**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington,
      D.C. 20549**


_______________





**Form
      10-K**





x
            **ANNUAL
                REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
                ACT OF
                1934****For
                the fiscal year ended December 31, 2006**£
            **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**
              *(State
                or other jurisdiction of incorporation or
                organization)*
            
            **75-2692967**
              *(I.R.S.
                Employer Identification No.)*





**6300
      Bridge Point Parkway, Building 2, Suite 500, Austin, Texas
      78730**


*(Address
      of principal executive offices) (Zip Code)*





**(512)
      427-3300**


*(Registrant’s
      telephone number, including area code)*





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








**Title
                of Each Class**
            
            **Name
                of Each Exchange on Which Registered**Common
                Stock, $0.01 par value
            
            NASDAQ
                Global Market





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


**None**


*(Title
      of Class)*





Indicate
      by check mark if the registrant is a well-known seasoned issuer, as defined
      in
      Rule 405 of the Securities Act.


Yes £ No x





Indicate
      by check mark if the registrant is not required to file reports pursuant to
      Section 13 or Section 15(d) of the Act. Yes £ No x





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. x





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer. See definition of “accelerated
      filer and large accelerated filer” in Rule 12b-2 of the Exchange
      Act.





Large
      accelerated filer £ Accelerated filer x Non-accelerated filer £





Indicate
      by check mark whether the registrant is a shell company (as defined in Rule
      12-b
      of the Act).   Yes £ No x





As
      of
      June 30, 2006, the registrant had 45,499,008 shares of voting common stock
      outstanding. The aggregate market value of the registrants outstanding shares
      of
      voting common stock held by non-affiliates, based on the closing price of these
      shares on June 30, 2006 of $7.91per share as reported on The NASDAQ Global
      Market, was $272 million. Shares held by each executive officer and director
      and
      by each person who owns 10% or more of the outstanding common stock are
      considered affiliates. The determination of affiliate status is not necessarily
      a conclusive determination for other purposes.





As
      of
      March 5, 2007, the registrant had 45,513,160 shares of voting common stock
      outstanding.





**DOCUMENTS
      INCORPORATED BY REFERENCE**





Portions
      of the definitive proxy statement for the Registrant’s 2007 Annual Meeting of
      Stockholders to be held on May 31, 2007, 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, 2006.










**BRIGHAM
      EXPLORATION COMPANY**





**TABLE
      OF CONTENTS**





**Page****Part
                I**Item
                1.
            Business
            2Item
                1A.
            Risk
                Factors
            8Item
                1B.
            Unresolved
                Staff Comments
            19Item
                2.
            Properties
            19Item
                3.
            Legal
                Proceedings
            30Item
                4.
            Submission
                of Matters to a Vote of Security
                Holders
            30Executive
                Officers of the Registrant
            30**Part
                II**Item
                5.
            Market
                for Registrant’s Common Equity, Related Stockholder
                Matters and Issuer Purchases of Equity Securities
            32Item
                6.
            Selected
                Consolidated Financial Data
            34Item
                7.
            Management’s
                Discussion and Analysis of Financial Condition and
                Results of Operations
            36Item
                7A.
            Quantitative
                and Qualitative Disclosures about Market
                Risk
            57Item
                8.
            Financial
                Statements and Supplementary Data
            61Item
                9.
            Changes
                in and Disagreements with Accountants on Accounting and
                Financial Disclosure
            61Item
                9A.
            Controls
                and Procedures
            61Item
                9B.
            Other
                Information
            62**Part
                III**Item
                10.
            Directors,
                Executive Officers and Corporate
                Governance
            63Item
                11.
            Executive
                Compensation
            63Item
                12.
            Security
                Ownership of Certain Beneficial Owners and Management
                and Related Stockholder Matters
            63Item
                13.
            Certain
                Relationships and Related Transactions, and Director
                Independence
            63Item
                14.
            Principal
                Accounting Fees and Services
            63**Part
                IV**Item
                15.
            Exhibits,
                Financial Statement Schedules
            63Glossary
                of Oil and Gas Terms
            64Signatures
            66Index
                to Financial Statements
            F-1


*Table
          of Contents*





**BRIGHAM
      EXPLORATION COMPANY**





**2006
      ANNUAL REPORT ON FORM 10-K**





**PART
      I**





**Item
      1.** ***Business***





**Overview**





We
      are an
      independent exploration, development and production company that utilizes 3−D
      seismic imaging and other advanced technologies to systematically explore for
      and develop domestic onshore oil and natural gas reserves. We focus our
      exploration and development activities in provinces where we believe technology
      and the knowledge of our technical staff can be effectively used to maximize
      our
      return on invested capital by reducing drilling risk and enhancing our ability
      to grow reserves and production volumes. Our exploration and development
      activities are currently concentrated in four provinces: the Onshore Gulf Coast,
      the Anadarko Basin, the Rocky Mountains and West Texas.





We
      regularly evaluate opportunities to expand our activities to other areas that
      may offer attractive exploration and development potential, with a particular
      interest in those areas with plays that complement our current exploration,
      development and production activities. As a result of this strategy, during
      late
      2005 and throughout 2006 we have been accumulating significant acreage
      positions in the Powder River Basin and the Williston Basin. Operations within
      these two basins are included in and constitute the bulk of our activity in
      our
      Rocky Mountains province. We also entered into two joint ventures in Southern
      Louisiana in 2006. We consider these joint ventures to be logical extensions
      of
      our prospect generating activities in the onshore Texas Gulf Coast.





At
      December 31, 2006, our estimated proved reserves of 146.5 Bcfe had a
      standardized measure value of $302.7 million and a pre-tax PV10% value of $338.5
      million. Approximately 82% of our proved reserves were natural gas and we
      operated approximately 62.4% of the pre-tax PV10% value. For the twelve month
      period ended December 31, 2006, our total revenue and net income were $106.3
      million and $19.8 million, respectively. Our average daily production for 2006
      was 36.8 MMcfe, which represents an increase of 11% from our production in
      2005.





The
      following table provides information regarding our assets and operations located
      in our core areas.





**At
                December 31, 2006****Productive**
            
            
            
            **2006****%**
            
            **Wells**
            
            **3-D**
            
            **Average****Proved**
            
            **Pre-tax**
            
            **Natural**
            
            
            
            **Seismic**
            
            **Daily****Province**
            
            **Reserves**
            
            **PV10%(a)**
            
            **Gas**
            
            **Gross**
            
            **Net**
            
            **Data**
            
            **Production****(Bcfe)**
            
            **(Millions)**
            
            
            
            
            
            
            
            **(Sq.
                Miles)**
            
            **(MMcfe)**Onshore
                Gulf Coast
            
            
            80.9
            
            $
            227.0
            
            
            85%
            
            
            88
            
            
            40.3
            
            
            4,369
            
            
            22.3Anadarko
                Basin
            
            
            52.8
            
            
            80.1
            
            
            93%
            
            
            142
            
            
            44.3
            
            
            2,381
            
            
            11.6Rocky
                Mountains
            
            
            7.7
            
            
            10.3
            
            
            8%
            
            
            6
            
            
            4.1
            
            
            100
            
            
            0.3West
                Texas/Other
            
            
            5.1
            
            
            21.1
            
            
            14%
            
            
            82
            
            
            25.3
            
            
            4,487
            
            
            2.6Total
            
            
            146.5
            
            $
            338.5
            (b)
            
            82%
            
            
            318
            
            
            114.0
            
            
            11,337
            
            
            36.8


____________





(a)
            The
                prices used to calculate this measure were $61.06 per barrel of oil
                and
                $5.475 per MMbtu of natural gas, both as of December 31,
                2006.





(b)
            The
                standardized measure for our proved reserves at December 31, 2006
                was
                $302.7 million. See “Item 2. Properties — Reconciliation of Standardized
                Measure to Pre-tax PV10%” for a definition of pre-tax PV10% and a
                reconciliation of our standardized measure to our pre-tax PV10%
                value.





Since
      inception through December 31, 2006, we have drilled, completed, or are
      completing 731 wells, consisting of 505 exploration and 226 development wells
      with an average completion rate of 73%. Over the three year period ended
      December 31, 2006, we drilled, completed, or were completing 139 wells,
      consisting of 53 exploratory and 86 development wells with an average completion
      rate of 88%. During 2006, we spud a total of 43 wells, consisting of 23
      exploration wells and 20 development wells and retained an average working
      interest in these wells of approximately 59%. At December 31, 2006, thirty-three
      of these wells have been or were being completed while nine of these wells
      were
      not completed and one was in the process of drilling. Including two wells that
      began drilling in 2005 and were completed in 2006, our average completion rate
      for 2006 was 76%.


2
 *Table
          of Contents*


As
      part
      of our exploration activities, we have accumulated 3-D seismic data covering
      approximately 11,337 square miles (7.3 million acres) in ten states. We
      generally focus our 3-D seismic acquisition efforts in and around existing
      producing fields where we can benefit from the imaging of producing analog
      wells. These 3-D defined analogs, combined with our experience in drilling
      731
      wells in our project areas, provide us with a knowledge base to evaluate other
      potential geologic trends, 3-D seismic projects within these trends and
      prospective drilling locations. Over the three year period ended December 31,
      2006, within our core provinces we spent $64.3 million on land and seismic
      activities. We currently plan to spend approximately $11.2 million in 2007
      on
      land and seismic activities. As a result of these activities, we have generated
      a multi-year inventory of exploration prospects, which due to our field
      discoveries, is complemented by a multi-year inventory of development
      locations.





Combining
      our geologic and geophysical expertise with a sophisticated land effort, we
      manage a significant majority of our projects from conception through leasing.
      In addition, we manage the negotiation and drafting of most of our geophysical
      exploration agreements, resulting in reduced contract risk and more consistent
      deal terms. Because we generate most of our projects, we can often control
      the
      size of the working interest that we retain as well as the selection of the
      operator and the non-operating participants. We expect to operate the drilling
      of the majority of the wells in the Onshore Gulf Coast, the Anadarko Basin,
      Powder River Basin and the Williston Basin.





In
      2006,
      we increased our level of drilling activity to capitalize on our multi-year
      inventory of exploration and development prospects by spending a total of $142.3
      million on drilling expenditures. This represents a 57% increase over the
      amounts we spent on drilling in 2005. These drilling expenditures were used
      to
      drill 23 exploratory wells and 20 development wells and for other development
      activities. We had three exploration and three development wells that were
      completing and one development well that was drilling as of December 31,
      2006.





In
      2006,
      we also increased our investment in new acreage and seismic inventory. We
      invested $13.6 million in land and $18.1 million in 3-D acquisitions, as
      compared to $13.9 million and $5.7 million in 2005. Our land and 3-D investments
      represent an increase of 62% relative to 2005. The majority of our new acreage
      was acquired in the Powder River Basin, the Williston Basin and Southern
      Louisiana. The majority of our new 3-D acquisition was in the western Anadarko
      Basin, where we acquired 177 square miles of proprietary high resolution 3-D
      seismic data targeting primarily the Hunton play in the Texas Panhandle. We
      expect this data to be processed by mid-year 2007, and believe the data will
      enhance the imaging of our Mills Ranch Field, further reduce the drilling risk
      of our current inventory of prospects in the play, and potentially generate
      new
      prospects for drilling in future years.





For
      2007,
      we plan to continue with an active drilling program and anticipate spending
      $91.2 million to drill seven exploratory wells and 15 development wells. In
      addition, we will complete wells that were in progress at December 31, 2006
      and
      incur costs related to other development activities.





**Business
      Strategy**





Our
      business strategy is to create value for our stockholders by growing reserves,
      production volumes and cash flow through exploration and development drilling
      in
      areas where we can use technology to generate high rates of return on our
      invested capital. Key elements of our business strategy include:





•
            *Focus
                on Core Provinces and Trends.*We
                have built our multi-year inventory of drilling prospects by leveraging
                our staff’s strong technical knowledge base in the following four core
                provinces and their associated trends: 1) our Onshore Gulf Coast
                province
                which includes the Vicksburg trend in South Texas, the Frio trend
                in and
                around Matagorda County, Texas and the Miocene and Upper Oligocene
                trends
                in Southern Louisiana; 2) our Anadarko Basin province in the Texas
                Panhandle and northwest Oklahoma, including the Hunton and Springer
                trends; 3) our Rocky Mountains province, which includes the Powder
                River
                Basin in Wyoming and the Williston Basin in North Dakota and Montana;
                and
                4) our West Texas province. Further, we believe our focus on these
                trends
                within our four core provinces provides us with important drilling
                investment diversification. Since 1999, our exploration success in
                these
                trends has resulted in seven significant field discoveries and a
                resulting
                multi-year inventory of development drilling locations. We plan to
                focus
                the majority of our near term capital expenditures in these trends,
                where
                we believe our accumulated 3-D seismic data and knowledge base provides
                us
                with a substantial competitive
                advantage.


3
 *Table
          of Contents*


•
            *Internally
                Generate Inventory of High Quality Exploratory Prospects.*Utilizing 3-D seismic data and other advanced technologies, our highly
                skilled staff of 13 geologists, four geophysicists, and one petrophysicist
                generates the majority of our drilling prospects. Historically, we
                have
                not relied heavily on third party generated opportunities, which
                usually
                involve the payment of consideration over and above the costs incurred
                to
                generate and drill the prospect. We believe that our seven significant
                field discoveries reflect the quality and depth of our 3-D delineated
                prospect inventory as well our ability to continue to generate such
                opportunities.




•
              *Leverage
                  our Operational Expertise.*In
                  addition to our utilization of advanced 3-D seismic imaging techniques,
                  our staff is very proficient with state-of-the-art drilling and
                  completion
                  techniques, including directional drilling, horizontal drilling
                  and
                  fracture stimulations. We have a demonstrated successful track
                  record of
                  drilling in difficult, deep and highly pressured environments.
                  During
                  2006, 55% of the vertical wells we drilled were directional and
                  the
                  average depth of these wells was over 14,700 feet. Since 1997,
                  we have
                  successfully utilized directional drilling with extensive fracture
                  stimulations at depths of between 13,000 and 14,000 feet in the
                  pressured
                  Vicksburg trend of South Texas, where we have proven over 190 Bcfe
                  in
                  gross reserves by drilling 36 wells to date. Our current activity
                  in the
                  Bakken of the Williston Basin and the Mowry of the Powder River
                  Basin
                  leverages our staff’s expertise at drilling and completing horizontal
                  wells in unconventional
                  plays.




•
            *Evaluate
                and Selectively Pursue New Potential Plays.*We
                have a 16 year track record of successfully evaluating and initiating
                new
                oil and natural gas plays. We are particularly interested in those
                plays
                with attractive exploration and development potential that complement
                our
                current exploration and production activities. After identifying
                such a
                play, we will often selectively build an acreage position in the
                play. Our
                current Vicksburg and Hunton plays are examples of successful plays
                where
                our position in the play was identified and originated by us. We
                believe
                our recent acreage acquisitions in the Powder River Basin of Wyoming,
                the
                Williston Basin of North Dakota and Montana, and Southern Louisiana
                should
                lead to additional growth in our reserves and production. For 2007,
                we
                currently plan to spend approximately $38.2 million in the Mowry,
                the
                Bakken and South Louisiana.





•
            *Capitalize
                on Exploration Successes Through Development of Field
                Discoveries.*From 1990 to 1999, we grew our reserves and production volumes primarily
                through successful 3-D delineated exploration drilling. In recent
                years,
                our exploratory drilling success has resulted in a multi-year inventory
                of
                development drilling locations, and over the three year period ended
                December 31, 2006, approximately 62% of our drilling expenditures
                were
                spent on development activities. We believe our ability to balance
                our
                higher risk exploratory drilling with lower risk development drilling
                has
                reduced our risk profile. For 2007, we anticipate allocating approximately
                74% of our planned drilling expenditures to development
                activities.





•
            *Continue
                to Actively Drill Our Multi-Year Prospect Inventory.*To
                capitalize on our multi-year inventory of exploration and development
                locations, we plan to continue with the accelerated level of drilling
                activity that we began in 2004. In 2007, we currently plan to spend
                $91.2
                million in drilling capital to drill a total of 22
                wells.





•
            *Enhance
                Returns Through Operational Control.*We
                seek to maintain operational control of our exploration and drilling
                activities. As operator, we retain more control over the timing and
                selection of drilling prospects, which enhances our ability to optimize
                our finding and development costs and to maximize our return on invested
                capital. Since we generate most of our projects, we generally have
                the
                ability to retain operational control over all phases of our exploration
                and development activities. As of December 31, 2006, we operated
                approximately 62.4% of the pre-tax PV10% value of our proved reserves.
                Further, in 2006 we operated 65% of the wells we drilled, representing
                93%
                of our drilling capital expenditures. We expect to operate approximately
                91% of our wells planned for 2007, representing approximately 92%
                of our
                planned 2007 drilling capital
                expenditures.





**Exploration
      and Development Staff**





Our
      experienced exploration staff includes 13 geologists, four geophysicists, one
      petrophysicist, two computer applications specialists and two geological
      technicians. Our geologists and geophysicists have varied but complementary
      backgrounds, and their diversity of experience in a wide-range of geological
      and
      geophysical settings, combined with various technical specializations (from
      hardware and systems to software and seismic data processing), provides us
      with
      valuable technical intellectual resources. Our geologists and geophysicists
      have
      an average of more than 21 years of experience in the industry. We have
      assembled our team of geologists and geophysicists with backgrounds that
      complement the areas where we focus our exploration and development activities.
      By integrating both geologic and geophysical expertise within our project teams,
      we believe we possess a competitive advantage in our exploration
      approach.


4
 *Table
          of Contents*


Our
      land
      department staff includes four landmen with an average of more than 23 years
      of
      experience, primarily within our core provinces, and three lease and division
      order analysts. Our land department contributed to pioneering many of the
      innovations that have facilitated exploration using large 3-D seismic
      projects.





**Operations
      and Operations Staff**





In
      an
      effort to retain better control of our project timing, drilling, operational
      costs and production volumes, we have significantly increased the percentage
      of
      the wells that we operate. We operated 65% of the gross wells and 85% of the
      net
      wells that we drilled during 2006, as compared with 10% of the gross wells
      and
      17% of the net wells we drilled during 1996. As a result of our increased
      operational control, wells operated by us constituted 62.4% of the pre-tax
      PV10%
      value of our proved reserves at year-end 2006, as compared to only 5% at
      year-end 1996.





Our
      operations staff includes seven engineers who have an average of over 12 years
      of experience in drilling, reservoir, environmental or operations engineering
      primarily within our four core operating provinces. These engineers work closely
      with our geologists and geophysicists and are integrally involved in all phases
      of the exploration and development process, including preparation of pre- and
      post-drill reserve estimates, well design, production management and analysis
      of
      full cycle risked drilling economics. We conduct field operations for our
      operated oil and natural gas properties through our field production
      superintendent and third party contract personnel.





**Oil
      and Natural Gas Market and Major Customers**





In
      an
      effort to achieve better price realizations from the sale of our oil and natural
      gas, we manage our commodities marketing activities in-house so that we are
      able
      to market and sell our oil and natural gas to a broader universe of potential
      purchasers. Due to the availability of other markets and pipeline connections,
      we do not believe that the loss of any single oil or natural gas customer would
      have a material adverse effect on our results of operations or cash
      flows.





We
      sell
      our oil and condensate at the lease to a variety of purchasers at prevailing
      market prices under short-term contracts that normally provide for us to receive
      an applicable posted price plus a market-based bonus.





Our
      natural gas production is sold to various purchasers including intrastate
      pipeline purchasers, operators of processing plants, and marketing companies
      under both monthly spot market contracts and multi-year arrangements. The vast
      majority of our natural gas sales are based on related natural gas index
      pricing, and in some cases our gas is processed at a plant and we receive a
      percentage of the value the plant operator receives from the resale of the
      natural gas liquids recovered and the remaining residue gas.





Since
      most of our oil and natural gas production is sold under price sensitive or
      spot
      market contracts, the revenues generated by our operations are highly dependent
      upon the prices of and demand for oil and natural gas. The price we receive
      for
      our oil and natural gas production depends upon numerous factors beyond our
      control, including seasonality, weather, competition, the condition of the
      United 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. See “Item 1A. Risk Factors — Oil and
      natural gas prices are volatile and a substantial reduction in these prices
      could adversely affect our results and the price of our common stock.”
Furthermore, a decrease in the price of oil and natural gas could have an
      adverse effect on the carrying value of our proved reserves and on our revenues,
      profitability and cash flow. See “Item 1A. Risk Factors - Lower oil and natural
      gas prices may cause us to record ceiling limitation write-downs, which would
      reduce our stockholders’ equity.”





Although
      we are not currently experiencing any significant involuntary curtailment of
      our
      oil or natural gas production, market, economic and regulatory factors may
      in
      the future materially affect our ability to sell our oil or natural gas
      production. See “Item 1A. Risk Factors — The marketability of our oil and
      natural gas production depends on services and facilities that we typically
      do
      not own or control. The failure or inaccessibility of any such services or
      facilities could result in a curtailment of production and
      revenues.”





**Competition**





The
      oil
      and natural gas industry is highly competitive in all phases. We encounter
      competition from other oil and natural gas companies in all areas of operation,
      including the acquisition of seismic and leasing options on oil and natural
      gas
      properties to the exploration and development of those properties. Our
      competitors include major integrated oil and natural gas companies, numerous
      independent oil and natural gas companies, individuals and drilling and income
      programs. Many of our competitors are large, well established companies that
      have substantially larger operating staffs and greater capital resources than
      we
      do. Such companies may be able to pay more for seismic and lease options on
      oil
      and natural gas properties and exploratory prospects and to define, evaluate,
      bid for and purchase a greater number of properties and prospects than our
      financial or human resources permit. Our ability to acquire additional
      properties and to discover reserves in the future will depend upon our ability
      to evaluate and select suitable properties and to consummate transactions in
      a
      highly competitive environment. See “Item 1A. Risk Factors — We face significant
      competition and many of our competitors have resources in excess of our
      available resources.”


5
 *Table
          of Contents*


**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 the
      new wells we drill will be productive or that we will recover all or any portion
      of our investment. Drilling for oil and natural gas may involve unprofitable
      efforts, not only from dry wells, but also from wells that are productive,
      but
      do not produce sufficient net revenues to return a profit after drilling,
      operating and other costs. The cost and timing of drilling, completing and
      operating wells is often uncertain. Our drilling operations may be curtailed,
      delayed or canceled as a result of numerous factors, many of which are beyond
      our control, including title problems, weather conditions, delays by project
      participants, compliance with governmental requirements, shortages or delays
      in
      the delivery of equipment and services and increases in the cost for such
      equipment and services. Our future drilling activities may not be successful
      and, if unsuccessful, such failure may have a material adverse effect on our
      business, financial condition, results of operations and cash flows. See “Item
      1A. Risk Factors — Our exploration, development and drilling efforts and the
      operation of our wells may not be profitable or achieve our targeted returns”,
“Item 1A. Risk Factors — Exploratory drilling is a speculative activity that may
      not result in commercially productive reserves and may require expenditures
      in
      excess of budgeted amounts,” “Item 1A. Risk Factors — Although our oil and
      natural gas reserve data is independently estimated, these estimates may still
      prove to be inaccurate” and “Item 1A. Risk Factors — The unavailability or high
      cost of drilling rigs, equipment, supplies, insurance, personnel and oil field
      services could adversely affect our ability to execute our exploration and
      development plans on a timely basis and within our budget.”





In
      addition, use of 3-D seismic technology requires greater pre-drilling
      expenditures than traditional drilling strategies. Although we believe that
      our
      use of 3-D seismic technology will increase the probability of drilling success,
      some unsuccessful wells are likely, and there can be no assurance that
      unsuccessful drilling efforts will not have a material adverse effect on our
      business, financial condition, results of operations and cash
      flows.





Our
      operations are subject to hazards and risks inherent in drilling for and
      producing and transporting oil and natural gas, such as fires, natural
      disasters, explosions, encountering formations with abnormal pressures,
      blowouts, cratering, pipeline ruptures and spills, any of which can result
      in
      the loss of hydrocarbons, environmental pollution, personal injury claims and
      other damage to our properties and those of others. We maintain insurance
      against some but not all of the risks described above. In particular, the
      insurance we maintain does not cover claims relating to failure of title to
      oil
      and natural gas leases, loss of surface equipment at well locations, trespass
      during 3-D survey acquisition or surface damage attributable to seismic
      operations, business interruption or loss of revenues due to well failure.
      Furthermore, in certain circumstances in which insurance is available, we may
      not purchase it. The occurrence of an event that is not covered, or not fully
      covered by insurance could have a material adverse effect on our business,
      financial condition, results of operations and cash flows in the period such
      event may occur. See “Item 1A. Risk Factors — We are subject to various
      operating and other casualty risks that could result in liability exposure
      or
      the loss of production and revenues” and “Item 1A. Risk Factors — We may not
      have enough insurance to cover all of the risks we face, which could result
      in
      significant financial exposure.”





**Governmental
      Regulation**





Our
      oil
      and natural gas exploration, production, transportation and marketing activities
      are subject to extensive laws, rules and regulations promulgated by federal
      and
      state legislatures and agencies, including the Federal Energy Regulatory
      Commission (FERC), the Environmental Protection Agency (EPA), the Texas
      Commission on Environmental Quality (TCEQ), the Texas Railroad Commission,
      the
      Louisiana Department of Natural Resources, the Industrial Commission of North
      Dakota, the Oklahoma Corporation Commission, the Wyoming Oil and Gas
      Conservation Commission, the Montana Board of Oil and Gas Conservation and
      similar commissions of the other states in which we do business. Failure to
      comply with such laws, rules and regulations can result in substantial
      penalties, including the delay or stopping of our operations. The legislative
      and regulatory burden on the oil and natural gas industry increases our cost
      of
      doing business and affects our profitability. See “Item 1A. Risk Factors — We
      are subject to various governmental regulations and environmental risks that
      may
      cause us to incur substantial costs.”





Although
      we do not own or operate any pipelines or facilities that are directly regulated
      by FERC, its regulation of third party pipelines and facilities could indirectly
      affect our ability to transport or market our production. Moreover, FERC has
      in
      the past, and could in the future, impose price controls on the sale of natural
      gas. In addition, we believe we are in substantial compliance with all
      applicable laws and regulations; however, we are unable to predict the future
      cost or impact of complying with such laws and regulations because they are
      frequently amended, interpreted and reinterpreted.


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The
      states of Texas, Oklahoma, Louisiana, Wyoming, North Dakota, Montana and most
      other states, as well as the federal government when operating on federal or
      Indian lands, 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 governmental
      authorities also have statutes or regulations addressing conservation matters,
      including provisions for the unitization or pooling of oil and natural gas
      properties, the establishment of maximum rates of production from wells and
      the
      regulation of spacing, plugging and abandonment of such wells.





**Environmental
      Matters**





Our
      operations and properties are, like the oil and natural 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 is generally toward stricter standards,
      and this trend will likely continue. These laws and regulations may: require
      a
      permit or other authorization before construction or drilling commences and
      for
      certain other activities; limit or prohibit access, seismic acquisition,
      construction, drilling and other activities on certain lands lying within
      wilderness and other protected areas; impose substantial liabilities for
      pollution resulting from our operations; and require the reclamation of certain
      lands.





The
      permits required for many of our operations are subject to revocation,
      modification and renewal by issuing authorities. Governmental authorities have
      the power to enforce compliance with their regulations, and violations are
      subject to fines, injunctions, or both. In the opinion of management, we are
      in
      substantial compliance with current applicable environmental laws and
      regulations, and we have no material commitments for capital expenditures to
      comply with existing environmental requirements. Nevertheless, changes in
      existing environmental laws and regulations or in interpretations thereof could
      have a significant impact on us, as well as the oil and natural gas industry
      in
      general. The Comprehensive Environmental Response, Compensation and Liability
      Act (CERCLA) and comparable state statutes impose strict and arguably joint
      and
      several liabilities on owners and operators of certain sites and on persons
      who
      disposed of or arranged for the disposal of “hazardous substances” found at such
      sites. It is not uncommon for the neighboring landowners and other third parties
      to file claims for personal injury and property damage allegedly caused by
      the
      hazardous substances released into the environment. The Resource Conservation
      and Recovery Act (RCRA) and comparable state statutes govern the disposal of
      “solid waste” and “hazardous waste” and authorize imposition of substantial
      fines and penalties for noncompliance. Although CERCLA currently excludes
      petroleum from its definition of “hazardous substance,” state laws affecting our
      operations impose clean-up liability relating to petroleum and petroleum related
      products. In addition, although RCRA classifies certain oil field wastes as
      “non-hazardous,” such exploration and production wastes could be reclassified as
      hazardous wastes, thereby making such wastes subject to more stringent handling
      and disposal requirements.





Federal
      regulations require certain owners or operators of facilities that store or
      otherwise handle oil, such as us, to prepare and implement spill prevention,
      control countermeasure and response plans relating to the possible discharge
      of
      oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous
      requirements relating to the prevention of and response to oil spills into
      waters of the United States. For onshore and offshore facilities that may affect
      waters of the United States, the OPA requires an operator to demonstrate
      financial responsibility. Regulations are currently being developed under
      federal and state laws concerning oil pollution prevention and other matters
      that may impose additional regulatory burdens on us. In addition, the Clean
      Water Act and analogous state laws require permits to be obtained to authorize
      discharge into surface waters or to construct facilities in wetland areas.
      The
      Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose
      permit requirements and necessitate certain restrictions on point source
      emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide)
      and
      particulates with respect to certain of our operations. We are required to
      maintain such permits or meet general permit requirements. The EPA and
      designated state agencies have in place regulations concerning discharges of
      storm water runoff and stationary sources of air emissions. These programs
      require covered facilities to obtain individual permits, participate in a group
      or seek coverage under an EPA general permit. Most agencies recognize the unique
      qualities of oil and natural gas exploration and production operations. Both
      the
      EPA and TCEQ have adopted regulatory guidance in consideration of the
      operational limitations on these types of facilities and their potential to
      emit
      air pollutants. We believe that we will be able to obtain, or be included under,
      such permits, where necessary, and to make minor modifications to existing
      facilities and operations that would not have a material effect on
      us.





There
      are
      various federal and state programs that regulate conservation and development
      of
      coastal resources. The federal Coastal Zone Management Act (CZMA) was passed
      to
      preserve and, where possible, restore the natural resources of the United
      States’ coastal zone. The CZMA provides for federal grants for the state
      management programs that regulate land use, water use and coastal
      development.


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The
      Texas
      Coastal Coordination Act (CCA) provides for coordination among local and state
      authorities to protect coastal resources through regulating land use, water,
      and
      coastal development and establishes the Texas Coastal Management Program that
      applies in the nineteen counties that border the Gulf of Mexico and its tidal
      bays. The CCA provides for the review of state and federal agency rules and
      agency actions for consistency with the goals and policies of the Coastal
      Management Plan. This review may affect agency permitting and may add a further
      regulatory layer to some of our projects.





The
      Louisiana Coastal Zone Management Program (LCZMP) was established to protect,
      develop and, where feasible, restore and enhance coastal resources of the state.
      Under the LCZMP, coastal use permits are required for certain activities, even
      if the activity only partially infringes on the coastal zone. Among other
      things, projects involving use of state lands and water bottoms, dredge or
      fill
      activities that intersect with more than one body of water, mineral activities,
      including the exploration and production of oil and natural gas, and pipelines
      for the gathering, transportation or transmission of oil, natural gas and other
      minerals require such permits. General permits, which entail a reduced
      administrative burden, are available for a number of routine oil and gas
      activities. The LCZMP and its requirement to obtain coastal use permits may
      result in additional permitting requirements and associated project schedule
      constraints.





See
“Item
      1A. Risk Factors — We are subject to various governmental regulations and
      environmental risks that may cause us to incur substantial costs.”





**Formation**





Our
      company was incorporated in the State of Delaware in February 1997.





**Facilities**





Our
      principal executive offices are located in Austin, Texas, where we lease
      approximately 34,330 square feet of office space at 6300 Bridge Point Parkway,
      Building 2, Suite 500, Austin, Texas 78730. In addition, we maintain a small
      satellite office in Denver, Colorado, where we lease approximately 475 square
      feet of office space at 820 16 th Street,
      Suite 412, Denver, Colorado 80202.





**Employees**





As
      of
      December 31, 2006, we had 66 full-time employees and 3 part-time employees.
      As
      of the end of 2006, none of our employees were represented by labor unions
      and
      we believe relations with them are good.





**Website
      Access**





We
      make
      available free of charge through our website, www.bexp3d.com, our annual report
      on Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K,
      and
      all amendments to those reports as soon as reasonably practicable after such
      material is electronically filed with the Securities and Exchange Commission.
      Information on our website is not a part of this report.





**Item
      1A.** ***Risk Factors***





You
      should carefully consider the following risk factors, in addition to the other
      information set forth in this report. Each of these risk factors could adversely
      affect our business, operating results and financial condition.




***Oil
      and natural gas prices are volatile and a substantial reduction in these prices
      could adversely affect our results and the price of our common
      stock.***





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.





The
      NYMEX
      daily settlement price for the prompt month natural gas contract in 2006 ranged
      from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu. In 2005, the same
      index ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu.


8
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The
      NYMEX
      daily settlement price for the prompt month oil contract in 2006 ranged from
      a
      high of $77.03 per barrel to a low of $55.81 per barrel. In 2005, the same
      index
      ranged from a high of $69.81 per barrel to a low of $42.12 per barrel.





The
      markets and prices for oil and natural gas depend on numerous factors beyond
      our
      control. These factors include demand for oil and natural gas, which fluctuate
      with changes in market and economic conditions and other factors,
      including:





•
            worldwide
                and domestic supplies of oil and natural gas;





•
            actions
                taken by foreign oil and natural gas producing nations;





•
            political
                conditions and events (including instability or armed conflict) in
                oil-producing or natural gas-producing
                regions;





•
            the
                level of global and domestic oil and natural gas inventories;





•
            the
                price and level of foreign imports including liquefied natural gas
                imports;




•
            the
                level of consumer demand;





•
            the
                price and availability of alternative fuels;





•
            the
                availability of pipeline or other takeaway capacity;





•
            weather
                conditions;





•
            domestic
                and foreign governmental regulations and taxes; and





•
            the
                overall worldwide and domestic economic environment.





Significant
      declines in oil and natural gas prices for an extended period may have the
      following effects on our business:





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





•
            reducing
                the amount of oil and natural gas that we can produce
                economically;





•
            causing
                us to delay or postpone some of our capital projects;





•
            reducing
                our revenues, operating income and cash flow;





•
            reducing
                the carrying value of our oil and natural gas properties;
                and





•
            limiting
                our access to sources of capital, such as equity and long-term
                debt.





***We
      may have difficulty financing our planned capital expenditures, which could
      adversely affect our business.***





We
      make
      and will continue to make substantial capital expenditures in our exploration
      and development projects. Without additional capital resources, our drilling
      and
      other activities may be limited and our business, financial condition and
      results of operations may suffer. We may not be able to secure additional
      financing on reasonable terms or at all and financing may not continue to be
      available to us under our existing or new financing arrangements. If additional
      capital resources are unavailable, we may curtail our drilling, development
      and
      other activities or be forced to sell some of our assets on an untimely or
      unfavorable basis. Any such curtailment or sale could have a material adverse
      effect on our business, financial condition and results of operation.


9
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***Our
      exploration, development and drilling efforts and the operation of our wells
      may
      not be profitable or achieve our targeted returns.***





We
      require significant amounts of undeveloped leasehold acreage in order to further
      our development efforts. Exploration, development, drilling and production
      activities are subject to many risks, including the risk that commercially
      productive reservoirs will not be discovered. We invest in property, including
      undeveloped leasehold acreage, which we believe will result in projects that
      will add value over time. However, we cannot guarantee that all of our prospects
      will result in viable projects or that we will not abandon our initial
      investments. Additionally, we cannot guarantee that the leasehold acreage we
      acquire will be profitably developed, that new wells drilled by us in provinces
      that we pursue will be productive or that we will recover all or any portion
      of
      our investment in such leasehold acreage or wells. 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 reserves to return
      a
      profit after deducting operating and other costs. In addition, wells that are
      profitable may not achieve our targeted rate of return. Our ability to achieve
      our target results is dependent upon the current and future market prices for
      oil and natural gas, costs associated with producing oil and natural gas and
      our
      ability to add reserves at an acceptable cost. We rely to a significant extent
      on 3-D seismic data and other advanced technologies in identifying leasehold
      acreage prospects and in conducting our exploration activities. The 3-D seismic
      data and other technologies we use do not allow us to know conclusively prior
      to
      the acquisition of leasehold acreage or the drilling of a well whether oil
      or
      natural gas is present or may be produced economically. The use of 3-D seismic
      data and other technologies also requires greater pre-drilling expenditures
      than
      traditional drilling strategies.





In
      addition, we may not be successful in implementing our business strategy of
      controlling and reducing our drilling and production costs in order to improve
      our overall return. The cost of drilling, completing and operating a well is
      often uncertain and cost factors can adversely affect the economics of a
      project. We cannot 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:





•
            unexpected
                drilling conditions;





•
            pressure
                or irregularities in formations;





•
            equipment
                failures or accidents;





•
            adverse
                weather conditions;





•
            compliance
                with governmental requirements; and





•
            shortages
                or delays in the availability of drilling rigs and the delivery of
                equipment.





***Exploratory
      drilling is a speculative activity that may not result in commercially
      productive reserves and may require expenditures in excess of budgeted
      amounts.***





Our
      future rate of growth greatly depends on the success of our exploratory drilling
      program. Exploratory drilling involves a higher degree of risk that we will
      not
      encounter commercially productive oil or natural gas reservoirs than
      developmental drilling. 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.





***Although
      our oil and natural gas reserve data is independently estimated, these estimates
      may still prove to be inaccurate.***





Our
      proved reserve estimates are generated each year by Cawley, Gillespie &
Associates, Inc., an independent petroleum consulting firm. In conducting its
      evaluation, the engineers and geologists of Cawley, Gillespie & Associates,
      Inc. evaluate our properties and independently develop proved reserve estimates.
      There are numerous uncertainties and risks that are inherent in estimating
      quantities of oil and natural gas reserves and projecting future rates of
      production and timing of development expenditures as many factors are beyond
      our
      control. We incorporate many factors and assumptions into our estimates
      including:





•
            expected
                reservoir characteristics based on geological, geophysical and engineering
                assessments;





•
            future
                production rates based on historical performance and expected future
                operating and investment
                activities;





•
            future
                oil and gas prices and quality and location differentials;
                and





•
            future
                development and operating costs.


10
 *Table
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Although
      we believe the Cawley, Gillespie & Associates, Inc. reserve estimates are
      reasonable based on the information available to them at the time they prepare
      their estimates, our actual results could vary materially from these estimated
      quantities of proved oil and natural gas reserves (in the aggregate and for
      a
      particular location), production, revenues, taxes and development and operating
      expenditures. In addition, these estimates of proved reserves may be subject
      to
      downward or upward revision based upon production history, results of future
      exploration and development, prevailing oil and natural gas prices, operating
      and development costs and other factors.





Finally,
      recovery of proved undeveloped reserves generally requires significant capital
      expenditures and successful drilling operations. At December 31, 2006,
      approximately 45% of our estimated proved reserves were classified as
      undeveloped. At December 31, 2006, we estimated that it would require additional
      capital expenditures of approximately $135 million to develop our proved
      undeveloped reserves. Our reserve estimates assume that we can and will make
      these expenditures and conduct these operations successfully, which may not
      occur.





***We
      need to replace our reserves at a faster rate than companies whose reserves
      have
      longer production periods. Our failure to replace our reserves would result
      in
      decreasing reserves and production over time.***





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 and production will decline as reserves are produced.





We
      may
      not be able to find, develop or acquire additional reserves to replace our
      current and future production. Accordingly, our future oil and natural gas
      reserves and production and therefore our future cash flow and income, are
      dependent upon our success in economically finding or acquiring new reserves
      and
      efficiently developing our existing reserves.





Our
      reserves in the Gulf Coast have high initial production rates followed by steep
      declines in production, resulting in a reserve life for wells in this area
      that
      is shorter than the industry average. This production volatility has impacted
      and, in the future, may continue to impact our quarterly and annual production
      levels.





We
      generally must locate and develop or acquire new oil and natural gas reserves
      to
      replace those being depleted by production. Without successful drilling and
      exploration or acquisition activities, our reserves and revenues will decline
      rapidly. We may not be successful in extending the reserve life of our
      properties generally and our Gulf Coast properties in particular. Our current
      strategy includes increasing our reserve base through drilling activities on
      our
      existing Gulf Coast properties and properties located in our other core areas,
      which have historically had longer-lived reserves. Our existing and future
      exploration and development projects may not result in significant additional
      reserves and we may not be able to drill productive wells at economically viable
      costs.





Our
      future cash flows are subject to a number of variables, such as the level of
      production from existing wells, prices of oil and natural gas and our success
      in
      finding and producing new reserves. If our revenues were to decrease as a result
      of lower oil and natural gas prices, decreased production or otherwise, and
      our
      access to capital were limited, we would have a reduced ability to replace
      our
      reserves or to maintain production at current levels, potentially resulting
      in a
      decrease in production and revenue over time.





***Drilling
      locations that we decide to drill may not yield oil or natural gas in
      commercially viable quantities or quantities sufficient to meet our targeted
      rate of return.***





Our
      drilling locations are in various stages of evaluation, ranging from locations
      that are ready to be drilled to locations that will require substantial
      additional evaluation and interpretation. There is no way to predict in advance
      of drilling and testing whether any particular drilling location will yield
      oil
      or natural gas in sufficient quantities to recover our drilling or completion
      costs or to be economically viable. Our use of seismic data and other
      technologies and the study of producing fields in the same area will not enable
      us to know conclusively prior to drilling whether oil and natural gas will
      be
      present or, if present, whether oil and natural gas will be present in
      commercial quantities. The analysis that we perform using data from other wells,
      more fully explored prospects and/or producing fields may not be useful in
      predicting the characteristics and potential reserves associated with our
      drilling locations. As a result, we may not find commercially viable quantities
      of oil and natural gas and, therefore, we may not achieve a targeted rate of
      return or have a positive return on investment.


11
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          of Contents*


***The
      unavailability or high cost of drilling rigs, equipment, supplies, insurance,
      personnel and oil field services could adversely affect our ability to execute
      our exploration and development plans on a timely basis and within our
      budget.***





Our
      industry is cyclical and, from time to time, there is a shortage of drilling
      rigs, equipment, supplies, insurance or qualified personnel. During these
      periods, the costs and delivery times of rigs, equipment and supplies are
      substantially greater. In addition, the demand for, and wage rates of, qualified
      drilling rig crews rise as the number of active rigs in service increases.
      As a
      result of increasing levels of exploration and production in response to strong
      prices of oil and natural gas, the demand for oilfield services has risen,
      and
      the costs of these services has increased, while the quality of these
      services may suffer. If the unavailability or high cost of drilling rigs,
      equipment, supplies, insurance or qualified personnel were particularly severe
      in Texas, Southern Louisiana, Oklahoma, Wyoming, North Dakota or Montana, we
      could be materially and adversely affected because our operations and properties
      are concentrated in those areas.





***The
      marketability of our oil and natural gas production depends on services and
      facilities that we typically do not own or control. The failure or
      inaccessibility of any such services or facilities could result in a curtailment
      of production and revenues.***





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 under interruptible or short term
      transportation agreements. Under the interruptible transportation agreements,
      the transportation of our natural gas may be interrupted due to capacity
      constraints on the applicable system, for maintenance or repair of the system,
      or for other reasons as dictated by the particular agreements. If any of the
      pipelines or other facilities become unavailable, we would be required to find
      a
      suitable alternative to transport and process the natural gas, which could
      increase our costs and reduce the revenues we might obtain from the sale of
      the
      natural gas. For example, in 2005, Hurricane Rita disrupted the operations
      of
      natural gas pipelines and fractionators and required the evacuation of personnel
      required to oversee some of our facilities in the Gulf Coast area. As a result
      of these disruptions, we were forced temporarily to curtail some of our
      production in our Onshore Gulf Coast province for approximately six
      days.





***Our
      level of indebtedness may adversely affect our cash available for operations,
      which would limit our growth, our ability to make interest and principal
      payments on our indebtedness as they become due and our flexibility to respond
      to market changes.***





At
      December 31, 2006, we had indebtedness of $123.4 million outstanding under
      our 9
      5/8% Senior Notes due 2014 (the “Senior Notes”), $25.9 million outstanding under
      our senior credit agreement, and $10.1 million of Series A preferred stock.
      Our
      level of indebtedness will have several important effects on our operations,
      including those listed below.





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





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





•
            Our
                ability to obtain additional financing in the future for working
                capital,
                capital expenditures, acquisitions, general corporate purposes or
                other
                purposes may be impaired.





•
            We
                may be more vulnerable to economic downturns and our ability to withstand
                sustained declines in oil and natural gas prices may be
                impaired.





•
            Since
                a portion of our indebtedness is subject to variable interest rates,
                we
                are vulnerable to increases in interest
                rates.





•
            Our
                flexibility in planning for or reacting to changes in market conditions
                may be limited.





We
      may
      incur additional debt in order to fund our exploration and development
      activities. A higher level of indebtedness increases the risk that we may
      default on our debt obligations. Our ability to meet our debt obligations and
      reduce our level of indebtedness depends on future performance. General economic
      conditions, oil and natural gas prices and financial, business and other factors
      will affect our operations and our future performance. Many of these factors
      are
      beyond our control and we may not be able to generate sufficient cash flow
      to
      pay the interest on our debt. In addition, borrowings and equity financing
      may
      not be available to pay or refinance such debt.


12
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          of Contents*


Under
      the
      terms of our senior credit agreement, our borrowing base is subject to
      semi-annual redetermination based in part on prevailing oil and natural gas
      prices. In the event the amount outstanding exceeds the redetermined borrowing
      base, we could be forced to repay a portion of our borrowings. We may not have
      sufficient funds to make such payments. If we do not have sufficient funds
      and
      are otherwise unable to negotiate renewals of our borrowings or arrange new
      financing, we may have to sell assets at unfavorable prices.





***Despite
      current indebtedness levels, we and our subsidiaries may still be able to incur
      substantially more debt, including secured debt. This could further exacerbate
      the risks associated with our substantial leverage.***





We
      and
      our subsidiaries may be able to incur substantial additional indebtedness in
      the
      future. The terms of the indenture governing the Senior Notes and our senior
      credit agreement do not prohibit us or our subsidiaries from doing so. In
      addition to the liens granted under our senior credit agreement, the indenture
      governing the Senior Notes allows us to grant liens on all of our other assets
      to secure indebtedness outstanding under the senior secured credit agreement
      and
      certain additional other debt without ratably securing the Senior Notes. Our
      senior credit agreement provides for total revolving credit borrowings up to
      $200 million (which borrowings are limited by a borrowing base that is subject
      to re-determination at least semi-annually and is currently set at
      $110 million) and all of those borrowings would be effectively senior to
      the Senior Notes and to the subsidiaries’ guarantees thereof to the extent of
      the value of the assets securing such indebtedness. If new indebtedness is
      added
      to our and our subsidiaries’ current debt levels, the related risks that we and
      they now face could intensify and we may not be able to meet all our debt
      obligations, including the repayment of the Senior Notes, in whole or in part.





***To
      service our indebtedness, we will require a significant amount of cash. Our
      ability to generate cash depends on many factors beyond our
      control.***





Our
      ability to make payments on and to refinance our indebtedness and to fund
      planned capital expenditures and development efforts will depend on our ability
      to generate cash in the future. This, to a certain extent, is subject to general
      economic, financial, competitive, legislative, regulatory and other factors
      that
      are beyond our control.





We
      cannot
      assure you that our business will generate sufficient cash flow from operations
      or that future borrowings will be available to us under our senior credit
      agreement or otherwise in an amount sufficient to enable us to pay our
      indebtedness or to fund our other liquidity needs. We may need to refinance
      all
      or a portion of our indebtedness on or before the maturity thereof. Any future
      borrowings under our senior credit agreement will mature in June 2010. As a
      result, we may be required to refinance any indebtedness then outstanding under
      our senior credit agreement prior to the maturity of the notes. We may not
      be
      able to obtain such financing on commercially reasonable terms or at all. If
      we
      are unable to generate sufficiently material cash flow to refinance our debt
      obligations, including the notes, on favorable terms, it could have a
      significant adverse effect on our financial condition and on our ability to
      pay
      principal and interest on the notes.





In
      addition, if for any reason we are unable to meet our debt service obligations,
      we would be in default under the terms of our agreements governing our
      outstanding debt. If such a default were to occur, the lenders under our senior
      credit agreement could elect to declare all amounts then outstanding under
      the
      senior credit agreement immediately due and payable, and the lenders would
      not
      be obligated to continue to advance funds under our senior credit agreement.
      In
      addition, if such a default were to occur, the Senior Notes would become
      immediately due and payable. If the amounts outstanding under these debt
      agreements are accelerated, we cannot assure you that our assets will be
      sufficient to repay in full the money owed to the banks or to our debt holders,
      including holders of notes.





***The
      indenture governing the Senior Notes imposes, and our senior credit agreement
      imposes, significant operating and financial restrictions, which may prevent
      us
      from capitalizing on business opportunities and taking some
      actions.***





The
      indenture governing the Senior Notes and our senior credit agreement contain,
      customary restrictions on our activities, including covenants that restrict
      our
      and our subsidiaries’ ability to:




•
            incur
                additional debt;





•
            pay
                dividends on, or redeem or repurchase
                stock;


13
 *Table
          of Contents*




•
            create
                liens;





•
            make
                specified types of investments;





•
            apply
                net proceeds from certain asset
                sales;





•
            engage
                in transactions with our
                affiliates;





•
            engage
                in sale and leaseback transactions;





•
            merge
                or consolidate;





•
            restrict
                dividends or other payments from
                subsidiaries;





•
            sell
                equity interests of
                subsidiaries; and





•
            sell,
                assign, transfer, lease, convey or dispose of
                assets.





Our
      senior credit agreement also requires us to meet a minimum current ratio and
      a
      minimum interest coverage ratio. We may not be able to maintain these ratios,
      and if we fail to be in compliance with these tests, we will not be able to
      borrow funds under our senior credit agreement which would make it difficult
      for
      us to operate our business.





The restrictions in the indenture governing the Senior Notes and our senior
      credit agreement may prevent us from taking actions that we believe would be
      in
      the best interest of our business, and may make it difficult for us to
      successfully execute our business strategy or effectively compete with companies
      that are not similarly restricted. We may also incur future debt obligations
      that might subject us to additional restrictive covenants that could affect
      our
      financial and operational flexibility. We cannot assure you that we will be
      granted waivers or amendments to these agreements if for any reason we are
      unable to comply with these agreements, or that we will be able to refinance
      our
      debt on terms acceptable to us, or at all.





The breach of any of these covenants and restrictions could result in a default
      under the indenture governing the Senior Notes or under our senior credit
      agreement. An event of default under our debt agreements would permit some
      of
      our lenders to declare all amounts borrowed from them to be due and payable.
      If
      we are unable to repay debt, lenders having secured obligations, such as the
      lenders under our senior credit agreement, could proceed against the collateral
      securing the debt. Because the indenture governing the Senior Notes and our
      senior credit agreement have customary cross-default provisions, if the
      indebtedness under the Senior Notes or under our senior credit agreements or
      any
      of our other facilities is accelerated, we may be unable to repay or finance
      the
      amounts due.





***We
      may not have the ability to raise the funds necessary to finance the change
      of
      control offer required by the indenture governing the Senior
      Notes.***





Upon
      the occurrence of certain kinds of change of control events, we will be required
      to offer to repurchase all outstanding Senior Notes at 101% of the principal
      amount thereof plus accrued and unpaid interest, if any, to the date of
      repurchase, unless all Senior Notes have been previously called for redemption.
      The holders of other debt securities that we may issue in the future, which
      rank
      equally in right of payment with the Senior Notes, may also have this right.
      Our
      failure to purchase tendered Senior Notes would constitute an event of default
      under the indenture governing the notes, which in turn, would constitute a
      default under our senior credit agreement. In addition, the occurrence of a
      change of control would also constitute an event of default under
      our
      senior credit agreement. A default under our senior credit agreement would
      result in a default under the indenture if the lenders accelerate the debt
      under
      our senior credit agreement.





Therefore,
      it is possible that we may not have sufficient funds at the time of the change
      of control to make the required repurchase of Senior Notes. Moreover, our senior
      credit agreement restricts, and any future indebtedness we incur may restrict,
      our ability to repurchase the Senior Notes, including following a change of
      control event. As a result, following a change of control event, we would not
      be
      able to repurchase the Senior Notes unless we first repay all indebtedness
      outstanding under our senior credit agreement and any of our other indebtedness
      that contains similar provisions, or obtain a waiver from the holders of such
      indebtedness to permit us to repurchase the Senior Notes. We may be unable
      to
      repay all of that indebtedness or obtain a waiver of that type. Any requirement
      to offer to repurchase the outstanding Senior Notes may therefore require us
      to
      refinance our other outstanding debt, which we may not be able to do on
      commercially reasonable terms, if at all. These repurchase requirements may
      also
      delay or make it more difficult for others to obtain control of us.


14
 *Table
          of Contents*


In
      addition, certain important corporate events, such as leveraged
      recapitalizations that would increase the level of our indebtedness, would
      not
      constitute a “Change of Control” under the indenture.




***Lower
      oil and natural gas prices may cause us to record ceiling limitation
      write-downs, which would reduce our stockholders’
equity.***





We
      use
      the full cost method of accounting to account for our oil and natural gas
      investments. Accordingly, we capitalize the cost to acquire, explore for and
      develop oil and natural gas properties. Under full cost accounting rules, the
      net capitalized cost of oil and natural gas properties may not exceed a “ceiling
      limit” that is based upon the present value of estimated future net revenues
      from proved reserves, discounted at 10%, plus the lower of the cost or fair
      market value of unproved properties. If net capitalized costs of oil and natural
      gas properties exceed the ceiling limit, we must charge the amount of the excess
      to earnings. This is called a “ceiling limitation write-down.” The risk that we
      will experience a ceiling test write-down increases when oil and gas prices
      are
      depressed or if we have substantial downward revisions in its estimated proved
      reserves. Once incurred, a write-down of oil and gas properties is not
      reversible at a later date. Write-downs required by these rules do not impact
      our cash flow from operating activities, but do reduce net income and
      stockholders’ equity.





***We
      are subject to various operating and other casualty risks that could result
      in
      liability exposure or the loss of production and
      revenues.***





Our
      operations are subject to hazards and risks inherent in drilling for and
      producing and transporting oil and natural gas, such as:





•
            fires;





•
            natural
                disasters;





•
            formations
                with abnormal pressures;





•
            blowouts,
                cratering and explosions; and





•
            pipeline
                ruptures and spills.





Any
      of
      these hazards and risks can result in the loss of hydrocarbons, environmental
      pollution, personal injury claims and other damage to our properties and the
      property of others.





***We
      may not have enough insurance to cover all of the risks we face, which could
      result in significant financial exposure.***





We
      maintain insurance coverage against some, but not all, potential losses in
      order
      to protect against the risks we face. We may elect not to carry insurance if
      our
      management believes that the cost of insurance is excessive relative to the
      risks presented. If an event occurs that is not covered, or not fully covered,
      by insurance, it could harm our financial condition, results of operations
      and
      cash flows. In addition, we cannot fully insure against pollution and
      environmental risks.


15
 *Table
          of Contents*





***We
      cannot control activities on properties we do not operate. Failure to fund
      capital expenditure requirements may result in reduction or forfeiture of our
      interests in some of our non-operated projects.***





We
      do not
      operate some of the properties in which we have an interest and we have limited
      ability to exercise influence over operations for these properties or their
      associated costs. As of December 31, 2006, approximately 37.6% of our oil and
      natural gas properties, based on pre-tax PV10% value, were operated by other
      companies. Our dependence on the operator and other working interest owners
      for
      these projects and our limited ability to influence operations and associated
      costs could materially adversely affect the realization of our targeted return
      on capital in drilling or acquisition activities and our targeted production
      growth rate. The success and timing of drilling, development and exploitation
      activities on properties operated by others depend on a number of factors that
      are beyond our control, including the operator’s expertise and financial
      resources, approval of other participants for drilling wells and utilization
      of
      technology.





When
      we
      are not the majority owner or operator of a particular oil or natural gas
      project, we may have no control over the timing or amount of capital
      expenditures associated with such project. If we are not willing or able to
      fund
      our capital expenditures relating to such projects when required by the majority
      owner or operator, our interests in these projects may be reduced or
      forfeited.





***Our
      future operating results may fluctuate and significant declines in them would
      limit our ability to invest in projects.***





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





•
            industry
                conditions;





•
            prices
                of oil and natural gas;





•
            rates
                of drilling success;





•
            capital
                availability;





•
            rates
                of production from completed wells; and





•
            the
                timing and amount of capital expenditures.





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





***Our
      hedging activities may prevent us from benefiting from price increases and
      may
      expose us to other risks.***





In
      an
      attempt to reduce our sensitivity to energy price volatility and in particular
      to downward price movements, we enter into hedging arrangements with respect
      to
      a portion of expected production, such as the use of derivative contracts that
      generally result in a range of minimum and maximum price limits or a fixed
      price
      over a specified time period.





Our
      hedging activities expose us to the risk of financial loss in certain
      circumstances. For example, if we do not produce our oil and natural gas
      reserves at rates equivalent to our derivative position, we would be required
      to
      satisfy our obligations under those derivative contracts on potentially
      unfavorable terms without the ability to offset that risk through sales of
      comparable quantities of our own production. This situation occurred during
      portions of 2000, due in part to our sale of certain producing reserves in
      mid-
      1999 and reduced our cash flow in 2000 by approximately $1.0 million.
      Additionally, because the terms of our derivative 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 prices we receive pursuant to our derivative
      contracts and our actual results could harm our anticipated profit margins
      and
      our ability to manage the risk associated with fluctuations in oil and natural
      gas prices. We also could be financially harmed if the counter parties to our
      derivative contracts prove unable or unwilling to perform their obligations
      under such contracts. Additionally, in the past, some of our derivative
      contracts required us to deliver cash collateral or other assurances of
      performance to the counter parties if our payment obligations exceeded certain
      levels. Future collateral requirements are uncertain but will depend on
      arrangements with our counter parties and highly volatile oil and natural gas
      prices.


16
 *Table
          of Contents*


***We
      face significant competition and many of our competitors have resources in
      excess of our available resources.***





We
      operate in the highly competitive areas of oil and natural gas exploration,
      exploitation, acquisition and production. We face intense competition from
      a
      large number of independent, technology-driven companies as well as both major
      and other independent oil and natural gas companies in a number of areas such
      as:





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





•
            marketing
                our oil and natural gas production; and





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





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.





***We
      are subject to various governmental regulations and environmental risks that
      may
      cause us to incur substantial costs.***





From
      time
      to time, in varying degrees, political developments and federal and state laws
      and regulations affect our operations. In particular, price controls, taxes
      and
      other laws relating to the oil and natural gas industry, changes in these laws
      and changes in administrative regulations have affected and in the future could
      affect oil and natural gas production, operations and economics. We cannot
      predict how agencies or courts will interpret existing laws and regulations
      or
      the effect of these adoptions and interpretations may have on our business
      or
      financial condition.





Our
      business is subject to laws and regulations promulgated by federal, state and
      local authorities, including the FERC, the EPA, the Texas Railroad Commission,
      the TCEQ, the Oklahoma Corporation Commission, the Louisiana Department of
      Natural Resources, the Industrial Commission of North Dakota, the Wyoming Oil
      and Gas Conservation Commission and the Montana Board of Oil and Gas
      Conversation, relating to the exploration for, and the development, production
      and marketing of, oil and natural gas, as well as safety matters. 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 federal, state and local environmental laws
      and regulations, including CERCLA, RCRA, OPA and the Clean Water Act.
      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 oil, natural gas 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
      depend on our key management personnel and technical experts and the loss any
      of
      these individuals could adversely affect our
      business.***





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 have assembled a team of geologists, geophysicists and engineers
      who
      have considerable experience in applying 3-D seismic imaging technology to
      explore for and to develop oil and natural gas. We depend upon the knowledge,
      skill and experience of these experts to provide 3-D seismic 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 Mr. Brigham, but do not have an employment agreement with any of our other
      employees.





***The
      market price of our stock is volatile.***





The
      trading price of our common stock and the price at which we may sell securities
      in the future are subject to large fluctuations in response to any of the
      following:





•
            limited
                trading volume in our stock;





•
            changes
                in government regulations;


17
 *Table
          of Contents*


•
            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.





***Our
      stock price may decline when our financial results decline or when events occur
      that are adverse to us or our industry.***





You
      can
      expect the market price of our common stock to decline when our financial
      results decline or otherwise fail to meet the expectations of the financial
      community or the investing public or at any other time when events actually
      or
      potentially adverse to us or the oil and natural gas industry occur. Our common
      stock price may decline to a price below the price you paid to purchase your
      shares of common stock.





***We
      do not intend to pay any dividends on our common
      stock.***





We
      anticipate that we will retain all future earnings and other cash resources
      for
      the future operation and development of our business. Accordingly, we do not
      intend to declare or pay any cash dividends on our common stock in the
      foreseeable future. Payment of any future dividends will be at the discretion
      of
      our board of directors after taking into account many factors, including our
      operating results, financial condition, current and anticipated cash needs
      and
      plans for expansion.





***Our
      shares that are eligible for future sale may have an adverse effect on the
      price
      of our common stock.***





Sales
      of
      substantial amounts of common stock, or a perception that such sales could
      occur, could adversely affect the market price of our common stock and could
      impair our ability to raise capital through the sale of our equity securities.
      At December 31, 2006, one of our stockholders, together with its affiliates,
      owned 16.7% of our outstanding common stock.





***Certain
      of our affiliates control a substantial portion of our outstanding common stock,
      which may affect your vote as a stockholder.***





Our
      directors, executive officers and 10% or greater stockholders, and certain
      of
      their affiliates, beneficially own a substantial portion of our outstanding
      common stock. Accordingly, these stockholders, as a group, may 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 our
      common stock may be able to affect our management or direction. These factors
      may also have the effect of delaying or preventing a change in our management
      or
      voting control.





***Certain
      anti-takeover provisions may adversely 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. In addition, our Series A
      preferred stock, our senior credit agreement and our subordinated credit
      agreement contain terms restricting our ability to enter into change of control
      transactions, including requirements to redeem or repay our outstanding Series
      A
      preferred stock, the amounts borrowed under our senior credit agreement and
      the
      amounts borrowed under our subordinated credit agreement upon a change in
      control. 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.


18
 *Table
          of Contents*


**Forward-Looking
      Statements**





This
      report and the documents incorporated by reference in this annual report on
      Form
      10-K contain forward-looking statements within the meaning of the federal
      securities laws.





These
      forward-looking statements include, among others, the following:





•
            our
                growth strategies;





•
            our
                ability to successfully and economically explore for and develop
                oil and
                gas resources;





•
            anticipated
                trends in our business;





•
            our
                future results of operations;





•
            our
                liquidity and ability to finance our exploration and development
                activities;





•
            market
                conditions in the oil and gas industry;





•
            our
                ability to make and integrate acquisitions; and





•
            the
                impact of governmental regulation.





Forward-looking
      statements are typically identified by use of terms such as “may,” “will,”
“expect,” “anticipate,” “estimate” and similar words, although some
      forward-looking statements may be expressed differently.





You
      should be aware that our actual results could differ materially from those
      contained in the forward-looking statements. You should consider carefully
      the
      statements in this “Item 1A. Risk Factors” and other sections of this report,
      which describe factors that could cause our actual results to differ from those
      set forth in the forward-looking statements.





**Item
      1B.** ***Unresolved
      Staff Comments***





None.





**Item
      2.** ***Properties***





Historically,
      our exploration and development activities have been focused primarily in the
      Onshore Gulf Coast, the Anadarko Basin in the Texas Panhandle and western
      Oklahoma and West Texas. We focus our activity in provinces where we believe
      technology and the knowledge of our technical staff can be effectively used
      to
      maximize our return on invested capital by reducing drilling risk and enhancing
      our ability to grow reserves and production volumes. We also regularly evaluate
      opportunities to expand our activities to areas that may offer attractive
      exploration and development potential, with a particular interest in those
      plays
      that complement our current exploration, development and production activities.
      Recent expansion initiatives include our acquisition of acreage in the Powder
      River Basin of Wyoming and the Williston Basin of North Dakota and Montana.
      In
      2006, we drilled two horizontal wells on our Powder River Basin acreage and
      three horizontal wells on our North Dakota Williston Basin acreage. We view
      these as early investments, which we hope will generate drilling inventory
      and potential reserves in future years. During 2006, we invested a total of
      $32.1 million in land, G&G and drilling in the Williston Basin and Powder
      River Basin. To support our efforts in these new operating areas as well as
      to
      evaluate other opportunities in the Rocky Mountains, we opened a small one
      person satellite office in Denver, Colorado during December 2006. Additionally,
      we have implemented joint ventures with two operators in Southern Louisiana,
      which we view as a logical extension of our onshore Texas Gulf Coast activities.
      During 2006, we drilled a total of eight wells with our two joint venture
      partners in South Louisiana, spending a total of $17.5 million in the area
      during 2006.


19
 *Table
          of Contents*


For
      the
      three-year period ended December 31, 2006, we completed 116 gross wells (59.9
      net) in 132 attempts for a completion rate of 88%. We also had three exploration
      wells and three development wells that were completing and one development
      well
      that was drilling as of December 31, 2006. For 2007, we plan to spend
      approximately $91.2 million to drill seven exploration wells and 15 development
      wells, to drill and complete wells that were in progress at December 31, 2006
      and for other development activities. We also plan to spend $11.2 million on
      land and seismic and $11.5 million for capitalized costs.. See “Item 7.
      Management’s Discussion and Analysis of Financial Condition and Results of
      Operations — Capital Commitments — Capital Expenditures.” The following is a
      summary of our properties by major province as of December 31, 2006, unless
      otherwise noted.








**Onshore**
              **Gulf
                Coast**
            
            **Anadarko**
              **Basin**
            
            **Rocky**
              **Mountains
                (a)**
            
            **West
                Texas**
              **&
                Other**
            
            **Total**Capital
                expenditures for drilling, land and seismic in 2006(in
                millions)
            
            $
            86.7
            
            $
            51.7
            
            $
            32.1
            
            $
            3.5
            
            $
            174.0***Proved
                Reserves at December 31, 2006***Pre-tax
                PV10% (in millions)
            
            $
            227.0
            
            $
            80.1
            
            
            10.3
            
            $
            21.1
            
            $
            338.5(b
            )Oil
                (MMBbls)
            
            
            2.0
            
            
            0.6
            
            
            1.2
            
            
            0.7
            
            
            4.5Natural
                gas (Bcf)
            
            
            68.9
            
            
            49.3
            
            
            0.6
            
            
            0.7
            
            
            119.5Natural
                gas equivalents (Bcfe)
            
            
            80.9
            
            
            52.8
            
            
            7.7
            
            
            5.1
            
            
            146.5%
                Natural gas
            
            
            85
            %
            
            93
            %
            
            8
            %
            
            14
            %
            
            82
            %Average
                daily production (MMcfe/d)
            
            
            22.3
            
            
            11.6
            
            
            0.3
            
            
            2.6
            
            
            36.8***Productive
                wells at December 31, 2006***Gross
            
            
            88.0
            
            
            142.0
            
            
            6.0
            
            
            82.0
            
            
            318.0Net
            
            
            40.3
            
            
            44.3
            
            
            4.1
            
            
            25.3
            
            
            114.03-D
                Seismic Data (square miles)
            
            
            4,369
            
            
            2,381
            
            
            100
            
            
            4,487
            
            
            11,337


__________


(a)
            Includes
                the Powder River Basin in Wyoming and the Williston Basin in North
                Dakota
                and Montana .





(b)
            The
                standardized measure for our proved reserves at December 31, 2006,
                was
                $302.7 million. See “— Reconciliation of Standardized Measure to Pre-tax
                PV10%” for a definition of pre-tax PV10% and a reconciliation of our
                standardized measure to our pre-tax PV10% value.





**Onshore
      Gulf Coast Province**





Our
      Onshore Gulf Coast province is a high potential, multi-pay province that lends
      itself to 3-D seismic exploration due to its substantial structural and
      stratigraphic complexity. In addition, certain sand reservoirs display seismic
      “bright spots,” which can be direct hydrocarbon indicators and can result in
      greatly reduced drilling risk. However, “bright spots” are not always reliable
      as direct hydrocarbon indicators and do not generally assess reservoir
      productivity. We believe our established 3-D seismic exploration approach,
      combined with our exploration staff’s extensive experience and accumulated
      knowledge base in this province, provides us with significant competitive
      advantages.





Key
      operating trends within this province include the Vicksburg trend in Brooks
      County, Texas and the Frio trend in and around Matagorda County, Texas. In
      addition, during the first quarter 2006 we announced joint ventures with two
      operators to explore for oil and natural gas in Southern Louisiana. We view
      Southern Louisiana as a logical extension of our current activities in the
      onshore Texas Gulf Coast. As such, Southern Louisiana operations have been
      consolidated within our Onshore Gulf Coast province.





Over
      the
      three year period ended December 31, 2006, approximately 57% of our total
      capital expenditures for drilling, land and seismic were allocated to our
      Onshore Gulf Coast province, where we completed 45 gross wells (31.8 net) in
      54
      attempts for a completion rate of 83%.





During
      2006, we completed 12 gross wells (9.1 net) in 17 attempts for a completion
      rate
      of 71% in this province. Five of the completed wells were exploration wells
      and
      seven were development wells. We also had one exploration well and one
      development well that were completing and one development well that was drilling
      as of December 31, 2006. We operated 80% of the wells that we drilled in this
      province during 2006. For 2006, we spent $86.7 million on drilling, land and
      seismic in our Onshore Gulf Coast province. Approximately 40% of the drilling,
      land and seismic was allocated to the Vicksburg, 38% to the Frio, 20% to
      Southern Louisiana, and 2% to other areas in the province.


20
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For
      2007,
      we currently plan to spend a total of $64.5 million in our Onshore Gulf Coast
      province. Approximately $61.6 million of this spending has been allocated to
      drilling, with the remaining $2.9 million allocated to capital spending for
      land
      and seismic activities. We plan to drill seven development wells and spend
      approximately $48.9 million on development drilling capital. We also plan to
      drill two exploration wells and spend $12.7 million on exploration drilling
      capital.




***Vicksburg
      Trend***





Our
      Vicksburg activity is focused principally in Brooks County, Texas, in our Home
      Run, Triple Crown, and Floyd Fields. We discovered these fields in 1999, 2001
      and 2002, respectively. In 2006, we successfully completed all five of our
      development drilling wells spud in 2006 including three in the Triple Crown
      Field, one in the Home Run Field and one in the Floyd Field. Total drilling,
      land and seismic capital expended in the Vicksburg during 2006 was $34.7
      million.





During
      2006, we operated all of our Vicksburg drilling, and the working interests
      we
      retained in our Vicksburg wells was higher than our historic average as our
      joint venture participant elected to take a more passive role in the development
      of the field. Rather than participating in the drilling of the wells with a
      paying working interest, our joint venture participant elected to receive a
      reversionary, or back-in working interest, based on certain payout thresholds
      in
      all of the 2006 Vicksburg wells. We continue to have discussions with our joint
      venture participant about other exploratory joint venture opportunities in
      the
      area and expect to continue to expand our activities in the trend.





Early
      in
      2006, we successfully completed the Triple Crown Field Sullivan C-32 and Home
      Run Field Palmer 3S #2, which were carryover wells from the 2005 drilling
      program, at approximately 1.7 MMcfe per day and 2.3 MMcfe per day, respectively.
      Thereafter, we completed the Home Run Field Palmer #11 and Triple Crown Field
      Dawson #3, which produced at initial rates of approximately 5.3 MMcfe per day
      and 4.7 MMcfe per day, respectively. In August, we completed the Triple Crown
      Field Dawson #4 well from the 9800’ sands at an initial rate of approximately
      3.0 MMcfe per day.





In
      September, we successfully completed the Triple Crown Field Sullivan F-33,
      which
      came on-line at approximately 9.5 MMcfe per day. We encountered four pay zones
      and are currently producing only out of the deepest zone, the Dawson sand.
      Our
      plans are to commingle the remaining three zones after flowing tubing pressures
      from the Dawson sand subside. The remaining 61 feet of apparent pay includes,
      from shallowest to deepest, the Brigham, 9800’ and Loma Blanca sands. Production
      from the Dawson sand indicates the potential for further reserve growth in
      the
      Vicksburg, as this is the first well to be completed to sales from this zone.





Also
      in
      September, we commenced drilling the Floyd Field Sullivan C-33, an offset to
      our
      highly productive Sullivan #10. The Sullivan C-33 was brought on line in January
      2007 at a rate of approximately 6.1 MMcf of natural gas and 570 barrels of
      oil
      per day (9.5 MMcfe per day). Subsequently, other pay intervals were brought
      on
      line and production increased to 10.6 MMcfe per day.





During
      2007, we plan to operate a drilling rig on a continuous basis in the Vicksburg.
      In mid-January, we spud the Dawson #1S, the first of five consecutive Vicksburg
      wells we expect to drill in 2007. The Dawson #1S is a sidetrack of the
      previously drilled Dawson #1 and is an east offset to the aforementioned
      Sullivan F-33.  Based
      on
      mud logs and wireline logs, the Dawson #1S appears to have encountered roughly
      comparable 9800’ and Loma Blanca pay to that found in the offsetting wells. We
      retained a 100% working and 75% net revenue interest in the Dawson
      #1S.Following the Dawson #1S, we plan to drill the Sullivan C-35 in
      our Triple Crown Field. This well will test a number of upper Vicksburg pay
      intervals, and has the potential to prove up significant and additional
      locations and reserves. We expect the Sullivan C-35 to be followed by the
      Sullivan #14, which is also a well that could prove up additional development
      locations in our Triple Crown Field. Following
      the Sullivan #14, Brigham plans to commence the Sullivan #15, a significant
      development well in our Home Run Field. The Sullivan #15 appears to be
      located in a structurally high location at various Lower Vicksburg intervals,
      and could potentially prove up significant additional locations and reserves.
      We
      expect to retain a 100% working interest in the Sullivan #15 subject to a 66%
      back-in at 350% payout.





During
      2007, we plan to spend $33.0 million to drill five development wells, to drill
      and complete wells that were in progress at December 31, 2006 and for other
      development activities. We expect to retain an average initial working interest
      of 100% in these wells. We also expect to spend $1.6 million on land and
      seismic.





Since
      1999, we have drilled 35 Vicksburg wells, and we have completed 33 of those
      tests. We believe we have a multi-year inventory of drilling locations in our
      Home Run, Triple Crown and Floyd Fault Block Fields, and we expect to add to
      this inventory in 2007.





***Frio
      Trend***





During
      2006, we drilled seven wells that targeted the Frio, including four exploratory
      and three development wells. Drilling, land and seismic capital expenditures
      for
      2006 totaled $32.4 million.


21
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The
      Sartwelle #4 was completed in the middle Frio and encountered 22 feet of
      apparent pay in a fault block that is estimated to be 320 acres. Production
      commenced in April 2006 at approximately 2.6 MMcfe per day. The Trull B #3
      encountered 36 feet of apparent pay in various Frio intervals and was brought
      on-line in June 2006 at 2.8 MMcfe per day.





Our
      State
      Tract #109 tested what has been mapped as a 500 acre complex in the lower Frio
      and encountered 60 feet of apparent Lower Frio pay, with an additional 73 feet
      of potential pay that will likely be tested at a later date. This exploratory
      well initially flowed at approximately 2.4 MMcfe per day, but experienced a
      decline in production and began producing some sand. As a consequence, a frac
      pac was put in place to enhance production and to limit sand production.
      Subsequent to the frac pac, the well produced approximately 500 Mcfe per day,
      with additional potential pay remaining behind pipe for future
      completion.





In
      December 2006, we commenced drilling our high potential Frio exploratory test,
      the Green Ranch #1. In January 2007, after encountering poor sand quality,
      the
      well was plugged and abandoned.





In
      2007,
      we currently plan to spend $ 7.7 million to drill one exploration well, to
      drill
      and complete wells that were in progress at December 31, 2006 and for other
      development activities.





***Southern
      Louisiana Trend***





In
      February 2006, we announced two new joint ventures to explore and develop 3-D
      delineated projects that target the Miocene and upper Oligocene trends located
      in South Louisiana. We view these projects as a logical extension of our
      activities in the onshore Texas Gulf Coast. In Southern Louisiana, we will
      utilize our geophysical, geological and operational expertise to explore for
      and
      develop potential Oligocene and Miocene reservoirs directly on trend to that
      of
      the Texas Gulf Coast Frio. During 2006, we drilled eight wells in the area
      with
      drilling, land and seismic expenditures totaling $17.5 million.





In
      our
      Bayou Postillion Project, which is located in Iberia Parish, Louisiana, we
      operated the drilling of the Cotten Land Corp. #1, with a 41% after casing
      point
      working interest. The Cotten Land Corp. #1 encountered 34 feet of apparent
      pay
      in a Miocene objective approximately 324 feet high to a down dip producer.
      The
      well put on line in September 2006 at an initial rate of approximately 10.1
      MMcfe per day and in March 2007 was producing at a rate of approximately 15
      MMcfe per day.





In
      August
      2006, we participated in drilling an offset to the Cotten Land #1, the Marie
      Snyder #1, which found 40 feet of apparent pay. We retain a 13% working interest
      in the well, which is in the process of being completed.





On
      December 31, 2006, we spud our Cotton Land #3, which is our second development
      well in Bayou Postillion. We
      successfully production tested the Cotten Land #3, which encountered
      approximately 80 feet of apparent net pay in two intervals. The Cotten Land
      #3
      was tested from the lowest 30 feet of pay at a production rate of 12.9 MMcf
      of
      natural gas and 48 barrels of oil per day with strong pressures. Based on the
      minimal pressure differences between the flowing and shut in tubing pressures,
      we expect to produce the well at an initial rate between 15 MMcfe and 20 MMcfe
      per day. Approximately 50 feet of shallower pay will remain behind pipe for
      future completion.Brigham operates the Cotten Land #3 with an
      approximate 47% working interest.




During
        the second quarter 2007, we plan to commence the Cotten Land #2, which is
        expected to test an apparent new fault block adjacent to the fault block
        in
        which Brigham drilled the Cotten Land #1 well. The unrisked reserve potential
        of
        this apparent fault block is estimated at approximately 4 to 12 Bcfe. Following
        the Cotten Land #2, Brigham plans to commence the Cotten Land #4, offsetting
        Brigham’s previously drilled Cotten Land #1 discovery.


In
      our
      Mystic Bayou Project located in St. Martin Parish, Louisiana, we identified
      at
      least three apparent fault blocks to test, all three of which we expect to
      encounter a Miocene objective structurally high to two wells that have combined
      to produce over 50 Bcfe to date. In November 2006, we commenced drilling of
      the
      Williams Land Company #1 on the first of the three prospective fault blocks.
      In
      December 2006, the well was plugged and abandoned after encountering tight
      and
      wet pay. The remaining two apparent fault blocks remain in inventory, one of
      which may be drilled in 2007 depending on the post-drill analysis of the
      Williams Land Company #1 dry hole. In addition, a number of shallow and deeper
      prospects and leads have been identified in the Mystic Bayou
      Project.





In
      2007,
      we plan to spend a total of $19.4 million to drill two development wells, one
      exploration well, to complete wells in progress and for other development
      activities. We also expected to spend $1.7 million in land and
      seismic.





**Anadarko
      Basin Province**





The
      Anadarko Basin is located in the Texas Panhandle and Western Oklahoma. We
      believe this prolific natural gas producing province offers a combination of
      relatively lower risk exploration and development opportunities in shallower
      horizons, as well as higher risk, but higher reserve potential opportunities
      in
      the deeper sections that have been relatively under explored.


22
 *Table
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We
      believe our drilling program in the Anadarko Basin generally provides us with
      longer life reserves and helps to balance our drilling program in our prolific,
      but generally shorter reserve life, Onshore Gulf Coast province.





The
      stratigraphic and structural objectives in the Anadarko Basin can provide
      excellent targets for 3-D seismic imaging. In addition, drilling economics
      in
      the Anadarko Basin are enhanced by the multi-pay nature of many of the
      prospects, with secondary or tertiary targets serving as either incremental
      value or as alternatives if the primary target zone is not productive. Our
      recent activity has been focused primarily in the Hunton trend, Springer Channel
      and Springer Bar trends and the Granite Wash trend.





During
      2006, we drilled ten development and three exploration wells. Of the $51.7
      million that we spent on this province in 2006, approximately 69% was allocated
      to the Hunton trend, 18% was allocated to the Granite Wash trend, 5% was
      allocated to the Springer trends and 8% to other Anadarko Basin projects. Of
      our
      capital spent in the Hunton in 2006, $13.7 million was spent in 2006 to acquire
      177 square miles of high resolution 3-D seismic data and land over a portion
      of
      Wheeler County, Texas, which includes our Mills Ranch Field as well as ten
      Hunton exploration prospects.





During
      2007, we expect to spend $14.0 million to drill four exploration wells, complete
      wells that were in progress and on other activities. We also expect to spend
      $4.4 million on net land and seismic.





***Hunton
      Trend***





In
      January 2006, we commenced operations on a re-entry and sidetrack of the
      previously drilled Mills Ranch 99 #1S. The Mills Ranch 99 #1S2 reentered and
      sidetracked out of the Mills Ranch 99 #1S borehole at a depth of approximately
      17,000 feet. We subsequently directionally drilled to a depth of approximately
      21,000 feet to test the Hunton in what we determined to be in an adjacent fault
      block and encountered 125 feet of apparent pay. The well came on-line at
      approximately 6.0 MMcfe per day and in January 2007 was producing at a rate
      of
      approximately 1.8 MMcfe per day.





In
      March
      2006, we commenced the drilling of the Mills Ranch #1-96, a development well
      on
      the westernmost end of the Mills Ranch field. The well was drilled to a depth
      of
      approximately 25,000 feet and offsets our Mills Ranch #1-97 well, which since
      December 2000 has produced approximately 6 Bcfe and is expected to ultimately
      produce approximately 15 Bcfe. Completion of the well was delayed due to
      operational complexities, primarily related to a mixed stream of water and
      gas
      from two different producing zones. The water bearing zone was isolated and
      production was tested from the Viola, the deepest producing interval in the
      well, which came on line at 8.3 MMcfe per day and then decreased to 3.0 MMcfe
      per day. We
      are
      preparing to perforate and stimulate the upper Chimney Hill, Haragan and
      Henryhouse Hunton intervals, which appear to be comparable pay intervals to
      the
      Mills Ranch #1-97 well discussed above.After production is
      established in the Hunton pay intervals, we expect to commingle these intervals
      with the Viola producing interval. We operate the Mills Ranch #1-96 with an
      appropriate 68% working interest.





In
      June
      2006, a tubing leak developed in our Mills Ranch 98-2 well. In July 2006, we
      commenced operations to pull the tubing and remediate the well, but had
      difficulties in fishing the tubing out of the well. Subsequent to fishing the
      tubing, we discovered the casing was parted. After further remediation was
      unsuccessful, it was determined that the best course of action was to sidetrack
      the well at a later date.  As a result, a kick-off plug was set. Prior
      to developing the tubing leak, the well was producing approximately 3.3 MMcfe
      per day.




***Granite
      Wash Trend***





In
      February 2006, we commenced the Hobart 59-2, which upon completion came on-line
      at approximately 3.4 MMcfe per day. Although no additional wells in our 4,000
      acre contiguous held by production acreage block were drilled in 2006 or are
      scheduled for 2007, with strong commodity prices, we could accelerate our
      Granite Wash drilling program in 2007. Assuming 40 acre spacing, approximately
      82 additional locations could be drilled to fully develop our
      acreage.





**Rocky
      Mountains Province**





***Powder
      River Basin***





In
      February 2006, we signed a letter of intent to acquire a 50% working interest
      in
      an unconventional shale play in the Powder River Basin of Wyoming. Vertical
      wells in the area, which date as far back as 1951, targeted shales approximately
      175 feet thick at a depth of about 7,500 feet. Approximately 18 of these wells
      were completed in the targeted shale and produced between 8 to 189 barrels
      of
      oil per day. Given the historical results, we believe the application of
      horizontal drilling technology and / or advanced fracture stimulation could
      significantly increase the productivity of the shale zone. To earn a 50% working
      interest in approximately 54,000 net acres that our joint venture partners
      had
      accumulated in the play, we carried the drilling and completion costs of the
      first two wells for our partners and also paid the first $1 million of
      incremental land acquisition costs. The vast majority of our obligations to
      carry our partners for drilling, completion and land acquisition costs were
      fulfilled in 2006. As of December 31, 2006, we hold a total of over
      approximately 120,000 gross and 60,000 net acres in the play, located primarily
      in Niobrara County, Wyoming.


23
 *Table
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Our
      first
      well in the play, the Krejci Federal 29#3H, was spud at the end of July 2006.
      We
      are currently conducting varied and extensive production tests to evaluate
      the
      effectiveness of different completion methodologies. Initially, we tested only
      the last 219 feet of the approximate 1,600 foot lateral, which was not cased.
      Subsequent to fracture stimulation and hook up to a rod pump, the Krejci was
      producing between 120 and 160 barrels of oil per day from the outer 219 feet
      of
      the lateral. In late December, we began operations to test the innermost 1,381
      foot cased portion of the well. We perforated and fractured stimulated three
      different intervals in this portion of the well bore and the well produce
      significant volumes of load water and between 50 and 90 barrels of oil per
      day.  We drilled out the temporary plug to commingle production and
      installed a submersible pump.  Pump problems, however, have prevented us
      from obtaining a stabilized rate.  We expect to reinstall a submersible
      pump or install a more conventional rod pump.





We
      are
      currently in the process of completing our second well in the area, the Mills
      Trust #1-12. The well was drilled to a vertical depth of approximately 7,600
      feet and then a 1,300 foot lateral was drilled. Casing was set on the first
      885
      feet of the lateral. The outermost 415 feet of the lateral was left uncased.
      We
      fracture stimulated the outer 415 feet of the lateral and installed pumping
      equipment. After
      stimulation, the well produced approximately 120 barrels of load water and
      47
      barrels of oil, with 400 to 500 barrels of load water remaining to be recovered.
      Subsequent to testing the open hole section, Brigham will production test the
      remaining 885 feet of the lateral which is currently behind production casing.Subsequent to completion testing in this part of the well bore, we will
      test the innermost 885 feet of the well bore.





In
      2006,
      we spent $9.5 million in the Powder River Basin to complete the two
      aforementioned horizontal wells, to drill two other unsuccessful shallow
      vertical exploration wells targeting other primary objectives and to acquire
      land and seismic data. Beginning in March, we currently plan on committing
      a rig
      full time to the development of our Mowry acreage. In 2007, we anticipate
      spending approximately $14.5 million to drill eight wells, to acquire additional
      acreage and conduct additional seismic delineation testing.





***Williston
      Basin***





On
      November 1, 2005, we spent approximately $4.6 million to acquire a 100% working
      interest in approximately 46,000 net acres in McKenzie and Williams Counties
      in
      North Dakota. Since then, we have acquired significant additional acreage,
      and
      as of December 31, 2006 we had approximately 120,000 gross and net acres under
      lease. Of this acreage, approximately 55,000 net acres are in North Dakota,
      with
      approximately 65,000 net acres in Roosevelt and Sheridan Counties, Montana.





The
      Bakken is an unconventional oil play at a depth of approximately 10,500 feet.
      Within a 324 square mile area of Richland County, Montana, approximately 227
      Bakken wells have generated average initial production rates of approximately
      345 barrels of oil per day, average cumulative production to date of
      approximately 112,000 barrels of oil per well, and estimated ultimate recoveries
      of approximately 376,000 barrels of oil per well based on data compiled from
      external sources.





Our
      current drilling activities are approximately 25 miles east of the ongoing
      Bakken activity in Richland County, Montana. Our original three well program
      consisted of wells approximately 10,600 feet deep with single long laterals
      of
      approximately 8,000 feet. In 2006, we spent $22.7 million on drilling, land
      and
      seismic. Approximately $17.5 million was allocated to the drilling of three
      pilot wells in North Dakota.





The
      first
      well, the Field 18-19 1-H, was spud in May 2006 and subsequent to stimulation
      and installation of a rod pump, came on-line at approximately 200 barrels of
      oil
      per day. By December 2006, the well appeared to have stabilized at between
      60
      and 70 barrels of oil per day. Our second well, the Mracheck 15-22 1-H, was
      hooked up to a rod pump prior to stimulation and recently was producing
      approximately 30 barrels of oil per day. A fracture stimulation of the well
      is
      planned for this spring. The third well, the Erickson 8-17 1-H, was fracture
      stimulated and initially produced at approximately 200 barrels of oil per day,
      but quickly declined to a rate of approximately 45 barrels of oil per day.
      Frac
      sand was apparently inhibiting production. In January 2007 we commenced
      operations to clean out the lateral and hook the well up to a rod pump for
      further production testing. After cleaning out the lateral, the well produced
      up
      to 227 barrels of oil per day and then declined to 82 barrels per
      day.





In
      2007,
      we anticipate spending approximately $2.6 million to complete wells in progress
      and acquire land and seismic. We are currently evaluating the feasibility of
      drilling a tri-lateral well on our North Dakota acreage, but will monitor
      activity by other operators in the areas either currently drilling or planning
      to drill tri-laterals. Depending on the drilling success that other operators
      have in the vicinity of our North Dakota acreage, we may commence a tri-lateral,
      dual lateral or single lateral well during the second half of 2007. In addition,
      we may form an area of mutual interest around a portion of our substantial
      Montana acreage position and bring in a joint venture participant to potentially
      recoup a portion of our costs, fund a seismic shoot, and fund a portion of
      our
      drilling and completion costs, in order to accelerate activity over some of
      our
      acreage.


24
 *Table
          of Contents*


**West
      Texas and Other Province**





The
      Permian Basin of West Texas and Eastern New Mexico is a predominantly oil
      producing province with generally longer life reserves than that of our onshore
      Gulf Coast. Our drilling activity in our West Texas province has been focused
      primarily in various carbonate reservoirs, including the Canyon Reef and
      Fusselman formations of the Horseshoe Atoll trend, the Canyon Reef of the
      Eastern Shelf, the Wolfcamp and Devonian section of New Mexico, and the
      Mississippian Reef of the Hardeman Basin, at depths ranging from 7,000 to 13,000
      feet.





Over
      the
      past three years, approximately 3% of our total capital expenditures for
      drilling, land and seismic have been allocated to our West Texas province where
      we have completed five gross wells (3.8 net) in eight attempts for a completion
      rate of 63%.





During
      2006, we completed two gross wells (0.9 net) in three attempts for a completion
      rate of 67%. All three of these wells were exploration wells, with two of the
      three operated by a private operator. The Pink Floyd and Pink Champagne wells
      in
      the Canyon Reef play came on-line at approximately 100 and 65 Bopd,
      respectively.





For
      2007,
      we currently plan to spend approximately $2.4 million on drilling, land and
      seismic.




**3-D
      Seismic Exploration**





We
      have
      accumulated 3-D seismic data covering approximately 11,337 square miles (7.3
      million acres) in ten states. We typically acquire 3-D seismic data in and
      around existing producing fields where we can benefit from the imaging of
      producing analog wells. These 3-D defined analogs, combined with our experience
      in drilling 731 wells, the majority of which were imaged utilizing our 3-D
      seismic data and interpretation, provide us with a knowledge base to evaluate
      other potential geologic trends, 3-D seismic projects within these trends and
      prospective 3-D delineated drilling locations. Through our experience in the
      early and mid 1990’s, we developed an expertise in the selection of geologic
      trends that we believe are best suited for 3-D seismic exploration. We have
      used
      the experience that we have gained within our core trends to enhance the quality
      of subsequent projects in the same trend and other analogous trends to help
      lower finding and development costs, compress project cycle times and enhance
      our return on capital.





Over
      the
      last 16 years, we have accumulated substantial experience exploring with 3-D
      seismic in a wide range of reservoir types and geologic trapping mechanisms.
      In
      addition, we typically acquire digital databases for integration on our
      computer-aided exploration workstations, including digital land grids, well
      information, log curves, production information, geologic studies, geologic
      top
      databases and existing 2-D seismic data. We use our knowledge base, local
      geological expertise and digital databases integrated with 3-D seismic data
      to
      create maps of producing and potentially productive reservoirs. As such, we
      believe our 3-D generated maps are more accurate than previous reservoir maps
      (which generally are based on subsurface geological information and 2-D seismic
      surveys), enabling us to more precisely evaluate recoverable reserves and the
      economic feasibility of projects and drilling locations.





Historically,
      we have acquired most of our raw 3-D seismic data using seismic acquisition
      vendors on either a proprietary basis or through alliances affording the
      alliance members the exclusive right to interpret and use data for extended
      periods of time. In addition, we have participated in non-proprietary group
      shoots of 3-D seismic data (commonly referred to as “spec data”) when we believe
      the expected full cycle project economics could not justify the acquisition
      of
      proprietary data. Further, we have exchanged certain interests in some of our
      non-core proprietary seismic data to gain access to additional 3-D seismic
      data.
      In most of our proprietary 3-D data acquisitions and alliances, we have selected
      the sites of projects, primarily guided by our knowledge and experience in
      the
      core provinces we explore, established and monitored the seismic parameters
      of
      each project for which seismic data was acquired, and typically selected the
      equipment that was used.





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


25
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          of Contents*


During
      2004, we added approximately 655 square miles of 3-D seismic data to our
      corporate database. Of this total, we acquired approximately 57 square miles
      of
      non-proprietary and 101 square miles of new proprietary 3-D seismic data in
      our
      Alamo project located in the Frio trend of the Upper Texas Gulf Coast. We sold
      a
      working interest in Alamo to an industry participant on a promoted basis and
      retained a 75% working interest in the project. Also included in the 3-D seismic
      data that we added to our corporate database in 2004 were approximately 120
      square miles of new proprietary data we acquired in our General Lee project,
      which is located in the Frio trend of the Upper Texas Gulf Coast. We sold a
      working interest in General Lee to an industry participant on a promoted basis
      and retained a 75% working interest.





During
      2005, we added approximately 247 square miles of 3-D seismic data to our
      corporate database. All 247 square miles of 3-D seismic data acquired were
      non-proprietary to us. Included in the 3-D seismic data that we added to our
      corporate database in 2005 was approximately 80 square miles of data in our
      Mudflats project located in the Frio trend along the Lower Texas Gulf Coast.
      We
      retained a 100% working interest in our Mudflats project.





During
      2006, we added approximately 637 square miles of 3-D seismic data to our
      corporate database. Approximately 225 square miles of 3-D seismic data was
      acquired on a proprietary basis and the remaining 412 square miles was acquired
      on a non-proprietary basis. Included in the 3-D seismic data that we added
      to
      our corporate database in 2006 was approximately 177 square miles of data from
      our proprietary Laker project, which is in the Hunton trend of our Anadarko
      Basin. We retained a 100% working interest in our Laker project.





See
“—
      Onshore Gulf Coast Province,” “— Anadarko Basin Province,” “— Rocky Mountains
      Province,” “— West Texas and Other Province,” and “Item 7. Management’s
      Discussion and Analysis of Financial Condition and Results of Operations —
Capital Commitments — Capital Expenditures” for additional discussion regarding
      our seismic capital expenditures.




**Title
      to Properties**





We
      believe we have satisfactory title, in all material respects, to substantially
      all of our producing properties in accordance with standards generally accepted
      in the oil and natural gas industry. Our properties are subject to royalty
      interests, standard liens incident to operating agreements, liens for current
      taxes and other burdens, which we believe do not materially interfere with
      the
      use of or affect the value of such properties. Substantially all of our proved
      oil and natural gas properties are pledged as collateral under first and second
      liens for borrowings under our senior credit agreement. See “Item 7.
      Management’s Discussion and Analysis of Financial Condition and Results of
      Operations — Liquidity and Capital Resources - Senior Credit Agreement” and
“Item 7. Management’s Discussion and Analysis of Financial Condition and Results
      of Operations — Liquidity and Capital Resources - 9 5/8% Senior Notes due 2014.”





**Oil
      and Natural Gas Reserves**





Our
      estimated total net proved reserves of oil and natural gas as of December 31,
      2006, 2005 and 2004, pre-tax PV10% value, standardized measure and the estimated
      future development cost attributable to these reserves as of those dates were
      as
      follows.




**At
                December 31,****2006**
            
            **2005**
            
            **2004****Estimated
                Net Proved Reserves:**Oil
                (MBbls)
            
            
            4,494
            
            
            3,326
            
            
            3,236Natural
                gas (MMcf)
            
            
            119,486
            
            
            113,264
            
            
            101,875Natural
                gas equivalent (MMcfe)
            
            
            146,452
            
            
            133,223
            
            
            121,290Proved
                developed reserves as a percentage of net proved reserves
            
            
            55
            %
            
            51
            %
            
            50
            %Pre-tax
                PV10% (in millions)(a)
            
            $
            338.5
            
            $
            519.8
            
            $
            294.5Standardized
                measure (in millions)
            
            
            302.7
            
            
            396.3
            
            
            239.7Estimated
                future development cost (in millions)
            
            
            145.9
            
            
            122.4
            
            
            79.9**Base
                price used to calculate reserves**(b)**:**Natural
                gas (per MMbtu)
            
            $
            5.48
            
            $
            9.44
            
            $
            6.19Oil
                (per Bbl)
            
            
            61.06
            
            
            61.04
            
            
            43.46




(a)
            See
                “- Reconciliation of Standardized Measure to Pre-tax PV10%” for a
                definition of pre-tax PV10% and a reconciliation of our standardized
                measure to our pre-tax PV10% value.





(b)
            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 our reserves at these
                dates.


26
 *Table
          of Contents*


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





In
      accordance with applicable requirements of the Securities and Exchange
      Commission (SEC), estimates of our net proved reserves and future net revenues
      are made using sales prices estimated to be in effect as of the date of such
      reserve estimates and are held constant throughout the life of the properties
      (except to the extent a contract specifically provides for escalation).
      Estimated quantities of net proved reserves and future net revenues there from
      are affected by oil and natural gas prices, which have fluctuated widely in
      recent years. There are numerous uncertainties inherent in estimating oil and
      natural gas reserves and their estimated values, including many factors beyond
      our control. The reserve data set forth in the Cawley, Gillespie &
Associates, Inc. report represents only estimates. Reservoir engineering is
      a
      subjective process of estimating underground accumulations of oil and natural
      gas that cannot be measured in an exact manner. The accuracy of any reserve
      estimate is a function of the quality of available data and of engineering
      and
      geologic interpretation and judgment. As a result, estimates of different
      engineers, including those used by us, may vary. In addition, estimates of
      reserves are subject to revision based upon actual production, results of future
      development and exploration activities, prevailing oil and natural gas prices,
      operating costs and other factors. The revisions may be material. Accordingly,
      reserve estimates are often different from the quantities of oil and natural
      gas
      that are ultimately recovered and are highly dependent upon the accuracy of
      the
      assumptions upon which they are based. Our estimated net proved reserves,
      included in our Security and Exchange Commission filings, have not been filed
      with or included in reports to any other federal agency. See “Item 1A. Risk
      Factors — Although our oil and gas reserve data is independently estimated,
      these estimates may still prove to be inaccurate.”





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





**Reconciliation
      of Standardized Measure to Pre-tax PV10%**





Pre-tax
      PV10% is the estimated present value of the future net revenues from our proved
      oil and natural gas reserves before income taxes discounted using a 10% discount
      rate. Pre-tax PV10% is considered a non-GAAP financial measure under SEC
      regulations because it does not include the effects of future income taxes,
      as
      is required in computing the standardized measure of discounted future net
      cash
      flows. We believe that pre-tax PV10% is an important measure that can be used
      to
      evaluate the relative significance of our oil and natural gas properties and
      that pre-tax PV10% is widely used by security analysts and investors when
      evaluating oil and natural gas companies. Because many factors that are unique
      to each individual company impact the amount of future income taxes to be paid,
      the use of a pre-tax measure provides greater comparability of assets when
      evaluating companies. We believe that most other companies in the oil and
      natural gas industry calculate pre-tax PV10% on the same basis. Pre-tax PV10%
      is
      computed on the same basis as the standardized measure of discounted future
      net
      cash flows but without deducting income taxes. The table below provides a
      reconciliation of our standardized measure of discounted future net cash flows
      to our pre-tax PV10% value.




**At
                December 31,****2006**
            
            **2005**
            
            **2004**Standardized
                measure of discounted future net cash flows
            
            $
            302.7
            
            $
            396.3
            
            $
            239.7Add
                present value of future income tax discounted at 10%
            
            
            34.6
            
            
            123.5
            
            
            54.8FAS
              143 assumption differences
            
            
            1.2
            
            
            —
            
            
            —Pre-tax
                PV10%
            
            $
            338.5
            
            $
            519.8
            
            $
            294.5




27
 *Table
          of Contents*


**Drilling
      Activities**




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




**Year
                Ended December 31,****2006
                (a)**
            
            **2005
                (b)**
            
            **2004
                (c)****Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net****Exploratory
                wells:**Natural
                gas
            
            
            4
            
            
            1.4
            
            
            8
            
            
            4.5
            
            
            10
            
            
            5.4Oil
            
            
            6
            
            
            4.6
            
            
            0
            
            
            0.0
            
            
            1
            
            
            0.9Non-productive
            
            
            10
            
            
            5.2
            
            
            4
            
            
            3.5
            
            
            7
            
            
            5.2Total
            
            
            20
            
            
            11.2
            
            
            12
            
            
            8.0
            
            
            18
            
            
            11.5**Development
                wells:**Natural
                gas
            
            
            13
            
            
            9.7
            
            
            19
            
            
            10.4
            
            
            35
            
            
            13.9Oil
            
            
            1
            
            
            0.0
            
            
            2
            
            
            1.1
            
            
            2
            
            
            0.3Non-productive
            
            
            3
            
            
            1.4
            
            
            3
            
            
            2.2
            
            
            5
            
            
            1.5Total
            
            
            17
            
            
            11.1
            
            
            24
            
            
            13.7
            
            
            42
            
            
            15.7





__________





(a)
            Excludes
                three (1.9 net) exploratory and two (0.8 net) development wells that
                are
                completing and one (0.4 net) development was that was
                drilling.





(b)
            Includes
                two (1.0 net) development wells that commenced drilling in 2005 and
                was
                completed productive in 2006.





(c)
            Includes
                one (1.0 net) exploratory well that commenced drilling in 2004 and
                were
                completed productive in 2005.





We
      do not
      own drilling rigs and all of our drilling activities have been conducted by
      independent contractors or by industry participant operators under standard
      drilling contracts.




**Productive
      Wells and Acreage**





***Productive
      Wells*** ****





The
      following table sets forth our ownership interest at December 31, 2006 in
      productive oil and natural gas wells in the areas indicated. Wells are
      classified as oil or natural gas according to their predominant production
      stream. Gross wells are the total number of producing wells in which we have
      an
      interest, and net wells are determined by multiplying gross wells by our average
      working interest.




**Natural
                Gas**
            
            **Oil**
            
            **Total****Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Onshore
                Gulf Coast
            
            
            67
            
            
            35.2
            
            
            21
            
            
            5.1
            
            
            88
            
            
            40.3Anadarko
                Basin
            
            
            126
            
            
            40.2
            
            
            16
            
            
            4.1
            
            
            142
            
            
            44.3Rocky
                Mountains
            
            
            0
            
            
            0
            
            
            6
            
            
            4.1
            
            
            6
            
            
            4.1West
                Texas and Other
            
            
            14
            
            
            1.9
            
            
            68
            
            
            23.4
            
            
            82
            
            
            25.3Total
            
            
            207
            
            
            77.3
            
            
            111
            
            
            36.7
            
            
            318
            
            
            114.0





Productive
      wells consist of producing wells and wells capable of production, including
      wells waiting on pipeline connection. Wells that are completed in more than
      one
      producing horizon are counted as one well. Of the gross wells reported above,
      two had multiple completions.





***Acreage***





Undeveloped
      acreage includes leased acres on which wells have not been drilled or completed
      to a point that would permit the production of commercial quantities of oil
      and
      natural gas, regardless of whether or not such acreage contains proved reserves.
      The following table sets forth the approximate developed and undeveloped acreage
      that we held a leasehold interest in at December 31, 2006.


28
 *Table
          of Contents*





**Developed(a)**
            
            **Undeveloped(a)**
            
            **Total****Gross**
            
            **Net**
            
            **Gross**
            
            **Net**
            
            **Gross**
            
            **Net**Onshore
                Gulf Coast
            
            
            18,668
            
            
            8,925
            
            
            38,265
            
            
            26,368
            
            
            56,933
            
            
            35,293Anadarko
                Basin
            
            
            63,955
            
            
            29,973
            
            
            21,341
            
            
            17,582
            
            
            85,296
            
            
            47,555Rocky
                Mountains
            
            
            7,630
            
            
            7,630
            
            
            106,252
            
            
            103,047
            
            
            113,882
            
            
            110,677West
                Texas & Other
            
            
            18,596
            
            
            6,278
            
            
            10,951
            
            
            8,476
            
            
            29,547
            
            
            14,754Total
            
            
            108,849
            
            
            52,806
            
            
            176,809
            
            
            155,473
            
            
            285,658
            
            
            208,279





(a)
            Does
                not include acreage for which assignments have not been
                received.





In
      addition, as of December 31, 2006, we had 2,442 gross and 1,824 net mineral
      acres.





All
      of
      our leases for undeveloped acreage summarized in the preceding table will expire
      at the end of their respective primary terms unless we renew the existing
      leases, we establish production from the acreage, or some other “savings clause”
is exercised. The following table sets forth the minimum remaining lease terms
      for our gross and net undeveloped acreage.




**Acres
                Expiring****Twelve
                Months Ending:**
            
            **Gross**
            
            **Net**December
                31, 2007
            
            
            22,233
            
            
            16,331December
                31, 2008
            
            
            42,107
            
            
            35,877December
                31, 2009
            
            
            35,375
            
            
            29,106December
                31, 2010
            
            
            8,679
            
            
            7,277December
                31, 2011
            
            
            61,203
            
            
            59,743Thereafter
            
            
            7,212
            
            
            7,139Total
            
            
            176,809
            
            
            155,473





In
      addition, as of December 31, 2006, we had lease options and rights of first
      refusal to acquire additional acres. The following table sets forth the
      expiration year of our options and right of first refusal agreements and our
      gross and net acres associated with those options and agreements.





**Acres
                Expiring****Twelve
                Months Ending:**
            
            **Gross**
            
            **Net**December
                31, 2007
            
            
            11,624
            
            
            10,724





**Volumes,
      Prices and Production Costs**





The following
        table sets forth our production volumes, the average prices we received before
        hedging, the average prices we received including hedging settlement gains
        (losses), the average price we received including hedging settlement and
        unrealized gains (losses) and average production costs associated with our
        sale
        of oil and natural gas for the periods indicated. On October 1, 2006, we
        de-designated all derivatives that were previously classified as cash flow
        hedges and as a result, we will mark-to-market these derivatives in future
        periods. In addition, all future derivatives will be undesignated and therefore
        subject to mark-to-market accounting. The mark-to-market accounting requires
        that we record both derivative settlement and unrealized gains (losses) to
        the
        consolidated statement of operations within a single income statement line
        item.
        We have elected to include both derivative settlements and unrealized gains
        (losses) within revenue. As such, unrealized gains (losses) on derivatives
        will
        no longer be included within either other comprehensive income or other income
        (expense) and will therefore be reflected in revenue. Prior periods for
        which unrealized gains (losses) have been included in other comprehensive
        income
        or other income (expense) are indicated with “NA” in the table on the next page.


29
 *Table
          of Contents*




**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004****Production:**Oil
                (MBbls)
            
            
            442
            
            
            450
            
            
            573Natural
                gas (MMcf)
            
            
            10,603
            
            
            9,213
            
            
            8,830Natural
                gas equivalent (MMcfe)
            
            
            13,254
            
            
            11,913
            
            
            12,265**Average
                oil prices:**Oil
                price (per Bbl)
            
            $
            64.04
            
            $
            54.73
            
            $
            40.13Oil
                price including derivative settlement gains (losses) (per
                Bbl)
            
            $
            64.39
            
            $
            51.95
            
            $
            35.17Oil
                price including derivative settlements and unrealized gains
                (losses)
              (per
                Bbl)
            
            $
            64.79
            
            
            NA
            
            
            NA**Average
                natural gas prices:**Natural
                gas price (per Mcf)
            
            $
            6.74
            
            $
            8.29
            
            $
            6.05Natural
                gas price including derivative settlement gains (losses) (per
                Mcf)
            
            $
            7.09
            
            $
            7.97
            
            $
            5.84Natural
                gas price including derivative settlements and unrealized gains (losses)
                (per Mcf)
            
            $
            7.31
            
            
            NA
            
            
            NA**Average
                equivalent prices:**Natural
                gas equivalent price (per Mcfe)
            
            $
            7.53
            
            $
            8.48
            
            $
            6.23Natural
                gas equivalent price including derivative settlement gains (losses)
                (per
                Mcfe)
            
            $
            7.82
            
            $
            8.13
            
            $
            5.85Natural
                gas equivalent price including derivative settlements and unrealized
                gains
                (losses) (per Mcfe)
            
            $
            8.01
            
            
            NA
            
            
            NA**Average
                production costs**(per
                Mcfe)**:**Lease
                operating expenses (includes costs for operating and maintenance
                and
                expensed workovers)
            
            $
            0.69
            
            $
            0.51
            
            $
            0.43Ad
                valorem taxes
            
            $
            0.12
            
            $
            0.09
            
            $
            0.07Production
                taxes
            
            $
            0.30
            
            $
            0.28
            
            $
            0.25








**Item
      3.** ***Legal Proceedings***





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





As
      of
      December 31, 2006, there are no known environmental or other regulatory matters
      related to our operations that are reasonably expected to result in a material
      liability to us. Compliance with environmental laws and regulations has not
      had,
      and is not expected to have, a material adverse effect on our capital
      expenditures.





**Item
      4.** ***Submission of Matters to a Vote of Security
      Holders***





No
      matter
      was submitted to a vote of our security holders during the fourth quarter of
      2006.





**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 are our executive officers as of March 5,
      2007.








**Name**
            
            **Age**
            
            **Position**Ben
                M. Brigham
            
            47
            
            Chief
                Executive Officer, President and ChairmanEugene
                B. Shepherd, Jr.
            
            48
            
            Executive
                Vice President and Chief Financial OfficerDavid
                T. Brigham
            
            46
            
            Executive
                Vice President — Land and Administration and DirectorA.
                Lance Langford
            
            44
            
            Executive
                Vice President — OperationsJeffery
                E. Larson
            
            48
            
            Executive
                Vice President — Exploration





30
 *Table
            of Contents*




*Ben
      M. “Bud” Brigham* has
      served as our Chief Executive Officer, President and Chairman of the Board
      since
      we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration
      geophysicist with Rosewood Resources, an independent oil and gas exploration
      and
      production company. Mr. Brigham began his career in Houston as a seismic data
      processing geophysicist for Western Geophysical, Inc. a provider of 3-D seismic
      services, after earning his B.S. in Geophysics from the University of Texas
      at
      Austin. Mr. Brigham is the brother of David T. Brigham, Executive Vice President
      — Land and Administration.





*Eugene
      B. Shepherd, Jr.* has
      served as Executive Vice President and Chief Financial Officer since October
      2003, and previously served as Chief Financial Officer from June 2002 to October
      2003. Mr. Shepherd has approximately 24 years of financial and operational
      experience in the energy industry. Prior to joining us, Mr. Shepherd served
      as
      Integrated Energy Managing Director for the investment banking division of
      ABN
      AMRO Bank, where he executed merger and acquisition advisory, capital markets
      and syndicated loan transactions for energy companies. Prior to joining ABN
      AMRO, Mr. Shepherd spent fourteen years as an investment banker for Prudential
      Securities Incorporated, Stephens Inc. and Merrill Lynch Capital Markets. Mr.
      Shepherd worked as a petroleum engineer for over four years for both Amoco
      Production Company and the Railroad Commission of Texas. He holds a B.S. in
      Petroleum Engineering and an MBA, both from the University of Texas at
      Austin.





*David
      T. Brigham* joined
      us
      in 1992 and has served as a Director since May 2003 and as Executive Vice
      President — Land and Administration since June 2002. Mr. Brigham served as
      Senior Vice President — Land and Administration from March 2001 to June 2002,
      Vice President — Land and Administration from February 1998 to March 2001, as
      Vice President — Land and Legal from 1994 until February 1998 and as Corporate
      Secretary from February 1998 to September 2002. From 1987 to 1992, Mr. Brigham
      worked as an attorney in the energy section with Worsham, Forsythe, Sampels
      & Wooldridge. For a brief period of time 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
      us
      in 1995 as Manager of Operations and served as Vice President — Operations from
      January 1997 to March 2001, served as Senior Vice President — Operations from
      March 2001 to September 2003 and has served as Executive Vice President —
Operations since September 2003. From 1987 to 1995, Mr. Langford served in
      various engineering capacities with Meridian Oil Inc., handling a variety of
      reservoir, production and drilling responsibilities. Mr. Langford holds a B.S.
      in Petroleum Engineering from Texas Tech University.





*Jeffery
      E. Larson* joined
      us
      in 1997 and was Vice President — Exploration from August 1999 to March 2001,
      Senior Vice President — Exploration from March 2001 to September 2003 and has
      served as Executive Vice President — Exploration since September 2003. Prior to
      joining us, Mr. Larson was an explorationist in the Offshore Department of
      Burlington Resources, a large independent exploration company, where he was
      responsible for generating exploration and development drilling opportunities.
      Mr. Larson worked at Burlington from 1990 to 1997 in various roles of
      responsibility. Prior to Burlington, Mr. Larson spent five years at Exxon as
      a
      Production Geologist and Research Scientist. He holds a B.S. in Earth Science
      from St. Cloud State University in Minnesota and a M.S. in Geology from the
      University of Montana.




31
 *Table
          of Contents*


**PART
      II**





**Item
          5.** ***Market
          for Registrant’s Common Equity, Related Stockholder Matters and
          Issuer Purchases of Equity Securities***





**Price
      Range of Common Stock, Performance Graph, and Dividend
      Policy**





Our
      common stock commenced trading on the NASDAQ Global Market (formerly the NASDAQ
      National Market) on May 8, 1997 under the symbol “BEXP.” The following table
      sets forth the high and low intra-day sales prices per share of our common
      stock
      for the periods indicated on the NASDAQ Global Market for the periods indicated.
      The sales information below reflects inter-dealer prices, without retail
      mark-ups, mark-downs or commissions and may not necessarily represent actual
      transactions.




**High**
            
            **Low****2005:**First
                Quarter
            
            $
            9.83
            
            $
            7.60Second
                Quarter
            
            
            9.65
            
            
            7.10Third
                Quarter
            
            
            13.42
            
            
            7.80Fourth
                Quarter
            
            
            14.68
            
            
            11.35**2006:**First
                Quarter
            
            $
            13.14
            
            $
            7.85Second
                Quarter
            
            
            10.00
            
            
            6.69Third
                Quarter
            
            
            8.10
            
            
            5.72Fourth
                Quarter
            
            
            8.80
            
            
            6.07








The
      closing market price of our common stock on March 5, 2007 was $5.30 per share.
      As of March 5, 2007, there were an estimated 181 record owners of our common
      stock.













No
      dividends have been declared or paid on our common stock to date. We intend
      to
      retain all future earnings for the development of our business. Our senior
      credit agreement, Senior Notes, and Series A preferred stock restrict our
      ability to pay dividends on our common stock.





We
      are
      obligated to pay dividends on our Series A preferred stock. At our option,
      these
      dividends were paid in kind through the issuance of additional shares of
      preferred stock in lieu of cash at a rate of 8% per annum through September
      2005. Since October 2005, all dividends related to our series A preferred stock
      have been and are required to be paid in cash at a rate of 6% per annum. See
      “Item 7. Management’s Discussion and Analysis of Financial Condition and Results
      of Operations — Liquidity and Capital Resources — Mandatorily Redeemable
      Preferred Stock.”




32
 *Table
          of Contents*


**Securities
      Authorized for Issuance under Equity Compensation Plans**





The
      following table includes information regarding our equity compensation plans
      as
      of the year ended December 31, 2006.








**Plan
                Category**
            
            **Number
                of Securities to be Issued upon Exercise of****Outstanding
                Options**
            
            **Weighted-Average
                Price of****Outstanding
                Options**
            
            **Number
                of Securities Remaining Available for Future Issuance Under Equity****Compensation
                Plans**Equity
                compensation plans approved by security holders(a)
            
            
            3,243,566
            
            $
            7.08
            
            
            940,420Equity
                compensation plans not approved by security holders
            
            
            —
            
            
            —
            
            
            —Total
            
            
            3,243,566
            
            $
            7.08
            
            
            940,420





____________





(a)
            Does
                not include 391,367 shares of restricted stock issued and outstanding
                at
                December 31, 2006.








**Issuer
      Purchases of Equity Securities**





In
      2006,
      we elected to allow employees to deliver shares of vested restricted stock
      with
      a fair market value equal to their federal, state and local tax withholding
      amounts on the date of issue in lieu of cash payment.




**Period**
            
            **Total
                Number of****Shares
                Purchased**
            
            **Average
                Price****Paid
                per Share**October
                2006
            
            
            2,720
            
            $
            6.970January
                2006
            
            
            17,968
            
            $
            11.740




33
 *Table
          of Contents*


**Item
      6.** ***Selected
      Consolidated Financial Data***





This
      section presents our selected consolidated financial data and should be read in
      conjunction with “Item 7. Management’s Discussion and Analysis of Financial
      Condition and Results of Operations” and our consolidated financial statements
      and related notes included in “Item 8. Financial Statements and Supplementary
      Data.” The selected consolidated financial data in this section is not intended
      to replace our consolidated financial statements.





We
      derived the statement of operations data and statement of cash flows data for
      the years ended December 31, 2006, 2005 and 2004, and balance sheet data as
      of
      December 31, 2006 and 2005 from the audited consolidated financial statements
      included in this report. We derived the statement of operations data and
      statement of cash flows data for the years ended December 31, 2003 and 2002
      and
      the balance sheet data as of December 31, 2004, 2003 and 2002, from our
      accounting books and records.





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2002****(In
                thousands, except per share information)****Statement
                of Operations Data:**Revenues:Oil
                and natural gas sales
            
            $
            102,835
            
            $
            96,820
            
            $
            71,713
            
            $
            51,545
            
            $
            35,100Gain
                (loss) on derivatives, net
            
            
            3,335
            
            
            —
            
            
            —
            
            
            —
            
            
            —Other
                revenue
            
            
            127
            
            
            220
            
            
            515
            
            
            132
            
            
            76Total
                revenues
            
            
            106,297
            
            
            97,040
            
            
            72,228
            
            
            51,677
            
            
            35,176Costs
                and expenses:Lease
                operating
            
            
            10,701
            
            
            7,161
            
            
            6,173
            
            
            5,200
            
            
            3,759Production
                taxes
            
            
            4,021
            
            
            3,353
            
            
            3,107
            
            
            2,477
            
            
            1,977General
                and administrative
            
            
            7,887
            
            
            5,533
            
            
            5,392
            
            
            4,500
            
            
            4,971Depletion
                of oil and natural gas properties
            
            
            46,386
            
            
            33,268
            
            
            23,844
            
            
            16,819
            
            
            14,694Depreciation
                and amortization
            
            
            537
            
            
            762
            
            
            722
            
            
            629
            
            
            440Accretion
                of discount on asset retirement obligations
            
            
            317
            
            
            180
            
            
            159
            
            
            142
            
            
            —Total
                costs and expenses
            
            
            69,849
            
            
            50,257
            
            
            39,397
            
            
            29,767
            
            
            25,841Operating
                income
            
            
            36,448
            
            
            46,783
            
            
            32,831
            
            
            21,910
            
            
            9,335Other
                income (expense):Interest
                income
            
            
            1,207
            
            
            245
            
            
            84
            
            
            45
            
            
            119Interest
                expense, net
            
            
            (9,688
            )
            
            (3,980
            )
            
            (3,144
            )
            
            (4,815
            )
            
            (6,238
            )Gain
                loss on derivatives, net
            
            
            3,213
            
            
            (814
            )
            
            625
            
            
            68
            
            
            (14
            )Other
                income (expense)
            
            
            1,352
            
            
            238
            
            
            117
            
            
            (669
            )
            
            (296
            )Debt
                conversion expense
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (630
            )Total
                other income (expense)
            
            
            (3,916
            )
            
            (4,311
            )
            
            (2,318
            )
            
            (5,371
            )
            
            (7,059
            )Income
                before income taxes and cumulative effect of change in accounting
                principle
            
            $
            32,532
            
            $
            42,472
            
            $
            30,513
            
            $
            16,539
            
            $
            2,276Income
                tax benefit (expense):Current
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Deferred
            
            
            (12,744
            )
            
            (15,037
            )
            
            (10,863
            )
            
            1,223
            
            
            —(12,744
            )
            
            (15,037
            )
            
            (10,863
            )
            
            1,223
            
            
            —Income
                before cumulative effect of change in accounting principle
            
            
            19,788
            
            
            27,435
            
            
            19,650
            
            
            17,762
            
            
            2,276Cumulative
                effect of change in accounting principle
            
            
            —
            
            
            —
            
            
            —
            
            
            268
            
            
            —Net
                income
            
            
            19,788
            
            
            27,435
            
            
            19,650
            
            
            18,030
            
            
            2,276Preferred
                dividend and accretion
            
            
            —
            
            
            —
            
            
            —
            
            
            3,448
            
            
            2,952Net
                income (loss) available tocommon stockholders
            
            $
            19,788
            
            $
            27,435
            
            $
            19,650
            
            $
            14,582
            
            $
            (676
            )Net
                Income (loss) per share before cumulative effect of change in accounting
                principle:Basic
            
            $
            0.44
            
            $
            0.65
            
            $
            0.49
            
            $
            0.62
            
            $
            (0.04
            )Diluted
            
            
            0.43
            
            
            0.63
            
            
            0.47
            
            
            0.51
            
            
            (0.04
            )Net
                income (loss) per share available to common shareholders:Basic
            
            $
            0.44
            
            $
            0.65
            
            $
            0.49
            
            $
            0.63
            
            $
            (0.04
            )Diluted
            
            
            0.43
            
            
            0.63
            
            
            0.47
            
            
            0.52
            
            
            (0.04
            )Weighted
                average shares outstanding:Basic
            
            
            45,017
            
            
            42,481
            
            
            40,445
            
            
            23,363
            
            
            16,138Diluted
            
            
            45,597
            
            
            43,728
            
            
            41,616
            
            
            34,354
            
            
            16,138




34
 *Table
          of Contents*





**At
                December 31,****2006**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2002****(In
                thousands)****Statement
                of Cash Flows Data:**Net
                cash provided (used) by:Operating
                activities
            
            $
            88,687
            
            $
            64,379
            
            $
            56,381
            
            $
            41,691
            
            $
            28,973Investing
                activities
            
            
            (171,747
            )
            
            (113,220
            )
            
            (84,645
            )
            
            (46,089
            )
            
            (27,206
            )Financing
                activities
            
            
            83,385
            
            
            50,535
            
            
            24,766
            
            
            (5,141
            )
            
            8,439**Balance
                Sheet Data:**Cash
                and cash equivalents
            
            $
            4,300
            
            $
            3,975
            
            $
            2,281
            
            $
            5,779
            
            $
            15,318Oil
                and natural gas properties, using the full cost method of accounting,
                net
            
            
            485,525
            
            
            347,329
            
            
            261,979
            
            
            198,490
            
            
            166,006Total
                assets
            
            
            522,587
            
            
            380,427
            
            
            286,307
            
            
            224,982
            
            
            203,085Long-term
                debt
            
            
            149,334
            
            
            63,100
            
            
            41,000
            
            
            39,000
            
            
            81,797Series
                A preferred stock, mandatorily redeemable
            
            
            10,101
            
            
            10,101
            
            
            9,520
            
            
            8,794
            
            
            19,540Series
                B preferred stock, mandatorily redeemable
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            4,777Total
                stockholders’ equity
            
            
            266,015
            
            
            241,640
            
            
            183,276
            
            
            139,111
            
            
            62,775




35
 *Table
          of Contents*


**Item
          7.** ***Management’s
          Discussion and Analysis of Financial Condition and Results
          of Operations***





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





**Sources
      of Our Revenues**





We
      derive
      our revenues from the sale of oil and natural gas that is produced from our
      properties. Revenues are a function of the volume produced and the prevailing
      market prices at the time of sale.





To
      achieve more predictable cash flows and to reduce our exposure to downward
      price
      fluctuations, we utilize derivative instruments to hedge future sales prices
      on
      a portion of our oil and natural gas production. Our current strategy is to
      hedge up to 90% of our proved developed producing (PDP) volumes for the upcoming
      12 months and 80% of our PDP for the remaining period. The use of certain types
      of derivative instruments may prevent us from realizing the benefit of upward
      price movements. See “Item 1A. Risk Factors — Our hedging activities may prevent
      us from benefiting from price increases and may expose us to other risks.”





**Components
      of Our Cost Structure**





*Production
      Costs* are
      the
      day-to-day costs we incur to bring hydrocarbons out of the ground and to the
      market combined with the daily costs we incur to maintain our producing
      properties. This includes lease operating expenses and production
      taxes.





—
            Lease
                operating expenses are generally comprised of several components
                including
                the cost of labor and supervision to operate our wells and related
                equipment; repairs and maintenance; related materials, supplies,
                fuel, and
                supplies utilized in operating our wells and related equipment and
                facilities; insurance applicable to our wells and related facilities
                and
                equipment. Lease operating expenses also include the cost for expensed
                workovers. Lease operating expenses are driven in part by the type
                of
                commodity produced, the level of workover activity and the geographical
                location of the properties. Oil is inherently more expensive to produce
                than natural gas.





—
            Lease
                operating expenses also include ad valorem taxes, which are imposed
                by
                local taxing authorities such as school districts, cities, and counties
                or
                boroughs. The amount of tax we pay is based on a percent of value
                of the
                property assessed or determined by the taxing authority on an annual
                basis. When oil and natural gas prices rise, the value of our underlying
                property interests increase, which results in higher ad valorem
                taxes.





—
            In
                the U.S. there are a variety of state and federal taxes levied on
                the
                production of oil and natural gas. These are commonly grouped together
                and
                referred to as production taxes. The majority of our production tax
                expense is based on a percent of gross value realized at the wellhead
                at
                the time the production is sold or removed from the lease. As a result,
                our production tax expense increases when oil and gas prices
                rise.





—
            Historically,
                taxing authorities have occasionally encouraged the oil and natural
                gas
                industry to explore for new oil and natural gas reserves, or to develop
                high cost reserves, through reduced tax rates or tax credits. These
                incentives have been narrow in scope and short-lived. A small number
                of
                our wells have qualified for reduced production taxes because they
                were discoveries based on the use of 3-D seismic or they are high
                cost
                wells.





*Depreciation,
      Depletion and Amortization* is
      the
      systematic expensing of the capital costs incurred to acquire, explore and
      develop oil and natural gas. As a full cost company, we capitalize all direct
      costs associated with our exploration and development efforts, including a
      portion of our interest and certain general and administrative costs, and
      apportion these costs to each unit of production sold through depletion expense.
      Generally, if reserve quantities are revised up or down, our depletion rate
      per
      unit of production will change inversely. When the depreciable base increases
      or
      decreases, the depletion rate will move in the same direction.





*Asset
      Retirement Accretion Expense* is
      the
      systematic, monthly accretion of future abandonment costs of tangible assets
      such as wells, service assets, pipelines, and other facilities.





*General
      and Administrative Expense* is
      our
      overhead, and includes payroll and benefits for our corporate staff, costs
      of
      maintaining our headquarters, managing our production and development operations
      and legal compliance. We capitalize general and administrative costs directly
      related to our exploration and development activities.


36
 *Table
          of Contents*


*Interest.* We rely
      on our Senior Notes, our Series A preferred stock and our senior credit facility
      to fund our short-term liquidity (working capital) and a portion of our
      long-term financing needs. We pay a fixed interest rate on both the Senior
      Notes
      and the preferred stock, but the interest rate that we pay on our senior credit
      facility correlates to both fluctuations in interest rates and to the extent
      that our cash flows from operations do not exceed our spending. We expect to
      continue to incur interest expense as we continue to grow. We capitalize
      interest directly related to our unevaluated properties and certain properties
      under development, which are not being amortized.





*Income
      Taxes.* We are
      generally subject to a 35% federal income tax rate. For income tax purposes,
      we
      are allowed deductions for accelerated depreciation, depletion, intangible
      drilling costs, and state taxes. Through 2006, all of our income taxes were
      deferred.





**Capital
      Commitments**





Our
      primary needs for cash are to fund our capital expenditure program, our working
      capital obligations and for the repayment of contractual obligations. In the
      future, cash will also be required to fund our capital expenditures for the
      exploration and development of properties necessary to offset the inherent
      declines in production and proven reserves that are typical in an extractive
      industry like ours. Future success in growing reserves and production will
      be
      highly dependent on our access to cost effective capital resources and our
      success in economically finding and producing additional oil and natural gas
      reserves. Funding for our exploration and development of oil and natural gas
      activities and the repayment of our contractual obligations may be provided
      by
      any combination of cash flow from operations, cash on our balance sheet, the
      unused committed borrowing capacity under our senior credit agreement,
      reimbursements of prior land and seismic costs by third parties who participate
      in our projects, and the sale of interests in projects and properties or
      alternative financing sources as discussed in “— Contractual Obligations” and “—
Liquidity and Capital Resources.” Cash flows from operations and the unused
      committed borrowing capacity under our senior credit agreement fund our working
      capital obligations. We believe that cash on hand, net cash provided by
      operating activities, and the unused committed borrowing capacity under our
      senior credit agreement will fund our future financial obligations and
      liquidity.





***Capital
      Expenditures***





The
      timing of most of our capital expenditures is discretionary because we have
      no
      material long-term capital expenditure commitments. Consequently, we have a
      significant degree of flexibility to adjust the level of our capital
      expenditures as circumstances warrant. Our capital expenditure program includes
      the following:





•
            cost
                of acquiring and maintaining our lease acreage position and our seismic
                resources;





•
            cost
                of drilling and completing new oil and natural gas wells;





•
            cost
                of installing new production infrastructure;





•
            cost
                of maintaining, repairing and enhancing existing oil and natural
                gas
                wells;





•
            cost
                related to plugging and abandoning unproductive or uneconomic wells;
                and,





•
            indirect
                costs related to our exploration activities, including payroll and
                other
                expenses attributable to our exploration professional
                staff.





Our
      budgeted capital expenditures for 2007 are as follows:





**2007****(In
                millions)**Drilling
            
            $
            91.2Net
                land and seismic
            
            
            11.2Capitalized
                interest and G&A
            
            
            11.5Other
                assets
            
            
            1.0Total
            
            $
            114.9





The
      capital that funds our drilling activities is allocated to individual prospects
      based on the value potential of a prospect, as measured by a risked net present
      value analysis. We start each year with a budget and re-evaluate this budget
      monthly. The primary factors that impact this value creation measure include
      forecasted commodity prices, drilling and completion costs, and a prospect’s
      risked reserve size and risked initial producing rate. Other factors that are
      also monitored throughout the year that influence the amount and timing of
      all
      our planned expenditures include the level of production from our existing
      oil
      and natural gas properties, the availability of drilling and completion
      services, and the success and resulting production of our newly drilled wells.
      The outcome of our monthly analysis results in a reprioritization of our
      exploration and development drilling schedule to ensure that we are optimizing
      our capital expenditure plan.


37
 *Table
          of Contents*


Over
      the
      past three years, we have spent approximately $301.4 million to drill 53
      exploratory wells and 86 developments wells. For 2007, we currently plan to
      spend approximately $91.2 million to drill seven exploratory wells with an
      average working interest of 62% and to drill 15 development wells with an
      average working interest of 65%. We believe that we possess a multi-year
      inventory of exploratory drilling prospects, the majority of which have been
      internally generated by our staff. We expect that we will continue to emphasize
      our prospect generation and drilling strategy as our primary means of creating
      value for our stockholders.





To
      support our prospect generation activities, we allocate a portion of our capital
      expenditures to land and seismic. Over the past three years, we have spent
      $64.3
      million on land and seismic activities. For 2007, we expect to spend
      approximately $11.2 million or 10% of our total planned capital expenditures
      on
      land and seismic activities.





Additionally,
      we currently plan to capitalize approximately $11.5 million of our forecasted
      general and administrative cost and forecasted interest in 2007.





The
      final
      determination with respect to our 2007 budgeted expenditures will depend on
      a
      number of factors, including:





•
            commodity
                prices;





•
            production
                from our existing producing wells;





•
            the
                results of our current exploration and development drilling
                efforts;





•
            economic
                and industry conditions at the time of drilling, including the
                availability of drilling and completion equipment;
                and





•
            the
                availability of more economically attractive prospects.





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





For
      a
      more in depth discussion of our 2006 capital expenditures see “Item 2.
      Properties.”





***Contractual
      Obligations***





The
      following schedule summarizes our known contractual cash obligations at December
      31, 2006 and the effect these obligations are expected to have on our future
      cash flow and liquidity.








**Payments
                Due by Year****Total**
            
            **2007**
            
            **2008**
            
            **2009-****2010**
            
            **2011
                and****Thereafter****(In
                thousands)****Debt:**Senior
                Notes
            
            $
            125,000
            
            $
            —
            
            $
            —
            
            $
            —
            
            $
            125,000Senior
                credit agreement
            
            
            25,900
            
            
            —
            
            
            —
            
            
            25,900
            
            
            —Mandatorily
                redeemable, Series A preferred stock
            
            
            10,101
            
            
            —
            
            
            —
            
            
            10,101
            
            
            —Total
            
            $
            161,001
            
            $
            —
            
            $
            —
            
            $
            36,001
            
            $
            125,000**Other
                commitments:**Interest,
                Senior Notes(a)
            
            $
            89,232
            
            $
            12,031
            
            $
            12,031
            
            $
            24,063
            
            $
            41,107Interest,
                senior credit agreement(b)
            
            
            5,956
            
            
            1,702
            
            
            1,702
            
            
            2,552
            
            
            —Dividend
                Mandatorily redeemable, Series A preferred stock(c)
            
            
            2,322
            
            
            606
            
            
            606
            
            
            1,110
            
            
            —Non-cancelable
                operating leases
            
            
            3,930
            
            
            702
            
            
            687
            
            
            1,425
            
            
            1,116Total
            
            $
            262,441
            
            $
            15,041
            
            $
            15,026
            
            $
            65,151
            
            $
            167,223


____________




38
 *Table
          of Contents*


(a)
            Senior
                Note interest calculated assuming $123.4 million of Senior Notes
                outstanding and an interest rate of 9.625%. The payments are made
                in May
                and November until its maturity in May
                2014.





(b)
            Senior
                credit agreement interest calculated assuming $25.9 million outstanding
                under our senior credit agreement, an interest rate of 6.57% and
                the
                agreement matures in June 2010. This interest rate assumes that we
                utilize
                approximately 24% of the available borrowing base during the period
                and a
                Eurodollar rate of 5.32% plus a margin of 1.25%. The Eurodollar rate
                used
                for the calculation is the one month Eurodollar rate on December
                29, 2006.
                The amount of interest that we pay on amounts borrowed under our
                senior
                credit agreement will fluctuate over time as borrowings increase
                or
                decrease, as the applicable Eurodollar rate increases and decreases
                and as
                the applicable interest rate increases or decreases. See “Item 7A.
                Quantitative and Qualitative Disclosures About Market Risk — Interest Rate
                Risk.”





(c)
            Dividend
                Mandatorily redeemable, Series A preferred stock calculated assuming
                $10.1
                million of Series A preferred stock outstanding, a cash dividend
                of 6% per
                annum and a maturity of October 31,
                2010.





We
      also
      have liabilities of $5.0 million related to asset retirement obligations on
      our
      Consolidated Balance Sheet as of December 31, 2006. Due to the nature of these
      obligations, we cannot determine precisely when payments will be made to settle
      these obligations. See “Item 8. Financial Statements and Supplementary Data —
Note 7.”





**Results
      of Operations**





***Comparison
      of the twelve-month periods ended December 31, 2006, 2005 and
      2004***





***Production
      volumes***





**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004**Oil
                (MBbls)
            
            
            442
            
            
            (2%)
            
            
            450
            
            
            (21%)
            
            
            573Natural
                gas (MMcf)
            
            
            10,603
            
            
            15%
            
            
            9,213
            
            
            4%
            
            
            8,830Total
                (MMcfe)(1)
            
            
            13,254
            
            
            11%
            
            
            11,913
            
            
            (3%)
            
            
            12,265Average
                daily production (MMcfe/d)
            
            
            36.8
            
            
            
            
            
            33.1
            
            
            
            
            
            34.1


__________


(1)
            MMcfe
                is defined one million cubic feet equivalent of natural gas, determined
                using the ratio of six MMcf of natural gas to one MBbl of crude oil,
                condensate or natural gas liquids.





Our
      net
      equivalent production volumes for 2006 increased by 11% to 13.3 Bcfe (36.8
      MMcfe/d) from 11.9 Bcfe (33.1 MMcfe/d) in 2005. Our production volumes for
      2006
      increased because of production from new wells that we drilled and completed
      during the year more than offset the natural decline of production from wells
      that we drilled and completed in prior periods. Natural gas represented 80%
      and
      77% of our total production in 2006 and 2005, respectively.





The
      following is additional information regarding our 2006 production.





•
            Production
                from our Onshore Gulf Coast province for 2006 increased 18% when
                compared
                to 2005. Production from this province represented 61% of our total
                production in 2006 versus 57% in 2005. Approximately 82% of our 2006
                production from this province was natural gas compared to 78% in
                2005.





•
            Production
                from our Anadarko Basin province for 2006 increased 3% when compared
                to
                2005. Production from this province represented 31% of our total
                production in 2006 versus 34% in 2005. Approximately 92% of our 2006
                and
                2005 production from this province was natural
                gas.





•
            Production
                from our Rocky Mountains province for 2006 represented 1% of our
                total
                production in 2006. Approximately 92% of our 2006 production from
                this
                province was oil.





•
            Production
                from our West Texas province for 2006 decreased 10% when compared
                to 2005.
                Production from this province represented 7% of our total production
                in
                2006 versus 9% in 2005. Approximately 83% of our 2006 production
                from this
                province was oil compared to 85% in
                2005.


39
 *Table
          of Contents*


Our
      net
      equivalent production volumes for 2005 were 11.9 Bcfe (33.1 MMcfe/d) compared
      to
      12.3 Bcfe (34.1 MMcfe/d) in 2004. Our production volumes for 2005 declined
      because new production from wells that we drilled and completed during the
      last
      quarter of 2004 and during 2005 did not offset the natural decline of production
      from wells that we drilled and completed in prior periods. However, our
      production volumes for the fourth quarter of 2005 were 40.8 MMcfe per day or
      23%
      higher than our average daily production volumes for 2005. Natural gas
      represented 77% and 72% of our total production in 2005 and 2004,
      respectively.





The
      following is additional information regarding our 2005 production.





•
            Production
                from our Onshore Gulf Coast province for 2005 decreased 10% when
                compared
                to 2004. Production from this province represented 57% of our total
                production in 2005 versus 61% in 2004. Approximately 78% of our 2005
                production from this province was natural gas compared to 74% in
                2004.





•
            Production
                from our Anadarko Basin province for 2005 increased 17% when compared
                to
                2004. Production from this province represented 34% of our total
                production in 2005 versus 29% in 2004. Approximately 92% of our 2005
                production from this province was natural gas compared to 88% in
                2004.





•
            Production
                from our West Texas province for 2005 decreased 18% when compared
                to 2004.
                Production from this province represented 9% of our total production
                in
                2005 versus 10% in 2004. Production from this province is primarily
                oil
                and approximately 85% of our production from this province in 2005
                was oil
                versus 86% in 2004.





***Revenue,
      commodity prices and hedging***





The
      following table shows our revenue from the sale of oil and natural gas for
      2006,
      2005 and 2004. On October 1, 2006, we de-designated all derivatives that were
      previously classified as cash flow hedges and, as a result, we will
      mark-to-market these derivatives in future periods. In addition, all future
      derivatives will be undesignated and therefore subject to mark-to-market
      accounting. Mark-to-Market accounting requires that we record both derivative
      settlements and unrealized gains (losses) to the consolidated statement of
      operations within a single income statement line item. Begining October 1,
      2006,
      we will include both derivative settlements and unrealized gains (losses) within
      revenue. As such, unrealized gains (losses) on derivatives will no longer be
      included within either other comprehensive income or other income (expense)
      and
      will therefore be reflected in the revenue as outlined in the table below.
      Prior
      periods for which unrealized gains (losses) have been included in other
      comprehensive income or other income (expense) are indicated with “NA” in the
      table below.





**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****(In
                thousands, except per unit measurements)****Oil
                revenue:**Oil
                revenue
            
            $
            28,291
            
            
            15%
            
            $
            24,628
            
            
            7%
            
            $
            22,976Oil
                derivative settlement gains (losses)
            
            
            157
            
            
            NM
            
            
            (1,249
            )
            
            (56%)
            
            
            (2,841
            )Oil
                revenue including oil derivative settlements
            
            $
            28,448
            
            
            22%
            
            $
            23,379
            
            
            16%
            
            $
            20,135Oil
                derivative unrealized gains (losses)
            
            
            175
            
            
            NM
            
            
            NA
            
            
            NM
            
            
            NAOil
                revenue including derivative settlements and unrealized gains
                (losses)
            
            
            28,623
            
            
            22%
            
            
            23,379
            
            
            16%
            
            
            20,135**Natural
                gas revenue:**Natural
                gas revenue
            
            $
            71,503
            
            
            (6%)
            
            $
            76,366
            
            
            43%
            
            $
            53,431Natural
                gas derivative settlement gains (losses)
            
            
            3,639
            
            
            NM
            
            
            (2,925
            )
            
            58%
            
            
            (1,853
            )Natural
                gas revenue including derivative settlements
            
            $
            75,142
            
            
            2%
            
            $
            73,441
            
            
            42%
            
            $
            51,578Natural
                gas derivative unrealized gains (losses)
            
            
            2,405
            
            
            NM
            
            
            NA
            
            
            NM
            
            
            NANatural
                gas revenue including derivative settlements and unrealizedgains
                (losses)
            
            
            77,547
            
            
            6%
            
            
            73,441
            
            
            42%
            
            
            51,578**Oil
                and natural gas revenue:**Oil
                and natural gas revenue
            
            $
            99,794
            
            
            (1%)
            
            $
            100,994
            
            
            32%
            
            $
            76,407Oil
                and natural gas derivative settlement gains (losses)
            
            
            3,796
            
            
            NM
            
            
            (4,174
            )
            
            (11%)
            
            
            (4,694
            )Oil
                and natural gas revenue including derivative settlement gains
                (losses)
            
            
            103,590
            
            
            7%
            
            $
            96,820
            
            
            35%
            
            $
            71,713Oil
                and natural gas derivative unrealized gains (losses)
            
            
            2,580
            
            
            NM
            
            
            NA
            
            
            NM
            
            
            NAOil
                and natural gas revenue including derivative settlements and unrealized
                gains (losses)
            
            
            106,170
            
            
            10%
            
            
            96,820
            
            
            35%
            
            
            71,713Other
                revenue
            
            
            127
            
            
            (42%)
            
            
            220
            
            
            (57%)
            
            
            515**Total
                revenue**
            
            **$**
            **106,297**
            
            
            **10%**
            
            **$**
            **97,040**
            
            
            **34%**
            
            **$**
            **72,228****Average
                oil prices:**Oil
                price (per Bbl)
            
            $
            64.04
            
            
            17%
            
            $
            54.73
            
            
            36%
            
            $
            40.13Oil
                price including derivative settlement gains (losses) (per
                Bbl)
            
            $
            64.39
            
            
            24%
            
            $
            51.95
            
            
            48%
            
            $
            35.17Oil
                price including derivative settlements and unrealized gains (losses)(per
                Bbl)
            
            $
            64.79
            
            
            NM
            
            
            NA
            
            
            NM
            
            
            NA**Average
                natural gas prices:**Natural
                gas price (per Mcf)
            
            $
            6.74
            
            
            (19%)
            
            $
            8.29
            
            
            37%
            
            $
            6.05Natural
                gas price including derivative settlement gains (losses) (per
                Mcf)
            
            $
            7.09
            
            
            (11%)
            
            $
            7.97
            
            
            36%
            
            $
            5.84Natural
                gas price including derivative settlements and unrealized gains (losses)
                (per Mcf)
            
            $
            7.31
            
            
            NM
            
            
            NA
            
            
            NM
            
            
            NA**Average
                equivalent prices:**Natural
                gas equivalent price (per Mcfe)
            
            $
            7.53
            
            
            (11%)
            
            $
            8.48
            
            
            36%
            
            $
            6.23Natural
                gas equivalent price including derivative settlement gains (losses)
                (per
                Mcfe)
            
            $
            7.82
            
            
            (4%)
            
            $
            8.13
            
            
            39%
            
            $
            5.85Natural
                gas equivalent price including derivative settlements and unrealized
                gains
                (losses) (per Mcfe)
            
            $
            8.01
            
            
            NM
            
            
            NA
            
            
            NM
            
            
            NA




40
 *Table
          of Contents*





**2005****to
                2006**
            
            **2004****to
                2005****Change
                in revenue from the sale of oil**Price
                variance impact
            
            $
            4,112
            
            $
            6,570Volume
                variance impact
            
            
            (449
            )
            
            (4,918
            )Cash
                settlement of derivative hedging contracts
            
            
            1,406
            
            
            1,592Unrealized
                gains (losses) due to derivative hedging contracts
            
            
            175
            
            
            NATotal
                change
            
            $
            5,244
            
            $
            3,244**Change
                in revenue from the sale of natural gas**Price
                variance impact
            
            $
            (16,400
            )
            $
            20,627Volume
                variance impact
            
            
            11,537
            
            
            2,308Cash
                settlement of derivative hedging contracts
            
            
            6,564
            
            
            (1,072
            )Unrealized
                gains (losses) due to derivative hedging contracts
            
            
            2,405
            
            
            NATotal
                change
            
            $
            4,106
            
            $
            21,863**Change
                in revenue from the sale of oil and natural gas**Price
                variance impact
            
            $
            (12,288
            )
            $
            27,197Volume
                variance impact
            
            
            11,088
            
            
            (2,610
            )Cash
                settlement of derivative hedging contracts
            
            
            7,970
            
            
            520Unrealized
                gains (losses) due to derivative hedging contracts
            
            
            2,580
            
            
            NATotal
                change
            
            $
            9,350
            
            $
            25,107








Our
      2006
      oil and natural gas revenue including derivative settlements and unrealized
      gains (losses) increased $9.4 million, or 10% when compared to 2005. The
      following were the primary reasons for the increase in our revenue:





•
            An
                11% decrease in the average natural gas equivalent price decreased
                revenue
                by $12.3 million;





•
            An
                11% increase in our production volumes increased revenue by $11.1
                million;





•
            A
                $3.8 million gain from the settlement of derivative contracts in
                2006
                versus a $4.2 million settlement loss in 2005 increased revenue by
                $8.0
                million.





•
            A
                $2.6 million unrealized gain due to derivative hedging contracts
                in 2006
                versus no unrealized gain (loss) due to derivative hedging contracts
                in
                2005 increased revenue by $2.6 million. In October 2006, we de-designated
                all derivatives that were previously classified as cash flow hedges
                and as
                such will mark-to-market these derivatives in future periods. In
                addition,
                all future derivatives will be undesignated and therefore subject
                to
                mark-to-market accounting. Mark-to-Market accounting requires that
                we
                record both derivative settlements and unrealized gains (losses)
                to the
                consolidated statement of operations within a single income statement
                line
                item. Begining October 1, 2006, we will include both derivative
                settlements and unrealized gains (losses) within revenue. As such,
                amounts
                that were previously recorded in other comprehensive income or other
                income (expense) will instead be incorporated within revenue.


41
 *Table
          of Contents*


Our
      2005
      oil and natural gas revenue including derivative settlements increased $25.1
      million, or 35% when compared to 2004. The following were the primary reasons
      for the increase in our revenue:





•
            A
                36% increase in the average natural gas equivalent price increased
                revenue
                by $27.2 million;





•
            A
                3% decrease in our production decreased revenue by $2.6
                million;





•
            A
                $4.2 million loss from the cash settlement of derivative contracts
                in 2005
                versus a $4.7 million settlement loss in 2004 increased revenue by
                $0.5
                million.





*Other
      revenue.* Other
      revenue relates to fees that we charge third parties who use our gas gathering
      systems to move their production from the wellhead to third party gas pipeline
      systems. Other revenue for 2006 was $127,000 compared to $220,000 in 2005 and
      $515,000 in 2004. Costs related to our gas gathering systems are recorded in
      lease operating expenses.





*Hedging.* We
      utilize swaps, collars, three way costless collars and floor contracts to (i)
      reduce the effect of price volatility on the commodities that we produce and
      sell, (ii) reduce commodity price risk and (iii) provide a base level of cash
      flow in order to assure we can execute at least a portion of our capital
      spending plans. See “Item 7A. Quantitative and Qualitative Disclosures About
      Market Risk — Derivative Instruments and Hedging Activities” for a description
      of our derivative contracts and our open derivative contracts.





The
      following table details derivative contracts that settled during 2006, 2005
      and
      2004 and includes the type of derivative contract, the volume, the weighted
      average NYMEX reference price for those volumes, and the associated gain /(loss)
      upon settlement.








**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004*****Oil
                swaps***Volumes
                (Bbls)
            
            
            —
            
            
            NM
            
            
            —
            
            
            NM
            
            
            73,050Average
                swap price (per Bbl)
            
            $
            —
            
            
            NM
            
            $
            —
            
            
            NM
            
            $
            24.65Gain
                /(loss) upon settlement (in thousands)
            
            $
            —
            
            
            NM
            
            $
            —
            
            
            NM
            
            $
            (1,073
            )***Oil
                collars***Volumes
                (Bbls)
            
            
            165,000
            
            
            40%
            
            
            118,105
            
            
            (34%)
            
            
            178,570Average
                floor price (per Bbl)
            
            $
            55.86
            
            
            49%
            
            $
            37.40
            
            
            50%
            
            $
            24.92Average
                ceiling price (per Bbl)
            
            $
            76.23
            
            
            62%
            
            $
            47.20
            
            
            51%
            
            $
            31.21Gain
                /(loss) upon settlement (in thousands)
            
            $
            157
            
            
            NM
            
            $
            (1,249
            )
            
            (29%)
            
            $
            (1,768
            )***Total
                oil***Volumes
                (Bbls)
            
            
            165,000
            
            
            40%
            
            
            118,105
            
            
            (53%)
            
            
            251,620Gain
                /(loss) upon settlement (in thousands)
            
            $
            157
            
            
            NM
            
            $
            (1,249
            )
            
            (56%)
            
            $
            (2,841
            )***Natural
                gas swaps***Volumes
                (MMbtu)
            
            
            —
            
            
            NM
            
            
            —
            
            
            NM
            
            
            753,000Average
                swap price (per MMbtu)
            
            $
            —
            
            
            NM
            
            $
            —
            
            
            NM
            
            $
            4.53Gain
                /(loss) upon settlement (in thousands)
            
            $
            —
            
            
            NM
            
            $
            —
            
            
            NM
            
            $
            (1,066
            )***Natural
                gas collars***Volumes
                (MMbtu)
            
            
            4,070,000
            
            
            54%
            
            
            2,643,000
            
            
            6%
            
            
            2,504,000Average
                floor price (per MMbtu)
            
            $
            7.90
            
            
            33%
            
            $
            5.93
            
            
            31%
            
            $
            4.54Average
                ceiling price (per MMbtu)
            
            $
            14.33
            
            
            82%
            
            $
            7.86
            
            
            15%
            
            $
            6.85Gain
                /(loss) upon settlement (in thousands)
            
            $
            3,639
            
            
            NM
            
            $
            (2,925
            )
            
            272%
            
            $
            (787
            )***Total
                natural gas***Volumes
                (MMbtu)
            
            
            4,070,000
            
            
            54%
            
            
            2,643,000
            
            
            (19%)
            
            
            3,257,000Gain
                /(loss) upon settlement (in thousands)
            
            $
            3,639
            
            
            NM
            
            $
            (2,925
            )
            
            58%
            
            $
            (1,853
            )




42
 *Table
          of Contents*





***Operating
      costs and expenses***





*Production
      costs.* We
      believe that per unit of production measures are the best way to evaluate our
      production costs. We use this information to internally evaluate our
      performance, as well as to evaluate our performance relative to our peers.





**Unit-of-Production**
              **(Per
                Mcfe)****Year
                ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****Production
                costs:**Operating
                & maintenance
            
            $
            0.63
            
            
            34%
            
            $
            0.47
            
            
            31%
            
            $
            0.36Expensed
                workovers
            
            
            0.06
            
            
            50%
            
            
            0.04
            
            
            (43%)
            
            
            0.07Ad
                valorem taxes
            
            
            0.12
            
            
            33%
            
            
            0.09
            
            
            29%
            
            
            0.07Lease
                operating expenses
            
            $
            0.81
            
            
            35%
            
            $
            0.60
            
            
            20%
            
            $
            0.50Production
                taxes
            
            
            0.30
            
            
            7%
            
            
            0.28
            
            
            12%
            
            
            0.25Production
                costs
            
            $
            1.11
            
            
            26%
            
            $
            0.88
            
            
            17%
            
            $
            0.75








**Amount**
              **(In
                thousands)****Year
                ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****Production
                costs:**Operating
                & maintenance
            
            $
            8,267
            
            
            48%
            
            $
            5,568
            
            
            24%
            
            $
            4,480Expensed
                workovers
            
            
            797
            
            
            62%
            
            
            492
            
            
            (44%)
            
            
            878Ad
                valorem taxes
            
            
            1,637
            
            
            49%
            
            
            1,101
            
            
            35%
            
            
            815Lease
                operating expenses
            
            $
            10,701
            
            
            49%
            
            $
            7,161
            
            
            16%
            
            $
            6,173Production
                taxes
            
            
            4,021
            
            
            20%
            
            
            3,353
            
            
            8%
            
            
            3,107Production
                costs
            
            $
            14,722
            
            
            40%
            
            $
            10,514
            
            
            13%
            
            $
            9,280








For
      2006,
      our unit production cost increased 26% when compared to 2005. The following
      were
      the primary reasons for the increase in our 2006 production costs relative
      to
      2005:





•
            O&M
                expenses increased 34%, or $0.16 per Mcfe. Increases in salt water
                disposal, equipment rental, chemical treating, and well service and
                repair
                accounted for 69% of the per unit change. The increase in O&M expenses
                was primarily because of an increase in the number of wells that
                came on
                line during 2006 as compared to 2005 and to a lesser extent by service
                cost inflation.





•
            Expense
                workovers were 50% higher, or $0.02 per Mcfe, due to a higher level
                of
                workover activity in 2006.





•
            Ad
                valorem taxes increased 33%, or $0.03 per Mcfe, due to an increase
                in
                estimated property valuations for our oil and natural gas properties
                because of higher commodity prices in 2005 which were the basis for
                determining property tax rates for
                2006.





•
            Production
                taxes were 7% higher, or $0.02 per Mcfe, due to $0.5 million less
                in
                severance tax refunds received in 2006 than in 2005.





Unit
      production cost increased 17% in 2005 as compared to 2004. The following were
      the primary reasons for the increase in 2005 production costs relative to
      2004:


43
 *Table
          of Contents*


•
            Approximately
                $0.04 per Mcfe of the increase in our O&M expenses was due to cost
                associated with new wells that began producing in
                2005.





•
            Ad
                valorem taxes increased due to higher property valuations for our
                oil and
                natural gas properties due to higher commodity prices in 2004 which
                were
                the basis for determining property tax rates for
                2005.





*General
      and administrative expenses.* We
      capitalize a portion of our general and administrative costs. Capitalized costs
      include the cost of technical employees who work directly on capital projects
      and a portion of our associated technical organization costs such as
      supervision, telephone and postage.








**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****(In
                thousands, except per unit measurements)**General
                and administrative costs
            
            $
            14,439
            
            
            39%
            
            $
            10,380
            
            
            1%
            
            $
            10,264Capitalized
                general and administrative costs
            
            
            (6,552
            )
            
            35%
            
            
            (4,847
            )
            
            (1%)
            
            
            (4,872
            )General
                and administrative expenses
            
            $
            7,887
            
            
            43%
            
            $
            5,533
            
            
            3%
            
            $
            5,392General
                and administrative expense (per Mcfe)
            
            $
            0.60
            
            
            30%
            
            $
            0.46
            
            
            5%
            
            $
            0.44





Our
      general and administrative expenses in 2006 were $2.4 million, or $0.14 per
      Mcfe, higher than 2005. The following were the primary reasons for the $4.1
      increase in our 2006 general and administrative costs before
      capitalization over that in 2005:





•
            General
                and administrative expense increased $1.6 million due to non-cash
                employee
                compensation costs associated with our 2006 adoption of SFAS 123R
                dealing
                with a change in accounting methodology for employee stock option
                expense.





•
            Increases
                in payroll, benefits expense, bonuses and FICA tax totaled $2.1 million
                or
                the majority of the remaining increase in general and administrative
                expense. This increase was primarily because of an increase
                in employee salaries earned by the base employees for retention
                purposes and to a lesser extent because of an increase in the number
                of
                employees.





•
            Increases
                in fees paid to our independent public accountants accounted for
                $0.5
                million of the increase and resulted primarily from our change in
                auditors
                and the requirement that both our old and new auditors review our
                financial statements for a two year transition
                period.





Our
      2005
      general and administrative expenses were $141,000, or $0.02 per Mcfe, higher
      than 2004. The following were the primary reasons for the $116,000 increase
      in
      our 2005 general and administrative costs before capitalization over that
      in 2004:





•
            A
                $147,000 increase in total compensation expense due to a combination
                of an
                increase in the number of employees hired and higher medical benefit
                costs.





•
            A
                $435,000 increase in bad debt expense. In 2005, we recorded $447,000
                in
                bad debt expense related to an unpaid account receivable. This amount
                is
                our estimate of the amount that will not be collected. Additionally,
                we
                recorded $9,000 in bad debt expense for an account receivable that
                has
                been deemed uncollectible.





•
            These
                increases were offset by a $188,000 decrease in legal fees, a $161,000
                decrease in office rent and a $31,000 decrease in costs for financial
                reporting.





*Depletion
      of oil and natural gas properties.* Our
      full-cost depletion expense is driven by many factors including certain costs
      spent in the exploration for and development of oil and gas reserves, production
      levels, and estimates of proved reserve quantities and future developmental
      costs at the end of the year.








**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****(In
                thousands, except per unit measurements)**Depletion
                of oil and natural gas properties
            
            $
            46,386
            
            
            39%
            
            $
            33,268
            
            
            40%
            
            $
            23,844Depletion
                of oil and natural gas properties (per Mcfe)
            
            $
            3.50
            
            
            25%
            
            $
            2.79
            
            
            44%
            
            $
            1.94




44
 *Table
          of Contents*





Our
      depletion expense for 2006 was 39% higher than 2005. Approximately $9.4 million
      of the increase in our depletion expense for 2006 was due to an increase in
      the
      depletion rate, while the remaining $3.7 million of the increase was due to
      an increase in our production volumes. The higher depletion rate was due to
      an
      increase in finding and development costs incurred in 2006 and an increase
      in
      future development costs associated with our year-end 2006 proved
      reserves.





Our
      depletion expense for 2005 was 40% higher than 2004. Approximately $10.2 million
      of the increase in our depletion expense for 2005 was due to an increase in
      our
      depletion rate. This increase was offset by $0.7 million due to the decline
      in
      our 2005 production volumes.





*Net
      interest expense.* Interest
      on our Senior Notes, our senior credit facility, our subordinated notes, which
      were terminated in April 2006, and dividends that we pay on our Series A
      mandatorily redeemable preferred stock represents the largest portion of our
      interest expense. Other costs include commitment fees that we pay on the unused
      portion of the borrowing base for our senior credit agreement. In addition,
      we
      typically pay loan and debt issuance costs when we enter into new lending
      agreements or amend existing agreements. When incurred, these costs are recorded
      as non-current assets and are then amortized over the life of the loan. We
      capitalize interest costs on borrowings associated with our major capital
      projects prior to their completion. Capitalized interest is added to the cost
      of
      the underlying assets and is amortized over the lives of the
      assets.







**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****(In
                thousands)**Interest
                on Senior Notes
            
            $
            8,632
            
            
            NM
            
            $
            —
            
            
            NM
            
            $
            —Interest
                on senior credit facility
            
            
            743
            
            
            (67%)
            
            
            2,267
            
            
            157%
            
            
            882Interest
                on senior subordinated notes(a)
            
            
            699
            
            
            (64%)
            
            
            1,948
            
            
            14%
            
            
            1,703Commitment
                fees
            
            
            174
            
            
            31%
            
            
            133
            
            
            (44%)
            
            
            236Dividend
                on mandatorily redeemable preferred stock
            
            
            606
            
            
            (17%)
            
            
            734
            
            
            1%
            
            
            726Amortization
                of deferred loan and debt issuance cost
            
            
            1,665
            
            
            239%
            
            
            491
            
            
            (36%)
            
            
            766Other
                general interest expense
            
            
            5
            
            
            (55%)
            
            
            11
            
            
            (58%)
            
            
            26Capitalized
                interest expense
            
            
            (2,836
            )
            
            77%
            
            
            (1,604
            )
            
            34%
            
            
            (1,195
            )Net
                interest expense
            
            $
            9,688
            
            
            143%
            
            $
            3,980
            
            
            27%
            
            $
            3,144Weighted
                average debt outstanding
            
            $
            123,031
            
            
            53%
            
            $
            80,180
            
            
            42%
            
            $
            56,352Average
                interest rate on outstanding indebtedness(b)
            
            
            8.8
            %
            
            
            
            
            6.3
            %
            
            
            
            
            6.3
            %


__________


(a)
            Our
                senior subordinated notes were repaid in April 2006 in conjunction
                with
                our Senior Notes issuance. The agreement was terminated upon repayment.
                In
                conjunction with the termination of the subordinated notes agreement,
                the
                associated interest rate swap was terminated. The $838,000 gain associated
                with the termination of the swap is included within other income
                (expense).





(b)
            Calculated
                as the sum of the interest on our outstanding indebtedness, commitment
                fees that we pay on our unused borrowing capacity and the dividend
                on our
                mandatorily redeemable preferred stock divided by the weighted average
                debt and preferred stock outstanding for the
                period.





Our
      net
      interest expense for 2006 was 143% higher than 2005. The primary drivers behind
      the increase in our interest expense were a 53% increase in our weighted average
      debt outstanding, a higher average interest rate associated with our Senior
      Notes and the $1.0 write-off of deferred loan and debt issuance costs associated
      with the termination of the senior subordinated notes. The write-off of the
      senior subordinated notes issuance costs is included within amortization of
      deferred loan and debt issuance costs.





Our
      net
      interest expense for 2005 was 27% higher than 2004. The primary driver behind
      the increase in our interest expense was a 42% increase in our weighted average
      debt outstanding.





*Other
      income (expense).* Prior to
      October 1, 2006, other income (expense) included non-cash gains (losses)
      resulting from the change in fair market value of oil and gas derivative
      contracts that did not qualify as cash flow hedges under SFAS 133, cash gains
      (losses) on the settlement of these contracts and non-cash gains (losses)
      related to charges for the ineffective portions of our derivative contracts
      that
      qualified as cash flow hedges under SFAS 133. On October 1, 2006, we
      de-designated all derivatives that were previously classified as cash flow
      hedges and as such will mark-to-market these derivatives in future periods.
      In
      addition, all future derivatives will be undesignated and therefore subject
      to
      mark-to-market accounting. Mark-to-Market accounting requires that we record
      both derivative settlements and unrealized gains (losses) to the consolidated
      statement of operations within a single income statement line item. Begining
      October 1, 2006, we will include both derivative settlements and unrealized
      gains (losses) within revenue. As such, amounts that were previously recorded
      in
      other comprehensive income and other income (expense) will instead be
      incorporated within revenue.


45
 *Table
          of Contents*





**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****(In
                thousands)****Derivative:**Non-cash
                gain (loss) due to change in fair market value of undesignated
                hedges
            
            $
            NA
            
            
            NM
            
            $
            (92
            )
            
            179%
            
            $
            (33
            )Non-cash
                gain (loss) for ineffective portion of cash flow hedges
            
            
            3,213
            
            
            NM
            
            
            (722
            )
            
            NM
            
            
            658Cash
                settlement of undesignated hedges
            
            
            NA
            
            
            NM
            
            
            —
            
            
            0%
            
            
            —Derivative
                other income
            
            
            3,213
            
            
            NM
            
            
            (814
            )
            
            NM
            
            
            625**Other:**Gain
                (loss) on inventory
            
            
            (64
            )
            
            (52%)
            
            
            (134
            )
            
            NM
            
            
            —Other
                income (loss)
            
            
            1,416
            
            
            281%
            
            
            372
            
            
            218%
            
            
            117Miscellaneous
                other income (loss)
            
            
            1,352
            
            
            468%
            
            
            238
            
            
            103%
            
            
            117Total
                other income (loss)
            
            $
            4,565
            
            
            NM
            
            $
            (576
            )
            
            NM
            
            $
            742





The
      following table shows the volumes and the weighted average NYMEX reference
      price
      for our derivative contracts that we did not designate as cash flow hedges
      under
      SFAS 133 in 2006, 2005 and 2004.





**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004*****Written
                oil puts***Volumes
                (Bbls)
            
            
            40,500
            
            
            (44%)
            
            
            72,000
            
            
            NM
            
            
            —Average
                price ($ per Bbl)
            
            $
            43.56
            
            
            26%
            
            $
            34.67
            
            
            NM
            
            $
            —***Total
                oil hedges***Volumes
                (Bbls)
            
            
            40,500
            
            
            (44%)
            
            
            72,000
            
            
            NM
            
            
            —Average
                price ($ per Bbl)
            
            $
            43.56
            
            
            26%
            
            $
            34.67
            
            
            NM
            
            $
            —***Written
                natural gas puts***Volumes
                (MMbtu)
            
            
            1,510,000
            
            
            21%
            
            
            1,250,000
            
            
            793%
            
            
            140,000Average
                price ($ per MMbtu)
            
            $
            6.81
            
            
            16%
            
            $
            5.88
            
            
            7%
            
            $
            5.50***Written
                natural gas basis swaps***Volumes
                (MMbtu)
            
            
            1,260,000
            
            
            NM
            
            
            —
            
            
            0%
            
            
            —Average
                price ($ per MMbtu)
            
            $
            0.20
            
            
            NM
            
            $
            —
            
            
            0%
            
            $
            —***Total
                natural gas hedges***Volumes
                (MMbtu)
            
            
            2,770,000
            
            
            122%
            
            
            1,250,000
            
            
            793%
            
            
            140,000Average
                price ($ per MMbtu)
            
            $
            3.80
            
            
            (35%)
            
            $
            5.88
            
            
            7%
            
            $
            5.50





See
“Item
      7A. Quantitative and Qualitative Disclosures About Market Risk — Derivative
      Instruments and Hedging Activities” for a description of our derivative
      contracts and our derivative contracts open at December 31, 2006.





*Income
      taxes:* A
      deferred tax liability or asset is recognized for the estimated future tax
      effects attributable to (i) NOLs and (ii) existing temporary differences between
      book and taxable income. Realization of net deferred tax assets is dependent
      upon generating sufficient taxable income within the carryforward period
      available under tax law.





In
      2004,
      we recognized a current year net deferred tax liability of $10.6 million due
      to
      reversals of our existing temporary differences between book and taxable income
      resulting mainly from our capital expenditures. Our $10.6 million net deferred
      tax liability consisted of a $10.9 million deferred income tax expense, a $0.3
      million tax effect of unrealized hedging gains, and a $0.6 million credit to
      equity for the tax benefit from the exercise of stock options. Our deferred
      tax
      expense was due primarily to increased capital expenditures and a $14 million
      increase in our pre-tax income. The primary reason for the difference between
      our effective tax rate of 35.6% and the federal statutory rate of 35% was due
      to
      the effect of preferred stock dividends which were partially offset by
      deductible stock compensation.


46
 *Table
          of Contents*


In
      2005,
      we recognized a current year net deferred tax liability of $14.3 million due
      to
      reversals of our existing temporary difference between book and taxable income
      resulting mainly from our capital expenditures. Our $14.3 million net deferred
      tax liability consisted of a $15 million increase in our 2005 deferred income
      tax expense, a $42,000 tax effect of unrealized hedging losses, and a $791,000
      credit to equity for the tax benefit from the exercise of stock options. Capital
      loss carryforwards of approximately $1.6 million expired at the end of 2005,
      reducing the valuation allowance we established in 2003 by $573,000. The $4.1
      million increase in our 2005 deferred tax expense was primarily due to increased
      capital expenditures and a $12 million increase in our pre-tax income. The
      primary reason for the difference between our effective tax rate of 35.4% and
      the federal statutory rate of 35% was due to the effect of preferred stock
      dividends that were partially offset by deductible stock
      compensation.





In
      2006,
      we recognized a current year net deferred federal tax liability of $12.3 million
      due to reversals of our existing temporary differences between book and taxable
      income resulting mainly from our capital expenditures. Our $12.3 million net
      deferred federal tax liability consisted of a $11.5 million increase in our
      2006
      deferred federal income tax expense and a $800,000 tax effect of unrealized
      hedging gains. The $2.3 million decrease in our 2006 deferred federal tax
      expense was primarily due to a $9.9 million decrease in pre-tax income. We
      also
      recognized a current year net deferred state tax liability of $1.2
      million. Our $1.2 million net deferred state tax liability consisted of a
      new $1.3 million Texas franchise tax and miscellaneous deferred tax benefits
      of
      other states. The primary reasons for the difference between our effective
      tax
      rate of 39.2% and the federal statutory rate of 35% were due to the effects
      of
      preferred stock dividends, changes in accounting for stock compensation, and
      the
      new Texas franchise tax.





In
      May
      2006, the state of Texas enacted legislation that replaces the taxable capital
      and earned surplus components of its franchise tax with a new franchise tax
      that
      is based on modified gross revenue. The new franchise tax (referred to as the
      “Margin Tax”) becomes effective beginning with this tax year. The current
      franchise tax remained in effect through the end of 2006. Within the context
      of
      generally accepted accounting principals in the United States, the Margin Tax
      is
      based on a measure of income and is thus accounted for in accordance with
      Statement of Financial Accounting Standards No. 109 “Accounting for Income
      Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects
      of the tax law change in the period of enactment. The Margin Tax applies a
      1%
      tax on operating margin beginning in 2007 and payable in 2008. As mentioned
      above, we booked $1.3 million of deferred Margin Tax ($872,000 after-tax)
      in June 2006 to reflect the estimated impact of the adoption of the margin
      tax
      in 2006. Beginning in 2007, due to our ability to deduct intangible drilling
      costs, we anticipate that the bulk of the associated Margin Tax should be
      deferred.





**Liquidity
      and Capital Resources**





***Sources
      of Capital***





For
      2007,
      we intend to fund our capital expenditure program and contractual commitments
      with cash flows from operations, borrowings under our senior credit agreement,
      reimbursements of prior land and seismic costs by third parties who participate
      in our projects, and the sale of interests in projects and properties or
      alternative financing sources.





***9
      5/8% Senior Notes due 2014***





In
      April
      2006, we issued $125 million of Senior Notes. The Senior Notes were priced
      at
      98.629% of their face value to yield 9 7/8 %
      and are
      fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries,
      Brigham, Inc. and Brigham Oil & Gas, L.P.(the “Guarantors”). We entered into
      an indenture (the “Indenture”), among us, the Guarantors and Wells Fargo Bank,
      N.A., as trustee, relating to the Senior Notes. The Senior Notes are fully
      and
      unconditionally guaranteed by the Guarantors.





The
      Senior Notes were originally issued pursuant to the Indenture in a transaction
      exempt from the registration requirements of the Securities Act of 1933. We
      have
      completed an exchange offer to exchange all of the unregistered Senior Notes
      for
      registered Senior Notes.





We
      are
      obligated to pay the $125 million aggregate principal amount of the Senior
      Notes
      in cash upon maturity in May 2014. Starting in November 2006, we paid 9 5/8 %
      interest per annum on the principal amount of the Senior Notes. Future interest
      payments are due semi-annually in arrears in May and November of each year.




The
      Senior Notes are our unsecured senior obligations, and:





•
            rank
                equally in right of payment with all our existing and future senior
                indebtedness;


•
            rank
                senior to all of our future subordinated indebtedness;
                and


•
            are
                effectively junior in right of payment to all of our and the Guarantors’
                existing and future secured indebtedness, including debt of our senior
                credit agreement.


47
 *Table
          of Contents*


The
      Indenture contains customary events of default. Upon the occurrence of certain
      events of default, the trustee or the holders of the Senior Notes may declare
      all outstanding Senior Notes to be due and payable immediately.





Additionally,
      the Indenture contains customary restrictions and covenants which could
      potentially limit our flexibility to manage and fund our business. We were
      in
      compliance with all covenants associated with the Senior Notes as of December
      31, 2006.





***Senior
      Credit Agreement***





In
      June
      2005, we amended and restated our $100 million senior credit agreement to
      provide for revolving credit borrowings up to $200 million and to extend the
      maturity of the agreement from March 2009 to June 2010. In conjunction with
      the
      issuance of our Senior Notes, the borrowing base was reset to $50 million.
      In
      November 2006, we concluded our semi-annual redetermination process, which
      is
      described in further detail below, and at that time the borrowing base was
      reset
      to $110 million.





In
      April
      2006, proceeds from the Senior Notes issuance were used to repay the $48.4
      million balance outstanding under the senior credit agreement. As of December
      31, 2006, we had $25.9 outstanding and therefore had $84.1 million of unused
      committed borrowing capacity available. As of December 31, 2005, we had $33.1
      million in borrowings outstanding under the agreement. As of March 5, 2007,
      we
      had $53.0 million of borrowings outstanding under the senior credit
      agreement.





Since
      the
      borrowing base for our senior credit agreement is redetermined at least
      semi-annually, the amount of borrowing capacity available to us under our senior
      credit agreement could fluctuate. While we do not expect the amount that we
      have
      borrowed under our senior credit agreement to exceed the borrowing base, in
      the
      event that the borrowing base is adjusted below the amount that we have
      borrowed, our access to further borrowings will be reduced, and we may not
      have
      the resources necessary to carry out our planned spending for exploration and
      development activities.





Borrowings
      under our senior credit agreement bear interest, at our election, at a base
      rate
      or a Eurodollar rate, plus in each case an applicable margin. These margins
      are
      reset quarterly and are subject to increase if the total amount borrowed under
      our senior credit agreement reaches certain percentages of the available
      borrowing base, as shown below:





**Percent
                of Borrowing Base****Utilized**
            
            **Eurodollar
                Rate****Advances**
            
            **Base
                Rate****Advances(1)**<50%
            
            1.250%
            
            0.000%50%
                and < 75%
            
            1.500%
            
            0.000%75%
                and < 90%
            
            1.750%
            
            0.250%90%
            
            2.000%
            
            0.500%





(1)
            Base
                rate is defined as for any day a fluctuating rate per annum equal
                to the
                higher of: (a) the Federal Funds Rate plus 1/2 of 1% or (b) the rate
                of
                interest in effect for such day as publicly announced from time to
                time by
                Bank of America as its “prime rate.” The “prime rate” is a rate set by
                Bank of America based upon various factors including Bank of America’s
                costs and desired return, general economic conditions and other factors,
                and is used as a reference point for pricing some loans, which may
                be
                priced at, above, or below such announced rate. Any change in such
                rate
                announced by Bank of America shall take effect at the opening of
                business
                on the day specified in the public announcement of such
                change.





We
      are
      also required to pay a quarterly commitment fee on the average daily unused
      portion of the borrowing base. The commitment fees we pay are reset quarterly
      and are subject to change as the percentage of the available borrowing base
      that
      we utilize changes. The margins and commitment fees that we pay are as
      follows:





**Percent
                of Borrowing Base****Utilized**
            
            **Quarterly****Commitment
                Fee**<50%
            
            0.250%50%
                and < 75%
            
            0.250%75%
                and < 90%
            
            0.375%90%
            
            0.375%




48
 *Table
          of Contents*


Our
      senior credit agreement also contains customary restrictions and covenants.
      Should we be unable to comply with these or other covenants, our senior lenders
      may be unwilling to waive compliance or amend the covenants and our liquidity
      may be adversely affected. Pursuant to our senior credit agreement, we are
      required to maintain a current ratio of at least 1 to 1 and an interest coverage
      ratio for the four most recent quarters of at least 3 to 1. Our current ratio
      at
      December 31, 2006 and interest coverage ratio for the twelve-month period ended
      December 31, 2006 were 1.9 to 1 and 8.8 to 1, respectively. As of December
      31,
      2006, we were in compliance with all covenant requirements in connection with
      our senior credit agreement.





Access
      to
      the committed and undrawn portion of our borrowing base could be limited based
      on the covenants that are part of the indenture governing the Senior Notes.
      Based on these covenants and the value of our proved reserves at December 2006,
      we calculate that we can incur up to $90.8 million of the $110 million borrowing
      base under the senior credit agreement. The future amounts of debt that we
      borrow under our senior credit agreement will depend primarily on net cash
      provided by operating activities, proceeds from other financing activities,
      reimbursements of prior land and seismic costs by third party participants
      in
      our projects and proceeds generated from asset dispositions. Further, growth
      in
      our proved reserves should give us the flexibility to incur additional debt
      under the senior credit agreement beyond the $90.8 million allowed under our
      Senior Notes covenants.





We
      strive
      to manage the amounts we borrow under our senior credit agreement in order
      to
      maintain excess borrowing capacity.





***Senior
      Subordinated Notes***





In
      April
      2006, we used a portion of the net proceeds from our sale of our Senior Notes
      issuance to repay the $30 million in borrowings that were outstanding under
      our
      subordinated credit agreement. Subsequent to this repayment, we terminated
      our
      subordinated credit agreement and the associated interest rate swap designated
      as a cash flow hedge.





***Mandatorily
      Redeemable Preferred Stock***





As
      of
      September 30, 2006, we had $10.1 million in mandatorily redeemable Series A
      preferred stock outstanding, which is held by DLJ Merchant Banking Partners
      III,
      L.P. and affiliated funds, which are managed by affiliates of Credit Suisse
      Securities (USA), LLC. Our option to pay the dividends on our Series A preferred
      stock in kind expired in October 2005 and we are now required to satisfy all
      dividend obligations related to our Series A preferred stock in cash at a rate
      of 6% per annum until it matures in October 2010 or until it is redeemed. Our
      Series A preferred stock is redeemable at our option at 100% or 101% of the
      stated value per share (depending upon certain conditions) at anytime prior
      to
      maturity.





***Access
      to Capital Markets***





We
      currently have two effective universal shelf registration statements covering
      the sale, from time to time, of our common stock, preferred stock, depositary
      shares, warrants and debt securities, or a combination of any of these
      securities. In July 2004, we sold 2,598,500 shares of our common stock and
      in
      November and December 2005, we sold 8,625,000 total shares of our common stock
      under the first of our two registration statements. We have $73.4 million
      remaining available under this shelf registration statement.





Our
      other
      universal shelf registration statement has not been utilized to date and has
      $300 million available.




However,
      our ability to raise additional capital using our shelf registration statements
      may be limited due to overall conditions of the stock market or the oil and
      natural gas industry.





***Off
      Balance Sheet Arrangements***





We
      currently have operating leases, which are considered off balance sheet
      arrangements. We do not currently have any other off balance sheet arrangements
      or other such unrecorded obligations, and we have not guaranteed the debt of
      any
      other party.


49
 *Table
          of Contents*


**Analysis
      of Changes In Cash and Cash Equivalents**





The
      table
      below summarizes our sources and uses of cash during 2006, 2005 and
      2004.





**Year
                Ended December 31,****2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****(In
                thousands)**Net
                income
            
            $
            19,788
            
            
            (28%)
            
            $
            27,435
            
            
            40%
            
            $
            19,650Non-cash
                charges
            
            
            57,555
            
            
            11%
            
            
            51,723
            
            
            42%
            
            
            36,455Changes
                in working capital and other items
            
            
            11,344
            
            
            NM
            
            
            (14,779
            )
            
            NM
            
            
            276Cash
                flows provided by operating activities
            
            $
            88,687
            
            
            38%
            
            $
            64,379
            
            
            14%
            
            $
            56,381Cash
                flows used by investing activities
            
            
            (171,747
            )
            
            52%
            
            
            (113,220
            )
            
            34%
            
            
            (84,645
            )Cash
                flows provided (used) by financing activities
            
            
            83,385
            
            
            65%
            
            
            50,535
            
            
            104%
            
            
            24,766Net
                increase (decrease) in cash and cash equivalents
            
            $
            325
            
            
            (81%)
            
            $
            1,694
            
            
            NM
            
            $
            (3,498
            )




***Analysis
      of net cash provided by operating activities***





Net
      cash
      provided by operating activities for 2006 was $24.3 million higher than 2005.
      The following are the primary reasons for the increase:





•
            An
                11% increase in our production volumes from 2005 to 2006 combined
                with an
                $8.0 million increase from 2005 to 2006 in the settlements of our
                derivative contracts increased net cash provided by operating activities
                by $19 million. This increase was partially offset by a $12.3 million
                decline in revenue due to lower commodity
                prices.





•
            An
                increase in production costs, cash general and administrative costs
                and
                net interest expense for 2006 reduced cash provided by operating
                activities by $11.7 million.





•
            An
                increase in accounts payable and decrease in accounts receivable
                increased
                cash by $26.1 million.





Net
      cash
      provided by operating activities increased by $8 million from 2004 to 2005.
      The
      following are the primary reasons for the increase:





•
            An
                increase in the sales prices we received from the sale of our oil
                and
                natural gas in 2005 combined with a decrease in losses related to
                the cash
                settlement of derivative contracts in 2005 increased net cash provided
                by
                operating activities by $27.2 million. This increase was partially
                offset
                by a $2.6 million decline in revenue due to lower production
                volumes;





•
            An
                increase in our production costs and cash general and administrative
                costs
                for 2005 reduced net cash provided by operating activities by
                $919,000;





•
            An
                increase in the cash interest expense that we paid in 2005 reduced
                our net
                cash provided by operating activities in 2005 by $1.3
                million;





•
            The
                payment of accounts payable in excess of the collection of accounts
                receivable resulted in a $10.3 million decrease to our 2005 net cash
                provided by operating activities;





•
            A
                decrease in advances paid to us by participants in our 3-D seismic
                projects and certain wells resulted in $4 million decrease to our
                2005 net
                cash provided by operating
                activities.





***Working
      Capital***





Working
      capital is the amount by which current assets exceed current liabilities. It
      is
      normal for us to report a working capital deficit at the end of a period. These
      deficits are primarily the result of accounts payable related to lease operating
      expenses, exploration and development costs, royalties payable and gas
      imbalances payable. Settlement of these payables will be funded by cash flows
      from operations or, if necessary, by additional borrowing under our senior
      credit facility.


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Our
      working capital deficit at December 31, 2006 was $26.2 million compared to
      a
      working capital deficit of $9.1 million at December 31, 2005. Our working
      capital deficit at December 31, 2006, included an asset of $5.7 million and
      a
      liability of $4,700 related to the fair value our derivative contracts. Our
      working capital deficit at December 31, 2005, included a liability of $2.2
      million and an asset of $224,000 related to the fair value of derivative
      contracts.





***Analysis
      of changes in cash flows used by investing activities***





Net
      cash
      used by investing activities increased by $58.5 million from 2005 to 2006.
      The
      primary drivers for the increase were an $40.1 million increase in our drilling
      capital expenditures net of changes in accrued drilling costs, a $12.0 million
      increase in our capital expenditures for land and seismic activities and a
      $3.2
      million increase in capitalized costs.





Net
      cash
      used by investing activities increased by $28.6 million from 2004 to 2005.
      The
      primary drivers for the increase were an $18.7 million increase in our drilling
      capital expenditures net of changes in accrued drilling costs, a $6.6 million
      increase in our capital expenditures for land and seismic activities and a
      $1.1
      million increase in capitalized costs.





The
      following is a detailed breakout of our capital expenditures for oil and natural
      gas activities for 2006, 2005 and 2004 in thousands.








**2006**
            
            **%
                Change**
            
            **2005**
            
            **%
                Change**
            
            **2004****Capital
                expenditures for oil and natural gas activities:**Drilling
            
            $
            142,338
            
            
            57%
            
            $
            90,873
            
            
            33%
            
            $
            68,205Land
                and seismic
            
            
            31,683
            
            
            61%
            
            
            19,641
            
            
            51%
            
            
            12,993Capitalized
                cost
            
            
            9,954
            
            
            47%
            
            
            6,789
            
            
            19%
            
            
            5,714Capitalized
                asset retirement obligation
            
            
            609
            
            
            (54%)
            
            
            1,324
            
            
            158%
            
            
            513Total
            
            $
            184,584
            
            
            56%
            
            $
            118,627
            
            
            36%
            
            $
            87,425**Reconciling
                Items:**Other
                property and equipment
            
            $
            (213
            )
            
            (81%)
            
            $
            (1,122
            )
            
            NM
            
            $
            378Change
                in accrued drilling costs
            
            
            (11,092
            )
            
            81%
            
            
            (6,119
            )
            
            180%
            
            
            (2,183
            )Other
            
            
            (1,532
            )
            
            NM
            
            
            1,834
            
            
            NM
            
            
            (975
            )Total
                Reconciling Items
            
            
            (12,837
            )
            
            137%
            
            
            (5,407
            )
            
            94%
            
            
            (2,780
            )Net
                cash used in investing activities
            
            $
            (171,747
            )
            
            52%
            
            $
            (113,220
            )
            
            34%
            
            $
            (84,645
            )








***Analysis
      of changes in cash flows from financing activities***





Over
      the
      three year period ended December 31, 2006, we have entered into various
      financing transactions with the intent of increasing our liquidity so that
      we
      could fund our capital expenditures for the exploration and development of
      oil
      and natural gas properties.





Our
      net
      cash provided by financing activities in 2006 was $32.9 million higher than
      in
      2005. The majority of the increase is due to the issuance of our Senior Notes
      in
      April 2006. Net cash provided by financing activities in 2005 was $ 25.8 million
      higher than that in 2004. The increase was due to a $10.1 million increase
      in
      our senior credit agreement, a $10.0 million increase in our subordinated credit
      agreement and common stock issuances totaling $6.1 million.





**Common
      Stock Transactions**





Our
      net
      proceeds from the sale of common stock and employee stock option exercises
      were
      $29.2 million lower in 2006 than they were in 2005. This compares to net
      proceeds that were $6.6 million higher in 2005 than in 2004.





The
      following is a list of common stock transactions that occurred in 2006, 2005
      and
      2004 in thousands except per share data.





**Shares
                Issued**
            
            **Net
                Proceeds*****2006
                common stock transactions:***Sale
                of common stock under universal shelf registration
                statement
            
            
            —
            
            $
            —Exercise
                of employee stock options
            
            
            95,100
            
            $
            467***2005
                common stock transactions:***Sale
                of common stock under universal shelf registration
                statement(a)
            
            
            2,500,000
            
            $
            28,321Exercise
                of employee stock options
            
            
            340,467
            
            $
            1,314***2004
                common stock transactions:***Sale
                of common stock under universal shelf registration
                statement(b)
            
            
            2,598,500
            
            $
            22,105Exercise
                of employee stock options
            
            
            314,181
            
            
            972


__________


(a)
            The
                net proceeds from the sale were used to repay debt outstanding under
                our
                senior credit agreement. Net proceeds does not include the net proceeds
                from the sale of common stock used to purchase 6,125,000 shares of
                our
                stock held by funds managed by affiliates of Credit Suisse First
                Boston
                (USA), Inc.





(b)
            The
                net proceeds from the sale were used to repay debt outstanding under
                our
                senior credit agreement.


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**Critical
      Accounting Policies**





The
      establishment and consistent application of accounting policies is a vital
      component of accurately and fairly presenting our consolidated financial
      statements in accordance with generally accepted accounting principles (GAAP),
      as well as ensuring compliance with applicable laws and regulations governing
      financial reporting. While there are rarely alternative methods or rules from
      which to select in establishing accounting and financial reporting policies,
      proper application often involves significant judgment regarding a given set
      of
      facts and circumstances and a complex series of decisions.





***Use
      of Estimates***





The
      preparation of financial statements in accordance with GAAP in the United States
      of America requires us to make estimates and assumptions that affect our
      reported assets, liabilities, revenues, expenses, and some narrative
      disclosures. Our estimates of our proved oil and natural gas reserves, future
      development costs, production expense, revenue and deferred income taxes are
      the
      most critical to our financial statements.





***Oil
      and Natural Gas Reserves***





The
      determination of depreciation, depletion and amortization expense as well as
      impairments that are recognized on our oil and natural gas properties are highly
      dependent on the estimates of the proved oil and natural gas reserves
      attributable to our properties. Our estimate of proved reserves is based on
      the
      quantities of oil and natural gas which geological and engineering data
      demonstrate, with reasonable certainty, to be recoverable in the future years
      from known reservoirs under existing economic and operating conditions. The
      accuracy of any reserve estimate is a function of the quality of available
      data,
      engineering and geological interpretation, and judgment. For example, we must
      estimate the amount and timing of future operating costs, severance taxes and
      development costs, all of which may in fact vary considerably from actual
      results. In addition, as the prices of oil and natural gas and cost levels
      change from year to year, the economics of producing our reserves may change
      and
      therefore the estimate of proved reserves may also change. Any significant
      variance in these assumptions could materially affect the estimated quantity
      and
      value of our reserves.





The
      information regarding present value of the future net cash flows attributable
      to
      our proved oil and natural gas reserves are estimates only and should not be
      construed as the current market value of the estimated oil and natural gas
      reserves attributable to our properties. Thus, such information includes
      revisions of certain reserve estimates attributable to our properties included
      in the prior year’s estimates. These revisions reflect additional
      information from subsequent activities, production history of the properties
      involved and any adjustments in the projected economic life of such properties
      resulting from changes in oil and natural gas prices. Any future downward
      revisions could adversely affect our financial condition, our borrowing ability,
      our future prospects and the value of our common stock.





The
      estimates of our proved oil and natural gas reserves used in the preparation
      of
      our consolidated financial statements were prepared by Cawley, Gillespie &
Associates, Inc., our independent petroleum consultants, and were prepared
      in
      accordance with the rules promulgated by the SEC.


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***Oil
      and Natural Gas Property***





The
      method of accounting we use to account for our oil and natural gas investments
      determines what costs are capitalized and how these costs are ultimately matched
      with revenues and expensed.





We
      utilize the full cost method of accounting to account for our oil and natural
      gas investments instead of the successful efforts method because we believe
      it
      more accurately reflects the underlying economics of our programs to explore
      and
      develop oil and natural gas reserves. The full cost method embraces the concept
      that dry holes and other expenditures that fail to add reserves are intrinsic
      to
      the oil and natural gas exploration business. Thus, under the full cost method,
      all costs incurred in connection with the acquisition, development and
      exploration of oil and natural gas reserves are capitalized. These capitalized
      amounts include the costs of unproved properties, internal costs directly
      related to acquisitions, development and exploration activities, asset
      retirement costs, geological and geophysical costs and capitalized interest.
      Although some of these costs will ultimately result in no additional reserves,
      they are part of a program from which we expect the benefits of successful
      wells
      to more than offset the costs of any unsuccessful ones. The full cost method
      differs from the successful efforts method of accounting for oil and natural
      gas
      investments. The primary differences between these two methods are the treatment
      of exploratory dry hole costs. These costs are generally expensed under the
      successful efforts method when it is determined that measurable reserves do
      not
      exist. Geological and geophysical costs are also expensed under the successful
      efforts method. Under the full cost method, both dry hole costs and geological
      and geophysical costs are initially capitalized and classified as unevaluated
      properties pending determination of proved reserves. If no proved reserves
      are
      discovered, these costs are then amortized with all the costs in the full cost
      pool.





Capitalized
      amounts except unevaluated costs are depleted using the units of production
      method. The depletion expense per unit of production is the ratio of the sum
      of
      our unamortized historical costs and estimated future development costs to
      our
      proved reserve volumes. Estimation of hydrocarbon reserves relies on
      professional judgment and use of factors that cannot be precisely determined.
      Subsequent reserve estimates materially different from those reported would
      change the depletion expense recognized during the future reporting periods.
      For
      the year ended December 31, 2006, our weighted average depletion expense per
      unit of production was $3.50 per Mcfe. A 10% decrease in our estimated net
      proved reserves at December 31, 2006, would result in a $0.38 per Mcfe increase
      in our per unit depletion expense and a $5.0 million decrease in our pre-tax
      net
      income.





To
      the
      extent the capitalized costs in our full cost pool (net of depreciation,
      depletion and amortization and related deferred taxes) exceed the sum of the
      present value (using a 10% discount rate and based on period-end oil and natural
      gas prices) of the estimated future net cash flows from our proved oil and
      natural gas reserves and the capitalized cost associated with our unproved
      properties, we would have a capitalized ceiling impairment. Such costs would
      be
      charged to operations as a reduction of the carrying value of oil and natural
      gas properties. The risk that we will be required to write down the carrying
      value of our oil and natural gas properties increases when oil and natural
      gas
      prices are depressed, even if the low prices are temporary. In addition,
      capitalized ceiling impairment charges may occur if we experience poor drilling
      results or estimations of our proved reserves are substantially reduced. A
      capitalized ceiling impairment is a reduction in earnings that does not impact
      cash flows, but does impact operating income and stockholders’ equity. Once
      recognized, a capitalized ceiling impairment charge to oil and natural gas
      properties cannot be reversed at a later date. The risk that we will experience
      a ceiling test write-down increases when oil and gas prices are depressed or
      if
      we have substantial downward revisions in its estimated proved reserves. Based
      on oil and gas prices in effect on December 29, 2006 ($5.475 per MMBtu for
      Henry
      Hub gas and $61.06 per barrel for West Texas Intermediate oil, adjusted for
      differentials), the unamortized cost of our oil and gas properties exceeded
      the
      ceiling limit by $40.4 million, net of tax. However, subsequent to the end
      of
      the quarter, oil and natural gas prices increased, and on February 28, 2007,
      reached $7.21 per MMBtu for natural gas and $61.80 per barrel for oil. Utilizing
      these prices, our net capitalized costs of oil and natural gas properties would
      not have exceeded the ceiling limit. As a result of the increase in the ceiling
      limit using subsequent prices, we were not required to write-down the net
      capitalized costs of its oil and gas properties. Write-downs required by these
      rules do not impact our cash flow from operating activities, but do reduce
      net
      income and stockholders’ equity. No assurance can be given that we will not
      experience a capitalized ceiling impairment charge in future periods. In
      addition, capitalized ceiling impairment charges may occur if estimates of
      proved hydrocarbon reserves are substantially reduced or estimates of future
      development costs increase significantly. See “Item 1A. Risk Factors —
Exploratory Drilling is a speculative activity that may not result in
      commercially productive reserves and may require expenditures in excess of
      budgeted amounts,” “Item 1A. Risk Factors — We need to replace our reserves at a
      faster rate than companies whose reserves have longer production periods. Our
      failure to replace our reserves would result in decreasing reserves and
      production over time” and “Item 1A. Risk Factors — Lower oil and natural gas
      prices may cause us to record ceiling limitation write-downs, which would reduce
      our stockholders’ equity.”


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***Asset
      Retirement Obligations***





We
      have
      significant obligations to plug and abandon our oil and natural gas wells and
      related equipment. Liabilities for asset retirement obligations are recorded
      at
      fair value in the period incurred. The related asset value is increased by
      the
      same amount. Asset retirement costs included in the carrying amount of the
      related asset are subsequently allocated to expense as part of our depletion
      calculation. See “— Oil and Natural Gas Property.” Additionally, increases in
      the discounted asset retirement liability resulting from the passage of time
      are
      reported as accretion of discount on asset retirement obligations expense on
      our
      Consolidated Statement of Operations.





Estimating
      future asset retirement obligations requires us to make estimates and judgments
      regarding timing, existence of a liability, as well as what constitutes adequate
      restoration. We use the present value of estimated cash flows related to our
      asset retirement obligations to determine the fair value. Present value
      calculations inherently incorporate numerous assumptions and judgments, which
      include the ultimate retirement and restoration costs, inflation factors, credit
      adjusted discount rates, timing of settlement, and changes in the legal,
      regulatory, environmental and political environments. To the extent future
      revisions to these assumptions impact the present value of our existing asset
      retirement obligation liability, a corresponding adjustment will be made to
      the
      carrying cost of the related asset.





***Income
      Taxes***





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





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





We
      have a
      significant deferred tax asset associated with net operating loss carryforwards
      (NOLs). It is more likely than not that we will use these NOLs to offset current
      tax liabilities in future years. Our NOLs are more fully described in “Item 8.
      Financial Statements and Supplementary Data — Note 8.”





***Revenue
      Recognition***





We
      derive
      revenue primarily from the sale of the oil and natural gas we produce, hence
      our
      revenue recognition policy for these sales is significant.





We
      recognize revenue from the sale of oil using the sales method of accounting.
      Under this method, we recognize revenue when we deliver oil and title
      transfers.





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





Settlements
      for hydrocarbon sales can occur up to two months after the end of the month
      in
      which the oil, natural gas or other hydrocarbon products were produced. We
      estimate and accrue for the value of these sales using information available
      to
      us at the time our financial statements are generated. Differences are reflected
      in the accounting period that payments are received from the
      purchaser.


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***Derivative
      Instruments and Hedging Activities***





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





We
      similarly use derivative contracts to manage our risks associated with interest
      rate fluctuations on long-term debt. During 2003, we entered into an interest
      rate swap to convert the floating interest rate on our senior subordinated
      notes
      to a fixed interest rate to reduce our exposure to potentially higher interest
      rates in the future. The senior subordinated notes agreement was terminated
      in
      April 2006 in conjunction with the issuance of our Senior Notes. The interest
      rate swap was also terminated at that time and the $838,00 gain on termination
      was recorded to other income (expense). The swap is more fully described in
      “Item 8. Financial Statements and Supplementary Data — Note 11.”





All
      derivatives are accounted for in accordance with FASB requirement SFAS 133
      and
      carried at fair value on the balance sheet. Prior to October 1, 2006, our
      derivatives were classified as either cash flow hedges or were undesignated.
      Cash flow hedges were valued quarterly and adjustments to the fair value of
      the
      contract prior to settlement were recorded to stockholders’ equity in other
      comprehensive income. Upon settlement, the gain (loss) on the cash flow hedge
      was recorded to revenue. Any unrealized gains (losses) for the ineffective
      portion of cash flow hedges were recorded to other income (expense). For
      undesignated hedges, both the changes in the fair market value of derivatives
      prior to settlement and the gains (losses) on the settlement of contracts were
      recorded to other income (expense). On October 1, 2006, we de-designated all
      cash flow hedges. In addition, all future hedges will be undesignated. At
      the
      end of each quarter, our derivatives will be marked-to-market to reflect the
      current fair value and both derivative settlements and unrealized gains (losses)
      will be recorded on the consolidated statement of operations. W e
      elected
      to include all derivative settlement and unrealized gains (losses) within
      revenue.





***New
      Accounting Pronouncements***





In
      February 2006, the FASB issued Statement of Financial Accounting Standards
      No.
      155 (SFAS 155) “Accounting for Certain Hybrid Instruments — an amendment of FASB
      Statements No. 133 and 140.” SFAS 155 amends SFAS 133 to permit fair value
      measurement for certain hybrid financial instruments that contain an embedded
      derivative, provides additional guidance on the applicability of SFAS 133 and
      SFAS 140 to certain financial instruments and subordinated concentrations of
      credit risk. SFAS 155 is effective for the first fiscal year that begins after
      September 15, 2006. This did not have any impact on our consolidated financial
      statements.





In
      September 2006, the Financial Accounting Standards Board issued Statement of
      Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157),
      which provides expanded guidance for using fair value to measure assets and
      liabilities. SFAS 157 establishes a hierarchy for data used to value assets
      and
      liabilities, and requires additional disclosures about the extent to which
      a
      company measures assets and liabilities at fair value, the information used
      to
      measure fair value, and the effect of fair value measurements on earnings.
      Implementation of SFAS 157 is required on January 1, 2008. We are currently
      evaluating the impact of adopting SFAS 157 on the financial statements.





On
      September 29, 2006, the Financial Accounting Standards Board issued Statement
      of
      Financial Accounting Standards No. 158 “Employers’ Accounting for Defined
      Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements
      No. 87, 88, 106, and 132(r)” (SFAS 158). The Statement requires the recognition
      of the overfunded or underfunded status of a defined benefit postretirement
      plan
      as an asset or liability on the balance sheet and the recognition of the changes
      of the funded status in the year in which the changes occur through
      comprehensive income. Implementation of SFAS 158 is required as of the end
      of
      the fiscal year ending after December 15, 2006. The adoption of SFAS 158 did
      not
      have an impact on our financial statements because we do not currently have
      any
      defined benefit pension or other postretirement benefit plans.





On
      September 13, 2006 the Securities Exchange Commission (SEC) issued Staff
      Accounting Bulletin No. 108 (“SAB 108”), which establishes an approach that
      requires quantification of financial statement errors based on the effects
      of
      the error on each of our financial statements and the related disclosures.
      SAB
      108 requires the use of a balance sheet and an income statement approach to
      evaluate whether either of these approaches results in quantifying a
      misstatement that, when all relevant quantitative and qualitative factors are
      considered, is material. This did not have any impact on our consolidated
      financial statements.





In
      July
      2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in
      Income Taxes--an Interpretation of FASB Statement 109” (FIN 48), which clarifies
      the accounting for uncertainty in tax positions taken or expected to be taken
      in
      a tax return, including issues relating to financial statement recognition
      and
      measurement. FIN 48 provides that the tax effects from an uncertain tax position
      can be recognized in the financial statements only if the position is
“more-likely-than-not” of being sustained if the position were to be challenged
      by a taxing authority. The assessment of the tax position is based solely on
      the
      technical merits of the position, without regard to the likelihood that the
      tax
      position may be challenged. If an uncertain tax position meets the
“more-likely-than-not” threshold, the largest amount of tax benefit that is
      greater than 50 percent likely of being recognized upon ultimate settlement
      with
      the taxing authority, is recorded. The provisions of FIN 48 are effective for
      fiscal years beginning after December 15, 2006, with the cumulative effect
      of
      the change in accounting principle recorded as an adjustment to opening retained
      earnings. We expect to recognize a liability of approximately $3.3 million
      as a
      result of adopting FIN 48.


55
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Effective
      January 1, 2006, Brigham adopted the provisions of SFAS 123R for its stock
      based
      compensation plans. Brigham previously accounted for these plans under the
      recognition and measurement principles of APB 25 and related interpretations
      and
      disclosure requirements established by SFAS 123.





Under
      APB
      25, Brigham recognized stock based compensation using the intrinsic value
      method. The pro forma effects on net income due to stock based compensation
      were
      disclosed in the notes to the consolidated financial statements. SFAS 123R
      eliminates the use of APB 25 and the intrinsic value method of accounting,
      and
      requires companies to recognize the cost of employee services received in
      exchange for awards of equity instruments, based on the grant date fair value
      of
      those awards, in the financial statements over the requisite service
      period.





We
      adopted SFAS 123R using the modified prospective method. Under this transition
      method, compensation cost recognized includes the cost for all stock based
      compensation granted prior to, but not yet vested, as of January 1, 2006. This
      cost was based on the grant date fair value estimated in accordance with the
      original provisions of SFAS 123. The cost for all stock based awards granted
      subsequent to January 1, 2006, was based on the grant date fair value that
      was
      estimated in accordance with the provisions of SFAS 123R. The maximum
      contractual life of stock based awards is seven years and the historical
      forfeiture rate used to estimate forfeitures prospectively is 14.5%. At adoption
      of SFAS 123R, Brigham elected to amortize newly issued and existing graded
      awards on a straight-line basis over the requisite service period including
      estimates of pre-vesting forfeiture rates. If actual forfeitures differ from
      the
      estimates, additional adjustments to compensation expense may be required in
      future periods. Unearned stock compensation recorded under APB 25 of $2.3
      million was eliminated and additional paid-in capital was reduced by a like
      amount on the consolidated balance sheet and consolidated statements of
      stockholders’ equity, in accordance with SFAS 123R. Results for prior periods
      have not been restated.





The
      estimated fair value of the options granted during 2006 and prior periods was
      calculated using a Black Scholes option pricing model. The Black-Scholes model
      incorporates assumptions to value stock based awards. The risk-free rate of
      interest for periods within the contractual life of the option is based on
      a
      zero-coupon U.S. government instrument over the contractual term of the equity
      instrument. Expected volatility is based on the historical volatility of
      Brigham’s stock for an equal period of the expected term. The expected life is
      determined using the contractual life and vesting term in accordance with the
      guidance in Staff Accounting Bulletin No. 107 for using the “simplified” method
      for “plain vanilla” options.





In
      November 2005, the FASB issued FASB Staff Position No. FAS 123R-3, “Transition
      Election Related to Accounting for the Tax Effects of Share-Based Payment
      Awards.” Brigham elected to adopt the alternative transition method provided in
      the FASB Staff Position for calculating the tax effects of stock based
      compensation pursuant to SFAS 123R. The alternative transition method includes
      simplified methods to establish the beginning balance of the APIC pool related
      to the tax effects of employee stock based compensation, and to determine the
      subsequent impact on the APIC pool and Consolidated Statements of Cash Flows
      of
      the tax effects of employee stock based compensation awards that are outstanding
      upon adoption of SFAS 123R.





Prior
      to
      the adoption of SFAS 123R, we presented all tax benefits of deductions resulting
      from the exercise of stock options as operating cash flows in the Consolidated
      Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the
      tax
      deductions in excess of the compensation cost recognized for those options
      (excess tax benefits) to be classified as financing cash flows. We did not
      have
      any excess tax benefits during 2006.





**Other
      Matters**





***Commodity
      Prices***





Changes
      in commodity prices significantly affect our capital resources, liquidity and
      operating results. Price changes directly affect revenues and can indirectly
      impact expected production by changing the amount of capital available we have
      to reinvest in our exploration and development activities. Commodity prices
      are
      impacted by many factors that are outside of our control. Over the past few
      of
      years, commodity prices have been highly volatile. We expect that commodity
      prices will continue to fluctuate significantly in the future. As a result,
      we
      cannot accurately predict future oil and natural gas prices, and therefore,
      we
      cannot determine what effect increases or decreases will have on our capital
      program, production volumes and future revenues.


56
 *Table
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The
      prices we receive for our oil production are based on global market conditions.
      Our average pre-hedged sales price for oil in 2006 was $64.04 per barrel, which
      was 17% higher than the prices we received in 2005. Significant factors that
      will impact 2007 oil prices include developments in Iraq, Iran and other Middle
      East countries and the extent to which members of the Organization of Petroleum
      Exporting Countries and other oil exporting nations are able to manage oil
      supply through export quotas.





Natural
      gas prices are primarily driven by North American market forces. Factors that
      can affect the price of natural gas are changes in market demands, overall
      economic activity, weather, pipeline capacity constraints, inventory storage
      levels, basis differentials and other factors. Over the past three years natural
      gas prices have been volatile. Our average pre-hedged sales price for natural
      gas in 2006 was $6.74 per Mcf, which was 19% lower than the price we received
      in
      2005. The decrease in North American gas prices in 2006 was in response to
      weak
      supply and demand fundamentals. Natural gas prices for 2007 will depend on
      the
      balance between North American supply and demand.





***Derivative
      Instruments***





Our
      results of operations and operating cash flow are impacted by changes in market
      prices for oil and gas. We believe the use of derivative instruments, although
      not free of risk, allows us to reduce our exposure to oil and natural gas sales
      price fluctuations and thereby achieve a more predictable cash flow. While
      the
      use of derivative instruments limits the downside risk of adverse price
      movements, their use may also limit future revenues from favorable price
      movements. Moreover, our derivative contracts generally do not apply to all
      of
      our production and thus provide only partial price protection against declines
      in commodity prices. We expect that the amount of our derivative contracts
      will
      vary from time to time. See “Item 1A. Risk Factors — Our hedging activities may
      prevent us from benefiting from price increases and may expose us to other
      risks” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk
      - Derivative Instruments and Hedging Activities.”





***Effects
      of Inflation and Changes in Prices***





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





***Environmental
      and Other Regulatory Matters***





Our
      business is subject to certain federal, state and local laws and regulations
      relating to the exploration for and the development, production and marketing
      of
      oil and natural gas, as well as environmental and safety matters. Many of these
      laws and regulations have become more stringent in recent years, often imposing
      greater liability on a larger number of potentially responsible parties.
      Although we believe that we are in substantial compliance with all applicable
      laws and regulations, the requirements imposed by laws and regulations are
      frequently changed and subject to interpretation, and we cannot predict the
      ultimate cost of compliance with these requirements or their effect on our
      operations. Any suspensions, terminations or inability to meet applicable
      bonding requirements could materially adversely affect our financial condition
      and operations. Although significant expenditures may be required to comply
      with
      governmental laws and regulations applicable to us, compliance has not had
      a
      material adverse effect on our earnings or competitive position. Future
      regulations may add to the cost of, or significantly limit, drilling activity.
      See “Item 1A. Risk Factors — We are subject to various governmental regulations
      and environmental risks that may cause us to incur substantial costs” and “Item
      1. Business — Governmental Regulation” and “Item 1. Business — Environmental
      Matters.”





**Item
      7A.** ***Quantitative
      and Qualitative Disclosures About Market
      Risk***





**Management
      Opinion Concerning Derivative Instruments**





We
      use
      derivative instruments to manage exposure to commodity prices and interest
      rate
      risks. Our objectives for holding derivatives are to achieve a relatively
      consistent level of cash flow to support a portion of our planned capital
      spending. Our use of derivative instruments for hedging activities could
      materially affect our results of operations in particular quarterly or annual
      periods since such instruments can limit our ability to benefit from favorable
      price movements. We do not enter into derivative instruments for trading
      purposes.


57
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          of Contents*


**Fair
      Value of Derivative Contracts**





Prior
      to
      October 1, 2006, our derivatives were classified as either cash flow hedges
      or
      were undesignated. Cash flow hedges were valued quarterly and adjustments to
      the
      fair value of the contract prior to settlement were recorded to stockholders’
equity in other comprehensive income. Upon settlement, the gain (loss) on the
      cash flow hedge was recorded to revenue. Any unrealized gains (losses) for
      the
      ineffective portion of cash flow hedges were recorded to other income (expense).
      For undesignated hedges, both the changes in the fair market value of
      derivatives prior to settlement and the gains (losses) on the settlement of
      contracts were recorded to other income (expense).





On
      October 1, 2006, we de-designated all cash flow hedges. In addition, all future
      hedges will be undesignated. At
      the
      end of each quarter, our derivatives will be marked-to-market to reflect the
      current fair value and both derivative settlements and unrealized gains (losses)
      will be recorded on the consolidated statement of operations. W e
      elected
      to include all derivative settlement and unrealized gains (losses) within
      revenue and will therefore no longer included those amounts within other income
      (expense).





The
      fair
      values of our derivative contracts are determined based on counterparties’
estimates and valuation models. We did not change our valuation methodology
      during the year ended December 31, 2006. The following table reconciles the
      changes that occurred in the fair values of our open derivative contracts during
      2006.








**Fair
                Value of Undesignated Derivative****Contracts**
            
            **Fair
                Value of Cash Flow Derivative****Contracts**
            
            ******Total****(In
                thousands)**Estimated
                fair value of open contracts at December 31, 2005
            
            $
            (125
            )
            $
            (1,295
            )
            $
            (1,420
            )**Changes
                in fair values of derivative contracts:**Natural
                gas collars
            
            $
            636
            
            $
            11,277
            
            $
            11,913Oil
                collars
            
            
            43
            
            
            370
            
            
            413Interest
                rate swap
            
            
            —
            
            
            (642
            )
            
            (642
            )De-designation
                of cash flow hedges
            
            
            6,720
            
            
            (6,720
            )
            
            —**Settlements
                of derivative contracts that were open at December 31,
                2005:**Natural
                gas collars
            
            $
            (699
            )
            $
            (3,040
            )
            $
            (3,739
            )Oil
                collars
            
            
            —
            
            
            50
            
            
            50Interest
                rate swap
            
            
            —
            
            
            —
            
            
            —Estimated
                fair value of open contracts at December 31, 2006
            
            $
            6,575
            
            $
            —
            
            $
            6,575





Based
      upon the market prices at December 31, 2006, we expect to transfer approximately
      $891,060 of the gain included on our balance sheet in accumulated other
      comprehensive income (loss) to earnings during the next twelve months when
      transactions actually occur.





**Derivative
      Instruments and Hedging Activities**





Our
      primary commodity market risk exposure is to changes in the prices that we
      receive for our oil and natural gas production. The market prices for oil and
      natural gas have been highly volatile and are likely to continue to be highly
      volatile in the future. As such, we employ established policies and procedures
      to manage our exposure to fluctuations in the sales prices we receive for our
      oil and natural gas production via using derivative instruments.





While
      the
      use of derivative instruments limits the downside risk of adverse price
      movements, their use may also limit future revenues from favorable price
      movements. Moreover, our derivative contracts generally do not apply to all
      of
      our production and thus provide only partial price protection against declines
      in commodity prices. We expect that the amount of our derivative contracts
      will
      vary from time to time.





During
      2006, we were party to natural gas costless collars, natural gas three-way
      costless collars, natural gas basis swaps, oil costless collars, oil three-way
      costless collars and interest rate swaps. See “Notes to the Consolidated
      Financial Statements — Note 11” for additional information regarding our
      derivative contracts.


58
 *Table
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We
      use
      costless collars to establish floor (purchased put option) and ceiling price
      (written call option) on our anticipated future oil and natural gas production.
      We receive no net premiums when we enter into these option arrangements. These
      contracts are settled monthly. When the settlement price for a period is above
      the ceiling price (written call option), we pay our counterparty. When the
      settlement price for a period is below the floor price (purchased put option),
      our counterparty is required to pay us. Prior to October 1, 2006, we designated
      these instruments as cash flow hedges as they were designed to achieve a more
      predictable cash flow, as well as reduce our exposure to price
      volatility.





A
      three-way costless collar consists of a costless collar (purchased put option
      and written call option) plus a put (written put) sold by us with a price below
      the floor price (purchased put option) of the costless collar. We receive no
      net
      premiums when we enter into these option arrangements. These contracts are
      settled monthly. The written put requires us to make a payment to our
      counterparty if the settlement price for a period is below the written put
      price. Combining the costless collar (purchased put option and written call
      option) with the written put results in us being entitled to a net payment
      equal
      to the difference between the floor price (purchased put option) of the costless
      collar and the written put price if the settlement price is equal to or less
      than the written put price. If the settlement price is greater than the written
      put price, the result is the same as it would have been with a costless collar.
      This strategy enables us to increase the floor and the ceiling price of the
      collar beyond the range of a traditional costless collar while offsetting the
      associated cost with the sale of the written put. Prior to October 1, 2006,
      the
      costless collar portion of the three-way was designated as a cash flow hedge
      while the written put was undesignated.





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





The
      following table reflects our open derivative contracts at December 31, 2006,
      the
      associated volumes and the corresponding weighted average NYMEX reference
      price.





**Settlement
                Period**
            
            **Natural
                Gas****(MMbtu)**
            
            **Purchased
                Put****(Nymex)**
            
            **Written
                Call****(Nymex)*****Natural
                Gas Costless Collars***01/01/07
                - 01/31/07
            
            
            180,000
            
            $
            8.00
            
            $
            23.2501/01/07
                - 01/31/07
            
            
            70,000
            
            $
            6.50
            
            $
            9.7501/01/07
                - 03/31/07
            
            
            270,000
            
            $
            8.00
            
            $
            21.2001/01/07
                - 03/31/07
            
            
            225,000
            
            $
            8.00
            
            $
            15.7501/01/07
                - 03/31/07
            
            
            150,000
            
            $
            7.25
            
            $
            9.6501/01/07
                - 03/31/07
            
            
            90,000
            
            $
            7.50
            
            $
            10.0001/01/07
                - 03/31/07
            
            
            300,000
            
            $
            7.25
            
            $
            10.0002/01/07
                - 02/28/07
            
            
            60,000
            
            $
            6.50
            
            $
            9.7502/01/07
                - 03/31/07
            
            
            300,000
            
            $
            8.00
            
            $
            25.7503/01/07
                - 03/31/07
            
            
            40,000
            
            $
            6.50
            
            $
            9.7504/01/07
                - 04/30/07
            
            
            60,000
            
            $
            7.00
            
            $
            10.0004/01/07
                - 10/31/07
            
            
            280,000
            
            $
            7.00
            
            $
            15.4504/01/07
                - 10/31/07
            
            
            280,000
            
            $
            7.25
            
            $
            15.2504/01/07
                - 10/31/07
            
            
            280,000
            
            $
            7.00
            
            $
            14.8504/01/07
                - 10/31/07
            
            
            700,000
            
            $
            7.50
            
            $
            11.0004/01/07
                - 10/31/07
            
            
            350,000
            
            $
            7.00
            
            $
            11.6004/01/07
                - 10/31/07
            
            
            350,000
            
            $
            7.00
            
            $
            9.1004/01/07
                - 10/31/07
            
            
            350,000
            
            $
            7.25
            
            $
            9.6005/01/07
                - 05/31/07
            
            
            50,000
            
            $
            7.00
            
            $
            10.0006/01/07
                - 06/30/07
            
            
            40,000
            
            $
            7.00
            
            $
            10.0007/01/07
                - 07/31/07
            
            
            30,000
            
            $
            7.00
            
            $
            10.0008/01/07
                - 08/31/07
            
            
            20,000
            
            $
            7.00
            
            $
            10.0011/01/07
                - 03/31/08
            
            
            250,000
            
            $
            8.00
            
            $
            13.4011/01/07
                - 03/31/08
            
            
            300,000
            
            $
            8.85
            
            $
            15.0011/01/07
                - 03/31/08
            
            
            300,000
            
            $
            9.30
            
            $
            15.0011/01/07
                - 03/31/08
            
            
            500,000
            
            $
            7.50
            
            $
            13.30




59
 *Table
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**Settlement
                Period**
            
            **Crude**
              **Oil****(Bbls)**
            
            **Purchased
                Put****(Nymex)**
            
            **Written
                Call**
              **(Nymex)*****Oil
                Costless Collars***01/01/07
                - 01/31/07
            
            
            5,000
            
            $
            60.00
            
            $
            74.7501/01/07
                - 02/28/07
            
            
            5,000
            
            $
            70.00
            
            $
            85.2001/01/07
                - 03/31/07
            
            
            21,000
            
            $
            55.00
            
            $
            74.5001/01/07
                - 03/31/07
            
            
            24,000
            
            $
            50.00
            
            $
            78.2501/01/07
                - 06/30/07
            
            
            24,000
            
            $
            59.00
            
            $
            90.0001/01/07
                - 12/31/07
            
            
            12,000
            
            $
            55.00
            
            $
            79.0002/01/07
                - 04/30/07
            
            
            9,000
            
            $
            60.00
            
            $
            74.7504/01/07
                - 05/31/07
            
            
            12,000
            
            $
            55.00
            
            $
            80.3004/01/07
                - 09/30/07
            
            
            30,000
            
            $
            50.00
            
            $
            81.5004/01/07
                - 09/30/07
            
            
            12,000
            
            $
            56.00
            
            $
            92.5005/01/07
                - 04/30/08
            
            
            24,000
            
            $
            60.00
            
            $
            74.7506/01/07
                - 07/31/07
            
            
            8,000
            
            $
            55.00
            
            $
            80.3006/01/07
                - 08/31/07
            
            
            6,000
            
            $
            65.00
            
            $
            80.0007/01/07
                - 10/31/07
            
            
            10,000
            
            $
            58.00
            
            $
            90.5008/01/07
                - 10/31/07
            
            
            9,000
            
            $
            55.00
            
            $
            80.3010/01/07
                - 12/31/07
            
            
            9,000
            
            $
            59.20
            
            $
            90.0010/01/07
                - 03/31/08
            
            
            18,000
            
            $
            56.00
            
            $
            89.9510/01/07
                - 03/31/08
            
            
            6,000
            
            $
            65.00
            
            $
            80.2511/01/07
                - 12/31/07
            
            
            4,000
            
            $
            55.00
            
            $
            80.3011/01/07
                - 03/31/08
            
            
            10,000
            
            $
            68.40
            
            $
            90.0001/01/08
                - 03/31/08
            
            
            7,500
            
            $
            57.60
            
            $
            90.0004/01/08
                - 10/31/08
            
            
            21,000
            
            $
            65.70
            
            $
            90.00








The
      following table reflects commodity derivative contracts entered into subsequent
      to December 31, 2006, the associated volumes and the corresponding weighted
      average NYMEX reference price.





**Settlement
                Period**
            
            **Natural
                Gas**
              **(MMbtu)**
            
            **Purchased
                Put****(Nymex)**
            
            **Written
                Call**
              **(Nymex)*****Natural
                Gas Costless Collars***03/01/07
                - 03/31/07
            
            
            120,000
            
            $
            7.00
            
            $
            8.0004/01/07
                - 04/30/07
            
            
            150,000
            
            $
            7.00
            
            $
            8.0005/01/07
                - 05/31/07
            
            
            130,000
            
            $
            7.00
            
            $
            8.0006/01/07
                - 06/30/07
            
            
            100,000
            
            $
            7.00
            
            $
            8.0007/01/07
                - 07/31/07
            
            
            80,000
            
            $
            7.00
            
            $
            8.0008/01/07
                - 08/31/07
            
            
            60,000
            
            $
            7.00
            
            $
            8.0009/01/07
                - 09/30/07
            
            
            40,000
            
            $
            7.00
            
            $
            9.3510/01/07
                - 10/31/07
            
            
            30,000
            
            $
            7.00
            
            $
            9.3511/01/07
                - 11/30/07
            
            
            50,000
            
            $
            8.00
            
            $
            10.2012/01/07
                - 12/31/07
            
            
            40,000
            
            $
            8.00
            
            $
            10.2001/01/08
                - 01/31/08
            
            
            30,000
            
            $
            8.00
            
            $
            10.2002/01/08
                - 02/29/08
            
            
            20,000
            
            $
            8.00
            
            $
            10.2003/01/08
                - 03/31/08
            
            
            10,000
            
            $
            8.00
            
            $
            10.20





Starting
      October 1, 2006, Brigham de-designated all derivatives that were previously
      designated as cash flow hedges and will mark-to-market all derivatives in future
      periods. At the end of each period, the derivatives will be marked-to-market
      to
      reflect the current fair value and the realized and unrealized gains or losses
      will be recorded on the consolidated statement of operations rather than as
      a
      component of other comprehensive income.


60
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          of Contents*


**Interest
      Rate Risk**





At
      December 31, 2006, we had $159.4 million of debt, of which $133.5 million was
      fixed rate debt. Our fixed rate debt consists of our $123.4 million Senior
      Notes
      and $10.1 million in Series A preferred stock. The remaining $25.9 million
      of
      debt we had outstanding at December 31, 2006, was floating rate debt, which
      consisted of debt outstanding under our senior credit agreement.





The
      interest rate that we pay on amounts borrowed under our senior credit agreement
      is derived from the Eurodollar rate and a margin that is applied to the
      Eurodollar rate. This calculation was performed using the one month Eurodollar
      rate on December 29, 2006 which was 5.32%. The margin that we pay is based
      upon
      the percentage of our available borrowing base that we utilize at the beginning
      of the quarter. At December 31, 2006, the borrowing base for our senior credit
      agreement was $110 million. Since the amount that we had borrowed under our
      senior credit at December 31, 2006 was $25.9 million, we were utilizing
      approximately 24% of our available borrowing base. At this level of borrowing,
      our senior credit agreement requires us to pay a margin of 1.25%, thus the
      interest rate that we would be required to pay on the amounts borrowed under
      our
      senior credit facility would be 6.57%. A 10% increase in the Eurodollar rate
      would equal approximately 53 basis points. Such an increase in the Eurodollar
      rate would change our annual interest expense by approximately $138,000,
      assuming borrowed amounts under our senior credit facility remain at $25.9
      million.





We
      are
      required to pay the dividends on our Series A preferred stock in cash at a
      rate
      of 6% per annum. The fair value of the Series A mandatorily redeemable preferred
      stock at December 31, 2006 was approximately $8.8 million.





**Item
      8.** ***Financial Statements and Supplementary
      Data***





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





**Item
      9.** ***Changes
      in and Disagreements with Accountants on Accounting and
      Financial Disclosure***





On
      June
      15, 2006, our audit committee engaged KPMG LLP as our independent registered
      public accounting firm for the fiscal year ending December 31, 2006 and
      dismissed PricewaterhouseCoopers LLP, our previous independent registered public
      accounting firm. Information regarding this change in independent auditors
      was
      included in our report on Form 8-K dated June 15, 2006. There have been no
      other
      changes in accountants nor any disagreements with accountants.





During
      the fiscal years ended December 31, 2005 and 2004, and through June 15, 2006,
      there were no disagreements with PricewaterhouseCoopers LLP on any matter of
      accounting principles or practices, financial statement disclosure, or auditing
      scope or procedures, which, if not resolved to their satisfaction, would have
      caused them to make reference thereto in its reports on the consolidated
      financial statements for such years.





The
      PricewaterhouseCoopers LLP reports on our consolidated financial statements
      and
      our subsidiaries as of and for the years ended December 31, 2005 and 2004,
      did
      not contain an adverse opinion or disclaimer of opinion, nor were they qualified
      or modified as to uncertainty, audit scope, or accounting
      principles.





**Item
      9A.** ***Controls
      and Procedures***





**Conclusion
      Regarding the Effectiveness of Disclosure Controls and
      Procedures**





As
      of
      December 31, 2006, our management, including our principal executive officer
      and
      principal financial officer, has evaluated the effectiveness of the design
      and
      operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
      under the Securities Exchange Act of 1934. There are inherent limitations to
      the
      effectiveness of any system of disclosure controls and procedures, including
      the
      possibility of human error and the circumvention or overriding of the controls
      and procedures. Accordingly, even effective disclosure controls and procedures
      can only provide reasonable assurance of achieving their control objectives.
      Based upon and as of the date of the evaluation, our principal executive officer
      and our principal financial officer concluded that the design and operation
      of
      our disclosure controls and procedures were effective at a reasonable assurance
      level.


61
 *Table
          of Contents*


**Management’s
      Report on Internal Control over Financial Reporting**





Our
      management is responsible for establishing and maintaining adequate internal
      control over financial reporting, as such term is defined in Exchange Act Rule
      13a-15(f). Because of its inherent limitations, internal control over financial
      reporting may not prevent or detect misstatements. Also, projections of any
      evaluation of effectiveness to future periods are subject to the risk that
      controls may become inadequate because of changes in conditions, or that the
      degree of compliance with the policies or procedures may deteriorate. Under
      the
      supervision and with the participation of our management, including our
      principal executive officer and principal financial officer, we conducted an
      evaluation of the effectiveness of our internal control over financial reporting
      based on the framework in *Internal
      Control — Integrated Framework* issued
      by
      the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
      Based on our evaluation under the framework in *Internal
      Control — Integrated Framework* issued
      by
      the COSO, our management concluded that our internal control over financial
      reporting was effective as of December 31, 2006.





Our
      management’s assessment of the effectiveness of our internal control over
      financial reporting as of December 31, 2006 has been audited by KPMG LLP, an
      independent registered public accounting firm, as stated in their report which
      is included herein.





**Changes
      in Internal Control over Financial Reporting**





There
      has
      been no change in our internal control over financial reporting during the
      fourth quarter of 2006 that has materially affected, or is reasonably likely
      to
      materially affect, our internal control over financial reporting.





**Item
      9B.** ***Other
      Information***





None.


62
 *Table
          of Contents*


**PART
      III**





**Item
      10.** ***Directors, Executive Officers and Corporate
      Governance***





The
      information required by this item is incorporated by reference to information
      under the caption “Proposal One — Election of Directors”, the information under
      the caption “Section 16(a) Beneficial Ownership Reporting Compliance” and the
      information under the caption “Corporate Governance — Code of Business Conducted
      and Ethics” in our 2007 Proxy Statement for our annual meeting of stockholders
      to be held on Thursday, May 31, 2007. The 2007 Proxy Statement will be filed
      with the Securities and Exchange Commission not later than 120 days subsequent
      to December 31, 2006.





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





**Item
      11.** ***Executive Compensation***





The
      information required by this item is incorporated herein by reference to the
      2007 Proxy Statement, which will be filed with the Securities and Exchange
      Commission not later than 120 days subsequent to December 31, 2006.





**Item
      12.** ***Security Ownership of Certain Beneficial Owners and Management
      and Related Stockholder Matters***





The
      information required by this item is incorporated herein by reference to the
      2007 Proxy Statement, which will be filed with the Securities and Exchange
      Commission not later than 120 days subsequent to December 31, 2006. See “Item 5.
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities,” which sets forth certain information with
      respect to our equity compensation plans.





**Item
      13.** ***Certain Relationships and Related Transactions, and Director
      Independence***





The
      information required by this item is incorporated herein by reference to the
      2007 Proxy Statement, which will be filed with the Securities and Exchange
      Commission not later than 120 days subsequent to December 31, 2006.





**Item
      14.** ***Principal Accounting Fees and Services***





The
      information required by this item is incorporated herein by reference to the
      2007 Proxy Statement, which will be filed with the Securities and Exchange
      Commission not later than 120 days subsequent to December 31, 2006.





**PART
      IV**





**Item
      15.** ***Exhibits, Financial Statement
      Schedules***





(a)
            1.
                Consolidated Financial Statements: See Index to Financial Statements
                on
                page F-1.





2.
      No
      schedules are required.





3.
      Exhibits:


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


63
 *Table
          of Contents*


**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. The definitions of proved developed
      reserves, proved reserves and proved undeveloped reserves have been abbreviated
      from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation
      S-X.





*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.





*Bbl.* One
      stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference
      to
      oil or other liquid hydrocarbons.





*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 or natural gas liquids.





*Completion.* The
      installation of permanent equipment for the production of oil or natural gas.
      Completion of the well does not necessarily mean the well will be
      profitable.





*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.





*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.





*Fault.* A break
      in the rocks along which there has been movement of one side relative to the
      other side.





*Fault
      Block.* A body
      of rocks bounded by one or more faults.





*Gross
      Acres or Gross Wells.* The
      total acres or wells, as the case may be, in which we have a working
      interest.





*Lease
      Operating Expenses.* The
      expenses, usually recurring, which pay for operating the wells and equipment
      on
      a producing lease.





*MBbl.* One
      thousand barrels of oil or other liquid hydrocarbons.





*Mcf.* One
      thousand cubic feet of natural gas.





*MMBbl.* One
      million barrels of oil or other liquid hydrocarbons.





*Mcfe.* One
      thousand cubic feet of natural gas equivalents.





*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.


64
 *Table
          of Contents*


*MMcfe/d.* MMcfe
      per day.





*Net
      Acres or Net Wells.* Gross
      acres or wells multiplied, in each case, by the percentage working interest
      we
      own.





*Net
      Production.* Production that we own 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.





*Pay.* The
      vertical thickness of an oil and gas producing zone. Pay can be measured as
      either gross pay, including non-productive zones or net pay, including only
      zones that appear to be productive based upon logs and test data.





*Pre-tax
      PV10%.* The
      pre-tax present value of estimated future revenues to be generated from the
      production of proved reserves calculated in accordance with Securities and
      Exchange Commission guidelines, net of estimated production and future
      development costs, using prices and costs as of the date of estimation without
      future escalation, without giving effect to non-property related expenses such
      as general and administrative expenses, debt service and depreciation, depletion
      and amortization, and discounted using an annual discount rate of
      10%.





*Proved
      Developed Reserves.* Reserves
      that can be expected to be recovered through existing wells with existing
      equipment and operating methods.





*Proved
      Reserves.* The
      estimated quantities of crude oil, natural gas and natural gas liquids which
      geological and engineering data demonstrate with reasonable certainty to be
      recoverable in future years from known reservoirs under existing economic and
      operating conditions.





*Proved
      Undeveloped Reserves.* Reserves
      that are expected to be recovered from new wells on undrilled acreage or from
      existing wells where a relatively major expenditure is required for
      recompletion.





*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
      after-tax present value of estimated future revenues to be generated from the
      production of proved reserves calculated in accordance with Securities and
      Exchange Commission 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%.





*Trend.* A
      geographical area that has been known to contain certain types of combinations
      of reservoir rock, sealing rock and trap types containing commercial amounts
      of
      hydrocarbons.





*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.


65
 *Table
          of Contents*


**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 6, 2007.





BRIGHAM
                EXPLORATION COMPANYBy
            /s/
                BEN M. BRIGHAMBen
                M. Brigham*Chief
                Executive Officer,**President
                and Chairman of the Board*





Pursuant
      to the requirements of the Securities Exchange Act of 1934, the following
      persons on behalf of the Registrant and in the capacity indicated have signed
      this report below as of March 6, 2007.





/s/
                BEN M. BRIGHAM
            
            Chief
                Executive Officer, President and Chairman ofBen
                M. Brigham
            
            the
                Board (Principal Executive Officer)/s/
                EUGENE B. SHEPHERD, JR.
            
            Executive
                Vice President and Chief FinancialEugene
                B. Shepherd, Jr.
            
            Officer
                (Principal Financial and Accounting Officer)/s/
                DAVID T. BRIGHAM
            
            Executive
                Vice President — Land andDavid
                T. Brigham
            
            Administration
                and Director/s/
                HAROLD D. CARTER
            
            DirectorHarold
                D. Carter/s/
                STEPHEN C. HURLEY
            
            DirectorStephen
                C. Hurley/s/
                STEPHEN P. REYNOLDS
            
            DirectorStephen
                P. Reynolds/s/
                HOBART A. SMITH
            
            DirectorHobart
                A. Smith/s/
                STEVEN A. WEBSTER
            
            DirectorSteven
                A. Webster/s/
                R. GRAHAM WHALING
            
            DirectorR.
                Graham Whaling




66
 *Table
          of Contents*


**BRIGHAM
      EXPLORATION COMPANY**





**INDEX
      TO FINANCIAL STATEMENTS**








**Page**Reports
                of Independent Registered Public Accounting Firms
            F-2Consolidated
                Balance Sheets as of December 31, 2006 and 2005
            F-5Consolidated
                Statements of Operations for the Years Ended December 31, 2006, 2005
                and
                2004
            F-6Consolidated
                Statements of Stockholders’ Equity for the Years Ended December 31, 2006,
                2005 and 2004
            F-7Consolidated
                Statements of Cash Flows for the Years Ended December 31, 2006, 2005
                and
                2004
            F-8Notes
                to the Consolidated Financial Statements
            F-9Supplemental
                Oil and Gas Information (Unaudited)
            F-28Supplemental
                Quarterly Financial Information (Unaudited)
            F-31




F-1
 *Table
          of Contents*


**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**





The
      Board
      of Directors and Stockholders


Brigham
      Exploration Company:







We
      have
      audited the accompanying consolidated balance sheet of Brigham Exploration
      Company and subsidiaries as of December 31, 2006, and the related consolidated
      statements of operations, stockholders’ equity, and cash flows for the year then
      ended. These consolidated financial statements are the responsibility of the
      Company’s management. Our responsibility is to express an opinion on these
      consolidated financial statements based on our audits.




We
      conducted our audit in accordance with the standards of the Public Company
      Accounting Oversight Board (United States). Those standards 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. An audit also includes assessing the accounting principles used
      and
      significant estimates made by management, as well as evaluating the overall
      financial statement presentation. We believe that our audit provides a
      reasonable basis for our opinion.




In
      our
      opinion, the consolidated financial statements referred to above present fairly,
      in all material respects, the financial position of Brigham Exploration Company
      and subsidiaries as of December 31, 2006, and the results of their operations
      and their cash flows for the year then ended, in conformity with U.S. generally
      accepted accounting principles.




As
      discussed in note 1 to the consolidated financial statements, the Company
      changed its method of accounting for share-based payments effective January
      1,
      2006 in connection with the adoption of Statement of Financial Accounting
      Standards No. 123R, Share-Based Payment.




We
      also
      have audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the effectiveness of Brigham Exploration
      Company’s internal control over financial reporting as of December 31, 2006,
      based on criteria established in *Internal Control—Integrated Framework* issued
      by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
      and our report dated March 6, 2007 expressed an unqualified opinion on
      management’s assessment of, and the effective operation of, internal control
      over financial reporting.




KPMG
      LLP




Dallas,
      Texas


March
      6,
      2007


F-2
 *Table
          of Contents*


**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**





The
      Board
      of Directors and Stockholders


Brigham
      Exploration Company:





We
      have
      audited management's assessment, included in Management’s Report on Internal
      Control over Financial Reporting appearing under Item 9A *,* that
      Brigham Exploration Company maintained effective internal control over financial
      reporting as of December 31, 2006, based on criteria established in *Internal Control—Integrated Framework* issued
      by the Committee of Sponsoring Organizations of the Treadway Commission
      (COSO *).* Brigham
      Exploration Company's management is responsible for maintaining effective
      internal control over financial reporting and for its assessment of the
      effectiveness of internal control over financial reporting. Our responsibility
      is to express an opinion on management's assessment and an opinion on the
      effectiveness of the Company’s internal control over financial reporting based
      on our audit.





We
      conducted our audit in accordance with the standards of the Public Company
      Accounting Oversight Board (United States). Those standards require that we
      plan
      and perform the audit to obtain reasonable assurance about whether effective
      internal control over financial reporting was maintained in all material
      respects. Our audit included obtaining an understanding of internal control
      over
      financial reporting, evaluating management's assessment, testing and evaluating
      the design and operating effectiveness of internal control, and performing
      such
      other procedures as we considered necessary in the circumstances. We believe
      that our audit provides a reasonable basis for our opinion.





A
      company's internal control over financial reporting is a process designed to
      provide reasonable assurance regarding the reliability of financial reporting
      and the preparation of financial statements for external purposes in accordance
      with generally accepted accounting principles. A company's internal control
      over
      financial reporting includes those policies and procedures that (1) pertain
      to
      the maintenance of records that, in reasonable detail, accurately and fairly
      reflect the transactions and dispositions of the assets of the company; (2)
      provide reasonable assurance that transactions are recorded as necessary to
      permit preparation of financial statements in accordance with generally accepted
      accounting principles, and that receipts and expenditures of the company are
      being made only in accordance with authorizations of management and directors
      of
      the company; and (3) provide reasonable assurance regarding prevention or timely
      detection of unauthorized acquisition, use, or disposition of the company’s
      assets that could have a material effect on the financial
      statements.





Because
      of its inherent limitations, internal control over financial reporting may
      not
      prevent or detect misstatements. Also, projections of any evaluation of
      effectiveness to future periods are subject to the risk that controls may become
      inadequate because of changes in conditions, or that the degree of compliance
      with the policies or procedures may deteriorate.





In
      our
      opinion, management's assessment that Brigham Exploration Company maintained
      effective internal control over financial reporting as of December 31, 2006
      is
      fairly stated, in all material respects, based on criteria established
      in *Internal Control—Integrated Framework* issued
      by
      the Committee of Sponsoring Organizations of the Treadway Commission
      (COSO *).* Also,
      in
      our opinion, Brigham Exploration Company maintained, in all material respects,
      effective internal control over financial reporting as of December 31, 2006,
      based on criteria
      established in *Internal Control—Integrated Framework* issued
      by
      the Committee of
      Sponsoring Organizations of the Treadway Commission (COSO *).*





We
      also
      have audited, in accordance with the standards of the Public Company Accounting
      Oversight Board (United States), the consolidated balance sheet of Brigham
      Exploration Company and subsidiaries as of December 31, 2006, and the related
      consolidated statements of operations, stockholders’ equity, and cash flows for
      the year then ended, and our report dated March 6, 2007 expressed an unqualified
      opinion on those consolidated financial statements.




KPMG
      LLP





Dallas,
      Texas


March
      6,
      2007


F-3
 *Table
          of Contents*


**Report
      of Independent Registered Public Accounting Firm**





To
      the
      Board of Directors and Stockholders of Brigham Exploration Company:





In
      our
      opinion, the consolidated financial statements listed in the index appearing
      under Item 15(a)(1) present fairly, in all material respects, the financial
      position of Brigham Exploration Company and its subsidiaries at December 31,
      2005, and the results of their operations and their cash flows for each of
      the
      two years in the period ended December 31, 2005, in conformity with accounting
      principles generally accepted in the United States of America. These financial
      statements are the responsibility of the Company's management. Our
      responsibility is to express an opinion on these financial statements based
      on
      our audits. We conducted our audits of these statements in accordance with
      the
      standards of the Public Company Accounting Oversight Board (United States).
      Those standards require that we plan and perform the audit to obtain reasonable
      assurance about whether the financial statements are free of material
      misstatement. An audit includes examining, on a test basis, evidence supporting
      the amounts and disclosures in the financial statements, assessing the
      accounting principles used and significant estimates made by management, and
      evaluating the overall financial statement presentation. We believe that our
      audits provide a reasonable basis for our opinion.








s/s
      PricewaterhouseCoopers LLP





Houston,
      Texas


February
      27, 2006


F-4
 *Table
          of Contents*


**BRIGHAM
      EXPLORATION COMPANY**




**CONSOLIDATED
      BALANCE SHEETS**


**(In
      thousands, except share data)**





**December
                31,****2006**
            
            **2005****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            4,300
            
            $
            3,975Accounts
                receivable
            
            
            18,352
            
            
            22,825Deferred
                income taxes
            
            
            —
            
            
            482Derivative
                assets
            
            
            5,676
            
            
            224Other
                current assets
            
            
            2,390
            
            
            819Property
                held for sale
            
            
            500
            
            
            —Total
                current assets
            
            
            31,218
            
            
            28,325Oil
                and natural gas properties, using the full cost method of
                accountingProved
            
            
            631,339
            
            
            483,760Unproved
            
            
            75,051
            
            
            38,048Accumulated
                depletion
            
            
            (220,865
            )
            
            (174,479
            )485,525
            
            
            347,329Other
                property and equipment, net
            
            
            936
            
            
            1,027Deferred
                loan fees
            
            
            3,420
            
            
            2,174Other
                noncurrent assets
            
            
            1,488
            
            
            1,572Total
                assets
            
            $
            522,587
            
            $
            380,427**LIABILITIES
                AND STOCKHOLDERS’ EQUITY**Current
                liabilities:Accounts
                payable
            
            $
            19,464
            
            $
            12,128Royalties
                payable
            
            
            5,012
            
            
            6,886Accrued
                drilling costs
            
            
            23,310
            
            
            12,218Participant
                advances received
            
            
            3,990
            
            
            2,116Other
                current liabilities
            
            
            5,677
            
            
            4,119Total
                current liabilities
            
            
            57,453
            
            
            37,467Senior
                Notes
            
            
            123,434
            
            
            —Senior
                credit facility
            
            
            25,900
            
            
            33,100Senior
                subordinated notes
            
            
            —
            
            
            30,000Series
                A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated
                and
                redemption value, 2,250,000 shares authorized, 505,051 and 505,051
                shares
                issued and outstanding at December 31, 2006 and 2005,
                respectively
            
            
            10,101
            
            
            10,101Deferred
                income taxes
            
            
            34,609
            
            
            23,563Other
                noncurrent liabilities
            
            
            5,075
            
            
            4,556Commitments
                and contingencies (Note 10)Stockholders’
                equity:Common
                stock, $.01 par value, 90 million shares authorized, 45,090,398 and
                44,917,768 shares issued and 45,011,362 and 44,917,768 shares outstanding
                at December 31, 2006 and 2005, respectively
            
            
            451
            
            
            449Additional
                paid-in capital
            
            
            203,643
            
            
            202,127Treasury
                stock, at cost; 79,036 and zero shares at December 31, 2006 and 2005,
                respectively
            
            
            (662
            )
            
            —Unearned
                stock compensation
            
            
            —
            
            
            (2,299
            )Accumulated
                other comprehensive income (loss)
            
            
            1,006
            
            
            (426
            )Retained
                earnings
            
            
            61,577
            
            
            41,789Total
                stockholders’ equity
            
            
            266,015
            
            
            241,640Total
                liabilities and stockholders’ equity
            
            $
            522,587
            
            $
            380,427





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


F-5
 *Table
          of Contents*


**BRIGHAM
      EXPLORATION COMPANY**





**CONSOLIDATED
      STATEMENTS OF OPERATIONS**


**(In
      thousands, except per share data)**





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**Revenues:Oil
                and natural gas sales
            
            $
            102,835
            
            $
            96,820
            
            $
            71,713Gain
                (loss) on derivatives, net
            
            
            3,335
            
            
            —
            
            
            —Other
                revenue
            
            
            127
            
            
            220
            
            
            515106,297
            
            
            97,040
            
            
            72,228Costs
                and expenses:Lease
                operating
            
            
            10,701
            
            
            7,161
            
            
            6,173Production
                taxes
            
            
            4,021
            
            
            3,353
            
            
            3,107General
                and administrative
            
            
            7,887
            
            
            5,533
            
            
            5,392Depletion
                of oil and natural gas properties
            
            
            46,386
            
            
            33,268
            
            
            23,844Depreciation
                and amortization
            
            
            537
            
            
            762
            
            
            722Accretion
                of discount on asset retirement obligations
            
            
            317
            
            
            180
            
            
            15969,849
            
            
            50,257
            
            
            39,397Operating
                income
            
            
            36,448
            
            
            46,783
            
            
            32,831Other
                income (expense):Interest
                income
            
            
            1,207
            
            
            245
            
            
            84Interest
                expense, net
            
            
            (9,688
            )
            
            (3,980
            )
            
            (3,144
            )Other
                income (expense)
            
            
            4,565
            
            
            (576
            )
            
            742(3,916
            )
            
            (4,311
            )
            
            (2,318
            )Income
                before income taxes and cumulative effect of change in accounting
                principle
            
            
            32,532
            
            
            42,472
            
            
            30,513Income
                tax benefit (expense):Current
            
            
            —
            
            
            —
            
            
            —Deferred
            
            
            (12,744
            )
            
            (15,037
            )
            
            (10,863
            )(12,744
            )
            
            (15,037
            )
            
            (10,863
            )Net
                Income
            
            $
            19,788
            
            $
            27,435
            
            $
            19,650Net
                income (loss) per share available to common stockholders:Basic:Income
                before cumulative effect of change in accounting principle
            
            $
            0.44
            
            $
            0.65
            
            $
            0.49Diluted:Income
                before cumulative effect of change in accounting principle
            
            $
            0.43
            
            $
            0.63
            
            $
            0.47Weighted
                average commonshares
                outstanding:Basic
            
            
            45,017
            
            
            42,481
            
            
            40,445Diluted
            
            
            45,597
            
            
            43,728
            
            
            41,616





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


F-6
 *Table
          of Contents*


**BRIGHAM
      EXPLORATION COMPANY**





**CONSOLIDATED
      STATEMENTS OF STOCKHOLDERS’ EQUITY**


**(In
      thousands)**





**Accumulated****Other**
            
            **Retained****Common
                Stock**
            
            **Additional**
            
            
            
            **Unearned**
            
            **Comprehensive**
            
            **Earnings**
            
            **Total****Paid
                In**
            
            **Treasury**
            
            **Stock**
            
            **Income**
            
            **(Accumulated**
            
            **Stockholders'****Shares**
            
            **Amounts**
            
            **Capital**
            
            **Stock**
            
            **Compensation**
            
            **(Loss)**
            
            **Deficit)**
            
            **Equity**Balance,
                December 31, 2003
            
            
            40,247
            
            $
            402
            
            $
            151,263
            
            $
            (4,402
            )
            $
            (1,816
            )
            $
            (1,040
            )
            $
            (5,296
            )
            $
            139,111Net
                income
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            19,650
            
            
            19,650Unrealized
                gains on cash flow hedges
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            1,485
            
            
            —
            
            
            1,485Tax
                provisions related to cash flow hedges
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (290
            )
            
            —
            
            
            (290
            )Net
                gains included in net income
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (658
            )
            
            —
            
            
            (658
            )Comprehensive
                income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            20,187Issuance
                of common stock
            
            
            2,598
            
            
            26
            
            
            22,079
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            22,105Issuance
                of restricted stock
            
            
            —
            
            
            —
            
            
            514
            
            
            —
            
            
            (514
            )
            
            —
            
            
            —
            
            
            —Vesting
                of restricted stock
            
            
            72
            
            
            1
            
            
            (1
            )
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Exercise
                of employee stock options
            
            
            314
            
            
            3
            
            
            969
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            972Forfeitures
                of restricted stock
            
            
            —
            
            
            —
            
            
            (131
            )
            
            (4
            )
            
            131
            
            
            —
            
            
            —
            
            
            (4
            )Tax
                benefit from the exercise of stock options
            
            
            —
            
            
            —
            
            
            577
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            577Repurchases
                of common stock
            
            
            —
            
            
            —
            
            
            —
            
            
            (301
            )
            
            —
            
            
            —
            
            
            —
            
            
            (301
            )Amortization
                of unearned stock compensation
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            629
            
            
            —
            
            
            —
            
            
            629Balance,
                December 31, 2004
            
            
            43,231
            
            $
            432
            
            $
            175,270
            
            $
            (4,707
            )
            $
            (1,570
            )
            $
            (503
            )
            $
            14,354
            
            $
            183,276Comprehensive
                income (loss):Net
                income
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            27,435
            
            
            27,435Unrealized
                losses on cash flow hedges
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (603
            )
            
            —
            
            
            (603
            )Tax
                provisions related to cash flow hedges
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (43
            )
            
            —
            
            
            (43
            )Net
                losses included in net income
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            723
            
            
            —
            
            
            723Comprehensive
                income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            27,512Issuance
                of common stock
            
            
            2,500
            
            
            25
            
            
            28,206
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            28,231Issuance
                of restricted stock
            
            
            —
            
            
            —
            
            
            1,435
            
            
            —
            
            
            (1,435
            )
            
            —
            
            
            —
            
            
            —Vesting
                of restricted stock
            
            
            65
            
            
            1
            
            
            (1
            )
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Exercise
                of employee stock options
            
            
            340
            
            
            3
            
            
            1,311
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            1,314Tax
                benefit from the exercise of stock options
            
            
            —
            
            
            —
            
            
            791
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            791Repurchases
                of common stock
            
            
            —
            
            
            —
            
            
            —
            
            
            (190
            )
            
            —
            
            
            —
            
            
            —
            
            
            (190
            )Retirement
                of treasury stock
            
            
            (1,218
            )
            
            (12
            )
            
            (4,885
            )
            
            4,897
            
            
            —
            
            
            —
            
            
            —
            
            
            —Amortization
                of unearned stock compensation
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            706
            
            
            —
            
            
            —
            
            
            706Balance,
                December 31, 2005
            
            
            44,918
            
            $
            449
            
            $
            202,127
            
            $
            —
            
            $
            (2,299
            )
            $
            (426
            )
            $
            41,789
            
            $
            241,640Comprehensive
                income (loss):Net
                income
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            19,788
            
            
            19,788Unrealized
                gains (losses) on cash flow hedges
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            8,016
            
            
            —
            
            
            8,016Tax
                provisions related to cash flow hedges
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (770
            )
            
            —
            
            
            (770
            )Net
                (gains) losses included in net income
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            (5,814
            )
            
            —
            
            
            (5,814
            )Comprehensive
                income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            21,220Issuance
                of common stock
            
            
            —
            
            
            —
            
            
            37
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            37Vesting
                of restricted stock
            
            
            77
            
            
            1
            
            
            (1
            )
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —Exercise
                of employee stock options
            
            
            95
            
            
            1
            
            
            468
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            469Repurchases
                of common stock
            
            
            —
            
            
            —
            
            
            —
            
            
            (230
            )
            
            —
            
            
            —
            
            
            —
            
            
            (230
            )Forfeitures
                of restricted stock
            
            
            —
            
            
            —
            
            
            432
            
            
            (432
            )
            
            —
            
            
            —
            
            
            —
            
            
            —Adoption
                of FAS 123R
            
            
            —
            
            
            —
            
            
            (2,299
            )
            
            
            
            
            2,299
            
            
            —
            
            
            —
            
            
            —Vesting
                of share-based payments
            
            
            —
            
            
            —
            
            
            2,879
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            2,879Balance,
                December 31, 2006
            
            
            45,090
            
            $
            451
            
            $
            203,643
            
            $
            (662
            )
            $
            —
            
            $
            1,006
            
            $
            61,577
            
            $
            266,015





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


F-7
 *Table
          of Contents*




BRIGHAM
      EXPLORATION COMPANY




CONSOLIDATED
      STATEMENTS OF CASH FLOWS


**(In
      thousands)**




**Year
                  Ended December 31,****2006**
              
              **2005**
              
              **2004**Cash
                  flows from operating activities:Net
                  income
              
              $
              19,788
              
              $
              27,435
              
              $
              19,650Adjustments
                  to reconcile net income to cash provided (used) by operating
                  activities:Depletion
                  of oil and natural gas properties
              
              
              46,386
              
              
              33,268
              
              
              23,844Depreciation
                  and amortization
              
              
              537
              
              
              762
              
              
              722Interest
                  paid through issuance of additional mandatorily redeemable preferred
                  stock
              
              
              —
              
              
              581
              
              
              726Stock
                  based compensation
              
              
              1,571
              
              
              —
              
              
              —Write-off
                  of deferred loan costs
              
              
              965
              
              
              —
              
              
              —Amortization
                  of discount and deferred loan fees
              
              
              717
              
              
              491
              
              
              766Accretion
                  of discount on asset retirement obligations
              
              
              317
              
              
              180
              
              
              159Market
                  value adjustment for derivative instruments
              
              
              (5,794
              )
              
              814
              
              
              (625
              )Deferred
                  income taxes
              
              
              12,744
              
              
              15,037
              
              
              10,863Provision
                  for doubtful accounts
              
              
              48
              
              
              456
              
              
              —Other
                  noncash items
              
              
              64
              
              
              134
              
              
              —Changes
                  in working capital and other items:Accounts
                  receivable
              
              
              4,425
              
              
              (3,766
              )
              
              (6,430
              )Other
                  current assets
              
              
              (1,874
              )
              
              (61
              )
              
              2,848Accounts
                  and royalties payable
              
              
              7,336
              
              
              (9,456
              )
              
              3,451Other
                  current liabilities
              
              
              1,803
              
              
              (989
              )
              
              552Noncurrent
                  assets
              
              
              —
              
              
              (514
              )
              
              —Noncurrent
                  liabilities
              
              
              (346
              )
              
              7
              
              
              (145
              )Net
                  cash provided by operating activities
              
              
              88,687
              
              
              64,379
              
              
              56,381Cash
                  flows from investing activities:Additions
                  to oil and natural gas properties
              
              
              (171,597
              )
              
              (112,856
              )
              
              (84,439
              )Proceeds
                  from sale of oil and natural gas properties
              
              
              25
              
              
              9
              
              
              92Additions
                  to other property and equipment
              
              
              (510
              )
              
              (345
              )
              
              (378
              )(Increase)
                  decrease in drilling advances paid
              
              
              335
              
              
              (28
              )
              
              80Net
                  cash used by investing activities
              
              
              (171,747
              )
              
              (113,220
              )
              
              (84,645
              )Cash
                  flows from financing activities:Proceeds
                  from issuance of common stock, net of issuance costs
              
              
              37
              
              
              28,231
              
              
              22,105Proceeds
                  from issuance of senior subordinated notes and warrants
              
              
              —
              
              
              10,000
              
              
              —Proceeds
                  from exercise of employee stock options
              
              
              469
              
              
              1,314
              
              
              972Proceeds
                  from Senior Notes offering
              
              
              123,286
              
              
              —
              
              
              —Repurchases
                  of common stock
              
              
              (230
              )
              
              (190
              )
              
              (301
              )Increase
                  in senior credit facility
              
              
              55,800
              
              
              63,100
              
              
              33,000Repayment
                  of senior credit facility
              
              
              (63,000
              )
              
              (51,000
              )
              
              (31,000
              )Principal
                  payments on senior subordinated notes
              
              
              (30,000
              )
              
              —
              
              
              —Deferred
                  loan fees paid
              
              
              (2,977
              )
              
              (920
              )
              
              (10
              )Net
                  cash provided (used) by financing activities
              
              
              83,385
              
              
              50,535
              
              
              24,766Net
                  increase (decrease) in cash and cash equivalents
              
              
              325
              
              
              1,694
              
              
              (3,498
              )Cash
                  and cash equivalents, beginning of year
              
              
              3,975
              
              
              2,281
              
              
              5,779Cash
                  and cash equivalents, end of year
              
              $
              4,300
              
              $
              3,975
              
              $
              2,281




F-8
 *Table
          of Contents*


**BRIGHAM
      EXPLORATION COMPANY**





**NOTES
      TO THE CONSOLIDATED FINANCIAL STATEMENTS**





**1.  
      Organization and Nature of Operations**





Brigham
      Exploration Company is a Delaware corporation formed on February 25, 1997 for
      the purpose of exchanging its common stock for the common stock of Brigham,
      Inc.
      and the partnership interests of Brigham Oil & Gas, L.P. (the
“Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are
      collectively referred to as “Brigham.” Brigham, Inc. is a Nevada corporation
      whose only asset is its ownership interest in the Partnership. The Partnership
      was formed in May 1992 to explore and develop onshore domestic oil and natural
      gas properties using 3-D seismic imaging and other advanced technologies. Since
      its inception, the Partnership has focused its exploration and development
      of
      oil and natural gas properties primarily in the onshore Texas Gulf Coast, the
      Anadarko Basin, the Rocky Mountains and West Texas.





**2.  
      Summary of Significant Accounting Policies**





***Use
      of Estimates***





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





***Principles
      of Consolidation***





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





***Cash
      and Cash Equivalents***





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





***Property
      and Equipment***





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





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





Capitalized
      costs associated with impaired properties and capitalized costs related to
      properties having proved reserves, plus the estimated future development costs,
      asset retirement costs under Statement of Financial Accounting Standards No.
      143, “Accounting for Asset Retirement Obligations” (SFAS 143) are amortized
      using the unit-of-production method based on proved reserves. Capitalized costs
      of oil and natural gas properties, net of accumulated amortization and deferred
      income taxes, are limited to the total of estimated future net cash flows from
      proved oil and natural gas reserves, discounted at ten percent, plus the cost
      of
      unevaluated properties. The estimated future net cash flows are determined
      using
      prices at the end of the year. Under certain specific conditions, companies
      my
      elect to use subsequent prices for determining the estimated future net cash
      flows. Brigham has elected to use subsequent pricing for this purpose. There
      are
      many factors, including global events that may influence the production,
      processing, marketing and the price of oil and natural gas. A reduction in
      the
      valuation of oil and natural gas properties resulting from declining prices
      or
      production could adversely impact depletion rates and capitalized cost
      limitations. Capitalized costs associated with properties that have not been
      evaluated through drilling or seismic analysis, including exploration wells
      in
      progress at December 31, are excluded from the unit-of-production amortization.
      Exclusions are adjusted annually based on drilling results and interpretative
      analysis.


F-9
 *Table
          of Contents*


Other
      property and equipment, which primarily consists of 3-D seismic interpretation
      workstations, is depreciated on a straight-line basis over the estimated useful
      lives of the assets after considering salvage value. Estimated useful lives
      are
      as follows:




Furniture
                and fixtures
            
            
            10
                yearsMachinery
                and equipment
            
            
            5
                years3-D
                seismic interpretation workstations and software
            
            
            3
                years





Betterments
      and major improvements that extend the useful lives are capitalized while
      expenditures for repairs and maintenance of a minor nature are expensed as
      incurred.





***Asset
      Retirement Obligations***





Brigham
      records the fair value of a liability for an asset retirement obligation in
      the
      period in which it is incurred and a corresponding increase in the carrying
      amount of the related long-lived asset. The liability is accreted to its present
      value each period, and the capitalized cost is depreciated over the useful
      life
      of the related asset. If the liability is settled for an amount other than
      the
      recorded amount, a gain or loss is recognized.





***Revenue
      Recognition***





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





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





***Derivative
      Instruments and Hedging Activities***





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





At
      the
      inception of a derivative contract, Brigham historically designated the
      derivative as a cash flow hedge. For all derivatives designated as cash flow
      hedges, Brigham formally documented the relationship between the derivative
      contract and the hedged items, as well as the risk management objective for
      entering into the derivative contract. To be designated as a cash flow hedge
      transaction, the relationship between the derivative and the hedged items must
      be highly effective in achieving the offset of changes in cash flows
      attributable to the risk both at the inception of the derivative and on an
      ongoing basis. Brigham historically measured hedge effectiveness on a quarterly
      basis and hedge accounting would be discontinued prospectively if it is
      determined that the derivative is no longer effective in offsetting changes
      in
      the cash flows of the hedged item. Gains and losses deferred in accumulated
      other comprehensive income related to cash flow hedge derivatives that become
      ineffective remain unchanged until the related production is delivered. If
      Brigham determines that it is probable that a hedged forecasted transaction
      will
      not occur, deferred gains or losses on the derivative are recognized in earnings
      immediately. See Note 11 for a description of the derivative contracts which
      Brigham executes.





Derivatives,
      historically, were recorded on the balance sheet at fair value and changes
      in
      the fair value of derivatives were recorded each period in net income or other
      comprehensive income, depending on whether a derivative was designated as part
      of a hedge transaction and, if it was, depending on the type of hedge
      transaction. Brigham’s derivatives historically consisted primarily of cash flow
      hedge transactions in which Brigham was hedging the variability of cash flows
      related to a forecasted transaction. Period to period changes in the fair value
      of derivative instruments designated as cash flow hedges were reported in other
      comprehensive income and reclassified to net income in the periods in which
      the
      contracts are settled. The ineffective portion of the cash flow hedges was
      reflected in net income as an increase or decrease to other income (expense).
      Gains and losses on derivative instruments that did not qualify for hedge
      accounting were also recorded as an increase or decrease to other income
      (expense), in the period in which they occur. The resulting cash flows from
      derivatives are reported as cash flows from operating
      activities.


F-10
 *Table
          of Contents*


On
      October 1, 2006, Brigham de-designated all derivates that were previously
      classified as cash flow hedges and, in addition, Brigham has elected not to
      designate any additional derivative contracts as accounting hedges under SFAS
      No. 133. As such, all derivative positions are carried at their fair value
      on
      the consolidated balance sheet and are
      marked-to-market at the end of each period. Any realized and unrealized gains
      or
      losses are recorded as gain (loss) on derivatives, net, as an increase or
      decrease in revenue on the consolidated statement of operations rather than
      as a
      component of other comprehensive income or other income (expense).





***Other
      Comprehensive Income (Loss)***





Brigham
      follows the provisions of Statement of Financial Accounting Standards No. 130,
      “Reporting Comprehensive Income,” which establishes standards for reporting
      comprehensive income. In addition to net income, comprehensive income includes
      all changes in equity during a period, except those resulting from investments
      and distributions to stockholders of Brigham.





The
      following table reflects the components of other comprehensive income (loss)
      for
      the years ended December 31, 2006, 2005 and 2004 (in thousands):




**2006**
            
            **2005**
            
            **2004**Balance,
                beginning of year
            
            $
            (426
            )
            $
            (503
            )
            $
            (1,040
            )Current
                period settlements reclassified to earnings
            
            
            (3,042
            )
            
            4,174
            
            
            4,694Current
                period change in fair value of hedges
            
            
            11,058
            
            
            (4,777
            )
            
            (3,209
            )Tax
                benefits (provisions) related to cash flow hedges
            
            
            (770
            )
            
            (43
            )
            
            (290
            )Net
                (gains) losses included in earnings
            
            
            (5,814
            )
            
            723
            
            
            (658
            )Balance,
                end of year
            
            $
            1,006
            
            $
            (426
            )
            $
            (503
            )





***Stock
      Based Compensation***





Effective
      January 1, 2006, Brigham adopted the provisions of SFAS 123R “Share Based
      Payment” for its stock based compensation plans. Brigham previously accounted
      for these plans under the recognition and measurement principles of Accounting
      Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to
      Employees,” (APB 25) and related interpretations and disclosure requirements
      established by SFAS 123, “Accounting for Stock-Based Compensation.”





Under
      APB
      25, Brigham recognized stock based compensation using the intrinsic value method
      and, thus, generally no compensation expense was recognized for stock options
      as
      they were generally granted at the market value on the date of grant. The pro
      forma effects on net income due to stock based compensation were disclosed
      in
      the notes to the consolidated financial statements. SFAS 123R eliminates the
      use
      of APB 25 and the intrinsic value method of accounting, and requires companies
      to recognize the cost of employee services received in exchange for awards
      of
      equity instruments, based on the grant date fair value of those awards, in
      the
      financial statements over the requisite service period.





***Income
      Taxes***





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


F-11
 *Table
          of Contents*


***Deferred
      Loan Fees***





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





***Segment
      Information***





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





***Treasury
      Stock***





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





***Mandatorily
      Redeemable Preferred Stock***





The
      Mandatorily Redeemable Preferred Stock is presented in accordance with SFAS
      150,
“Accounting for Certain Financial Instruments with Characteristics of both
      Liabilities and Equity”. SFAS 150 requires an issuer to classify certain
      financial instruments within its scope, such as mandatorily redeemable preferred
      stock, as liabilities (or assets in some circumstances). SFAS 150 defines a
      financial instrument as mandatorily redeemable if it embodies an unconditional
      obligation requiring the issuer to redeem the instrument by transferring its
      assets at a specified or determinable date(s) or upon an event certain to occur.
      Brigham adopted this standard as required on July 1, 2003.





***New
      Pronouncements***





In
      February 2006, the FASB issued Statement of Financial Accounting Standards
      No.
      155 (SFAS 155) “Accounting for Certain Hybrid Instruments — an amendment of FASB
      Statements No. 133 and 140.” SFAS 155 amends SFAS 133 to permit fair value
      measurement for certain hybrid financial instruments that contain an embedded
      derivative, provides additional guidance on the applicability of SFAS 133 and
      SFAS 140 to certain financial instruments and subordinated concentrations of
      credit risk. SFAS 155 is effective for the first fiscal year that begins after
      September 15, 2006. This did not have any impact on Brigham’s consolidated
      financial statements.





In
      July
      2006, the Financial Accounting Standards Board issued FASB Interpretation No.
      48
“Accounting for Uncertainty in Income Taxes--an Interpretation of FASB Statement
      109” (FIN 48), which clarifies the accounting for uncertainty in tax positions
      taken or expected to be taken in a tax return, including issues relating to
      financial statement recognition and measurement. FIN 48 provides that the tax
      effects from an uncertain tax position can be recognized in the financial
      statements only if the position is “more-likely-than-not” of being sustained if
      the position were to be challenged by a taxing authority. The assessment of
      the
      tax position is based solely on the technical merits of the position, without
      regard to the likelihood that the tax position may be challenged. If an
      uncertain tax position meets the “more-likely-than-not” threshold, the largest
      amount of tax benefit that is greater than 50 percent likely of being recognized
      upon ultimate settlement with the taxing authority, is recorded. The provisions
      of FIN 48 are effective for fiscal years beginning after December 15, 2006,
      with
      the cumulative effect of the change in accounting principle recorded as an
      adjustment to opening retained earnings. The Company expects to recognize a
      liability of approximately $3.3 million as a result of adopting FIN 48.





In
      September 2006 the Financial Accounting Standards Board issued Statement of
      Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157),
      which provides expanded guidance for using fair value to measure assets and
      liabilities. SFAS 157 establishes a hierarchy for data used to value assets
      and
      liabilities, and requires additional disclosures about the extent to which
      a
      company measures assets and liabilities at fair value, the information used
      to
      measure fair value, and the effect of fair value measurements on earnings.
      Implementation of SFAS 157 is required on January 1, 2008. The Company is
      currently evaluating the impact of adopting SFAS 157 on the financial
      statements.





On
      September 29, 2006, the Financial Accounting Standards Board issued Statement
      of
      Financial Accounting Standards No. 158 “Employers’ Accounting for Defined
      Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements
      No. 87, 88, 106, and 132(r)” (SFAS 158). The Statement requires the recognition
      of the overfunded or underfunded status of a defined benefit postretirement
      plan
      as an asset or liability on the balance sheet and the recognition of the changes
      of the funded status in the year in which the changes occur through
      comprehensive income. Implementation of SFAS 158 is required as of the end
      of
      the fiscal year ending after December 15, 2006. The adoption of SFAS 158 did
      not
      have an impact on the Company’s financial statements because the Company does
      not currently have any defined benefit pension or other postretirement benefit
      plans.


F-12
 *Table
          of Contents*


On
      September 13, 2006 the Securities Exchange Commission (SEC) issued Staff
      Accounting Bulletin No. 108 (SAB 108), which establishes an approach that
      requires quantification of financial statement errors based on the effects
      of
      the error on each of the company's financial statements and the related
      disclosures. SAB 108 requires the use of a
      balance
      sheet and an income statement approach to evaluate whether either of these
      approaches results in quantifying a misstatement that, when all relevant
      quantitative and qualitative factors are considered, is material. The adoption
      of SAB 108 did not have an impact on the Company’s financial
      statements.





**3.  
      Property and Equipment**





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





**December
                31,****2006**
            
            **2005**Oil
                and natural gas properties
            
            $
            706,390
            
            $
            521,808Accumulated
                depletion
            
            
            (220,865
            )
            
            (174,479
            )485,525
            
            
            347,329Other
                property and equipment:3-D
                seismic interpretation workstations and software
            
            
            1,357
            
            
            1,673Office
                furniture and equipment
            
            
            2,817
            
            
            2,714Accumulated
                depreciation
            
            
            (3,238
            )
            
            (3,360
            )936
            
            
            1,027$
            486,461
            
            $
            348,356




Depletion
      expense is based on units-of-production. Production volumes used to determine
      depletion expense were 13,254 MMcfe for 2006 and 11,913 MMcfe for
      2005.




Brigham
      capitalizes certain payroll and other internal costs directly attributable
      to
      acquisition, exploration and development activities as part of its investment
      in
      oil and natural gas properties over the periods benefited by these activities.
      Capitalized costs do not include any costs related to production, general
      corporate overhead, or similar activities. Capitalized costs are summarized
      as
      follows for the years ended December 31, 2006, 2005 and 2004 (in
      thousands):




**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**Capitalized
                certain payroll and other internal costs
            
            $
            7,118
            
            $
            4,847
            
            $
            4,872Capitalized
                interest costs
            
            
            2,836
            
            
            1,604
            
            
            1,195$
            9,954
            
            $
            6,451
            
            $
            6,067





The
      risk
      that the Company will experience a ceiling test writedown increases when oil
      and
      gas prices are depressed or if the Company has substantial downward revisions
      in
      its estimated proved reserves. Based on oil and gas prices in effect on December
      29, 2006 ($5.475 per MMBtu for Henry Hub natural gas and $61.06 per barrel
      for
      West Texas Intermediate oil, adjusted for differentials), the unamortized cost
      of the Company's oil and gas properties exceeded the ceiling limit by $40.4
      million, net of tax. However, subsequent to the end of the year, oil and natural
      gas prices increased, and on February 28, 2006, reached $7.205 per MMBtu for
      natural gas and $61.80 per barrel for oil. Utilizing these prices, the Company’s
      net capitalized costs of oil and natural gas properties would not have exceeded
      the ceiling limit. As a result of the increase in the ceiling limit using
      subsequent prices, the Company was not required to writedown the net capitalized
      costs of its oil and gas properties.




Undesignated
      hedges are excluded from the ceiling test
      calculation. The company de-designated its cash flow hedges effective October
      1,
      2006.


F-13
 *Table
          of Contents*


**4. 
       Senior Credit Facility, Senior Notes, and Senior Subordinated
      Notes**





The
      following table reflects the outstanding balances of the senior credit facility,
      senior notes, and senior subordinated notes for the years ended December 31,
      2006 and 2005:





**December
                31,****2006**
            
            **2005****(In
                thousands)**Senior
                Credit Facility
            
            $
            25,900
            
            $
            33,100Senior
                Subordinated Notes
            
            
            —
            
            
            30,000Senior
                Notes
            
            
            125,000
            
            
            —Discount
                on Senior Notes
            
            
            (1,566
            )
            
            —Total
                Debt
            
            $
            149,334
            
            $
            63,100Less:
                Current Maturities
            
            
            —
            
            
            —Total
                Long-Term Debt
            
            $
            149,334
            
            $
            63,100




***Senior
      Credit Facility***





During
      June 2005, Brigham amended and restated its senior credit facility to provide
      for revolving credit borrowings up to a maximum principal amount of $200 million
      at any one time outstanding. Borrowings under Brigham’s senior credit facility
      cannot exceed its borrowing base, which is determined at least semiannually.
      Brigham’s borrowing base under the amended and restated senior credit facility
      increased from $80 million to $90 million in November 2005. In conjunction
      with
      the issuance of the Senior Notes, the borrowing base was reset to $50 million.
      In November 2006, Brigham concluded the semi-annual redetermination process,
      which is described in further detail below, and at that time the borrowing
      base
      was reset to $110 million.





Brigham
      also extended the maturity of its senior credit facility from March 2009 to
      June
      2010 and changed the interest rate that it pays on borrowings under the
      facility. Borrowings under the senior credit facility bear interest, at
      Brigham’s election, at a base rate (as the term is defined in the senior credit
      facility) or Eurodollar rate (5.32% at December 31, 2006), plus in each case
      an
      applicable margin that is reset quarterly (1.25% at December 31, 2006). The
      applicable interest rate margin varies from 0.0% to 0.5% in the case of
      borrowings based on the base rate (as the term is defined in the senior credit
      facility) and from 1.25% to 2.0% in the case of borrowings based on the
      Eurodollar rate, depending on percentage of the available borrowing base
      utilized. In addition, Brigham is required to pay a commitment fee on the unused
      portion of its borrowing base. The applicable commitment fee varies from 0.25%
      to 0.375%, depending on the percentage of the available borrowing base not
      utilized. Borrowings under the senior credit facility are collateralized by
      substantially all of Brigham’s oil and natural gas properties under first
      liens.





The
      senior credit facility contains various covenants, including among others
      restrictions on liens, restrictions on incurring other indebtedness,
      restrictions on mergers, restrictions on investments, and restrictions on
      hedging activity of a speculative nature or with counterparties having credit
      ratings below specified levels. The senior credit facility requires Brigham
      to
      maintain a current ratio (as defined) of at least 1 to 1 and an interest
      coverage ratio (as defined) of at least 3 to 1. At December 31, 2006, Brigham
      was in compliance with all covenants under the senior credit
      facility.





In
      April
      2006, proceeds from the Senior Notes issuance were used to repay the $48.4
      million balance outstanding under the senior credit agreement. As of December
      31, 2006, Brigham had $25.9 million in borrowings outstanding under its senior
      credit facility.





***Senior
      Subordinated Notes***





In
      April
      2006, Brigham used a portion of the net proceeds from the sale of the Senior
      Notes issuance to repay the $30 million in borrowings that were outstanding
      under the senior subordinated credit agreement. Subsequent to this repayment,
      Brigham terminated the senior subordinated credit agreement and the associated
      interest rate swap designated as a cash flow hedge.





***Senior
      Notes***





In
      April
      2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the
“Senior Notes”). The Senior Notes were priced at 98.629% of their face value to
      yield 9 7/8% and are fully and unconditionally guaranteed by Brigham Exploration
      and its wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P.
      (the “Guarantors”). The guarantees are joint and several. Brigham Exploration
      does not have any independent assets or operations and the aggregate assets
      and
      revenues of the subsidiaries not guaranteeing are less than 3% of the Company’s
      consolidated assets and revenues. As of December 31, 2006, Brigham had $123.4
      million of senior notes outstanding, net of discount of $1.6
      million.


F-14
 *Table
          of Contents*


The
      Senior Notes agreement contains various covenants, including among others
      restrictions on incurring other indebtedness, restrictions on liens,
      restrictions on the sale of assets, and restrictions on certain payments. The
      Senior Notes agreement requires Brigham to maintain a fixed charge coverage
      ratio (as defined) for the most recent four full fiscal quarters of at least
      2.5
      to 1. At December 31, 2006, Brigham was in compliance with all covenants under
      the Senior Notes agreement.





**5.   
      Preferred Stock**





***Series
      A Mandatorily Redeemable Preferred Stock***





The
      following table reflects the outstanding shares of Series A mandatorily
      redeemable preferred stock and the activity related thereto for the years ended
      December 31, 2006 and 2005 (in thousands, except share amounts):





**Year
                Ended**
              **December
                31, 2006**
            
            **Year
                Ended**
              **December
                31, 2005****Shares**
            
            **Amounts**
            
            **Shares**
            
            **Amounts**Balance,
                beginning of year
            
            
            505,051
            
            $
            10,101
            
            
            475,986
            
            $
            9,520Dividends
                paid in kind
            
            
            —
            
            
            —
            
            
            29,065
            
            
            581Balance,
                end of year
            
            
            505,051
            
            $
            10,101
            
            
            505,051
            
            $
            10,101





Brigham
      has designated 2,250,000 shares of preferred stock as Series A Preferred Stock.
      The Series A Preferred Stock has a par value of $0.01 per share and a stated
      value of $20 per share. The Series A Preferred Stock is cumulative and pays
      dividends quarterly at a rate of 6% per annum of the stated value if paid in
      cash or 8% per annum of the stated value if paid in kind (PIK) through the
      issuance of additional Series A Preferred Stock in lieu of cash. From issuance,
      through September 30, 2005, Brigham paid the dividends on the Series A preferred
      stock in kind through the issuance of additional shares of preferred stock
      at a
      rate of 8% per annum. Beginning on October 1, 2005, Brigham’s option
      to pay
      dividends in kind expired and Brigham was required to pay all dividend
      obligations related to the Series A preferred stock in cash at a rate of 6%
      per
      annum. The Series A Preferred Stock matures on October 31, 2010 and is
      redeemable at Brigham’s option at 100% or 101% of stated value (depending upon
      certain conditions) at anytime prior to maturity. The Series A Preferred Stock
      does not generally have any voting rights, except for certain approval rights
      and as required by law.





**6.   
      Issuance of Common Stock**





In
      February 2005, Brigham filed a second universal shelf registration statement
      that allows Brigham to issue common stock, preferred stock, depositary shares,
      warrants, senior debt and subordinated debt up to an aggregate amount of $300
      million.





In
      November 2005, Brigham issued 2,500,000 shares of Brigham common stock
      under its first universal shelf registration statement and received
      proceeds of approximately $28.2 million, net of underwriting commissions and
      other offering expenses. During July and August 2004, Brigham completed the
      sale
      of 2,598,500 shares of its common stock under the same universal shelf
      registration statement. Net proceeds from the stock sale were approximately
      $22.1 million.





**7.   
      Asset Retirement Obligations**





Brigham
      has asset retirement obligations associated with the future plugging and
      abandonment of proved properties and related facilities. Prior to the adoption
      of SFAS 143, Brigham assumed salvage value approximated plugging and abandonment
      costs. As such, estimated salvage value was not excluded from depletion and
      plugging and abandonment costs were not accrued for over the life of the oil
      and
      gas properties. Under the provisions of SFAS 143, the fair value of a liability
      for an asset retirement obligation is recorded in the period in which it is
      incurred and a corresponding increase in the carrying amount of the related
      long-lived asset. The liability is accreted to its present value each period,
      and the capitalized cost is depreciated over the useful life of the related
      asset. If the liability is settled for an amount other than the recorded amount,
      a gain or loss is recognized.


F-15
 *Table
          of Contents*


Brigham
      has no assets that are legally restricted for purposes of settling asset
      retirement obligations. The following table summarizes Brigham’s asset
      retirement obligation transactions recorded in accordance with the provisions
      of
      SFAS 143 during the years ended December 31, 2006 and 2005 (in
      thousands):




**Year
                Ended**
              **December
                31,****2006**
            
            **2005**Beginning
                asset retirement obligations
            
            $
            4,390
            
            $
            2,896Liabilities
                incurred for new wells placed on production
            
            
            608
            
            
            469Liabilities
                settled
            
            
            (313
            )
            
            (10
            )Revisions
                to estimates
            
            
            —
            
            
            855Accretion
                of discount on asset retirement obligations
            
            
            317
            
            
            180$
            5,002
            
            $
            4,390





**8.   
      Income Taxes**





The
      income tax expense (benefit) consists of the following (in
      thousands):





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**Current
                income taxes:Federal
            
            $
            —
            
            $
            —
            
            $
            —State
            
            
            —
            
            
            —
            
            
            —Deferred
                income taxes:Federal
            
            
            11,528
            
            
            15,037
            
            
            10,863State
            
            
            1,216
            
            
            —
            
            
            —$
            12,744
            
            $
            15,037
            
            $
            10,863





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





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**Tax
                at statutory rate
            
            $
            11,386
            
            $
            14,865
            
            $
            10,679Add
                the effect of:Nondeductible
                expenses
            
            
            27
            
            
            —
            
            
            5Deductible
                stock compensation
            
            
            —
            
            
            (91
            )
            
            (194
            )Preferred
                stock dividends
            
            
            212
            
            
            257
            
            
            373Valuation
                allowance
            
            
            —
            
            
            —
            
            
            —Incentive
                stock options not exercised
            
            
            252
            
            
            —
            
            
            —Adoption
                of Texas Margin tax
            
            
            872
            
            
            —
            
            
            —Other
            
            
            (5
            )
            
            6
            
            
            —$
            12,744
            
            $
            15,037
            
            $
            10,863





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





**December
                31,****2006**
            
            **2005**Deferred
                tax assetsCurrent:Unrealized
                hedging and other derivative losses
            
            $
            —
            
            $
            497Current
            
            
            —
            
            
            497Non-current:Net
                operating loss carryforwards
            
            
            40,338
            
            
            39,393Capital
                loss carryforwards
            
            
            61
            
            
            61Percentage
                depletion carryforwards
            
            
            2,971
            
            
            —Stock
                compensation
            
            
            1,516
            
            
            942Asset
                retirement obligations
            
            
            1,751
            
            
            1,536Other
            
            
            (85
            )
            
            196Non-current
            
            
            46,552
            
            
            42,12846,552
            
            
            42,625




F-16
 *Table
          of Contents*





**December
                31,****2006**
            
            **2005**Deferred
                tax liabilitiesCurrent:Unrealized derivative
                gains
            
            $
            (1,986
            )
            $
            —Gas
                imbalances
            
            
            —
            
            
            (15
            )Current
            
            
            (1,986
            )
            
            (15
            )Non-current:Depreciable
                and depletable property
            
            
            (76,713
            )
            
            (65,630
            )Other
            
            
            (200
            )
            
            —Non-current
            
            
            (76,913
            )
            
            (65,630
            )(78,899
            )
            
            (65,645
            )Net
                deferred tax asset (liability)
            
            
            (32,347
            )
            
            (23,020
            )Valuation
                allowance
            
            
            (3,032
            )
            
            (61
            )Total
                federal deferred tax asset (liability)
            
            
            (35,379
            )
            
            (23,081
            )Total
                state deferred tax asset (liability)
            
            
            (1,216
            )
            
            —Total
                deferred tax asset (liability)
            
            $
            (36,595
            )
            $
            (23,081
            )Reflected
                in the accompanying balance sheets as:Current
                deferred income tax asset
            
            $
            —
            
            $
            482Current
                deferred income tax liability
            
            
            (1,986
            )
            
            —Non-current
                deferred income tax liability
            
            
            (34,609
            )
            
            (23,563
            )$
            (36,595
            )
            $
            (23,081
            )





A
      deferred liability or asset is recognized for the estimated future tax effects
      attributable to (i) net operating loss carryforwards (“NOLs”) and (ii) existing
      temporary differences between book and taxable income. In 2006, Brigham
      recognized a current year net deferred federal tax liability of $12.3 million
      due to reversals of existing temporary differences between book and taxable
      income resulting mainly from capital expenditures. Brigham also recognized
      a
      current year net deferred state tax liability of $1.2 million, consisting of
      a
      $1.3 million new Texas franchise tax and miscellaneous deferred tax benefits
      of
      other states. At December 31, 2006, Brigham has capital loss carryforwards
      of
      approximately $175,000 that expire in 2007 on which Brigham has established
      a
      valuation allowance. In addition, Brigham has percentage depletion carryforwards
      of approximately $8.5 million on which Brigham has established a valuation
      allowance.





Brigham
      believes an Internal Revenue Code Sec. 382 ownership change may have occurred
      in
      March 2001 and in November 2005, as a result of a potential 50% change in
      ownership among its 5% shareholders over a three-year period. The limitations
      resulting from the March 2001 and November 2005 ownership changes approximate
      $5.2 million annually and $22 million annually, respectively, which can be
      increased by recognized Built-in-Gains over five years following the ownership
      change. Management believes that the limitations will not have a material impact
      on the utilization of its NOL’s because the maximum limitations to be utilized
      exceed total NOL’s affected by the limitations.





In
      May
      2006, the state of Texas enacted legislation that replaces the taxable capital
      and earned surplus components of its franchise tax with a new franchise tax
      that
      is based on modified gross revenue. The new franchise tax (referred to as the
      “Margin Tax”) becomes effective beginning with the 2007 tax year. The current
      franchise tax remains in effect through the end of 2006. Within the context
      of
      generally accepted accounting principals in the United States, the Margin Tax
      is
      based on a measure of income and is thus accounted for in accordance with
      Statement of Financial Accounting Standards No. 109 “Accounting for Income
      Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects
      of the tax law change in the period of enactment. As discussed above, Brigham
      has recorded a deferred tax liability in the amount of $1.3 million to reflect
      the estimated impact of the adoption of the Margin Tax in 2006. The Margin
      Tax
      legislation contains significant inconsistencies in language describing the
      computation of the tax, which combined with unclear legislative intent preclude
      reliable interpretation of the law. The Texas Comptroller of public accounts
      (responsible for administering Texas tax laws) has issued guidance on
      calculating the Margin Tax that the Company has followed in determining the
      effects of the Margin Tax, even though the comptroller’s guidance differs in
      several respects from the text of the enacted law.





At
      December 31, 2006, Brigham had regular tax NOLs of approximately $116 milion
      available as a deduction against future taxable income. Additionally, Brigham
      has approximately $102.1 million of alternative minimum tax (“AMT”) NOLs. The
      NOLs expire from 2012 through 2026. The value of these NOLs depends on the
      ability of Brigham to generate taxable income. A summary of the NOLs follows
      (in
      thousands):


F-17
 *Table
          of Contents*





**Regular****NOLs**
            
            **AMT****NOLs**Expiration
                Date:December
                31, 2012
            
            $
            13,311
            
            $
            8,686December
                31, 2018
            
            
            27,031
            
            
            23,791December
                31, 2019
            
            
            20,329
            
            
            19,720December
                31, 2020
            
            
            13,559
            
            
            8,634December
                31, 2021
            
            
            18,990
            
            
            18,314December
                31, 2022
            
            
            5,287
            
            
            4,949December
                31, 2023
            
            
            5,352
            
            
            5,421December
                31, 2024
            
            
            3,729
            
            
            4,141December
                31, 2025
            
            
            6,583
            
            
            6,972December
                31, 2026
            
            
            1,849
            
            
            1,439$
            116,020
            
            $
            102,067




**9.   
      Net Income Available Per Common Share**





Basic
      earnings per share are computed by dividing net income (loss) available to
      common stockholders by the weighted average number of common shares outstanding
      for the period. Diluted EPS is computed by dividing net income by the weighted
      average number of common shares and potential common shares outstanding (if
      dilutive) during each period. Potential common shares include stock options
      and
      restricted stock. The number of potential common shares outstanding relating
      to
      stock options and restricted stock is computed using the treasury stock
      method.





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004****(In
                thousands, except per share amounts)**Basic
                EPS:Income
                (loss) available to common stockholders
            
            $
            19,788
            
            $
            27,435
            
            $
            19,650Weighted
                average common shares outstanding — basic
            
            
            45,017
            
            
            42,481
            
            
            40,445Basic
                EPS:Income
                (loss) available to common stockholders
            
            $
            0.44
            
            $
            0.65
            
            $
            0.49








**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004****(In
                thousands, except per share amounts)**Diluted
                EPS:Income
                (loss) available to common stockholders — diluted
            
            $
            19,788
            
            $
            27,435
            
            $
            19,650Common
                shares outstanding
            
            
            45,017
            
            
            42,481
            
            
            40,445Effect
                of dilutive securities:Stock
                options and restricted stock
            
            
            580
            
            
            1,247
            
            
            1,171Potentially
                dilutive common shares
            
            
            580
            
            
            1,247
            
            
            1,171Adjusted
                common shares outstanding — diluted
            
            
            45,597
            
            
            43,728
            
            
            41,616Diluted
                EPS:Income
                (loss) available to common stockholders
            
            $
            0.43
            
            $
            0.63
            
            $
            0.47




At
      December 31, 2006, 2005, and 2004, potential dilution of approximately 1.7
      million, 330,000, and, 718,500 shares of common stock, respectively, related
      to
      mandatorily redeemable preferred stock and options were outstanding, but were
      not included in the computation of diluted income (loss) per share because
      the
      effect of these instruments would have been anti-dilutive.





**10.  Contingencies,
      Commitments and Factors Which May Affect Future Operations**





***Litigation***


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


F-18
 *Table
          of Contents*


As
      of
      December 31, 2006, there are no known environmental or other regulatory matters
      related to Brigham’s operations that are reasonably expected to result in a
      material liability to Brigham. Compliance with environmental laws and
      regulations has not had, and is not expected to have, a material adverse effect
      on Brigham’s financial position, results of operations or cash
      flows.





***Operating
      Lease Commitments***





Brigham
      leases office equipment and space under operating leases expiring at various
      dates. The noncancelable term of the leases for Brigham’s office space expires
      in 2012. The future minimum annual rental payments under the noncancelable
      terms
      of these leases at December 31, 2006 are as follows (in thousands):








2007
            
            $
            7022008
            
            
            6872009
            
            
            7042010
            
            
            7212011
            
            
            738Thereafter
            
            
            378$
            3,930





Rental
      expense for the years ended December 31, 2006, 2005 and 2004 was approximately
      $651,000, $596,000, and $754,000, respectively.





***Major
      Purchasers***





The
      following purchasers accounted for 10% or more of Brigham’s oil and natural gas
      sales for the years ended December 31, 2006, 2005 and 2004:




**2006**
            
            **2005**
            
            **2004**Purchaser
                A
            
            
            —
            
            
            —
            
            
            11
            %Purchaser
                B
            
            
            —
            
            
            —
            
            
            12
            %Purchaser
                C
            
            
            15
            %
            
            20
            %
            
            —Purchaser
                D
            
            
            14
            %
            
            —
            
            
            —





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





***Factors
      Which May Affect Future Operations***





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





**11.  Derivative
      Instruments and Hedging Activities**





Brigham
      utilizes various commodity swap and option contracts to (i) reduce the effects
      of volatility in price changes on the oil and natural gas commodities it
      produces and sells, (ii) reduce commodity price risk and (iii) provide a base
      level of cash flow in order to assure it can execute at least a portion of
      its
      capital spending plans.





Brigham
      reports average oil and natural gas prices and revenues including the net
      results of hedging activities. On October 1, 2006, Brigham de-designated all
      derivates that were previously classified as cash flow hedges and, in addition,
      Brigham has elected not to designate any additional derivative contracts as
      accounting hedges under SFAS No. 133. Beginning on October 1, 2006, all
      derivative positions are carried at their fair value on the consolidated balance
      sheet and are marked-to-market at the end of each period. As such, the realized and unrealized
      gains or losses are recorded as gain (loss) on derivatives, net, as an increase
      or decrease in revenue on the consolidated statement of operations rather than
      as a component of other comprehensive income. The
      following table sets forth Brigham’s oil and natural gas prices including and
      excluding the realized and unrealized hedging gains and losses and the increase
      or decrease in oil and natural gas revenues as a result of the hedging
      activities for the three year period ended December 31, 2006:


F-19
 *Table
          of Contents*





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004****Natural
                gas**Average
                price per Mcf realized excluding gas hedging results
            
            $
            6.74
            
            $
            8.29
            
            $
            6.05Average
                price per Mcf including gas hedging settlement results
            
            $
            7.09
            
            $
            7.97
            
            $
            5.84Increase
                (decrease) in revenue, in thousands
            
            $
            3,639
            
            $
            (2,925
            )
            $
            (1,853
            )Average
                price per Mcf including gas hedging settlement results and any unrealized
                gains (losses)
            
            $
            7.31
            
            
            NA
            
            
            NAIncrease
                (decrease) in revenue, in thousands
            
            $
            6,044
            
            
            NA
            
            
            NA**Oil**Average
                price per Bbl realized excluding oil hedging results
            
            $
            64.04
            
            $
            54.73
            
            $
            40.13Average
                price per Bbl including oil hedging settlement results
            
            $
            64.39
            
            $
            51.95
            
            $
            35.17Increase
                (decrease) in revenue, in thousands
            
            $
            157
            
            $
            (1,249
            )
            $
            (2,841
            )Average
                price per Mcf including oil hedging settlement results and any unrealized
                gains (losses)
            
            $
            64.79
            
            
            NA
            
            
            NAIncrease
                (decrease) in revenue, in thousands
            
            $
            332
            
            
            NA
            
            
            NA





For
      the
      years ended December 31, 2006, 2005 and 2004, ineffectiveness associated with
      Brigham’s derivative contracts designated as cash flow hedges increased
      (decreased) earnings by approximately $3.2 million, $(0.7) million, and $0.7
      million, respectively. Effective October 1, 2006, Brigham de-designated all
      existing cash flow hedges. Subsequent derivative contracts are undesignated
      for
      accounting purposes. Brigham continues to designate derivative contracts as
      cash
      flow hedges for tax purposes.





***Natural
      Gas and Crude Oil Derivative Contracts***





***Cash
      flow hedges***





Prior
      to
      October 1, 2006, all derivative positions that qualified for hedge accounting
      were designated on the date Brigham entered into the contract as a hedge against
      the variability in cash flows associated with the forecasted sale of future
      oil
      and gas production. Brigham’s cash flow hedges consisted of costless collars
      (purchased put options and written call options). The costless collars are
      used
      to establish floor and ceiling prices on anticipated future oil and natural
      gas
      production. There were no net premiums paid or received when Brigham entered
      into these option agreements. The cash flow hedges were valued at the end of
      each period and adjustments to the fair value of the contract prior to
      settlement were recorded on the consolidated statement of stockholders’ equity
      as other comprehensive income. Upon settlement, the gain (loss) on the cash
      flow
      hedge was recorded as an increase or decrease in revenue on the consolidated
      statement of operations. Additionally, any unrealized gains (losses) relating
      to
      the ineffective portion of the cash flow hedges was recorded as an increase
      or
      decrease in other income (expense).





On
      October 1, 2006, Brigham de-designated all derivates that were previously
      classified as cash flow hedges and, in addition, Brigham has elected not to
      designate any additional derivative contracts as accounting hedges under SFAS
      No. 133. As such, all derivative positions are carried at their fair value
      on
      the consolidated balance sheet and are
      marked-to-market at the end of each period. Any realized and unrealized gains
      or
      losses are recorded as gain (loss) on derivatives, net, as an increase or
      decrease in revenue on the consolidated statement of operations rather than
      as a
      component of other comprehensive income or as other income
      (expense).





Derivative
      positions included written put options that were not designated as cash flow
      hedges and were reflected at fair value on the balance sheet. These positions
      were entered into in conjunction with a costless collar to offset the cost
      of
      other option positions that were designated as cash flow hedges. Historically,
      at each balance sheet date, the value of written put options not designated
      as
      cash flow hedges was adjusted to reflect current fair value and any realized
      and
      unrealized gains or losses were recorded as an increase or decrease in other
      income (expense). During the current year, any realized and unrealized gains
      or
      losses associated with the written put options was recorded as gain (loss)
      on
      derivatives, net, as an in increase or decrease in revenue on the consolidated
      statement of operations with any other undesignated derivatives. The following
      table provides a summary of the fair value of the written put options included
      in other current liabilities (in thousands):




**December
                31,****2006**
            
            **2005**Fair
                value of undesignated written put options
            
            $
            —
            
            $
            (125
            )




F-20
 *Table
          of Contents*





The
      following table provides a summary of the impact on earnings from non-cash
      gains
      (losses) related to changes in the fair values of these derivative contracts
      for
      the three years ended December 31 (in thousands):




**Year
                Ended**
              **December
                31,****2006**
            
            **2005**
            
            **2004**Increase
                (decrease) in earnings due to changes in fair value of written put
                options
            
            $
            125
            
            $
            (92
            )
            $
            (33
            )








The
      following table reflects our open commodity derivative contracts at December
      31,
      2006, the associated volumes and the corresponding weighted average NYMEX
      reference price.





**Settlement
                Period**
            
            **Hedge
                Strategy**
            
            **Natural
                Gas****(MMBTU)**
            
            **Oil****(Barrels)**
            
            **Purchased
                Put****Nymex**
            
            **Written
                Call****Nymex*****Natural
                Gas Costless Collars***01/01/07
                - 01/31/07
            
            
            Cash
                flow
            
            
            180,000
            
            
            
            
            $
            8.00
            
            $
            23.2501/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            270,000
            
            
            
            
            $
            8.00
            
            $
            21.2001/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            225,000
            
            
            
            
            $
            8.00
            
            $
            15.7501/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            170,000
            
            
            
            
            $
            6.50
            
            $
            9.7501/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            150,000
            
            
            
            
            $
            7.25
            
            $
            9.6501/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            90,000
            
            
            
            
            $
            7.50
            
            $
            10.0001/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            300,000
            
            
            
            
            $
            7.25
            
            $
            10.0002/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            300,000
            
            
            
            
            $
            8.00
            
            $
            25.7504/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            280,000
            
            
            
            
            $
            7.00
            
            $
            15.4504/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            280,000
            
            
            
            
            $
            7.25
            
            $
            15.2504/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            280,000
            
            
            
            
            $
            7.00
            
            $
            14.8504/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            700,000
            
            
            
            
            $
            7.50
            
            $
            11.0004/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            350,000
            
            
            
            
            $
            7.00
            
            $
            11.6004/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            350,000
            
            
            
            
            $
            7.00
            
            $
            9.1004/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            350,000
            
            
            
            
            $
            7.25
            
            $
            9.6004/01/07
                - 08/31/07
            
            
            Cash
                flow
            
            
            200,000
            
            
            
            
            $
            7.00
            
            $
            10.0011/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            250,000
            
            
            
            
            $
            8.00
            
            $
            13.4011/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            300,000
            
            
            
            
            $
            8.85
            
            $
            15.0011/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            300,000
            
            
            
            
            $
            9.30
            
            $
            15.0011/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            500,000
            
            
            
            
            $
            7.50
            
            $
            13.30***Oil
                Costless Collars***01/01/07
                - 06/30/07
            
            
            Cash
                flow
            
            
            
            
            
            24,000
            
            $
            59.00
            
            $
            90.0001/01/07
                - 02/28/07
            
            
            Cash
                flow
            
            
            
            
            
            5,000
            
            $
            70.00
            
            $
            85.2001/01/07
                - 04/30/08
            
            
            Cash
                flow
            
            
            
            
            
            38,000
            
            $
            60.00
            
            $
            74.7501/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            
            
            
            21,000
            
            $
            55.00
            
            $
            74.5001/01/07
                - 03/31/07
            
            
            Cash
                flow
            
            
            
            
            
            24,000
            
            $
            50.00
            
            $
            78.2501/01/07
                - 12/31/07
            
            
            Cash
                flow
            
            
            
            
            
            12,000
            
            $
            55.00
            
            $
            79.0004/01/07
                - 09/30/07
            
            
            Cash
                flow
            
            
            
            
            
            30,000
            
            $
            50.00
            
            $
            81.5004/01/07
                - 09/30/07
            
            
            Cash
                flow
            
            
            
            
            
            12,000
            
            $
            56.00
            
            $
            92.5004/01/07
              -
              12/31/07
            
            
            Cash flow
            
            
            
            
            
            33,000
            
            $
            55.00
            
            $
            80.3006/01/07
                - 08/31/07
            
            
            Cash
                flow
            
            
            
            
            
            6,000
            
            $
            65.00
            
            $
            80.0007/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            
            
            
            10,000
            
            $
            58.00
            
            $
            90.5010/01/07
                - 12/31/07
            
            
            Cash
                flow
            
            
            
            
            
            9,000
            
            $
            59.20
            
            $
            90.0010/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            
            
            
            18,000
            
            $
            56.00
            
            $
            89.9510/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            
            
            
            6,000
            
            $
            65.00
            
            $
            80.2511/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            
            
            
            10,000
            
            $
            68.40
            
            $
            90.0001/01/08
                - 03/31/08
            
            
            Cash
                flow
            
            
            
            
            
            7,500
            
            $
            57.60
            
            $
            90.0004/01/08
                - 10/31/08
            
            
            Cash
                flow
            
            
            
            
            
            21,000
            
            $
            65.70
            
            $
            90.00




F-21
 *Table
          of Contents*





The
      following table reflects commodity derivative contracts entered subsequent
      to
      December 31, 2006, the associated volumes and the corresponding weighted average
      NYMEX reference price.





**Settlement
                Period**
            
            **Hedge
                Strategy**
            
            **Natural
                Gas****(MMBTU)**
            
            
            **Purchased
                Put****Nymex**
            
            **Written
                Call****Nymex*****Natural
                Gas Costless Collars***03/01/07
                - 08/31/07
            
            
            Cash
                flow
            
            
            640,000
            
            
            $
            7.00
            
            $
            8.0009/01/07
                - 10/31/07
            
            
            Cash
                flow
            
            
            70,000
            
            
            $
            7.00
            
            $
            9.3511/01/07
                - 03/31/08
            
            
            Cash
                flow
            
            
            150,000
            
            
            $
            8.00
            
            $
            10.20





***Interest
      rate swap***





Periodically,
      Brigham may use interest rate swap contracts to adjust the proportion of its
      total debt that is subject to variable interest rates to fixed rates. Under
      such
      an interest rate swap contract, Brigham agrees to pay an amount equal to a
      specified fixed-rate of interest for a certain notional amount and receive
      in
      return an amount equal to a variable-rate. The notional amounts of the contract
      are not exchanged. No other cash payments are made unless the contract is
      terminated prior to maturity. Although no collateral is held or exchanged for
      the contract, the interest rate swap contract is entered into with a major
      financial institution with an investment grade credit rating in order to
      minimize Brigham’s counterparty credit risk. The interest rate swap contract is
      designated as cash flow hedges against changes in the amount of future cash
      flows associated with Brigham’s interest payments on variable-rate debt. The
      effect of this accounting on operating results is that interest expense on
      a
      portion of variable-rate debt being hedged is recorded based on fixed interest
      rates.





At
      March
      31, 2006, Brigham had an interest rate swap contract to pay a fixed-rate of
      interest of 7.6% on $20.0 million notional amount of senior subordinated notes.
      The $20.0 million notional amount of the outstanding contract was to mature
      in
      March 2009. Brigham used the net proceeds from the Senior Notes offering to
      repay all amounts currently outstanding under its senior and subordinated credit
      agreements which totaled $78.4 million at the time the offering closed.
      Subsequent to this repayment, Brigham terminated the subordinated credit
      agreement and the associated interest rate swap. Upon termination of the
      interest rate swap, Brigham received $838,000 for the fair market value of
      the
      swap, which was recognized as gain (loss) on derivatives, net.





***Fair
      values***





The
      current asset and liability amounts represent the fair values expected to be
      included in the results of operations for the subsequent year. The fair value
      of
      derivative contracts is reflected on the balance sheet as detailed in the
      following schedule (in thousands):




**December
                31,****2006**
            
            **2005**Other
                current liabilities
            
            $
            (5
            )
            $
            (2,112
            )Other
                noncurrent liabilities
            
            
            —
            
            
            (61
            )Other
                current assets
            
            
            5,676
            
            
            224Other
                noncurrent assets
            
            
            904
            
            
            654Net
                fair value of derivative contracts
            
            $
            6,575
            
            $
            (1,295
            )




**12. 
      Financial Instruments**





Brigham’s
      non-derivative financial instruments include cash and cash equivalents, accounts
      receivable, accounts payable and long-term debt. The carrying amount of cash
      and
      cash equivalents, accounts receivable and accounts payable approximate fair
      value because of their immediate or short-term maturities. The carrying value
      of
      Brigham’s senior credit facility approximates its fair market value since it
      bears interest at floating market interest rates. The fair value of Brigham’s
      senior subordinated notes at December 31, 2006 and 2005 was zero and $29.4
      million, respectively. The fair value of Brigham’s Senior Notes at December 31,
      2006 and 2005 was $125.5 million and zero, respectively. The fair value of
      the
      Series A mandatorily redeemable preferred stock at December 31, 2006 and 2005
      was approximately $8.8 million and $8.9 million, respectively.


F-22
 *Table
          of Contents*


Brigham’s
      accounts receivable relate to oil and natural gas sold to various industry
      companies, and amounts due from industry participants for expenditures made
      by
      Brigham on their behalf. Credit terms, typical of industry standards, are of
      a
      short-term nature and Brigham does not require collateral. Brigham’s accounts
      receivable at December 31, 2006 and 2005 do not represent significant credit
      risks as they are dispersed across many counterparties. Counterparties to
      Brigham’s oil and natural gas financial hedges are investment grade financial
      institutions.





**13. 
      Stock Based Compensation**





Brigham
      adopted SFAS 123R using the modified prospective method. Under this transition
      method, compensation cost recognized includes the cost for all stock based
      compensation granted prior to, but not yet vested, as of January 1, 2006. This
      cost was based on the grant date fair value estimated in accordance with the
      original provisions of SFAS 123. The cost for all stock based awards granted
      subsequent to January 1, 2006, was based on the grant date fair value that
      was
      estimated in accordance with the provisions of SFAS 123R. The maximum
      contractual life of stock based awards is seven years and the historical
      forfeiture rate used to estimate forfeitures prospectively is 14.5%. At adoption
      of SFAS 123R, Brigham elected to amortize newly issued and existing granted
      awards on a straight-line basis over the requisite service period including
      estimates of pre-vesting forfeiture rates. If actual forfeitures differ from
      the
      estimates, additional adjustments to compensation expense may be required in
      future periods. Unearned stock compensation recorded under APB 25 of $2.3
      million was eliminated and additional paid-in capital was reduced by a like
      amount on the consolidated balance sheet and consolidated statements of
      stockholders’ equity, in accordance with SFAS 123R. Results for prior periods
      have not been restated.





The
      estimated fair value of the options granted during 2006 and prior periods was
      calculated using a Black-Scholes Merton option pricing model (Black-Scholes).
      The following table summarizes the weighted average assumptions used in the
      2006
      Black-Scholes model:




**2006**
              
              **2005**
              
              **2004**Risk-free
                  interest rate
              
              
              4.7
              %
              
              4.29
              %
              
              3.68
              %Expected
                  life (in years)
              
              
              5.0
              
              
              4.2
              
              
              3.8Expected
                  volatility
              
              
              52
              %
              
              43
              %
              
              43
              %Expected
                  dividend yield
              
              
              —
              
              
              —
              
              
              —Weighted
                  average fair value per share of stock compensation
              
              $
              3.33
              
              $
              4.78
              
              $
              3.31




The
      Black-Scholes model incorporates assumptions to value stock based awards. The
      risk-free rate of interest for periods within the contractual life of the option
      is based on a zero-coupon U.S. government instrument over the contractual term
      of the equity instrument. Expected volatility is based on the historical
      volatility of Brigham’s stock for an equal period of the expected term. The
      expected life is determined using the contractual life and vesting term in
      accordance with the guidance in Staff Accounting Bulletin No. 107 for using
      the
“simplified” method for “plain vanilla” options.





In
      November 2005, the Financial Accounting Standards Board (FASB) issued FASB
      Staff
      Position No. FAS 123R-3, “Transition Election Related to Accounting for the Tax
      Effects of Share-Based Payment Awards.” Brigham elected to adopt the alternative
      transition method provided in the FASB Staff Position for calculating the tax
      effects of stock based compensation pursuant to SFAS 123R. The alternative
      transition method includes simplified methods to establish the beginning balance
      of the additional paid-in capital pool (APIC pool) related to the tax effects
      of
      employee stock based compensation, and to determine the subsequent impact on
      the
      APIC pool and Consolidated Statements of Cash Flows of the tax effects of
      employee stock based compensation awards that are outstanding upon adoption
      of
      SFAS 123R.





Prior
      to
      the adoption of SFAS 123R, Brigham presented all tax benefits of deductions
      resulting from the exercise of stock options as operating cash flows in the
      Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting
      from the tax deductions in excess of the compensation cost recognized for those
      options (excess tax benefits) to be classified as financing cash flows. Brigham
      did not have any excess tax benefits during 2006.





Had
      compensation cost for Brigham's stock options been determined based on the
      fair
      market value at the grant dates of the awards consistent with the methodology
      prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income
      and net income per share for the years ended December 31, 2005 and 2004 would
      have been the pro forma amounts as indicated below (in thousands, except per
      share amounts):


F-23
 *Table
          of Contents*





**Twelve
                Months Ended**
              **Dec
                31, 2005**
            
            **Twelve
                Months Ended**
              **Dec
                31, 2004**Net
                income, as reported
            
            $
            27,435
            
            $
            19,650Add
                back: Stock compensation expense previously included in net
                income
            
            
            462
            
            
            434Effect
                of total employee stock-based compensation expense, determined under
                fair
                value method for all awards
            
            
            (1,330
            )
            
            (3,189
            )Pro
                forma
            
            $
            26,567
            
            $
            16,895Net
                income per share:Basic,
                as reported
            
            $
            0.65
            
            $
            0.49Basic,
                pro forma
            
            
            0.63
            
            
            0.42Diluted,
                as reported
            
            $
            0.63
            
            $
            0.47Diluted,
                pro forma
            
            
            0.61
            
            
            0.41




Prior
      to
      January 1, 2006, Brigham’s stock compensation expense largely consisted of the
      amortization of unearned stock compensation due to unvested (restricted) stock,
      in accordance with APB 25. The following table summarizes the components of
      stock based compensation included in general and administrative expense (in
      thousands):





**Twelve
                Months Ended**
              **December
                31,****2006**
            
            **2005**
            
            **2004**Pre-tax
                stock based compensation expense
            
            $
            2,879
            
            $
            706
            
            $
            629Capitalized
                stock based compensation
            
            
            (1,308
            )
            
            (337
            )
            
            (291
            )Tax
                benefit
            
            
            (550
            )
            
            (129
            )
            
            (118
            )Stock
                based compensation expense, net
            
            $
            1,021
            
            $
            240
            
            $
            220





The
      adoption of SFAS 123R did not impact basic and diluted net income per share
      for
      the year ended December 31, 2006





Brigham
      provides an incentive plan for the issuance of stock options, stock appreciation
      rights, stock, restricted stock, cash or any combination of the foregoing.
      The
      objective of this plan is to provide incentive and reward key employees whose
      performance may have a significant impact on the success of Brigham. It is
      Brigham’s policy to use unissued shares of stock when stock options are
      exercised. The number of shares available under the plan is equal to the lesser
      of 5,915,414 or 15% of the total number of shares of common stock outstanding.
      At December 31, 2006, approximately 940,420 shares remain available for grant
      under the current incentive plan. The Compensation Committee of the Board of
      Directors determines the type of awards made to each participant and the terms,
      conditions and limitations applicable to each award. Except for one stock option
      grant, options granted subsequent to March 4, 1997 have an exercise price equal
      to the fair market value of Brigham’s common stock on the date of grant, vest
      over five years and have a contractual life of seven years.





Brigham
      also maintains a director stock option plan under which stock options are
      awarded to non-employee directors. Options granted under this plan have an
      exercise price equal to the fair market value of Brigham common stock on the
      date of grant and vest over five years. Stockholders have authorized the
      issuance of 430,000 shares to non-employee directors and approximately 2,300
      remain available for grant under the director stock option
      plan.


F-24
 *Table
          of Contents*


The
      following table summarizes option activity under the incentive plans for each
      of
      the three years ended December 31, 2006:








**2006**
            
            **2005**
            
            **2004****Shares**
            
            **Weighted-
                Average Exercise****Price**
            
            **Shares**
            
            **Weighted-
                Average Exercise****Price**
            
            **Shares**
            
            **Weighted-
                Average Exercise****Price**Options
                outstanding at beginning of year
            
            
            2,946,333
            
            $
            6.96
            
            
            2,977,600
            
            $
            6.01
            
            
            2,582,675
            
            $
            4.78Granted
            
            
            608,000
            
            $
            6.57
            
            
            350,000
            
            $
            12.13
            
            
            790,000
            
            $
            8.75Forfeited
                or cancelled
            
            
            (215,667
            )
            $
            4.96
            
            
            (40,800
            )
            $
            6.92
            
            
            (80,894
            )
            $
            (4.72
            )Exercised
            
            
            (95,100
            )
            $
            4.93
            
            
            (340,467
            )
            $
            3.88
            
            
            (314,181
            )
            $
            (3.06
            )Options
                outstanding at end of year
            
            
            3,243,566
            
            $
            7.08
            
            
            2,946,333
            
            $
            6.96
            
            
            2,977,600
            
            $
            6.01Options
                exercisable at end of year
            
            
            1,439,866
            
            $
            6.18
            
            
            1,085,133
            
            $
            5.31
            
            
            792,557
            
            $
            4.30








The
      weighted-average grant-date fair value of share options granted during the
      years
      ended December 31, 2006, 2005, and 2004 was $3.33, $4.78, and $3.31,
      respectively. The total intrinsic value of options exercised during the years
      ended December 31, 2006, 2005 and 2004 was $401,667, $2.3 million, and $1.5
      million, respectively





The
      following table summarizes information about stock options outstanding at
      December 31, 2006:




**Options
                Outstanding**
            
            **Options
                Exercisable****Exercise
                Price**
            
            **Number
                Outstanding at December 31,****2006**
            
            **Weighted-
                Average Remaining****Contractual
                Life**
            
            **Weighted-
                Average****Exercise
                Price**
            
            **Number
                Exercisable at December 31,****2006**
            
            **Weighted-
                Average Remaining****Contractual
                Life**
            
            **Weighted-
                Average****Exercise
                Price**$3.05
                to $3.41
            
            
            231,166
            
            
            1.9
                years
            
            $
            3.35
            
            
            214,866
            
            
            1.9
                years
            
            $
            3.343.66  to  5.08
            
            
            497,900
            
            
            2.5
                years
            
            $
            4.22
            
            
            388,700
            
            
            2.4
                years
            
            $
            4.216.14  to  6.73
            
            
            1,267,000
            
            
            4.8
                years
            
            $
            6.50
            
            
            473,000
            
            
            3.8
                years
            
            $
            6.697.08  to  8.84
            
            
            832,500
            
            
            5.0
                years
            
            $
            8.50
            
            
            282,300
            
            
            4.6
                years
            
            $
            8.698.93 to 12.31
            
            
            415,000
            
            
            5.7
                years
            
            $
            11.47
            
            
            81,000
            
            
            5.7
                years
            
            $
            11.503.05 to 12.31
            
            
            3,243,566
            
            
            4.4
                years
            
            $
            7.08
            
            
            1,439,866
            
            
            3.4
                years
            
            $
            6.18





The
      aggregate intrinsic value of options outstanding and exercisable at December
      31,
      2006 was $3.5 million and $2.4 million, respectively. The aggregate intrinsic
      value represents the total pre-tax value (the difference between Brigham’s
      closing stock price on the last trading day of 2006 and the exercise price,
      multiplied by the number of in-the-money options) that would have been received
      by the option holders had all option holders exercised their options on December
      31, 2006. The amount of aggregate intrinsic value will change based on the
      fair
      market value of Brigham’s stock.





As
      of
      December 31, 2006 there was approximately $5.9 million of total unrecognized
      compensation expense related to unvested stock based compensation plans. This
      compensation expense is expected to be recognized, net of forfeitures, on a
      straight-line basis over the remaining vesting period of approximately 3.3
      years.





***Restricted
      Stock***





During
      the years ended December 31, 2006 and 2005, Brigham issued 129,595 and 137,650,
      respectively, restricted shares of common stock as compensation to officers
      and
      employees of Brigham. The restricted shares vest over five years or cliff-vest
      at the end of five years. As of December 31, 2006, there was approximately
      $2.3
      million of total unrecognized compensation expense related to unvested
      restricted stock. This compensation expense is expected to be recognized, net
      of
      forfeitures, over the remaining weighted average vesting period of approximately
      2.3 years. Brigham had previously assumed a zero percent forfeiture rate for
      restricted stock. During 2006, stock compensation expense related to unvested
      restricted stock was adjusted to recognize actual forfeitures during the year
      as
      they occurred. Brigham has assumed a 6% weighted average forfeiture rate for
      restricted stock to be used prospectively at December 31, 2006. If actual
      forfeitures differ from the estimates, additional adjustments to compensation
      expense may be required in future periods.


F-25
 *Table
          of Contents*


The
      following table reflects the outstanding restricted stock awards and activity
      related thereto for the years ended December 31:





**Year
                Ended****December
                31, 2006**
            
            **Year
                Ended****December
                31, 2005****Number
                of****Shares**
            
            **Weighted-
                Average****Price**
            
            **Number
                of****Shares**
            
            **Weighted-
                Average****Price**Restricted
                Stock Awards:Restricted
                shares outstanding at the beginning of the year
            
            
            397,650
            
            $
            7.22
            
            
            325,000
            
            $
            5.65Shares
                granted
            
            
            129,595
            
            $
            10.84
            
            
            137,650
            
            $
            10.42Lapse
                of restrictions
            
            
            (77,530
            )
            $
            6.37
            
            
            (65,000
            )
            $
            5.23Forfeitures
            
            
            (58,348
            )
            $
            8.16
            
            
            —
            
            $
            —Restricted
                shares outstanding at the end of the year
            
            
            391,367
            
            $
            8.60
            
            
            397,650
            
            $
            7.22




**14. 
      Employee Benefit Plans**





Brigham
      has adopted a defined contribution 401(k) plan for substantially all of its
      employees. The plan provides for Brigham matching of employee contributions
      to
      the plan, at Brigham’s discretion. During 2006, 2005 and 2004, Brigham provided
      a base match equal to 25% of eligible employee contributions. Based on
      attainment of performance goals established at the beginning of each fiscal
      year, Brigham matched an additional 45%, 41%, and 25.25% of eligible employee
      contributions made during 2006, 2005 and 2004, respectively. Brigham contributed
      approximately $230,000, $303,000, and $204,000 to the 401(k) plan for the years
      ended December 31, 2006, 2005 and 2004, respectively, to match eligible
      contributions by employees





**15. 
      Related Party Transactions**





During
      the years ended December 31, 2006, 2005, and 2004, Brigham incurred costs of
      approximately $4.1 million, $2.3 million and $2.9 million, respectively, in
      fees
      for land acquisition services performed by a company owned by a brother of
      Brigham’s Chairman, President and Chief Executive Officer and its Executive Vice
      President — Land and Administration. Other participants in Brigham’s 3-D seismic
      projects reimbursed Brigham for a portion of these amounts. At December 31,
      2006
      and 2005, Brigham had a liability recorded in accounts payable of approximately
      $300 and $25,000, respectively, related to services performed by this
      company.





Mr.
      Harold Carter, a director of Brigham, served as a consultant to Brigham on
      various aspects of its business and strategic issues. Fees paid for these
      services by Brigham were approximately $30,000 for each the years ended December
      31, 2006, 2005, and 2004. Additional payments totaling approximately $12,000
      were made during each of the years ended December 31, 2006, 2005, and 2004,
      for
      the reimbursement of certain expenses. At December 31, 2006 and 2005, there
      were
      no payables related to these services recorded by Brigham.





From
      time
      to time, in the normal course of business, Brigham has engaged a drilling
      company in which Mr. Steven Webster, one of Brigham’s current directors, owns
      stock and serves on the board of directors. There were no payments to the
      drilling company during 2006. Total payments to the drilling company during
      2005
      and 2004 were $3.5 million, and $3.5 million, respectively. Brigham did not
      owe
      the drilling company any amounts at December 31, 2006 and 2005. Brigham owed
      the
      drilling company approximately $0.7 million at December 31, 2004. At December
      31, 2006, there were no short-term accounts receivable from Mr. Webster. At
      December 31, 2005, and 2004, Brigham had short-term accounts receivable from
      Mr.
      Webster of approximately $1,500 and $2,200, respectively. These receivables
      represent the director’s share of costs related to his working interest
      ownership in the Staubach #1, Burkhart #1R and Matthes-Huebner #1 wells that
      are
      operated by Brigham. Mr. Webster obtained his interest in these wells through
      an
      exploration and production company, Carrizo, that is not affiliated with
      Brigham. Mr. Webster was a co-founder of Carrizo and is currently chairman
      of
      Carrizo’s board of directors. At December 31, 2006, 2005, and 2004, Carrizo owed
      Brigham $71,000, $175,000, and $114,000, respectively, for exploration and
      production activities. Brigham had no accounts payable owed to Carrizo at
      December 31, 2006. Brigham owed Carrizo $20,000 and $0 at December 31, 2005
      and
      2004, respectively. Mr. Webster is also chairman of the board of directors
      for a
      well services company that Brigham made payments totaling approximately $1.1
      million and $560,000 during 2006 and 2005. Brigham had no accounts payable
      owed
      to the well services company at December 31, 2006. Brigham owed the well
      services company approximately $43,000 at December 31, 2005.


F-26
 *Table
          of Contents*


From
      time
      to time, in the normal course of business, Brigham has engaged a service company
      in which Mr. Hobart Smith, one of Brigham’s current directors, owns stock and
      serves as a consultant. Total payments to the service company during 2006,
      2005
      and 2004 were $1.9 million, $1.2 million, and $1 million, respectively. At
      December 31, 2006, 2005, and 2004, Brigham owed the service company
      approximately $77,000, $61,000, and $132,000, respectively.





**16. 
      Supplemental Cash Flow Information**





Supplemental
      cash flow information consists of the following (in thousands):





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**Cash
                paid for interest, net of capitalized amounts
            
            $
            5,893
            
            $
            2,575
            
            $
            1,634Noncash
                investing and financing activities:Dividends
                and accretion on mandatorily redeemable preferred stock
            
            
            —
            
            
            581
            
            
            726Capitalized
                asset retirement obligations
            
            
            610
            
            
            1,324
            
            
            512Accrued
                drilling costs
            
            
            11,092
            
            
            6,119
            
            
            2,183Capitalized
                stock compensation
            
            
            1,308
            
            
            337
            
            
            291Issuance
                of restricted stock
            
            
            —
            
            
            1,435
            
            
            514Forfeitures
                of restricted stock
            
            
            —
            
            
            —
            
            
            131





**17. 
      Other Assets and Liabilities**





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





**December
                31****2006**
            
            **2005**Prepayments
            
            $
            932
            
            $
            593Other
            
            
            1,458
            
            
            226$
            2,390
            
            $
            819





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





**December
                31****2006**
            
            **2005**Accrued
                interest
            
            $
            2,191
            
            $
            722Derivative
                liabilities
            
            
            5
            
            
            2,236Other
                accrued liabilities
            
            
            3,481
            
            
            1,161$
            5,677
            
            $
            4,119




F-27
 *Table
          of Contents*


**BRIGHAM
      EXPORATION COMPANY**





**SUPPLEMENTAL
      OIL AND GAS INFORMATION (UNAUDITED)**





**Oil
      and Natural Gas Exploration and Production Activities**





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





***Costs
      Incurred and Capitalized Costs***





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





**December
                31,****2006**
            
            **2005**
            
            **2004**Costs
                incurred for the year:Exploration
                (including geological and geophysical costs)
            
            $
            77,704
            
            $
            54,338
            
            $
            30,327Property
                acquisition
            
            
            15,846
            
            
            15,701
            
            
            6,226Development
            
            
            91,058
            
            
            48,588
            
            
            50,872$
            184,608
            
            $
            118,627
            
            $
            87,425





Excluded
      costs for prospects are accumulated by year. Costs are reflected in the full
      cost pool as the drilling program is executed or as costs are evaluated and
      deemed impaired. Brigham anticipates these excluded costs will be included
      in
      the depletion computation over the next five years. Brigham is unable to predict
      the future impact on depletion rates. The following is a summary of capitalized
      costs (in thousands) excluded from depletion at December 31, 2006 by year
      incurred.




**December
                31,****2006**
            
            **2005**
            
            **2004**
            
            **Prior****Years**
            
            **Total**Property
                acquisition
            
            $
            5,267
            
            $
            6,209
            
            $
            2,816
            
            $
            3,257
            
            $
            17,549Exploration
                (including geological and geophysical costs)
            
            
            17,623
            
            
            4,423
            
            
            4,802
            
            
            9,222
            
            
            36,070Drilling
            
            
            19,312
            
            
            —
            
            
            —
            
            
            —
            
            
            19,312Capitalized
                interest
            
            
            2,120
            
            
            —
            
            
            —
            
            
            —
            
            
            2,120Total
            
            $
            44,322
            
            $
            10,632
            
            $
            7,618
            
            $
            12,479
            
            $
            75,051





**Oil
      and Natural Gas Reserves and Related Financial Data**





Information
      with respect to Brigham’s oil and natural gas producing activities is presented
      in the following tables. Reserve quantities, as well as certain information
      regarding future production and discounted cash flows, were determined by
      Brigham’s independent petroleum consultants, Cawley, Gillespie and Associates,
      Inc.





***Oil
      and Natural Gas Reserve Data***





The
      following tables present Brigham’s independent petroleum consultants’ estimates
      of its proved oil and natural gas reserves. Brigham emphasizes reserves are
      approximates and are expected to change as additional information becomes
      available. Reservoir engineering is a subjective process of estimating
      underground accumulations of oil and natural gas that cannot be measured in
      an
      exact way, and the accuracy of any reserve estimate is a function of the quality
      of available data and of engineering and geological interpretation and
      judgment.


F-28
 *Table
          of Contents*





**Natural
                Gas****(MMcf)**
            
            **Oil****(MBbls)**Proved
                reserves at December 31, 2003
            
            
            109,403
            
            
            4,130Revisions
                of previous estimates
            
            
            (11,142
            )
            
            (642
            )Extensions,
                discoveries and other additions
            
            
            12,444
            
            
            321Production
            
            
            (8,830
            )
            
            (573
            )Proved
                reserves at December 31, 2004
            
            
            101,875
            
            
            3,236Revisions
                of previous estimates
            
            
            (595
            )
            
            (11
            )Purchases
                of reserves in place
            
            
            4,054
            
            
            65Extensions,
                discoveries and other additions
            
            
            17,143
            
            
            486Production
            
            
            (9,213
            )
            
            (450
            )Proved
                reserves at December 31, 2005
            
            
            113,264
            
            
            3,326Revisions
                of previous estimates
            
            
            (861
            )
            
            97Extensions,
                discoveries and other additions
            
            
            17,687
            
            
            1,513Production
            
            
            (10,603
            )
            
            (442
            )Proved
                reserves at December 31, 2006
            
            
            119,487
            
            
            4,494Proved
                developed reserves at December 31:2003
            
            
            49,920
            
            
            2,8632004
            
            
            47,494
            
            
            2,1242005
            
            
            55,664
            
            
            2,0692006
            
            
            64,401
            
            
            2,752





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





***Standardized
      Measure of Discounted Future Net Cash Inflows and Changes
      Therein***





The
      following table presents a standardized measure of discounted future net cash
      inflows (in thousands) relating to proved oil and natural gas reserves. Future
      cash flows were computed by applying year-end prices of oil and natural gas
      relating to Brigham’s proved reserves to the estimated year-end quantities of
      those reserves. Future price changes were considered only to the extent provided
      by contractual agreements in existence at year-end. Future production and
      development costs were computed by estimating those expenditures expected to
      occur in developing and producing the proved oil and natural gas reserves at
      the
      end of the year, based on year-end costs. Actual future cash inflows may vary
      considerably, and the standardized measure does not necessarily represent the
      fair value of Brigham’s oil and natural gas reserves.




**December
                31,****2006**
            
            **2005**
            
            **2004**Future
                cash inflows
            
            $
            900,982
            
            $
            1,259,009
            
            $
            766,344Future
                production costs
            
            
            (186,440
            )
            
            (220,499
            )
            
            (159,697
            )Future
                development costs
            
            
            (145,949
            )
            
            (122,419
            )
            
            (79,868
            )Future
                income tax expense
            
            
            (83,591
            )
            
            (237,268
            )
            
            (116,254
            )Future
                net cash inflows
            
            
            485,002
            
            
            678,823
            
            
            410,52510%
                annual discount for estimated timing of cash flows
            
            
            (182,328
            )
            
            (282,482
            )
            
            (170,816
            )Standardized
                measure of discounted future net cash flows
            
            $
            302,674
            
            $
            396,341
            
            $
            239,709




F-29
 *Table
          of Contents*


Year-end
      spot prices were adjusted to reflect applicable transportation and quality
      differentials on a well-by-well basis to arrive at realized sales prices used
      to
      estimate Brigham’s reserves. The sales prices for Brigham’s reserve estimates
      were as follows:




**Natural
                Gas****(MMbtu)**
            
            **Oil****(Bbl)**December
                31, 2006
            
            $
            5.48
            
            $
            61.06December
                31, 2005
            
            
            9.44
            
            
            61.04December
                31, 2004
            
            
            6.19
            
            
            43.46





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





**December
                31,****2006**
            
            **2005**
            
            **2004**Beginning
                of period
            
            $
            396,341
            
            $
            239,709
            
            $
            261,598Sales
                of oil and natural gas produced, net of production costs
            
            
            (85,070
            )
            
            (90,480
            )
            
            (67,127
            )Previously
                estimated development costs incurred during the period
            
            
            51,373
            
            
            17,524
            
            
            37,109Extensions
                and discoveries
            
            
            55,020
            
            
            78,184
            
            
            27,053Net
                change of prices and production costs
            
            
            (243,607
            )
            
            171,764
            
            
            38,027Change
                in future development costs
            
            
            (27,214
            )
            
            (32,838
            )
            
            (40,086
            )Changes
                in production rates (timing)
            
            
            5,905
            
            
            32,284
            
            
            (33,579
            )Revisions
                of previous quantity estimates
            
            
            (883
            )
            
            (2,871
            )
            
            (47,327
            )Accretion
                of discount
            
            
            51,981
            
            
            29,447
            
            
            34,381Change
                in income taxes
            
            
            88,842
            
            
            (68,711
            )
            
            27,452Purchases
                of reserves in place
            
            
            —
            
            
            14,221
            
            
            —Other
            
            
            9,986
            
            
            8,108
            
            
            2,208End
                of period
            
            $
            302,674
            
            $
            396,341
            
            $
            239,709




F-30
 *Table
          of Contents*


**BRIGHAM
      EXPLORATION COMPANY**





**SUPPLEMENTAL
      QUARTERLY FINANCIAL INFORMATION**





**Quarterly
      Financial Data (Unaudited)**





**Year
                Ended December 31, 2006****Quarter**
              **1**
            
            **Quarter**
              **2**
            
            **Quarter**
              **3**
            
            **Quarter**
              **4**Revenue
            
            $
            25,546
            
            $
            25,828
            
            $
            26,023
            
            $
            28,900Operating
                income
            
            
            9,462
            
            
            8,752
            
            
            7,977
            
            
            10,257Net
                income
            
            
            5,875
            
            
            3,666
            
            
            5,246
            
            
            5,001Net
                income per share:Basic
            
            $
            0.13
            
            $
            0.08
            
            $
            0.12
            
            $
            0.11Diluted
            
            $
            0.13
            
            $
            0.08
            
            $
            0.12
            
            $
            0.11








**Year
                Ended December 31, 2005****Quarter**
              **1**
            
            **Quarter**
              **2**
            
            **Quarter**
              **3**
            
            **Quarter**
              **4**Revenue
            
            $
            16,746
            
            $
            18,490
            
            $
            25,226
            
            $
            36,758Operating
                income
            
            
            5,954
            
            
            8,003
            
            
            13,447
            
            
            19,379Net
                income
            
            
            3,048
            
            
            4,810
            
            
            7,678
            
            
            11,899Net
                income per share:Basic
            
            $
            0.07
            
            $
            0.11
            
            $
            0.18
            
            $
            0.27Diluted
            
            $
            0.07
            
            $
            0.11
            
            $
            0.18
            
            $
            0.26


F-31
 *Table
          of Contents*




INDEX
                  TO EXHIBITS**Number**
              
              **Description**3.1
              —
              Certificate
                  of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement
                  on Form S-1 (Registration No. 333-22491), and incorporated herein
                  by
                  reference).3.2
              —
              Certificates
                  of Amendment to Certificate of Incorporation (filed as Exhibit
                  3.1.1 to
                  Brigham’s Registration Statement on Form S-3 (Registration No. 333-37558),
                  and incorporated herein by reference).3.3
              —
              Bylaws
                  (filed as Exhibit 3.2 to Brigham’s Registration Statement on Form S-1
                  (Registration No. 333-22491), and incorporated herein by
                  reference).4.1
              —
              Form
                  of Common Stock Certificate (filed as Exhibit 4.1 to Brigham’s
                  Registration Statement on Form S-1 (Registration No. 333-22491),
                  and
                  incorporated herein by reference).4.2
              —
              Certificate
                  of Designations of Series A Preferred Stock (Par Value $.01 Per
                  Share) of
                  Brigham Exploration Company filed October 31, 2000 (filed as Exhibit
                  4.1
                  to Brigham’s Current Report on Form 8-K, as amended (filed November 8,
                  2000), and incorporated herein by reference).4.3
              —
              Certificate
                  of Amendment of Certificate of Designations of Series A Preferred
                  Stock
                  (Par Value $.01 Per Share) of Brigham Exploration Company, filed
                  March 2,
                  2001 (filed as Exhibit 4.2.1 to Brigham’s Annual Report on Form 10-K for
                  the year ended December 31, 2000 (filed March 23, 2001), and incorporated
                  herein by reference).4.4
              —
              Certificate
                  of Designations of Series B Preferred Stock (Par Value $.01 Per
                  Share) of
                  Brigham Exploration Company filed December 20, 2002 (filed as Exhibit
                  4.4
                  to Brigham’s Annual Report on Form 10-K for the year ended December 31,
                  2002 (filed March 31, 2003) and incorporated herein by
                  reference).4.5
              —
              Certificate
                  of Elimination of Certificate of Designations of Series B Preferred
                  Stock
                  of Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit
                  99.2
                  to Brigham’s Current Report on Form 8-K (filed July 20, 2004), and
                  incorporated herein by reference).4.6
              —
              Indenture,
                  dated April 20, 2006, among Brigham Exploration Company, the Guarantors
                  named therein and Wells Fargo Bank, N.A., as trustee (filed as
                  Exhibit 4.1
                  to Brigham’s Current Report on Form 8-K, as amended (filed April 24,
                  2006), and incorporated herein by reference).4.7
              —
              Notations
                  of Guarantees, dated April 20, 2006, among Brigham Exploration
                  Company,
                  the Guarantors named therein and Wells Fargo Bank, N.A., as trustee,
                  (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K, as amended
                  (filed April 24, 2006), and incorporated herein by
                  reference).4.8
              —
              Rule
                  144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed
                  as Exhibit
                  4.3 to Brigham’s Current Report on Form 8-K, as amended (filed April 24,
                  2006), and incorporated herein by reference).4.9
              —
              Reg
                  S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as
                  Exhibit 4.4
                  to Brigham’s Current Report on Form 8-K, as amended (filed April 24,
                  2006), and incorporated herein by reference).10.1
              —
              Amended
                  and Restated Agreement of Limited Partnership of Brigham Oil & Gas,
                  L.P., dated December 30, 1997 by and among Brigham, Inc., Brigham
                  Holdings
                  I, L.L.C. and Brigham Holdings II, L.L.C. (filed as Exhibit 10.1.4
                  to
                  Brigham’s Annual Report on Form 10-K for the year ended December 31, 1998,
                  and incorporated herein by reference)10.2*
              —
              Consulting
                  Agreement dated May 1, 1997, by and between Brigham Oil & Gas, L.P.
                  and Harold D. Carter (filed as Exhibit 10.4 to Brigham’s Registration
                  Statement on Form S-1 (Registration No. 33-53873), and incorporated
                  herein
                  by reference).10.3*
              —
              Letter
                  agreement, dated as of March 20, 2000, setting forth amendments
                  effective
                  January 1, 2000, to the Consulting Agreement, dated May 1, 1997,
                  by and
                  between Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit
                  10.5.1 to Brigham’s Annual Report on Form 10-K for the year ended December
                  31, 1999, and incorporated herein by reference).10.4*
              —
              Letter
                  agreement, setting forth amendments to the Consulting Agreement,
                  dated May
                  1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter.
                  (filed as Exhibit 10.4 to Brigham’s Annual Report on Form 10-K for the
                  year ended December 31, 2003 and incorporated herein by
                  reference10.5*
              —
              Employment
                  Agreement, by and between Brigham Exploration Company and Ben M.
                  Brigham
                  (filed as Exhibit 10.7 to Brigham’s Registration Statement on Form S-1
                  (Registration No. 333-22491), and incorporated herein by
                  reference).10.6*
              —
              1997
                  Incentive Plan of Brigham Exploration Company as amended through
                  April 9,
                  2003 (filed as Appendix B to Brigham’s Definitive Proxy Statement on
                  Schedule 14-A on May 7, 2003 and incorporated herein by
                  reference).10.7*
              —
              Form
                  of Option Agreement for certain executive officers (filed as Exhibit
                  10.9.1 to Brigham’s Registration Statement on Form S-1 (Registration No.
                  333-22491), and incorporated herein by reference).10.8*
              —
              Form
                  of Restricted Stock Agreement for certain executive officers dated
                  as of
                  October 27, 2000 (filed as Exhibit 10.8.2 to Brigham’s Annual Report on
                  Form 10-K for the year ended December 31, 2000 (filed March 23,
                  2001), and
                  incorporated herein by reference).10.9
              —
              Two
                  Bridgepoint Lease Agreement dated September 30, 1996, by and between
                  Investors Life Insurance Company of North America and Brigham Oil
&
                  Gas, L.P. (filed as Exhibit 10.14 to Brigham’s Registration Statement on
                  Form S-1 (Registration No. 333-22491), and incorporated herein
                  by
                  reference).10.10
              —
              First
                  Amendment to Two Bridge Point Lease Agreement dated April 11, 1997
                  between
                  Investors Life Insurance Company of North America and Brigham Oil
&
                  Gas, L.P. (filed as Exhibit 10.9.1 to Brigham’s Registration Statement on
                  Form S-1 (Registration No. 333-53873), and incorporated herein
                  by
                  reference).10.11
              —
              Second
                  Amendment to Two Bridge Point Lease Agreement dated October 13,
                  1997
                  between Investors Life Insurance Company of North America and Brigham
                  Oil
                  & Gas, L.P. (filed as Exhibit 10.9.2 to Brigham’s Registration
                  Statement on Form S-1 (Registration No. 333-53873), and incorporated
                  herein by reference).


10.12
                —
                Letter
                    dated April 17, 1998 exercising Right of First Refusal to Lease
‘3rd
                    Option Space’ (filed as Exhibit 10.9.3 to Brigham’s Registration Statement
                    on Form S-1 (Registration No. 333-53873), and incorporated herein
                    by
                    reference).10.13
                —
                Third
                    Amendment to Two Bridge Point Lease Agreement dated November
                    1998 between
                    Hub Properties Trust and Brigham Oil & Gas, L.P. (filed as Exhibit
                    10.14 to Brigham's Annual Report on Form 10-K for the year ended
                    December
                    31, 2004 and incorporated herein by reference).10.14
                —
                Fourth
                    Amendment to Two Bridge Point Lease Agreement dated February
                    7, 2002
                    between Hub Properties Trust and Brigham Oil & Gas, L.P. (filed as
                    Exhibit 10.13 to Brigham's Annual Report on Form 10-K for the
                    year ended
                    December 31, 2004 and incorporated herein by
                    reference).10.15
                —
                Fifth
                    Amendment to Two Bridge Point Lease Agreement dated December
                    20, 2004
                    between Hub Properties Trust, a Maryland real estate investment
                    trust, and
                    Brigham Oil & Gas, L.P. (filed as Exhibit 10.15 to Brigham's Annual
                    Report on Form 10-K for the year ended December 31, 2004 and
                    incorporated
                    herein by reference).10.16
                —
                Registration
                    Rights Agreement dated February 26, 1997 by and among Brigham
                    Exploration
                    Company, General Atlantic Partners III L.P., GAP-Brigham Partners,
                    L.P.,
                    RIMCO Partners, L.P. II, RIMCO Partners L.P. III, and RIMCO Partners,
                    L.P.
                    IV, Ben M. Brigham, Anne L. Brigham, Harold D. Carter, Craig
                    M. Fleming,
                    David T. Brigham and Jon L. Glass (filed as Exhibit 10.29 to
                    Brigham’s
                    Registration Statement on Form S-1 (Registration No. 333-22491),
                    and
                    incorporated herein by reference).10.17*
                —
                1997
                    Director Stock Option Plan, as amended as of April 9, 2003. (filed
                    as
                    Exhibit 10.15 to Brigham’s Annual Report on Form 10-K for the year ended
                    December 31, 2003 and incorporated herein by reference10.18
                —
                Form
                    of Employee Stock Ownership Agreement (filed as Exhibit 10.31
                    to Brigham’s
                    Registration Statement on Form S-1 (Registration No. 333-22491),
                    and
                    incorporated herein by reference).10.19
                —
                Form
                    Change of Control Agreement dated as of September 20, 1999 between
                    Brigham
                    Exploration Company and certain Officers (filed as Exhibit 10.3
                    to
                    Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended
                    September 30, 1999 and incorporated by reference
                    herein).


F-32
 *Table
          of Contents*




10.20
                —
                Registration
                    Rights Agreement dated November 1, 2000 by and between Brigham
                    Exploration
                    Company, DLJ MB Funding III, Inc., and DLJ ESC II, LP. (filed
                    as Exhibit
                    10.10 to Brigham’s Current Report on Form 8-K, as amended (filed November
                    8, 2000), and incorporated herein by reference).10.21
                —
                First
                    Amendment to Registration Rights Agreement, dated March 5, 2001,
                    by and
                    among Brigham Exploration Company, DLJMB Funding III, Inc., DLJ
                    Merchant
                    Banking Partners III, LP, DLJ ESC II, LP and DLJ Offshore Partners
                    III, CV
                    (filed as Exhibit 10.71 to Brigham’s Annual Report on Form 10-K for the
                    year ended December 31, 2000 (filed March 23, 2001), and incorporated
                    herein by reference).10.22
                —
                Registration
                    Rights Agreement dated December 20, 2002 between Brigham Exploration
                    Company and Shell Capital Inc. (filed as Exhibit 10.50 to Brigham’s Annual
                    Report on Form 10-K for the year ended December 31, 2002 and
                    incorporated
                    herein by reference).10.23
                —
                Second
                    Amendment to Registration Rights Agreement dated December 21,
                    2002 between
                    Brigham Exploration Company and Credit Suisse First Boston Entities
                    (filed
                    as Exhibit 10.51 to Brigham’s Annual Report on Form 10-K for the year
                    ended December 31, 2002 and incorporated herein by
                    reference).10.24
                —
                Third
                    Amendment to Registration Rights Agreement May 24, 2004 between
                    Brigham
                    Exploration Company and Credit Suisse First Boston Entities (filed
                    as
                    Exhibit 99.1 to Brigham’s Current Report on Form 8-K (filed July 20,
                    2004), and incorporated herein by reference).10.25
                —
                Third
                    Amended and Restated Credit Agreement, dated January 21, 2005
                    between
                    Brigham Oil & Gas, L.P., Société Générale, Societe Generale, The Royal
                    Bank of Scotland plc and Bank of America, N.A.10.26
                —
                Second
                    Amended and Restated Subordinated Credit Agreement dated January
                    21, 2005
                    between Brigham Oil & Gas, L.P., and The Royal Bank of Scotland
                    plc.10.27
                —
                Fourth
                    Amended and Restated Credit Agreement, dated June 29, 2005 between
                    Brigham
                    Oil & Gas, L.P., Bank of America, N.A., The
                    Royal Bank of Scotland plc, BNP Paribas and Banc of America Securities
                    LLC. (filed as Exhibit 10.1 to Brigham’s Quarterly Report on Form 10-Q for
                    the six month period ended June 30, 2005 and incorporated herein
                    by
                    reference).10.28
                —
                The
                    Resignation of Agent, Appointment of Successor Agent and Assignment
                    of
                    Security Instruments dated June 29, 2005 by and among Brigham
                    Oil &
                    Gas, L.P., Société Générale and Bank of America, N.A. (filed as Exhibit
                    10.2 to Brigham’s Quarterly Report on Form 10-Q for the six month period
                    ended June 30, 2005 and incorporated herein by
                    reference).10.29
                —
                First
                    Amendment to Second Amended and Restated Subordinated Credit
                    Agreement
                    dated June 29, 2005, between Brigham Oil & Gas, L.P., and The Royal
                    Bank of Scotland plc. (filed as Exhibit 10.3 to Brigham’s Quarterly Report
                    on Form 10-Q for the six month period ended June 30, 2005 and
                    incorporated
                    herein by reference).10.30
                —
                Second
                    Amended and Restated Intercreditor and Subordination Agreement,
                    dated
                    January 21, 2005 (filed as Exhibit 10.4 to Brigham’s Quarterly Report on
                    Form 10-Q for the six month period ended June 30, 2005 and incorporated
                    herein by reference).10.31
                —
                First
                    Amendment to the Second Amended and Restated Intercreditor and
                    Subordination Agreement (filed as Exhibit 10.5 to Brigham’s Quarterly
                    Report on Form 10-Q for the six month period ended June 30, 2005
                    and
                    incorporated herein by reference).10.32*
                —
                Form
                    of Restricted Stock Agreement (filed as Exhibit 10.1 to Brigham’s
                    Quarterly Report on Form 10-Q for the nine month period ended
                    September
                    30, 2005 and incorporated herein by reference).10.33
                —
                Second
                    Amendment to Second Amended Restated Subordinated Credit Agreement
                    dated
                    December 19, 2005 between Brigham Oil & Gas L.P., and The Royal Bank
                    of Scotland plc.10.34
                —
                Purchase
                    Agreement dated April 12, 2006, among Brigham Exploration Company,
                    the
                    Guarantors named therein (filed as Exhibit 10.1 to Brigham’s Current
                    Report on Form 8-K, as amended (filed April 24, 2006), and incorporated
                    herein by reference).10.35
                —
                Registration
                    Rights Agreement, dated April 20, 2006, among Brigham Exploration
                    Company,
                    the Guarantors named therein and the Initial Purchasers named
                    therein (
                    filed as Exhibit 10.2 to Brigham’s Current Report on Form 8-K, as amended
                    (filed April 24, 2006), and incorporated herein by
                    reference).10.36
                —
                First
                    Amendment to Fourth Amended and Restated Credit Agreement, between
                    Brigham
                    Exploration Company and the banks named therein, dated April
                    10, 2006
                    (filed as Exhibit 10.3 to Brigham’s Current Report on Form 8-K, as amended
                    (filed April 24, 2006), and incorporated herein by
                    reference).10.37
                —
                Form
                    of the Amended and Restated Indemnity Agreement, dated November
                    9, 2006
                    (filed as Exhibit 99.1 to Brigham’s Current Report on Form 8-K, as amended
                    (filed December 5, 2006), and incorporated herein by
                    reference).21†
                —
                Subsidiaries
                    of the Registrant.23.1†
                —
                Consent
                    of KPMG LLP, Independent Registered Public Accounting
                    Firm.23.2†
                —
                Consent
                    of PricewaterhouseCoopers, LLP.23.3†
                —
                Consent
                    of Cawley Gillespie & Associates, Inc.31.1†
                —
                Certification
                    of Chief Executive Officer pursuant to Sec. 302 of the Sarbanes-Oxley
                    Act
                    of 200231.2†
                —
                Certification
                    of Chief Financial Officer pursuant to Sec. 302 of the Sarbanes-Oxley
                    Act
                    of 200232.1†
                —
                Certification
                    of Chief Executive Officer pursuant to 18 U.S.C. SECTION
                    135032.2†
                —
                Certification
                    of Chief Financial Officer pursuant to 18 U.S.C. SECTION
                    1350


__________


*
            Management
                contract or compensatory plan.





†
            Filed
                herewith.






F-33