsequent Deposit") to be utilized by Brigham in acquiring Leasehold Interests and/or Royalty Interests within the Subject Lands ("Full Continuation"), (ii) fund an additional two hundred thousand dollars that may only be utilized by Brigham in acquiring Leasehold Interests and/or Royalty Interests within Prospect Areas ("Active Prospect Areas") within which Aspect has already funded the acquisition of Acquired Interests ("Partial Termination"), or (iii) completely terminate its obligation to fund the acquisition of additional Leasehold Interests and Royalty Interests beyond the Subsequent Deposit previously made by Aspect ("Full Termination"). In order to elect to fund an additional Subsequent Deposit of two hundred thousand dollars under Full Continuation or Partial Termination, Aspect must notify Brigham of such election in writing and tender to Brigham in readily available funds the Subsequent Deposit prior to the expiration of the Election Period. In the event of Full Termination, this Agreement shall terminate as to any Leasehold Interests and Royalty Interests which are acquired after the funds from the Initial Deposit have been exhausted by Brigham, whichever is the earlier to occur. In the event of Partial Termination this Agreement shall terminate as to any Leasehold Interests and Royalty Interests which are acquired after the funds from the Initial Deposit have been exhausted by Brigham, except as to Leasehold Interests and Royalty Interests that cover lands that are located within Active Prospect Areas. In the event of Full Termination any outstanding assignments which are due shall be completed and any activities for the acquisition of Acquired Interests on Aspect's behalf shall cease. In the event that Aspect has elected Full Continuation as provided above and it subsequently appears to Brigham that it will spend more than the last Subsequent Deposit which has been made by Aspect in acquiring Leasehold Interests and/or Royalty Interests within the Subject Lands during the AMI Term, Brigham shall again provide Aspect with copies of the Back-Up Materials related to the Acquired Interests obtained with such Subsequent Deposit and Aspect shall have the same elections provided for in the previous paragraph to make another Subsequent Deposit of two hundred thousand dollars under the same terms and conditions which are set forth above. Similarly, during the AMI Term Aspect shall continue to have the same elections as to continued participation as the immediately preceding Subsequent Deposit runs out until such time as Aspect elects either Partial Termination or Full Termination. 1 In the event that Aspect has previously elected Partial Termination as provided above and it appears to Brigham that it will spend more than the last Subsequent Deposit which has been made by Aspect in acquiring Leasehold Interests and Royalty Interests within the Active Prospect Areas during the AMI Term, Brigham shall provide Aspect with copies of the Back-Up Materials related to the Acquired Interests obtained with such Subsequent Deposit. Within three business days of Aspects receipt of the Back-Up Materials ("Election Period") Aspect shall have the election to either: (i) fund an additional two hundred thousand dollar Subsequent Deposit that may only be utilized by Brigham in acquiring Leasehold Interests and/or Royalty Interests within the Active Prospect Areas, or (ii) elect Full Termination and thus completely terminate its obligation to fund the acquisition of additional Leasehold Interests and Royalty Interests beyond the last Subsequent Deposit made. During the AMI Term Aspect shall continue to have the same elections as to the continued funding of Subsequent Deposits in the amount of two hundred thousand dollars for continued participation in the Active Prospect Areas as each prior Subsequent Deposit runs out until such time as Aspect elects Full Termination. Anything to the contrary contained above notwithstanding, in the event that prior to the spending or commitment of all of the available funds under the last Initial Deposit or Subsequent Deposit which is made by Aspect right before Aspect has elected Full Termination or Partial Termination hereunder, Brigham has acquired or intends to acquire Leasehold Interests and/or Royalty Interests from a mineral, leasehold or royalty owner and the total consideration for such package of Leasehold Interests and/or Royalty Interests shall exceed the amount of the last made Initial Deposit or Subsequent Deposit, no part of the Leasehold Interests and/or Royalty Interests that are included in the package owned by such mineral, leasehold or royalty owner shall be funded through Aspect's Deposit or be deemed an Acquired Interest for purposes of this Agreement, without the mutual agreement of both Aspect and Brigham; provided, however, that in the event that Aspect has only elected Partial Termination and the entire package of Leasehold Interests and/or Royalty Interests are located within Active Prospect Areas, such Leasehold Interests and/or Royalty Interests shall constitute Acquired Interests for purposes of this Agreement. Anything to the contrary contained herein notwithstanding, the Parties agree that any interests that are acquired by Brigham (i) as part of the acquisition of producing properties, (ii) as part of the acquisition of substantially all of the assets of another company, or (iii) as a result of any merger or other consolidation of assets with another company shall not constitute Leasehold Interests, Royalty Interests or Acquired Interests for purposes of this Agreement. In addition, the Parties agree that the interests to be acquired pursuant to the terms of a farm-in (or other similar arrangement) under which interests in oil and/or gas leasehold are not earned by Brigham unless Brigham commits to drill a well and pay a disproportionate share (disproportionate to Brigham's final revenue interest in the well) of the drilling and/or completion costs for such well, shall not constitute Leasehold Interests or Royalty Interests for purposes of this Agreement. Such excluded interests shall not be acquired with the funds provided by Aspect hereunder. 2 For purposes of this Article I, the Initial Deposit and any Subsequent Deposit funds are to be utilized to pay (i) for any brokerage costs actually associated with the Acquired Interests incurred on or after February 1, 1999 to run title and acquire the Leasehold Interest and/or Royalty Interest, (ii) all lease bonus payments, royalty or mineral interest acquisition payments to the mineral or royalty interest owner, (iii) any delay rentals that are paid prior to the expiration of the Brigham Election Period (as defined in Article III below) for the subject Leasehold Interest and/or Royalty Interest and (iv) any other costs or consideration that are directly related to the acquisition of a Leasehold Interest or Royalty Interest pursuant to the terms hereof. It is further stated that none of the funds provided by Aspect shall be used to cover any of Brigham's overhead expenses. For purposes of this Article I, a Leasehold Interest or Royalty Interest shall be deemed to have been acquired at such time as the mineral, leasehold or royalty owner has executed an instrument in a form acceptable to Brigham, has delivered such instrument to Brigham or to a third party for delivery to Brigham and such mineral, leasehold or royalty owner has been paid all of the consideration which is due for such acquisition. Within 60 days of the earlier to occur of the end of the AMI Term or Full Termination, Brigham shall reimburse Aspect for any part of the Initial Deposit or any Subsequent Deposits which were not utilized to obtain Acquired Interests hereunder. II. BRIGHAM PARTIAL PAYBACK ELECTION At any time prior to the expiration of 6 months following the end of a calendar quarter that occurred during the AMI Term (the earlier to occur of the expiration of such 6 month period or such time as Brigham makes the election under this Article II being herein referred to as the "Brigham Election Period"), Brigham shall have the election to reimburse Aspect for 75% of all of the costs which have were funded by Aspect and utilized to acquire the Leasehold Interests that were acquired by Brigham within such calendar quarter. To exercise such election Brigham shall tender the reimbursement in readily available funds to Aspect prior to the expiration of such six month period. The Parties recognize and acknowledge that Brigham does not have the election to reimburse Aspect for any of the costs which have been utilized to acquire Royalty Interests during the AMI Term. III. ASSIGNMENT OF INTEREST IN ACQUIRED INTERESTS Upon obtaining an Acquired Interest Brigham shall promptly assign Aspect an interest in such Acquired Interest utilizing the form of Assignment which is attached hereto as Exhibit B. In the event that the Acquired Interest is a Leasehold Interest, Brigham shall assign an undivided twenty-five percent (25%) interest in such Acquired Interest to Aspect. In the event that the Acquired Interest is a Royalty Interest, Brigham shall assign an undivided fifty percent (50%) interest in such Acquired Interest to Aspect. Immediately following the expiration of the Brigham Election Period for Acquired Interests obtained during a calendar quarter hereunder, in the event that Brigham has not elected to reimburse Aspect for 75% of the costs which were funded by Aspect to acquire the Leasehold Interests that make up the Acquired Interests obtained during such calendar quarter as provided in Article II above, Brigham shall assign to Aspect an additional 25% interest in the Leasehold Interests that were acquired during such calendar quarter utilizing the form of Assignment which is attached hereto as Exhibit B. Any assignment shall be conveyed subject only to revenue burdens as acquired. Brigham will not retain any burden against production on the interests in the Acquired Interests that are assigned to Aspect. 3 IV. PROSPECT DESIGNATION The Parties agree that the separate areas described in Exhibit C shall constitute separate prospect areas (herein defined as "Prospect Area") for potential future exploration and/or development. In addition, prior to obtaining an Acquired Interest that covers lands that are not already included within an existing Prospect Area, Brigham shall designate in writing to Aspect a Prospect Area which includes within its boundaries at a minimum all of the lands which are the subject of the Acquired Interest. In addition, the boundaries of each such designated Prospect Area shall cover at least the geographical extent of what Brigham reasonably believes could potentially be a continuous oil and/or gas reservoir that may be proved up as potentially productive with a single exploratory well. V. JOINT OPERATING AGREEMENT Upon the designation of a Prospect Area as provided in Article IV above, the Parties' interests in Leasehold Interests that are located within each such Prospect Area shall be deemed to be governed by a separate Joint Operating Agreement in the form attached hereto as Exhibit D. Prior to the commencement of drilling operations by either Party hereto within a Prospect Area, each Party agrees to execute a Joint Operating Agreement in the form attached hereto as Exhibit D which shall be completed to describe the Contract Area for such Joint Operating Agreement as the Prospect Area. Anything to the contrary contained in the Joint Operating Agreement notwithstanding, prior to the expiration of one hundred eighty days following Brigham's designation of the subject Prospect Area, without Brigham's mutual consent, Aspect shall not have the right to propose the drilling of a well within such Prospect Area unless such well is necessary to maintain a Leasehold Interest. VI. CONFIDENTIALITY AND NON-COMPETE Without obtaining Brigham's prior written consent to same, for a period of 5 years following the effective date of this Agreement and subject to any additional restrictions that are imposed by the seismic contractor or other party licensing the seismic data to Brigham, Aspect shall not disclose any information related to the seismic data or seismic data interpretations covering any part of the Subject Lands that Brigham may provide or disclose to Aspect. In addition, during the AMI Term, Aspect shall not compete with Brigham within the Subject Lands by acquiring any interest in oil, gas and or other minerals of any kind (whether leasehold, mineral fee, royalty, overriding royalty or otherwise) within the Subject Lands, through any related entities, agents or otherwise, other than the ownership acquired hereunder. Furthermore, for a period of 5 years following the effective date of this Agreement, Aspect shall not compete with Brigham within any of the Prospect Areas within which Acquired Interests have been obtained, by acquiring any additional interest in oil, gas and or other minerals of any kind (whether leasehold, mineral fee, royalty, overriding royalty or otherwise) within the Subject Lands, through any related entities, agents or otherwise, other than the ownership acquired hereunder and the rights related thereto pursuant to the governing Joint Operating Agreement. In the event that there are any conflicts or inconsistencies between the terms of this Agreement and the Joint Operating Agreement that governs the Parties' interests in any Prospect Area, the terms and provisions of this Agreement shall control. 4 VII. DISCLAIMERS RELATED TO SEISMIC DATA AND INTERPRETATIONS ASPECT UNDERSTANDS AND AGREES THAT BRIGHAM MAKES NO REPRESENTATIONS OR WARRANTIES OF ANY KIND AS TO THE SEISMIC DATA OR INTERPRETATIONS THAT HAVE BEEN OR MAY IN THE FUTURE BE PROVIDED TO ASPECT BY BRIGHAM, INCLUDING WITHOUT LIMITATION, THEIR FITNESS FOR A PARTICULAR PURPOSE, MERCHANTABILITY OR ACCURACY, AND BRIGHAM HEREBY DISCLAIMS ANY AND ALL SUCH REPRESENTATIONS OR WARRANTIES, AND ANY USE OF SUCH SEISMIC DATA OR INTERPRETATIONS BY ASPECT, OR ANY ACTION TAKEN BY ASPECT SHALL BE BASED SOLELY ON THEIR OWN JUDGMENT, AND NEITHER BRIGHAM , OR ITS SUCCESSORS OR ASSIGNS, SHALL BE LIABLE OR RESPONSIBLE TO ASPECT OR ITS SUCCESSOR OR ASSIGNS FOR ANY LOSS, COST, DAMAGES, OR EXPENSE WHATSOEVER, INCLUDING INCIDENTAL OR CONSEQUENTIAL DAMAGES, INCURRED OR SUSTAINED AS A RESULT OF THE USE OF OR RELIANCE UPON SUCH SEISMIC DATA OR INTERPRETATIONS, REGARDLESS OF WHETHER OR NOT SUCH LOSS, COST, DAMAGE OR EXPENSE IS FOUND TO RESULT IN WHOLE OR IN PART FROM THE SOLE OR CONCURRENT NEGLIGENCE OR OTHER FAULT OF BRIGHAM. VIII. ASPECT FIRST LOOK In the event that at any time during the AMI Term and prior to an election as to Full Termination by Aspect, Brigham desires to sell or assign leasehold or working interests within the Subject Lands in return for consideration that does not include the trade or exchange of interests owned by the third party which are located within the Subject Lands, then in such event, Brigham shall provide Aspect the first opportunity to review the interests that are proposed to be sold or assigned and Brigham shall make a good faith effort to negotiate a mutually agreeable arrangement for the sell or assignment of such interests to Aspect ("First Look"). However, in the event that Brigham and Aspect do not reach agreement with respect to the sell or assignment of such interests within a reasonable amount of time, which amount of time shall in no event exceed fifteen days, Brigham shall have the right to market, sell and/or assign such interests to other parties upon any terms Brigham deems acceptable, regardless of whether or not such terms were offered to Aspect. Anything to the contrary contained above notwithstanding, in the event that Aspect has elected Partial Termination, the First Look described above shall only apply to interests that are located within Active Prospect Areas that are proposed to be sold or assigned by Brigham. In addition, anything to the contrary contained herein notwithstanding, Aspect shall not have a First Look with respect to any interests which are to be sold or assigned by Brigham pursuant to an agreement with a third party which also provides for such third-party's participation or ownership in leasehold, projects, prospects and/or wells which are located outside of the Subject Lands. 5 IX. MISCELLANEOUS Subject to the terms of any restrictions that may be contained in any Acquired Interest and the limitations contained below in this paragraph, any Party may assign, convey or otherwise transfer all or any part of its interest under the terms of this Agreement. This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and their respective assigns of rights hereunder; provided, however, that the conveyance, assignment or other instrument of transfer vesting such transferee with all or part of such rights, interests and unaccrued obligations must expressly provide that the assignment, conveyance or other transfer is made subject to the terms and conditions contained in this Agreement and in the absence of such language in the instrument of transfer any such attempted conveyance, assignment or other transfer shall be void and of no legal force and effect. In addition, in any such assignment, conveyance or other instrument of transfer, the transferee shall expressly agree to assume and be responsible for any liabilities, damages, obligations, covenants and agreements arising from and after the date of such assignment, conveyance or other transfer, in relation to or otherwise out of the properties, rights and interests that are the subject of this Agreement and/or such assignment, conveyance or transfer, and the transferor shall remain responsible for any of the foregoing arising prior to the date of such assignment, conveyance or other transfer, and in the absence of such language in the instrument of transfer, any such attempted transfer shall be void and of no force and effect. Any subsequent assignment, conveyance or transfer shall likewise contain express language so allocating responsibility as between transferor and transferee, and in the absence of such language in the instrument of transfer, any such attempted transfer shall be void and of no force and effect. All notices and other communications required or permitted under this Agreement shall be in writing, and unless otherwise specifically provided, shall be delivered personally, or by mail, telecopier or delivery service, to the addresses set forth opposite the signatures of the Parties below, and shall be considered delivered upon the date of receipt. Each Party may specify its proper address or any other post office address within the continental limits of the United States by giving notice to other Parties, in the manner provided in this Section, at least ten (10) days prior to the effective date of such change of address. This Agreement supersedes any and all prior and existing agreements, whether oral or in writing, between the Parties hereto with respect to the subject matter hereof and contains all of the covenants and agreements between the Parties with respect to the subject matter hereof. Each Party acknowledges that no Party to this Agreement or anyone on their behalf has made any representations, inducements, promises or agreements, orally or otherwise, relating to the subject matter of this Agreement that are not embodied herein. This Agreement may be executed in multiple counterparts, each of which shall be binding upon the signing Party or Parties thereto as fully as if all Parties had executed one instrument, and all of such counterparts shall constitute one and the same instrument. If counterparts of this Agreement are executed, the signatures of the Parties, as affixed hereto, may be combined in and treated and given effect for all purposes as a single instrument. However, anything to the contrary contained herein notwithstanding, this Agreement shall not be binding upon any Party hereto unless and until all of the Parties sign a counterpart thereof. IN WITNESS WHEREOF this Agreement is executed by the Parties on the dates set forth opposite their respective signatures below but is effective for all purposes as of the date first set forth above. Address: BRIGHAM OIL & GAS, L.P., 6300 Bridge Point Pkwy by Brigham, Inc. Bldg. 2, Suite 500 its Managing General Partner Austin, Texas 78730 Phone (512) 427-3300 Fax (512) 427-3400 Dated:______________________ By: /s/ Ben M. Brigham --------------------------------- Ben M. Brigham, President 6 Address: ASPECT RESOURCES LLC 511 16th Street, Suite 300 by Aspect Management Corporation Denver, Colorado 80202 its Manager Phone (303) 573-7011 Fax (303) 573-7340 By: /s/ Alex Campbell Dated:______________________ Alex Campbell, Vice President 7 EX-10.65.1 6 FIRST AMENDMENT EXHIBIT 10.65.1 FIRST AMENDMENT TO JOINT DEVELOPMENT AGREEMENT This First Amendment (the "Amendment") to that certain Joint Development Agreement (the "Agreement") entered into dated effective as of February 10, 1999, by and between BRIGHAM OIL & GAS, L.P. ("Brigham") and ASPECT RESOURCES LLC ("Aspect") (Brigham and Aspect being sometimes referred to herein individually as a "Party" and collectively as the "Parties"), is dated effective as of May 1, 1999. I. DEFINED TERMS Unless a term is specifically defined in this Amendment, all capitalized terms shall have the defined meaning set forth in the Agreement. II. AMENDMENT TO EXPAND SUBJECT LANDS The Parties hereby agree that Exhibit A to the Agreement is replaced with Exhibit A which is attached hereto and incorporated herein for all purposes. III. AMENDMENT TO PROVIDE FOR AVO COSTS In addition to and without limitation of its other funding obligations under the Agreement, Aspect hereby agrees to pay Brigham for the actual third-party costs that are incurred to purchase processed amplitude versus offset ("AVO") data covering approximately 65.64 square miles of land within the Subject Lands which is generally outlined on Exhibit B attached hereto. Brigham shall not be required to reimburse Aspect for any of the costs described in this Article III, regardless of whether or not Brigham exercises its partial payback election which is set forth in Article II of the Agreement. The Parties estimate that the AVO processing and analysis costs will total approximately $400 per square mile. Following Aspect's receipt of an invoice from Brigham, Aspect shall promptly reimburse Brigham for the total costs incurred to acquire the AVO data, but in any event such payment shall be made within 30 days of Aspect's receipt of the invoice. In return for Aspect funding the above-described AVO costs, Brigham shall interpret the resulting AVO data and, subject to the restrictions that have been imposed by the seismic contractor or other party licensing the seismic data to Brigham, Brigham shall immediately share the results of such interpretation with Aspect during the AMI Term. ASPECT UNDERSTANDS AND AGREES THAT BRIGHAM MAKES NO REPRESENTATIONS OR WARRANTIES OF ANY KIND AS TO THE AVO DATA OR INTERPRETATIONS THAT MAY BE PROVIDED TO ASPECT BY BRIGHAM, INCLUDING WITHOUT LIMITATION, THEIR FITNESS FOR A PARTICULAR PURPOSE, MERCHANTABILITY OR ACCURACY, AND BRIGHAM HEREBY DISCLAIMS ANY AND ALL SUCH REPRESENTATIONS OR WARRANTIES, AND ANY USE OF SUCH AVO DATA OR INTERPRETATIONS BY ASPECT, OR ANY ACTION TAKEN BY ASPECT SHALL BE BASED SOLELY ON THEIR OWN JUDGMENT, AND NEITHER BRIGHAM , OR ITS SUCCESSORS OR ASSIGNS, SHALL BE LIABLE OR RESPONSIBLE TO ASPECT OR ITS SUCCESSOR OR ASSIGNS FOR ANY LOSS, COST, DAMAGES, OR EXPENSE WHATSOEVER, INCLUDING INCIDENTAL OR CONSEQUENTIAL DAMAGES, INCURRED OR SUSTAINED AS A RESULT OF THE USE OF OR RELIANCE UPON SUCH AVO DATA OR INTERPRETATIONS, REGARDLESS OF WHETHER OR NOT SUCH LOSS, COST, DAMAGE OR EXPENSE IS FOUND TO RESULT IN WHOLE OR IN PART FROM THE SOLE OR CONCURRENT NEGLIGENCE OR OTHER FAULT OF BRIGHAM. IV. MISCELLANEOUS Except as expressly modified herein, all other terms, conditions and provisions of the Agreement shall remain in full force and effect. This Amendment may be executed in multiple counterparts, each of which shall be binding upon the signing Party or Parties thereto as fully as if all Parties had executed one instrument, and all of such counterparts shall constitute one and the same instrument. If counterparts of this Amendment are executed, the signatures of the Parties, as affixed hereto, may be combined in and treated and given effect for all purposes as a single instrument. However, anything to the contrary contained herein notwithstanding, this Amendment shall not be binding upon any Party hereto unless and until all of the Parties sign a counterpart thereof. IN WITNESS WHEREOF this Amendment is executed by the Parties on the dates set forth opposite their respective signatures below but is effective for all purposes as of the date first set forth above. BRIGHAM OIL & GAS, L.P. ASPECT RESOURCES LLC by Brigham, Inc. by Aspect Management Corporation its Managing General Partner its Manager By: /s/ Ben M. Brigham By: /s/ Alex Campbell ------------------------------------- --------------------------------- Ben M. Brigham, President Alex Campbell, Vice President Date: 9/28/99 Date: 9/30/99 ----------------------------------- ------------------------------- EX-10.65.2 7 ACQUISITION AND PARTICIPATION AGREEMENT ACQUISITION AND PARTICIPATION AGREEMENT This Acquisition and Participation Agreement (this "Agreement") is executed as of the 21st day of October, 1999, by Brigham Oil & Gas, L.P. ("BOG") and Aspect Resources LLC ("Aspect") (BOG and Aspect are herein collectively called "Parties" or "Participants" and individually called a "Party" or a "Participant"). Recitals: (a) BOG currently owns interests in and to the oil and gas leases described in Exhibit A hereto (such leases, insofar only as they cover the lands described in Exhibit A hereto, and further as heretofore amended or extended, are herein called the "BOG Leases") and proprietary interpretations of certain geological and/or geophysical information relating to the AMI Lands, as hereinafter defined (the "G & G Data"). (b) Aspect desires to acquire from BOG, and BOG agrees to assign to Aspect, a share of the undivided interest of BOG in the BOG Leases and the right to use the G & G Data, all upon and subject to the terms and conditions hereof. (c) BOG and Aspect further desire to establish an area of mutual interest covering all of the AMI Lands, and agree upon a scheme of joint operation thereof, all upon and subject to the terms and conditions hereof. Defined Terms: "Acquired Interest" shall have the meaning assigned to it in Section 2.2. "Affiliate" means (a) any Person directly or indirectly owning, controlling or holding with power to vote 50% or more of the outstanding voting securities of any other Person, (b) any Person 50% or more of whose outstanding voting securities are directly or indirectly owned, controlled or held with power to vote by any other Person, (c) any Person directly or indirectly controlling, controlled by or under common control with any other Person, and (d) any officer, director, partner or sanguinal or affinal kin of any other Person or any Person described in subsection (c) of this paragraph; as used in this definition, the term "Person" means an individual, an estate, a corporation, a partnership, an association, a joint stock company, a limited liability company, a joint venture, a trust and any other legally recognized entity. "AMI" shall have the meaning assigned to it in Section 2.1(a). "AMI Lands" shall mean the lands described in Exhibit A hereto. "AMI Party" and "AMI Parties" shall have the meaning(s) assigned to them in Article II. "AMI Term" shall have the meaning assigned to it in Section 2.1(b). 1 "BOG Leases" has the meaning assigned to it in the Recitals. "BOG/Aspect Assignment" shall have the meaning assigned to it in Section 3.1. "Business Days" means all days of the week, other than Saturday, Sunday or any legal holiday on which commercial banks in Texas are closed for business. "Code" shall have the meaning assigned to it in Section 1.1. "Dickson Prospect" has the meaning assigned to it in Section 4.1. "Effective Date" shall have the meaning assigned to it in the BOG/Aspect Assignment. "Farm-In" means a farm-in or any other agreement, other than a Lease or Option, that affords the holder the right to earn or otherwise acquire an interest in oil, gas or other minerals, whether leasehold, fee, royalty, overriding royalty or otherwise. "G & G Data" has the meaning assigned to it in the Recitals. "Initial Well" means, as to any particular Prospect Area, the first well drilled hereunder in such Prospect Area. "JOA" means an Operating Agreement in substantially the form attached hereto as Exhibit E, with each Prospect Area to be covered by a separate JOA. "Lease" means an oil, gas and/or mineral lease, fee interest or mineral servitude affording the holder the right to explore for, develop and produce oil, gas and/or other minerals. "Option" means an agreement affording the holder an option, exercisable upon certain circumstances, to acquire a Lease. "Ownership Interest Share" or "Participation Share" shall mean, relative to any particular Prospect Area and unless expressly provided otherwise herein, the respective interests set out for each of BOG and Aspect in Exhibit C hereto; provided that, in the event fewer than all of the AMI Parties elect to participate in any particular Acquired Interest within a Prospect Area, the Ownership Interest Shares and Participation Shares shall be adjusted as to such Acquired Interest as more particularly described in Article II, below. "Participant(s)" shall have the meaning assigned to it in the introductory paragraph. "Party" shall have the meaning assigned to it in the introductory paragraph. "Prospect Areas" means all of the lands described in Parts One through Four of Exhibit A hereto, with the lands described in any one of such parts of Exhibit A being individually called a "Prospect Area". 2 "Subsequent Well" means, relative to any particular Prospect Area, any well drilled hereunder after the drilling of the Initial Well for such Prospect Area. ARTICLE I Relationship of Parties Section 1.1. Several Liability. The liabilities, covenants and undertakings of the Parties are several, not joint or collective. Under no circumstances shall any Party be considered a fiduciary to any other Party, nor shall there otherwise be a confidential, special or other relationship of trust created between any one or more Parties under or by virtue of this Agreement. Section 1.2. No Partnership. It is not the intention of the Parties to create, nor shall this Agreement be deemed as creating a joint venture or a mining, tax or other partnership or association or to otherwise render the Parties liable as co-venturers or partners. However, if for federal income tax purposes, this Agreement and the operations hereunder are regarded as a partnership, each Party thereby affected elects to be excluded from the application of all of the provisions of Subchapter "K," Chapter 1, Subtitle "A," of the Internal Revenue Code of 1986, as amended (hereinafter referred to as the "Code"), as permitted and authorized by Section 761 of the Code and the regulations promulgated thereunder. Should there be any requirement that each Party hereby affected give further evidence of this election, each such Party shall execute such documents and furnish such other evidence as may be required by the federal Internal Revenue Service or as may be necessary to evidence this election. No Party shall give any notice or take any other action inconsistent with the election made hereby. In making the foregoing election, each Party states that the income derived by such Party from operations hereunder can be adequately determined without the computation of partnership taxable income. ARTICLE II Area of Mutual Interest Section 2.1. Establishing an Area of Mutual Interest. (a) BOG and Aspect hereby establish an area of mutual interest ("AMI") which shall encompass the AMI Lands (as used in this Article II, BOG and Aspect are herein collectively called the "AMI Parties" and individually called an "AMI Party"). (b) The AMI shall remain in force for a term of three years, unless sooner terminated by mutual agreement of the Parties (the "AMI Term "). 3 Section 2.2. Notification and Response Procedures. In the event that any AMI Party acquires or proposes to acquire, at any time during the AMI Term, by purchase, exchange, gift or otherwise, a Lease, Option or a Farm-In covering lands, any part of which are located within the AMI (such Leases, Options and Farm-Ins, insofar and only insofar as they cover lands within the AMI, are herein called "Acquired Interests"), such AMI Party (the "Acquiring Party") shall notify the other AMI Parties (the "Notified Parties"), in writing, of such acquisition or proposed acquisition and the initial consideration paid or to be paid for the Acquired Interest. Each Notified Party shall, within thirty (30) days after receipt of such a notice from the Acquiring Party, notify the Acquiring Party, in writing, whether it wishes to participate in such acquisition; provided that failure to respond within the time and in the manner set forth above shall be deemed to be an election to not participate in such acquisition. However, if a Notified Party reasonably desires additional information with respect to an Acquired Interest before it makes its election whether or not to participate in the acquisition of an Acquired Interest, such Notified Party may notify the Acquiring Party in writing within fifteen (15) days of its receipt of the Acquiring Party's notice, detailing in such notice to the Acquiring Party the additional information reasonably desired by such Notified Party, and such Notified Party shall have fifteen (15) days from the date of its receipt of the additional information it has reasonably requested from the Acquiring Party in which to make its election whether to participate in the acquisition of the Acquired Interest. Payment for a Participating Party's share of an Acquired Interest is due within 30 days after the participation election was due. Failure to timely make any portion of such payment as is not in good faith dispute shall result in a forfeiture of the right to participate in same. In the event a rig is drilling within one mile of the Prospect Area to which any particular Acquired Interest relates, the period within which an election must be made shall be reduced from 30 days to 48 hours (exclusive of weekends and legal holidays). Notice of the 48-hour election data shall be set out in the election notification notice. Anything to the contrary contained herein notwithstanding, a sale, exchange, gift or other disposition of any part of an AMI Party's interest in any Leases, Options or Farm-Ins to any other AMI Party hereto shall not be deemed to be an Acquired Interest for purposes of this Section 2.2, and this Section 2.2 shall not apply to any such sale, exchange, gift or other disposition. Section 2.3. Effect of a Party's Election Regarding Participation. Should all of the AMI Parties elect to participate in an acquisition of an Acquired Interest, upon payment of its Ownership Interest Share of the acquisition costs (or to the extent not yet due, upon agreement to pay when due), each AMI Party shall be entitled to its Ownership Interest Share of the Acquired Interest, and the Acquiring Party shall execute an Assignment, in substantially the form attached hereto as Exhibit B, in favor of the Notified Parties. If any AMI Party elects not to participate in any particular Acquired Interest, the Ownership Interest Share for each AMI Party electing to participate shall, unless all of the Parties electing to participate agree otherwise, be the percentage determined by dividing, for each participating AMI Party, the Ownership Interest Share otherwise applicable (if all Parties had participated) to such participating AMI Party by the total Ownership Interest Share for all participating AMI Parties; the Acquiring Party shall then execute in favor of those Notified Parties electing to participate in such Acquired Interest an Assignment, in substantially the form attached hereto as Exhibit B, with appropriate adjustments for relative quantum of interest being transferred. The AMI Parties that acquire part of a non-participating AMI Party's Ownership Interest Share in an Acquired Interest shall be responsible for a proportionate share of such non-participating AMI Party's share of the costs of such Acquired Interest. An Acquired Interest shall be subject to one or more JOA's, depending upon the Prospect Area(s) within which such Acquired Interest is situated, all as more particularly described in Section 2.5, below. Notwithstanding any provision hereof to the contrary, in the event an Acquired Interest also covers lands outside the AMI, the Acquiring Party shall be obligated to offer the Notified Parties the right to participate in the subject acquisition only insofar as it relates to the Acquired Interest (i.e., as limited to the extent it covers lands in the AMI). In the event the Acquiring Party voluntarily elects to authorize a Notified Party or Parties to participate in the entire acquisition (i.e., insofar as it covers lands within and without the AMI), any lands outside the AMI shall not become a part of the AMI and shall not otherwise be subject to the provisions of the Agreement. 4 Section 2.4. Election as to Participation in Maintenance or Extension Costs. In the event maintenance or extension costs are incurred with respect to an Acquired Interest, each AMI Party that owns an Ownership Interest Share in such Lease, Option or Farm-In shall have the right to elect whether to participate in such maintenance or extension cost for the Lease, Option or Farm-In, utilizing the same procedures set forth in Sections 2.2 and 2.3 above for Acquired Interests; provided, however, that in the event that an AMI Party elects not to participate in a maintenance or extension cost, such AMI Party shall promptly relinquish and assign to the AMI Parties participating in such maintenance or extension cost (in proportion to their relative Ownership Interest Shares) all of such non-participating AMI Party's Ownership Interest Share in the Acquired Interest that would have been relinquished or lost if the maintenance or extension cost had not been paid. Section 2.5. JOA's. Immediately upon execution hereof, each Prospect Area within which both AMI Parties own a Lease, Option and/or Farm-In interest shall be deemed subject to a separate JOA in substantially the form attached hereto as Exhibit E. Within thirty (30) days after written request by either AMI Party, the other AMI Party shall formally execute a JOA covering any Prospect Area within which both AMI Parties own a Lease, Option or Farm-In interest. Aspect agrees that BOG shall be named as the Operator under each JOA. In the event there is any irreconcilable conflict between the terms hereof and the terms of any JOA, the terms hereof shall control. ARTICLE III Acquisition by Aspect of Interest in BOG Leases and Use of G & G Data. Section 3.1. Conveyance and Payment of Consideration. Immediately upon execution of this Agreement, BOG shall execute in favor of Aspect an Assignment in substantially the form attached hereto as Exhibit D (the "BOG/Aspect Assignment"), and Aspect shall pay over to BOG the sum of $397,890, as full consideration for the properties covered thereby (herein and therein called the "Interests"). For a period of thirty (30) days from and after the date hereof, BOG shall, at its sole discretion, have the right to remove the Prospect Area described in Part Four of Exhibit A hereto ("Saenz Prospect Area") from the operation of this Agreement; failure to affirmatively so elect removal shall be deemed an election to maintain the Saenz Prospect Area under operation of this Agreement. If BOG elects to remove the Saenz Prospect Area from operation of this Agreement, (a) Aspect shall reassign to BOG all of its right, title and interest that was acquired pursuant hereto in the Saenz Prospect Area, together with its right to review and use any G & G Data related thereto, and (b) BOG shall immediately refund to Aspect the sum of $46,800 (being the portion of the consideration allocable to the Saenz Prospect Area and its allocable G & G Data), and thereafter the Saenz Prospect Area shall no longer be included in the AMI Lands or otherwise subject to this Agreement. The Prospect Area described in Part Two of Exhibit A hereto (the Geissen Prospect Area") was prepared based upon the best information currently available to BOG. In the event, however, that the Geissen Prospect Area is reconfigured under the terms of that certain Geophysical Exploration Agreement, SW Danbury Project, dated as of July 1, 1996, such that BOG and Aspect are collectively entitled to less than a 40% working interest in the Initial Well to be drilled in the Geissen Prospect Area, Aspect shall have the right to remove the Geissen Prospect Area from the operation of this Agreement; failure to affirmatively so elect removal within 10 days after the date the prospect designation becomes effective shall be deemed an election to maintain the Geissen Prospect Area under this Agreement. If Aspect elects to remove the Geissen Prospect Area from operation of this Agreement, (a) Aspect shall reassign to BOG all of its right, title and interest in the Geissen Prospect Area that was acquired by Aspect pursuant hereto, together with its right to review and use any G & G Data related thereto, and (b) BOG shall immediately refund to Aspect the sum of $132,490 (being the portion of the consideration allocable to the Geissen Prospect Area and its allocable G & G Data), and thereafter the Geissen Prospect Area shall no longer be included in the AMI Lands or otherwise subject to this Agreement. 5 Section 3.2 Seismic Licenses.Notwithstanding any provision hereof to the contrary, neither this Agreement in general nor the defined term "G & G Data" in particular is intended to or shall be construed to cover any seismic or related data that is covered by a license or similar agreement in favor of BOG, it being recognized that interpretations of such data created by or on behalf of BOG are not covered by any such license or similar agreement and thus are covered hereby and expressly included in the defined term "G & G Data". Section 3.3 G & G Data. With respect to any G & G Data covered hereby, the following provisions shall apply: (a) During the term of this Agreement, Aspect shall have the right to review and use the G & G Data for its own purposes in evaluating the Prospect Areas; legal ownership of such G & G Data, however, shall remain solely vested in BOG. (b) Aspect shall keep and maintain the G & G Data strictly confidential and shall not disclose any G & G Data to any third party, except (i) employees, officers or directors of any such Party or employees, officers, directors or consultants of any lender or other supplier of material debt or similar proceeds, (ii) any third parties (including without limitation any governmental authority) to whom such G & G Data must be disclosed pursuant to applicable laws, rules, orders and/or regulations, (iii) third parties engaged in bona fide, good faith negotiations with any such Party to (A) acquire or be acquired by such Party(by merger, consolidation or stock acquisition), (B) acquire all or substantially all of the assets of such Party, including all of its interests in the AMI Lands, (C) participate with such Party in the exploration and/or development of the AMI Lands, (D) acquire all or a part of such Party's interests under this Agreement and in the AMI Lands, (E) consult with such Party in order to aid in analyzing or interpreting the G & G Data or in preparing reserve estimates, (F) invest in such Party by acquiring a material part of such Party's stock (or by having a material part of such third party's stock acquired by such Party) or by advancing material loan funds or some other form of debt proceeds, and/or (G) farm-out or otherwise transfer to such Party all or a portion of the third party's interest in the AMI Lands; provided that, prior to any such disclosure, the disclosee must execute a Confidentiality Agreement wherein it expressly recognizes and agrees to be bound by the confidentiality provisions hereof. (c) Aspect hereby releases BOG from any liability or obligations arising in relation to the G & G Data (or the processing or interpretation thereof), WHETHER OR NOT ANY SUCH LIABILITY OR OBLIGATIONS AROSE OR ARISE OUT OF OR OTHERWISE IN RELATION TO BOG'S SOLE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY. 6 (d) THE PARTIES UNDERSTAND THAT NONE OF BOG AND ITS OFFICERS, EMPLOYEES, AGENTS, CONSULTANTS AND SHAREHOLDERS (hereinafter collectively referred to as the "BOG GROUP") MAKE ANY REPRESENTATIONS OR WARRANTIES OF ANY KIND AS TO THE G & G DATA, INCLUDING WITHOUT LIMITATION, ITS FITNESS FOR A PARTICULAR PURPOSE, MERCHANTABILITY OR ACCURACY, AND THE BOG GROUP HEREBY DISCLAIMS ANY AND ALL SUCH REPRESENTATIONS OR WARRANTIES, AND ANY USE OF THE G & G DATA BY THE PARTIES OR THEIR SUCCESSORS OR ASSIGNS, OR ANY ACTION TAKEN BY THE PARTIES OR THEIR SUCCESSORS OR ASSIGNS SHALL BE BASED SOLELY ON THEIR OWN JUDGMENT, AND NO MEMBER OF THE BOG GROUP SHALL BE LIABLE OR RESPONSIBLE TO THE OTHER PARTIES OR THEIR SUCCESSORS OR ASSIGNS FOR ANY LOSS, COST, DAMAGES, OR EXPENSE WHATSOEVER, INCLUDING INCIDENTAL OR CONSEQUENTIAL DAMAGES, INCURRED OR SUSTAINED AS A RESULT OF THE USE OF OR RELIANCE UPON THE G & G DATA, REGARDLESS OF WHETHER OR NOT SUCH LOSS, COST, DAMAGE OR EXPENSE IS FOUND TO RESULT IN WHOLE OR IN PART FROM THE SOLE OR CONCURRENT NEGLIGENCE OR OTHER FAULT OF ANY MEMBER OF THE BOG GROUP. Each Party hereto waives all of the provisions of any applicable Deceptive Trade Practices or Consumer Protection Act ("DTPA"), other than Section 17.555 of the Texas DTPA, and expressly agrees and acknowledges that it (i) has assets of twenty-five million dollars or more, and (ii) has knowledge and experience in financial and business matters that enable it to evaluate the merits and risks of the transaction and operations contemplated by this Agreement, (iii) has been represented by counsel of its choosing, and (iv) is not in a significantly disparate bargaining position relative to each other Party to this Agreement, but has agreed to this provision in negotiations involving real choice on the part of each Party. ARTICLE IV Participation in Wells Section 4.1. Limitation on Well Proposals. BOG and Aspect hereby agree that, until December 31, 1999, and notwithstanding any provision of any JOA to the contrary, Aspect shall not be authorized to propose the drilling of any Initial Well or Subsequent Well, except for the Initial Well to be drilled on the Prospect Area described in Part One of Exhibit A hereto (the "Dickson Prospect"). Section 4.2 Elections. (i) Initial Wells. In the event that a Party elects not to participate in the drilling of the Initial Well proposed and then actually drilled within any particular Prospect Area, anything to the contrary contained herein or in the applicable JOA to the contrary, such Party (A) must permanently relinquish and assign (without reimbursement for costs) all of its right, title, interest and properties (whether legal or equitable, vested or contingent and whether real/immovable, personal/movable or mixed), other than the G & G Data in the case of BOG, in the applicable Prospect Area to the Parties participating in the drilling of such well (in the ratio that each participating Party's leasehold working interest in the acreage included within the Prospect Area for such well bears to the total of the leasehold working interests of all of the Parties hereto participating in the operation), (B) shall no longer (as of the date it elects not to participate in the drilling of the well) be deemed a party to the applicable JOA, and (C) shall not own or acquire, whether directly or indirectly, itself or through any Affiliate, representative, agent or broker, any Lease, Option, Farm-In or other interest in oil, gas and/or other minerals within such Prospect Area for a period of three (3) years from the date of this Agreement. 7 (ii) Subsequent Wells. In the event a Party that elected to participate in the Initial Well drilled within any particular Prospect Area, thereafter elects not to participate in any Subsequent Well proposed and then drilled within such Prospect Area, anything to the contrary contained herein or in the applicable JOA to the contrary, such Party (A) must permanently relinquish and assign (without reimbursement for costs) all of its right, title, and interest and properties (whether legal or equitable, vested or contingent and whether real/immovable, personal/movable or mixed) in the wellbore of the Subsequent Well and a sufficient interest in the Leases, Options and Farm-Ins allocable to such Subsequent Well to afford the relinquishing party its full allowable share of production from the Subsequent Well (the "Subsequent Well Interests"), to the Parties participating in the drilling of such Subsequent Well (in the ratio that each participating Party's leasehold working interest in the acreage included within the Prospect Area for such well bears to the total of the leasehold working interests of all of the Parties hereto participating in the operation), (B) shall no longer (as of the date it elects not to participate in the drilling of the Subsequent Well) be deemed a party to the applicable JOA insofar as it pertains to the Subsequent Well Interests, and (C) shall not own or acquire, whether directly or indirectly, itself or through any Affiliate, representative, agent or broker, any Lease, Option, Farm-In, Permit or other interest in oil, gas and/or other minerals directly relating to the Subsequent Well Interests for a period of three (3) years from the date of this Agreement. (iii) Completion Elections. In the event that a Party has participated in the drilling of the Initial Well in any particular Prospect Area, and then elects not to participate in a completion operation proposed for such well, such Party (A) must permanently relinquish (without reimbursement for costs) and assign all of its right, title, interest and properties (whether legal or equitable, vested or contingent and whether real/immovable, personal/movable or mixed) in the completed formation, insofar as it can be produced out of the wellbore of such well, (B) shall relinquish (as of the date it elects not to participate in the completion operation) all of its rights and interests under the JOA, insofar as it covers the relinquished completed formation, insofar as such completed formation can be produced out of the wellbore of such well, and (C) shall not, for a period of three (3) years from the date of this Agreement, own or acquire, whether directly or indirectly, itself or through any Affiliate, representative, agent or broker, any Lease, Option, Farm-In, or other interest in oil, gas and/or other minerals located within the completed formation, insofar as such completed formation can be produced out of the wellbore of such well. In each of the foregoing cases, such relinquishment and assignment is to be made to the Parties participating in such completion in the ratio that each participating Party's leasehold working interest in the acreage included within the Prospect for such well bears to the total of the leasehold working interests of all of the Parties hereto participating in the operation. Where the completion election relates to a Subsequent Well in such Drilling Unit, the non-consent and other operative provisions of the applicable JOA shall govern completion point elections. If a Party has elected to participate in the drilling of a well and then elects not to participate in a proposed completion operation within the well, but then subsequently participates in the completion of another formation within the same well, such Party will be obligated to pay for its proportionate share of the completion operation costs which were previously incurred in completing the other formation in accordance with the drilling footage ratio method set forth in COPAS Bulletin No. 2 in paragraph B.1(b) for intangible costs and in paragraphs B.1 and B.2 for tangible costs. 8 (iv) Any well drilled to replace a well drilled within a Prospect Area because of drilling or mechanical difficulties incurred in the drilling of such well shall be deemed to be the same well for purposes of the relinquishment and assignment provisions of this Section 4.2; provided, however, that only the Parties that participated in the original drilling of the well shall have the right to participate in the drilling of a replacement well for such well. (iv) In the event of any required relinquishment and assignment of interests as provided in this Section 4.2, the relinquishing Party shall promptly execute all conveyance instruments necessary to effectuate such relinquishment and assignment. ARTICLE V. Miscellaneous Section 5.1. Assignments. This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and assigns; provided, however, that the conveyance, assignment or other instrument of transfer vesting such transferee with all or part of such rights, interests and unaccrued obligations must expressly provide that the assignment, conveyance or other instrument of transfer is made subject to the terms and conditions contained in this Agreement and in the absence of such language any such attempted transfer shall be void and of no legal force and effect. In addition, in any such assignment, conveyance or other instrument of transfer, the transferee shall expressly agree to assume and be responsible for any liabilities, damages, obligations, covenants and agreements arising from and after the date of such assignment, conveyance or other instrument of transfer, in relation to or otherwise out of the properties, rights and interests that are the subject of this Agreement and/or such assignment, conveyance or other instrument of transfer, and the transferor shall remain responsible for any of the foregoing arising prior to the date of such assignment, conveyance or other instrument of transfer and in the absence of such language, any such attempted transfer shall be void and of no force and effect. Any subsequent assignment, conveyance or other instrument of transfer shall likewise contain express language so allocating responsibility as between transferor and transferee, and in the absence of such language any such attempted transfer shall be void and of no force and effect. Section 5.2. Termination. This Agreement shall terminate at the expiration of the AMI Term except as to any Prospect Area covered or deemed covered at such time by a JOA between the Parties, and as to each such Prospect Area the terms hereof, other than those set out in Sections 2.1 through 2.4, shall remain in force and effect for so long as the applicable JOA remains in force and effect. Section 5.3. Notices. All notices and other communications required or permitted under this Agreement shall be in writing, and unless otherwise specifically provided, shall be delivered personally, or by mail, telecopier or delivery service, to the addresses set forth opposite the signatures of the Parties below, and shall be considered delivered upon the date of receipt. Each Party may specify its proper address or any other post office address within the continental limits of the United States by giving notice to other Parties, in the manner provided in this section, at least ten (10) days prior to the effective date of such change of address. 9 Section 5.4. Merger. This Agreement supersedes any and all prior and existing agreements, whether oral or in writing, between the Parties hereto with respect to the subject matter hereof and contains all of the covenants and agreements between the Parties with respect to the subject matter hereof. Each Party acknowledges that no Party to this Agreement or anyone on their behalf has made any representations, inducements, promises or agreements, orally or otherwise, relating to the subject matter of this Agreement that are not embodied herein. Section 5.5. Counterparts. This Agreement may be executed in multiple counterparts, each of which shall be binding upon the signing Party or Parties thereto as fully as if all Parties had executed one instrument, and all of such counterparts shall constitute one and the same instrument. If counterparts of this Agreement are executed, the signatures of the Parties, as affixed hereto, may be combined in and treated and given effect for all purposes as a single instrument. However, anything to the contrary contained herein notwithstanding, this Agreement shall not be binding upon any Party hereto unless and until all of the Parties sign a counterpart thereof. Section 5.6. CHOICE OF LAW/VENUE. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. This Agreement is executed by the Parties the dates set forth opposite their respective signatures below but is effective for all purposes as on of the date first set forth above. Address: BRIGHAM OIL & GAS, L.P. 6300 Bridge Point Parkway By: Brigham, Inc., its Building 2, Suite 500 Managing General Partner Austin, Texas 78730 (512) 427-3300 Fax: (512) 427-3400 By: /s/ Karen E. Lynch -------------------- Name: Karen E. Lynch Dated: October 21, 1999 Title: Vice President Address: ASPECT RESOURCES LLC 511 16th Street, Suite 300 Denver, Colorado 80202 (303) 573-7011 By: /s/ Alex B. Campbell --------------------- Fax: (303) 573-7340 Name: Alex B. Campbell --------------------- Title: Vice President Dated: October 18, 1999 10 EX-10.65.3 8 LETTER AGREEMENT EXHIBIT 10.65.3 December 30, 1999 Via Facsimile Mr. Alex Cranberg ASPECT RESOURCES, LLC 511 16th Street, Suite 300 Denver, Colorado 80202 Phone (303) 573-7011 Fax (303) 573-7340 Re: Millenium Joint Development Agreement, Millenium Project, dated February 10, 1999, as amended (the "Millenium Agreement"); Acquisition and Participation Agreement, dated October 21, 1999, as amended (the "Participation Agreement") Dear Alex: This letter agreement shall set forth the agreement between Brigham Oil & Gas, L.P. ("Brigham") and Aspect Resources, LLC ("Aspect"), to amend our Millenium Agreement and Participation Agreement as described below. Aspect hereby agrees that notwithstanding anything to the contrary contained in the Millenium Agreement, Brigham shall have until January 31, 2000, as opposed to December 31, 1999, to makes its election under Article II of the Millenium Agreement whether to reimburse Aspect for 75% of all of the costs which were funded by Aspect and utilized to acquire Leasehold Interests during the second quarter of 1999. Aspect Resources, LLC Letter Agreement December 30, 1999 Page 2 Brigham recognizes that in the event that Brigham does not propose the drilling of a well within any of the Prospect Areas covered under the Participation Agreement within 30 days from the date hereof, Aspect may exercise its right to propose a well within any one of such Prospect Areas. Anything to the contrary contained in the Participation Agreement, or the form Joint Operating Agreement attached thereto, notwithstanding, Brigham and Aspect agree that in the event that Aspect or any other party proposes the drilling of the Initial Well within any of the Prospect Areas and Brigham desires to elect not to participate in the drilling of such Initial Well, prior to the due date for its participation election, Brigham shall assign to Aspect all of Brigham's interest in the applicable Prospect Area, subject to a 35% back-in interest after 100% payout of the Initial Well drilled on such Prospect Area, being 35% of the interest assigned by Brigham to Aspect pursuant to the terms of this paragraph, together with a like interest in all wells and all equipment and facilities related to such wells. Anything to the contrary contained in the Participation Agreement, or the form Joint Operating Agreement attached thereto, notwithstanding, Brigham and Aspect agree that in the event that Aspect or any other party proposes the drilling of a Subsequent Well within any of the Prospect Areas and Brigham desires to elect not to participate in the drilling of such Subsequent Well, prior to the due date for its participation election, Brigham shall assign to Aspect all of Brigham's interest in the wellbore of the Subsequent Well, subject to a 35% back-in interest after 100% payout of the Subsequent Well, being 35% of the interest assigned by Brigham to Aspect pursuant to the terms of this paragraph, together with a like interest in the Subsequent Well and all equipment and facilities related to the Subsequent Well. For purposes of this letter agreement, "100% payout" shall be deemed to have occurred at such point in time, if ever, that Aspect (and/or its successor or assign) has received net proceeds attributable to the interest in the Initial Well or Subsequent Well, as the case may be, assigned to Aspect pursuant to the term hereof, equaling all of the costs and expenses which have been incurred by Aspect in the drilling, testing, completing, producing, operating, and reworking the Initial Well or Subsequent Well, as the case may be. All other terms of the Millenium Agreement and the Participation Agreement shall continue in full force and effect, except as expressly modified by this letter agreement. This letter agreement shall be binding upon and shall enure to the benefit of the parties hereto and all of their successors and assigns. If this letter agreement correctly reflects the agreement and understanding of the parties with respect to the subject matter hereof, we ask that an authorized representative of Aspect execute a duplicate original or copy of same and return same to our offices as soon as possible. Both parties agree that the parties may accept execution and delivery of this letter agreement by facsimile transmission and that either party's execution of a facsimile copy of this letter agreement shall be an effective execution. Sincerely, BRIGHAM OIL & GAS, L.P. by Brigham, Inc. its Managing General Partner /s/ David T. Brigham David T. Brigham, Vice President AGREED TO AND ACCEPTED: ASPECT RESOURCES, LLC by Aspect Management Corporation its Manager By: /s/ Alex B. Campbell (name printed) Alex B. Campbell Its: Vice President EX-10.66 9 LETTER AGREEMENT EXHIBIT 10.66 October 15, 1999 Via Regular Mail Mr. Vincent M. Brigham Brigham Land Management Company P.O. Box 780375 Oklahoma City, OK 73116 Re: Amendment to Consulting Agreement Work Performed Within Angleton Project Dear Vincent: This letter agreement shall set forth the agreement between Brigham Oil & Gas, L.P.'s ("BOG") and Brigham Land Management Company, Inc. ("BLM") to amend that certain Consulting Agreement dated August 1, 1998, by and between BOG and BLM (the "Consulting Agreement") with respect to certain work that is to be performed by Vincent M. Brigham within BOG's Angleton Project (as described on Exhibit "A" which is attached hereto). Anything to the contrary contained in the Consulting Agreement notwithstanding, BOG and BLM (BOG and BLM being sometimes collectively referred to herein as the "Parties") agree that any land work performed by Vincent M. Brigham related to BOG's Angleton Project, between September 6, 1999 and the earlier to occur of such time as either BOG or BLM notifies the other that this amendment is terminated or December 6, 1999 (such time period being hereinafter referred to as the "Amendment Term"), shall be governed by the following terms: (1) The Fee (as defined in the Consulting Agreement) for any work performed by Vincent M. Brigham shall be $357.50 per day. (2) BOG shall not be required to pay the Fees, costs or expenses related to consulting services provided by Vincent M. Brigham, before December 15, 1999; however, BLM shall continue to invoice BOG on a bi-monthly basis for all work performed and all costs and expenses incurred in performing such work in accordance with the terms of the Consulting Agreement. On or before December 6, 1999, BOG shall elect whether to pay BLM for the consulting services and expenses which have been provided and incurred by BLM during the Amendment Term with cash or with an equivalent overriding royalty as set forth below: (A) In the event that BOG elects to pay for such consulting services and expenses with cash, BOG will pay BLM for such consulting services within 15 days of BOG's receipt of BLM's invoices for all of the consulting services and expenses provided and incurred by Vincent M. Brigham during the Amendment Term. (B) In the event that BOG elects to pay for such consulting services and expenses with an equivalent overriding royalty, the BOG Participants (as defined below) shall grant BLM an overriding royalty (the "BLM ORRI") burdening the BOG Participants' interests in the first 4 Net Wells (as defined below), if any, that are drilled by the BOG Participants within the Angleton Project within 10 years from the date of this letter amendment. The amount of the BLM ORRI shall equal the product obtained by multiplying (i) the product obtained by dividing (a) the total of the Fees and expenses for the consulting services performed by Vincent M. Brigham during the Amendment Term by (b) $10,000, times (ii) .25. The assignment of the BLM ORRI for each well shall be in the form which is attached hereto as Exhibit B, but shall not be required to be completed and executed until immediately preceding the commencement of actual drilling operations for the well. The Parties recognize that the BLM ORRI only burdens the BOG Participants' interests in the first 4 Net Wells, if any, which are drilled within the Angleton Project within such 10 year period. As such, in the event that any other party participates in the drilling of any the subject wells, the BLM ORRI will be proportionately reduced to the total of the BOG Participants' working interest in the well. (C) For purposes of this letter agreement, a "BOG Participant" shall be anyone that BOG assigns part of its interest in oil and gas leasehold or mineral interests that are located within the Angleton Project, insofar and only insofar as the interest which is assigned by BOG to such party. For example, in the event that BOG assigns to hypothetical ABC Company an undivided 25% of BOG's interest in hypothetical Lease A covering an undivided 50% of the minerals in hypothetical Tract 1 which covers 100 gross acres in the Angleton Project, for purposes of this letter agreement, ABC Company would be deemed to be a BOG Participant with respect to such 25% of BOG's interest in Lease A. However, in the event that ABC Company already owned or subsequently acquired hypothetical Lease B which covers the remaining undivided 50% of the minerals in Tract 1 from someone other than BOG, ABC Company would not be deemed to be a BOG Participant with respect to its interest in Lease B. (D) For purposes of this letter agreement, the number of Net Wells shall be calculated by the BOG Participants total working interest in the wells drilled to date. For every 100% of working interest held by BOG Participants in wells, one Net Well shall be deemed to have existed. For example, in the event that at a given point in time, the BOG Participants have participated in the drilling of 3 wells within the Angleton Project, the BOG Participants having a total of a 40% working interest in the first well, 15% working interest in the second well, and 70% working interest in the third well, in such event, for purposes of this letter agreement, 1.25 Net Wells would have been drilled by BOG and BLM's ORRI would burden the BOG Participants' interest in each of those 3 wells. In the event that BOG participates in more than 4 Net Wells prior to the expiration of 10 years from the date hereof, BLM's ORRI would burden all of the BOG Participants' interests in the first wells that are spud by the BOG Participants within the Angleton Project which are necessary to cause BLM's ORRI to burden 4 Net Wells and in the event that the last well which would be burdened by the BLM ORRI would cause the BLM ORRI to burden more than 4 Net Wells, the BLM ORRI in the last well necessary to cause the BLM ORRI to burden 4 Net Wells would be proportionately reduced such that the BLM ORRI burdens exactly 4 Net Wells. For example, in the event that the BOG Participants have a 50% working interest in the first well, a 75% working interest in the second well, an 85% interest in the third well, a 90% working interest in the fourth well, a 70% working interest in the fifth well and a 65% working interest in the sixth well drilled by the BOG Participants within the Angleton Project, the BLM ORRI would burden all of the BOG Participants' interests in the first 5 wells drilled and would burden only 46.154% of the BOG Participants' interests in the sixth well drilled, calculated as follows: 2 First 5 wells = 3.7 Net Wells .3 Net Wells needed out of the 6th well to equal exactly 4 Net Wells .65X=.3 X=.3/.65 X=46.154%. These terms replace all compensation provisions contained in the Consulting Agreement insofar as they would apply to work related to BOG's Angleton Project performed by Vincent M. Brigham during the Amendment Term. These terms shall not apply to any work performed by other employees, agents or contractors of BLM, which work, if any, shall continue to be governed by the terms of the Consulting Agreement as originally drafted. Anything to the contrary contained in the Consulting Agreement notwithstanding, during the Amendment Term, BLM shall not have the right to have anyone other than Vincent M. Brigham perform consulting services within the Angleton Project without BOG's prior written consent. All other terms of the Consulting Agreement, except as specifically modified herein, shall continue in full force and effect. If this letter agreement correctly sets forth the agreement between BOG and BLM with respect to the amendment to the Consulting Agreement, we ask that BLM execute the duplicate originals of same below. Sincerely, BRIGHAM OIL & GAS, L.P. /s/ David T. Brigham David T. Brigham Vice President AGREED AND ACCEPTED EFFECTIVE AS OF SEPTEMBER 6, 1999: BRIGHAM LAND MANAGEMENT COMPANY, INC. By: /s/ Vincent M. Brigham Vincent M. Brigham, President EX-21 10 SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21 SUBSIDIARIES Brigham Oil & Gas, L.P., a Delaware limited partnership EX-23.1 11 CONSENT Exhibit 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-85435) and Form S-8 (Nos. 333-56961 and 333-70137) of Brigham Exploration Company of our report dated March 7, 2000, which appears on page F1-2 of this Form 10-K. We also consent to the incorporation by reference of our report dated March 7, 2000, on the financial statements of Brigham Oil & Gas L.P.; Brigham Holdings I, LLC; Brigham Holdings II, LLC and Brigham, Inc., which appears on page F2-1 of this Form 10-K. PricewaterhouseCoopers LLP Dallas, Texas March 24, 2000 EX-23.2 12 CONSENT EXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS As independent petroleum consultants, we hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-85435) of Brigham Exploration Company of our estimates of reserves, included in this Annual Report on Form 10-K, and to all references to our firm included in this Annual Report. CAWLEY, GILLESPIE & ASSOCIATES, INC. Fort Worth, Texas March 24, 2000 EX-27 13 FINANCIAL DATA SCHEDULE
5 1,000 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 2,742 0 4,945 0 0 8,264 113,752 0 125,683 17,744 0 0 0 145 8,853 125,683 14,992 15,277 0 3,227 11,799 0 9,697 (21,628) 0 (21,628) 0 0 0 (21,628) (1.53) (1.53)
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