Filed by Bowne Pure Compliance

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007


o		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 Select 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 o No þ

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 o No þ

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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

(Do not check if a smaller reporting company)

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

As of June 29, 2007, the registrant had 45,673,160 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 29, 2007 of $5.87 per share as reported on The NASDAQ Global Select Market, was $203 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 3, 2008, the registrant had 46,126,710 shares of voting common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2008 Annual Meeting of Stockholders to be held on May 23, 2008, 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, 2007.

BRIGHAM EXPLORATION COMPANY

2007 ANNUAL REPORT ON FORM 10-K

PART I

Item 1. Business

Overview

We are an independent exploration, development and production company that utilizes advanced 3–D seismic imaging, drilling and completion 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, from late 2005 through 2007, we have been accumulating significant acreage positions in the Williston and Powder River Basins. Operations within these two basins are included in and constitute the bulk of our activity in our Rocky Mountains province. We have also entered into four joint ventures in Southern Louisiana over the last two years. We consider these joint ventures to be logical extensions of our prospect generating activities along the onshore Texas Gulf Coast.

At December 31, 2007, our estimated proved reserves of 140.2 Bcfe had a standardized measure of $394.5 million and a pre-tax PV10% value of $491.6 million. Approximately 76% of our proved reserves are natural gas and we operate approximately 61% of our proved reserves. For the twelve month period ended December 31, 2007, our total revenue and net income were $119.0 million and $10.2 million, respectively. Our average daily production for 2007 was 41.6 MMcfe, which represents an increase of 13% from our production in 2006.

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


	At December 31, 2007
														2007
					%			Productive				3-D		Average
	Proved		Pre-tax		Natural			Wells				Seismic		Daily
Province	Reserves		PV10%(a)(b)		Gas			Gross		Net		Data		Production
	(Bcfe)		(Millions)									(Sq. Miles)		(MMcfe)
Onshore Gulf Coast		86.6	$	319.4		83	%		94		45.3		4,423		30.3
Anadarko Basin		34.6		82.7		94	%		98		28.4		2,381		8.2
Rocky Mountains		11.0		50.4		12	%		9		5.1		358		0.8
West Texas and Other		8.0		39.1		14	%		83		25.5		4,669		2.3

Total		140.2	$	491.6		76	%		284		104.3		11,831		41.6


(a)		The prices used to calculate this measure were $96.01 per barrel of oil and $7.10 per MMbtu of natural gas, both as of December 31, 2007.

(b)		The standardized measure for our proved reserves at December 31, 2007 was $394.5 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, 2007, we have drilled, completed, or are completing 760 wells, consisting of 515 exploration and 245 development wells with an average completion rate of 73%. Over the three year period ended December 31, 2007, we drilled, completed, or were completing 108 wells, consisting of 45 exploratory and 63 development wells with an average completion rate of 81%. During 2007, we spud a total of 29 wells, consisting of 10 exploratory wells and 19 development wells. We retained an average working interest in these wells of approximately 51%. At December 31, 2007, 19 of these wells have been or were being completed, while six of these wells were not completed and four were in the process of drilling. Our average completion rate for 2007 was 71%.

As part of our exploration activities, we have accumulated 3-D seismic data covering approximately 11,831 square miles (7.6 million acres) in 11 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 760 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, 2007, within our core provinces we spent $68.8 million on land and seismic activities. We currently plan to spend approximately $18.3 million in 2008 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. 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 each of our four provinces.

In 2007, we spent a total of $96.8 million on drilling expenditures. This represents a 32% decrease from the amounts we spent on drilling in 2006. In 2007, we drilled 29 wells versus 43 wells in 2006. Our 2007 drilling program was comprised of 19 development and 10 exploratory wells. We had four development wells that were completing and two development wells and two exploratory wells that were drilling as of December 31, 2007.

In 2007, we invested $17.5 million in land and 3-D acquisitions, as compared to $31.7 million in 2006. Our land and 3-D investments represent a decrease of 45% relative to 2006. The majority of our new acreage in 2007 was acquired in the Williston Basin in Mountrail County, North Dakota and surrounding counties.

For 2008, we plan to continue an active drilling program and anticipate spending $102.6 million to drill 24 development wells, nine exploratory wells and we will complete wells that were in progress at December 31, 2007. In 2008, we also anticipate spending approximately $18.3 million on land and seismic.

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 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 Williston Basin in North Dakota and Montana and the Powder River Basin in Wyoming; and 4) our West Texas province. Further, we believe our focus on these four core provinces and associated trends 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 knowledge base provides us with a substantial competitive advantage.

	•		Internally Generate Inventory of High Quality Exploratory Prospects. Utilizing 3-D seismic data and other advanced technologies, our highly skilled staff of 13 geologists and four geophysicists generates the majority of our drilling prospects. 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. Our staff is very proficient with state-of-the-art drilling and completion techniques, including directional drilling, horizontal drilling and multi-stage fracture stimulations, including those utilizing swell packers. We have demonstrated a successful track record of drilling in difficult, deep and highly pressured environments. 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 up over 234.8 Bcfe in gross reserves by drilling 40 wells to date.

	•		Evaluate and Selectively Pursue New Potential Plays. We have a 17 year track record of successfully identifying, 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, development 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 Williston Basin located in North Dakota and Montana and the Powder River Basin located in Wyoming, as well as our joint ventures in Southern Louisiana are examples of our new potential plays that should lead to growth in our reserves and production. For 2008, we currently plan to spend approximately $70.2 million, or approximately 58% of our 2008 exploration and development expenditures, in the Bakken, the Mowry and Southern 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 generated a multi-year inventory of development drilling locations. Over the three year period ended December 31, 2007, approximately 63% 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 2008, we are forecasting that approximately 71% of our planned drilling capital expenditures that we announced at the beginning of the year will fund 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 2008, we currently plan to spend $102.6 million to drill and hopefully complete 33 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 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, 2007, we operated approximately 61% of our proved reserves. Further, in 2007 we operated 92% of the net wells we drilled, representing 96% of our drilling capital expenditures. We expect to operate approximately 94% of our net wells planned for 2008, representing approximately 93% of our planned 2008 drilling capital expenditures.

Exploration and Development Staff

Our experienced exploration staff includes 13 geologists, four geophysicists, two computer applications specialists and three geological technicians. Our geologists and geophysicists have varied, but complementary backgrounds. 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 22 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.

Our land department staff includes three landmen with an average of more than 29 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 62% of the gross wells and 92% of the net wells that we drilled during 2007, 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 61% of our proved reserves at year-end 2007, as compared to only 5% at year-end 1996.

Our operations staff includes seven engineers who have an average of over 13 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 improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us 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. 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 but not limited to 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.”

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 lack of availability 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, our 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 but not limited to the Federal Energy Regulatory Commission (FERC), the Environmental Protection Agency (EPA), the Bureau of Land Management (BLM), the Texas Commission on Environmental Quality (TCEQ), the Texas Railroad Commission (TRRC), the Louisiana Department of Natural Resources (LDNR), the Industrial Commission of North Dakota (NDIC), the Oklahoma Corporation Commission (OCC), the Wyoming Oil and Gas Conservation Commission (WOGCC), the Montana Board of Oil and Gas Conservation (MBOGC) and similar type commissions within these states and 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. 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.

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 both environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and safety and health. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to 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. A number of agencies including but not limited to the EPA, the BLM, the TCEQ, the LDNR, the NDIC, the OCC, the WOGCC, the MBOGC and similar commissions within these states and of other states in which we do business have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit 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.

In addition to the aforementioned regulatory agencies, 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.

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 on February 25, 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 one person satellite office in Denver, Colorado, where we lease office space at 1444 Wazee Street, Suite 310, Denver, Colorado 80202.

Employees

As of December 31, 2007, we had 66 full-time employees and 1 part-time employee. As of the end of 2007, 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 2007 ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu. In 2006, the same index ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu.

The NYMEX daily settlement price for the prompt month oil contract in 2007 ranged from a high of $98.18 per barrel to a low of $50.48 per barrel. In 2006, the same index ranged from a high of $77.03 per barrel to a low of $55.81 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:

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

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

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

	•		reduce our revenues, operating income and cash flow;

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

	•		limit 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.

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.

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, 2007, approximately 51% of our estimated proved reserves were classified as undeveloped. At December 31, 2007, we estimated that it would require additional capital expenditures of approximately $146.8 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.

The lack of availability 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 lack of availability 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.

As of December 31, 2007, we had indebtedness of $158.5 million outstanding under our 9 5/8% Senior Notes due 2014 (the “Senior Notes”), $10.0 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.

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 $101 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;

	•		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.

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. Based on oil and gas prices in effect at the end of June 2007 ($6.80 per MMBtu for Henry Hub gas and $70.47 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit and we recorded a $6.5 million ($4.1 million after tax) impairment to our oil and gas properties at June 30, 2007. 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.

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, 2007, approximately 39% of our oil and natural gas proved reserves 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. 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.

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 but not limited to the FERC, the EPA, the BLM, the TRRC, the TCEQ, the OCC, the LDNR, the NDIC, the WOGCC and the MBOGC 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, 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;

	•		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, 2007, one of our stockholders, together with its affiliates, owned 16.3% 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 indenture governing our Senior Notes contain terms restricting our ability to enter into change of control transactions, including requirements to redeem or repay upon a change in control our outstanding Series A preferred stock, the amounts borrowed under our senior credit agreement and Senior Notes. 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.

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;

Item 2. Properties

Historically, our exploration and development activities have been focused in the Onshore Gulf Coast, the Anadarko Basin, which encompasses 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 included our acquisition of acreage in both the Williston Basin located in North Dakota and Montana and the Powder River Basin located in Wyoming. In 2007, we drilled eight horizontal Bakken wells and one conventional Red River vertical well on our Williston Basin acreage and three horizontal Mowry wells on our Powder River Basin acreage, investing in a total of $37.1 million in land, seismic and drilling in these two new plays. In addition, over the last two years, we have entered into four joint ventures in Southern Louisiana, which we view as a logical extension of our onshore Texas Gulf Coast exploration activities. During 2007, we spent $21.0 million to drill three wells and acquire land and seismic in Southern Louisiana.

For the three-year period ended December 31, 2007, we completed 81 gross wells (47.7 net) in 100 attempts for a completion rate of 81%. We also had four development wells that were completing and two development wells and two exploratory wells that were drilling as of December 31, 2007. During 2008, we plan to spend approximately $102.6 million to drill 24 development wells and nine exploratory wells and to drill and complete wells that were in progress at December 31, 2007. We also plan to spend $18.3 million on land and seismic and $12.8 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, 2007, unless otherwise noted.


	Onshore			Anadarko			Rocky			West Texas
	Gulf Coast			Basin			Mountains (a)			& Other (b)			Total
Capital expenditures for drilling, land and seismic in 2007 (in millions)	$	64.3		$	12.2		$	37.1		$	0.7		$	114.3

*Proved Reserves at December 31, 2007*
Pre-tax PV10% (in millions) (c)	$	319.4		$	82.7		$	50.4		$	39.1		$	491.6
Oil (MMBbls)		2.5			0.3			1.6			1.1			5.5
Natural gas (Bcf)		71.7			32.5			1.3			1.1			106.6
Natural gas equivalents (Bcfe)		86.6			34.6			11.0			8.0			140.2
% Natural gas		83	%		94	%		12	%		14	%		76	%

Average daily production (MMcfe/d)		30.3			8.2			0.8			2.3			41.6

*Productive wells at December 31, 2007*
Gross		94			98			9			83			284
Net		45.3			28.4			5.1			25.5			104.3

3-D Seismic Data (square miles)		4,423			2,381			358			4,669			11,831


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

(b)		Capital expenditures for drilling, land and seismic in 2007 for West Texas & Other includes capital associated with the Barnett Shale.

(c)		The standardized measure for our proved reserves at December 31, 2007, was $394.5 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 the Onshore Gulf Coast province, provides us with significant competitive advantages.

Key operating trends within this province include the Vicksburg trend in Brooks County, Texas, the Frio trend in and around Matagorda County, Texas and the Miocene and Upper Oligocene trends in Southern Louisiana. In 2007, we entered into two joint ventures in an effort to continue to expand our position in Southern Louisiana.

Over the three year period ended December 31, 2007, approximately 56% of our total capital expenditures for drilling, land and seismic were allocated to our Onshore Gulf Coast province, where we completed 36 gross wells (27.0 net) in 46 attempts for a completion rate of 78%.

During 2007, we completed five gross wells (5.0 net) in eight attempts for a completion rate of 63% in this province. All of the completed wells were development wells. We also had one exploratory well that was drilling as of December 31, 2007. Subsequent to year-end, we were in the process of completing this well. We operated 100% of the wells that we drilled in this province during 2007. For 2007, we spent $64.3 million on drilling, land and seismic in our Onshore Gulf Coast province. Approximately 51% of the drilling, land and seismic was allocated to the Vicksburg, 33% to Southern Louisiana, 14% to the Frio and 2% to other areas in the province.

For 2008, we currently plan to spend $51.7 million in our Onshore Gulf Coast province. Approximately $48.1 million of this spending has been allocated to drilling, with the remaining $3.6 million allocated to capital spending for land and seismic activities. We anticipate that approximately 58% of the drilling, land and seismic will be allocated to the Vicksburg, 34% to Southern Louisiana, 3% to the Frio, and 5% to other areas in the province. We plan to drill six development wells and spend approximately $32.9 million on development drilling capital. We also plan to drill five exploratory wells and spend $15.2 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. Since 1999, we have drilled 40 Vicksburg wells and we have completed 38 of those wells. We believe we have a multi-year inventory of drilling locations in our Home Run, Triple Crown and Floyd Fault Block Fields.

In 2007, we successfully completed all five of our development wells spud in 2007 of which three were in the Triple Crown Field and two were in the Home Run Field. Total drilling, land and seismic capital expended in the Vicksburg during 2007 was $32.6 million.

During 2007, we operated all of our Vicksburg drilling and the working interests we retained in our 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 March 2007, we successfully completed the Triple Crown Field Dawson #1S from the Dawson Sand at an initial production rate of approximately 2.7 MMcfe per day. The Dawson #1S was followed by the Triple Crown Field Sullivan C-35, which found pay in the Brigham, 9,800’, Loma Blanca and Dawson Sands. The well was brought on-line at an initial production rate of approximately 2.3 MMcfe per day from the 9,800’, Loma Blanca and Dawson Sands.

In July 2007, we completed the Triple Crown Field Sullivan #14, which encountered pay in the 9,800’ and Brigham Sands. The well was brought on-line at an initial production rate of approximately 1 MMcfe per day from the 9,800’ Sand. The Sullivan #14 was followed by the Home Run Sullivan #15, which was a test of the eastern extent of the Home Run Field. Using new drilling technologies, the well was completed in a record 24 days resulting in an estimated $1.2 million reduction in drilling costs. The well was completed from the Vick “8” Sand at an initial production rate of approximately 3.2 MMcfe per day.

Given the successful completion of the Sullivan #15, we immediately commenced drilling the Home Run Sullivan C-36 and found approximately 100 feet of apparent pay in various lower Vicksburg objectives. The well was completed at an initial production rate of approximately 5.5 MMcfe per day, with additional pay behind pipe for future completion.

Subsequent to the C-36, we temporarily halted drilling in the Vicksburg in order update our structural interpretation of the three fields, which are essentially one highly faulted structural feature, based on our recent drilling results and our recently reprocessed proprietary 3-D data. Our recent Sullivan #15 and Sullivan C-36 completions in the Home Run Field were drilled to confirm new interpretational ideas. At the same time, we had commenced reprocessing the 3-D seismic data over the fields and believed it was important to integrate the new processing and recent drilling results into a new interpretation of the fields and surrounding arrears.

During 2008, we currently plan to spend approximately $28.3 million in the Vicksburg to drill four development wells and one exploration well. We also currently expect to spend approximately $1.8 million on land and seismic in 2008. In February 2008, we resumed our continuous Vicksburg drilling program and spud the Floyd Field Sullivan C-38, a development well, which is an attempt to extend the prolific Floyd fault block to the North. As of March 3, 2008, we had reached an approximate depth of 10,610 feet. We expect the C-38 to reach a total depth of 14,000 feet and anticipate providing drilling results in April. We will have a 100% working interest in the well subject to a back-in.

Frio Trend

Our Frio trend drilling, land and seismic capital expenditures for 2007 totaled $9.4 million. During 2007, we drilled one exploratory well in the Frio, the Randall #2. The well was plugged and abandoned after encountering non-commercial Frio pay.

In 2008, we currently plan to spend approximately $1.2 million to drill one Frio development well and for other activities. Capital costs on our Frio well will be mitigated by a partial carry to casing point by industry partners.

Southern Louisiana Trend

In Southern Louisiana, we utilize our geophysical, geological and operational expertise to explore for hydrocarbon bearing Oligocene and Miocene reservoirs. These reservoirs are generally on trend with the Texas Gulf Coast Frio and are therefore logical extensions of our drilling activities. During 2007, we drilled two wells and are in process of drilling another with drilling, land and seismic expenditures totaling $21.0 million.

In January 2007, we announced that that Cotten Land #3 encountered 30 feet of pay in the primary objective and 50 feet of apparent pay in an unexpected shallower zone. In March 2007, the well commenced production at an initial production rate of approximately 19 MMcfe per day from the primary objective. The shallower pay continues to remain behind pipe for future completion.

Also in March, we announced that the Marie Snyder #1 commenced production at an initial production rate of approximately 9.6 MMcfe per day. This well proved to be an important control point as it extended the gas water contact in the Cotten Land #3 fault block.

In May 2007, we commenced the Cotten Land #2, which was in an adjacent fault block to the Cotten Land #1. A primary upper sand objective was not present and the well was sidetracked. The sidetrack was also unsuccessful and a decision was made to undertake a second sidetrack to target our Cotten Land #4 objective in adjacent fault block, thereby realizing approximately $2 million in cost savings versus drilling a new well. The second sidetrack was plugged and abandoned as the target sands were wet.

In August 2007, we entered into a drilling project to participate in at least two wells in Jefferson Davis and Acadia Parishes. The two wells targeted 3-D seismic delineated Oligocene objectives at depths of 14,600 and 13,900 feet. The first well, the Blue Heron #1, was plugged and abandoned late in 2007. The second well, the Cary Sr. Estate #1 is currently being completed after encountering approximately 26 feet of apparent pay at a true vertical depth of 12,300 feet. Results from this well are expected in late March 2008.

In December 2007, we entered into a joint venture to operate the drilling of at least six prospects over the next 18 months with a 50% working interest. The five prospects planned for 2008 will target 3-D delineated, primarily amplitude related prospects at depths of 9,000 to 10,500 feet in Plaquemines and Saint Bernard Parishes.

In 2008, we currently plan to spend approximately $17.3 million to drill four exploratory wells, one development well, to complete wells in progress at December 31, 2007 and for other activities. We also currently expect to spend approximately $0.5 million on 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. 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, Springer Channel, Springer Bar and Granite Wash trends.

During 2007, we drilled three development and two exploratory wells. We successfully completed all three development wells and plugged and abandoned the two exploratory wells for an overall success rate of 60%. Of the $12.2 million that we spent on this province in 2007, approximately 58% was allocated to the Hunton trend, 14% was allocated to the Granite Wash trend, 11% was allocated to the Springer trends and 17% to other Anadarko Basin projects.

During 2008, we currently expect to spend approximately $11.7 million to drill four development wells, one exploratory well, to complete wells that were in progress and on other activities. We also expect to spend $1.9 million on net land and seismic.

Hunton Trend

Our Mills Ranch 96 #1 commenced production in January 2007 from the Viola and was producing approximately 3 MMcfe per day prior to being shut in to complete the upper, middle and lower Hunton objectives. Production from the Hunton objectives began in mid-March at an initial production rate of approximately 4.5 MMcfe per day. While production testing the well, it was determined that a substantial number of perforations were not contributing to the production stream and we undertook operations to open these perforations. During this time, a tubing failure was identified that required remediation. After completing the remediation, the well was brought on-line in July 2007 at a production rate of approximately 3.7 MMcfe per day.

Granite Wash Trend

In September 2007, we announced closing on the sale of our Granite Wash divestiture package for net proceeds of $35.4 million based on an effective date of September 1, 2007. The properties sold had current net production of approximately 1.8 MMcfe per day and proved reserves at the time of sale of approximately 23.8 Bcfe. Year-end 2006 proved reserves associated with the properties were approximately 13.6 Bcfe. The Granite Wash properties were sold because the rates of return on the 33 wells drilled in the Granite Wash over the last four years were not competitive with the rates of return on our other projects. Proceeds from the sale were initially used to pay off the outstanding balance under the credit facility and will eventually be used to fund other projects.

Rocky Mountains Province

We 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. In late 2005, we began accumulating acreage in the Williston Basin located in North Dakota and Montana and in early 2006 entered into a joint venture agreement in the Powder River Basin located in Wyoming. During 2007, we invested approximately $37.1 million in drilling, land and seismic in the Williston and Powder River Basins. During 2007, we spud 12 wells in the province with four wells completing and two wells still drilling at year-end. We successfully completed the remaining six wells we spud during 2007 for an overall completion success rate of 100%.

Williston Basin

The Williston Basin is spread across North Dakota, Montana and Canada with the United States portion of the basin encompassing approximately 143,000 square miles. The basin produces oil and gas from numerous producing horizons including, but not limited to, the Bakken and Red River, which are currently our primary objectives.

The Bakken is an unconventional oil play at depths of approximately 8,500 to 10,500 feet. In Richland County, Montana, approximately 227 Bakken wells in the Elm Coulee Field have generated average initial production rates of approximately 345 barrels of oil per day and estimated ultimate recoveries of approximately 376,000 barrels of oil per well, based on data compiled from external sources. In North Dakota, oil and gas companies are rapidly accelerating their activity east of the Nesson Anticline with much of the activity focused in and around Mountrail County.

In 2007, we spud nine wells in the Williston Basin, eight of which targeted the Bakken and one of which targeted the Red River. At year-end, we were completing four wells, drilling one well and had successfully completed the four remaining wells for a 100% success rate. Of the eight Bakken wells spud during 2007, four were operated by us, and four were non-operated wells. Total drilling, land and seismic capital expended in the Williston Basin during 2007 was approximately $24.6 million.

The Bergstrom Family Trust 26 #1H, which was our first operated well drilled in Mountrail County, North Dakota, produced at an early peak rate of approximately 202 barrel of oil equivalent per day up 4.5” casing and was drilled and completed for approximately $6.1 million. After installing 2 7/8” production tubing and placing the well on rod pump, we indicated on March 3, 2008 that the well was currently producing approximately 119 barrels of oil equivalent per day. The Bergstrom Family Trust 26 #1H is located approximately 6.5 miles northeast of the Parshall Field, and approximately 6 miles southeast of EOG’s Austin #1-02H and the Austin #2-03H discoveries.

Approximately 25 miles to the northwest of the Bergstrom Family Trust 26 #1H, we successfully drilled and completed our second operated Mountrail County, North Dakota well, the Hynek 2 #1H. The Hynek 2 #1H produced at an early peak 24 hour rate of approximately 585 Boe per day up 7” casing. After installing 2 7/8” production tubing and placing the well on rod pump, we indicated on March 3, 2008 that the well was currently producing approximately 142 barrels of oil equivalent per day. The Hynek 2 #1H was drilled and completed for approximately $4.9 million.

We successfully drilled and completed our third Mountrail County, North Dakota operated well, the Bakke 23 #1H, which produced at an early peak 24 hour rate of approximately 380 Boe per day up 7” casing. After installing 2 7/8” production tubing and placing the well on rod pump, we indicated on March 3, 2008 that the well was currently producing approximately 310 barrels of oil equivalent per day. The Bakke 23 #1H is located approximately 6 miles east of the Hynek 2 #1H, 12 miles west of EOG’s recently announced Austin #1-02H completion, and approximately 20 miles northwest of our Bergstrom Family Trust 26 #1H. The Bakke 23#1H was drilled and completed for approximately $4.7 million.

At year-end, we were drilling our fourth operated Mountrail County, North Dakota horizontal Bakken well, the Hallingstad 27 #1H. The Hallingstad 27 #1H is located approximately one mile west of the Bergstrom Family Trust 26 #1H well. On March 3, 2008, we indicated that after fracture stimulation the well was producing at an early rate of approximately 450 barrels of oil equivalent per day up 4.5” casing.

After completing the Hallingstad 27 #1H, we moved the rig to a location proximal to the Hynek 2 #1H to drill the 100% working interest Manitou State 36 #1H. As of March 3, 2008, the well was drilling at a depth of approximately 9,000 feet. We currently plan to keep this operated rig running continuously in 2008 drilling horizontal Bakken wells in North Dakota.

In December 2007, we successfully drilled and completed the Richardson 25 #1, a Red River discovery, which commenced production at an initial production rate of approximately 220 barrels of oil equivalent per day. As of March 3, 2008, we indicated that the well was currently producing approximately 279 barrels of equivalent per day. The Richardson 25 #1 is a conventional vertical well and was drilled and completed for approximately $2.4 million. We plan to commence our next Red River test in April 2008.

During 2008, we currently expect to spend approximately $37.4 million to drill 17 wells, complete wells that were in progress and on other activities. We also currently expect to spend approximately $10.5 million on net land and seismic.

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 located in Wyoming. Eighteen vertical wells in the area, which date as far back as 1951, targeted the approximate 175 foot Mowry shale at depths of about 7,500 feet and produced between 8 to 189 barrels of oil per day. Given the historical results, we believe the application of horizontal drilling technology and advanced fracture stimulation could significantly increase the productivity of the shale. Our obligations to carry our partners for the drilling and completion of two horizontal wells and $1.0 million of land acquisition costs were fulfilled in 2007 resulting in us earning a 50% working interest in approximately 54,000 net acres. As of December 31, 2007, we hold approximately 66,000 net acres in the play, located primarily in Niobrara County, Wyoming.

In 2007, we spent $12.5 million in the Powder River Basin to complete one horizontal well that spud in 2006, to drill and complete two new wells that spud in 2007, to commence drilling a third well and to acquire land and seismic data.

The Krejci #3-29H, drilled in 2006, was our first well drilled in the Powder River Basin. The well produced initially from the outermost 219 feet of the wellbore and pumped between 120 and 160 barrels of oil per day. In December 2007, operations began to complete the innermost 1,381 feet of the wellbore and after fracture stimulation the well produced between 50 and 90 barrels of oil per day. It appears that the outermost section of the uncased wellbore collapsed and therefore we are no longer in full communication with the section of the wellbore that was producing 120 to 160 barrels of oil per day rate. The well is currently pumping approximately 35 barrels of oil per day. The Krejci #3-29H was followed later in 2006 by the Mill Trust 1-12H. In July 2007, we fracture stimulated the 885 foot cased portion of the wellbore and installed production tubing and pumping equipment. The well is currently pumping approximately 12 barrels of oil per day. Results after cleanout show a good possibility that he cased hole interval was not properly stimulated.

The Werner #1-14H was the first well drilled in our 2007 Powder River Basin program. In July 2007, we fracture stimulated the wellbore and installed production tubing and pumping equipment. The well is currently producing intermittently at 12 barrels of oil per day. The State 1-16H, the second Powder River Basin well in our 2007 drilling program, was spud in May 2007. The State 1-16H was completed in July 2007 and is currently pumping intermittently at approximately 1 to 2 barrels of oil per day. A proper stimulation was never achieved in this wellbore and we are currently accessing the next plan of action. In November 2007, we spud the Krejci Federal #1-32H well, which is proximate to our first well in the basin, the Krejci Federal 29#3H. The Krejci Federal #1-32H will be completed using swell packer technology, a method enabling the isolation of fracture stimulations along the lateral utilizing an uncemented liner. Completions utilizing swell packers have generated positive operational results in the horizontal Bakken wells in the Williston Basin. As of March 3, 2008, we indicated that the well had been drilled and swell packers had been installed. We anticipate that the well will be fracture stimulated in mid-March 2008 and anticipate results will be provided in early April 2008.

In 2008, we currently anticipate spending approximately $4.5 million to complete the well that was drilling at year-end, acquire additional acreage and conduct additional seismic delineation testing.

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.

During 2007, we completed one gross well in two attempts for a 50% completion rate and spent a total of $0.7 million on drilling, land and seismic.

For 2008, we currently plan to spend approximately $3.2 million on drilling, land and seismic.

3-D Seismic Exploration

We have accumulated 3-D seismic data covering approximately 11,831 square miles (7.6 million acres) in 11 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 760 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 17 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 data, geologic trend studies, formation/reservoir 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.

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.

During 2007, we added approximately 494 square miles of 3-D seismic data to our corporate database. Approximately 62 square miles of 3-D seismic data was acquired on a proprietary basis and the remaining 432 square miles was acquired on a non-proprietary basis. Included in our 2007 3-D seismic additions is approximately 240 square miles of data in the Williston Basin targeting Bakken and Red River objectives offsetting and on trend with recent discoveries in the area. We retained an approximate overall 95% working interest in our 2007 3-D projects.

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 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, 2007, 2006 and 2005, 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,
	2007			2006			2005
Estimated Net Proved Reserves:
Oil (MBbls)		5,593			4,494			3,326
Natural gas (MMcf)		106,643			119,486			113,264
Natural gas equivalent (MMcfe)		140,202			146,452			133,223
Proved developed reserves as a percentage of net proved reserves		49	%		55	%		51	%
Pre-tax PV10% (in millions)(a)	$	491.6		$	338.5		$	519.8
Standardized measure (in millions)		394.5			302.7			396.3
Estimated future development cost (in millions)		160.5			145.9			122.4
Base price used to calculate reserves(b):
Natural gas (per MMbtu)	$	7.10		$	5.48		$	9.44
Oil (per Bbl)		96.01			61.06			61.04


(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.

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 SEC 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 securities 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,
	2007		2006		2005
Standardized measure of discounted future net cash flows	$	394.5	$	302.7	$	396.3
Add present value of future income tax discounted at 10%		97.1		34.6		123.5
FAS 143 assumption differences		—		1.2		—

Pre-tax PV10%	$	491.6	$	338.5	$	519.8

Drilling Activities

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


	Year Ended December 31,
	2007 (a)				2006 (b)				2005 (c)
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells:
Natural gas		0		0.0		4		1.4		8		4.5
Oil		2		1.0		6		4.6		0		0.0
Non-productive		6		3.2		10		5.2		4		3.5

Total		8		4.2		20		11.2		12		8.0


Development wells:
Natural gas		8		5.7		13		9.7		19		10.4
Oil		5		1.0		1		0.0		2		1.1
Non-productive		0		0.0		3		1.4		3		2.2

Total		13		6.7		17		11.1		24		13.7


(a)		Excludes two (0.6 net) exploratory wells and two (1.0 net) development wells that were drilling and four (2.2 net) development wells that were completing.

(b)		Excludes three (1.9 net) exploratory and two (0.8 net) development wells that were completing and one (0.4 net) development well that was drilling.

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

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, 2007 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		72		40.2		22		5.1		94		45.3
Anadarko Basin		84		25.3		14		3.1		98		28.4
Rocky Mountains		0		0		9		5.1		9		5.1
West Texas and Other		13		1.9		70		23.6		83		25.5

Total		169		67.4		115		36.9		284		104.3

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, 2007.


	Developed(a)				Undeveloped(a)				Total
	Gross		Net		Gross		Net		Gross		Net
Onshore Gulf Coast		19,080		8,943		31,468		22,691		50,548		31,634
Anadarko Basin		49,573		18,249		16,694		15,398		66,267		33,647
Rocky Mountains		16,714		12,643		293,544		225,915		310,258		238,558
West Texas & Other		15,175		5,648		15,124		9,207		30,299		14,855

Total		100,542		45,483		356,830		273,211		457,372		318,694


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

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, 2008		72,047		48,858
December 31, 2009		58,938		42,008
December 31, 2010		32,408		27,477
December 31, 2011		92,782		77,278
December 31, 2012		52,317		43,319
Thereafter		48,338		34,271

Total		356,830		273,211

In addition, as of December 31, 2007, we had mineral interests covering approximately 3,447 gross and 2,148 net acres. The mineral acres will continue into perpetuity and will not expire.

In addition, as of December 31, 2007, 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, 2008		6,775		6,775
December 31, 2009		3,775		3,775

Total		10,550		10,550

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 including hedging settlements 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 mark-to-market these derivatives. In addition, all subsequent derivatives are 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. We have elected to include both derivative settlements and unrealized gains (losses) within revenue. As such, unrealized gains (losses) on derivatives are no longer included within either other comprehensive income or other income (expense) and are therefore 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 following table .


	Year Ended December 31,
	2007		2006		2005
Production:
Oil (MBbls)		392		442		450
Natural gas (MMcf)		12,626		10,603		9,213
Natural gas equivalent (MMcfe)		14,978		13,254		11,913

Average oil prices:
Oil price (per Bbl)	$	72.30	$	64.04	$	54.73
Oil price including derivative settlement gains (losses) (per Bbl)	$	71.51	$	64.39	$	51.95
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	65.57		64.79	NA

Average natural gas prices:
Natural gas price (per Mcf)	$	7.30	$	6.74	$	8.29
Natural gas price including derivative settlement gains (losses) (per Mcf)	$	7.66	$	7.09	$	7.97
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	7.38		7.31	NA

Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	8.05	$	7.53	$	8.48
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)	$	8.33	$	7.82	$	8.13
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	7.94	$	8.01	NA

Average production costs (per Mcfe):
Lease operating expenses (includes costs for operating and maintenance and expensed workovers)	$	0.61	$	0.69	$	0.51
Ad valorem taxes	$	0.10	$	0.12	$	0.09
Production taxes	$	0.17	$	0.30	$	0.28

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, 2007, 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 2007.

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 3, 2008.


Name	Age		Position
Ben M. Brigham		48	Chief Executive Officer, President and Chairman
Eugene B. Shepherd, Jr.		49	Executive Vice President and Chief Financial Officer
David T. Brigham		47	Executive Vice President — Land and Administration and Director
A. Lance Langford		45	Executive Vice President — Operations
Jeffery E. Larson		49	Executive Vice President — Exploration

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 25 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, 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.

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
2006:
First Quarter	$	13.14	$	7.85
Second Quarter		10.00		6.69
Third Quarter		8.10		5.72
Fourth Quarter		8.80		6.07
2007:
First Quarter	$	7.44	$	5.30
Second Quarter		6.85		5.61
Third Quarter		6.12		4.17
Fourth Quarter		8.08		5.66

The closing market price of our common stock on March 3, 2008 was $8.01 per share. As of March 3, 2008, there were an estimated 178 record owners of our common stock.

The following graph is a comparison of cumulative total returns. It assumes that $100 was invested in Brigham’s common stock, the Nasdaq Market Index, and the Hemscott Group Index at the beginning of 2002 and remained invested through year-end 2007. The Indexes and the graph were prepared by an independent third part. The Hemscott Group Index is an index of independent oil and gas companies primarily engaged in the exploration, development and production of crude petroleum and natural gas. The NASDAQ Market Index is calculated using all companies, which trade as NASD Capital Markets, NASD Global Markets or NASD Global Select, including both domestic and foreign companies.

COMPARE CUMULATIVE TOTAL RETURN
AMONG BRIGHAM EXPLORATION CO.,
NASDAQ MARKET INDEX AND HEMSCOTT GROUP INDEX

ASSUMES $ 100 INVESTED ON DEC. 31, 2002
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2007

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.”

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, 2007.

Number of

Securities

Number of

Remaining

Securities to be

Available for

Issued upon

Weighted-

Future Issuance

Exercise of

Average Price of

Under Equity

Outstanding

Compensation

Plan Category

Options

Plans

Equity compensation plans approved by security holders(a)

3,044,166

7.14

1,236,123

Equity compensation plans not approved by security holders

—

Total

3,044,166

7.14

1,236,123


(a)		Does not include 653,623 shares of restricted stock issued and outstanding at December 31, 2007.

Issuer Purchases of Equity Securities

In 2007, 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.


	Total Number of		Average Price
Period	Shares Purchased		Paid per Share
October 2007		3,113	$	5.890
July 2007		6,724	$	5.985
January 2007		17,963	$	7.425

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, 2007, 2006 and 2005, and balance sheet data as of December 31, 2007 and 2006 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, 2004 and 2003 and the balance sheet data as of December 31, 2005, 2004 and 2003, from our accounting books and records.


	Year Ended December 31,
	2007			2006		2005		2004		2003
	(In thousands, except per share information)
Statement of Operations Data:
Revenues:
Oil and natural gas sales	$	120,557		$	102,835	$	96,820	$	71,713	$	51,545
Gain (loss) on derivatives, net		(1,664	)		3,335		—		—		—
Other revenue		88			127		220		515		132

Total revenues		118,981			106,297		97,040		72,228		51,677


Costs and expenses:
Lease operating		10,704			10,701		7,161		6,173		5,200


	Year Ended December 31,
	2007			2006			2005			2004			2003
	(In thousands, except per share information)
Production taxes		2,541			4,021			3,353			3,107			2,477
General and administrative		9,276			7,887			5,533			5,392			4,500
Depletion of oil and natural gas properties		59,079			46,386			33,268			23,844			16,819
Impairment of oil and natural gas properties		6,505			—			—			—			—
Depreciation and amortization		613			537			762			722			629
Accretion of discount on asset retirement obligations		379			317			180			159			142

Total costs and expenses		89,097			69,849			50,257			39,397			29,767

Operating income		29,884			36,448			46,783			32,831			21,910

Other income (expense):
Interest income		654			1,207			245			84			45
Interest expense, net		(14,622	)		(9,688	)		(3,980	)		(3,144	)		(4,815	)
Gain loss on derivatives, net		—			3,213			(814	)		625			68
Other income (expense)		1,022			1,352			238			117			(669	)

Total other income (expense)		(12,946	)		(3,916	)		(4,311	)		(2,318	)		(5,371	)

Income before income taxes and cumulative effect of change in accounting principle	$	16,938		$	32,532		$	42,472		$	30,513		$	16,539
Income tax benefit (expense):
Current		—			—			—			—			—
Deferred		(6,728	)		(12,744	)		(15,037	)		(10,863	)		1,223

		(6,728	)		(12,744	)		(15,037	)		(10,863	)		1,223
Income before cumulative effect of change in accounting principle		10,210			19,788			27,435			19,650			17,762
Cumulative effect of change in accounting principle		—			—			—			—			268

Net income		10,210			19,788			27,435			19,650			18,030
Preferred dividend and accretion		—			—			—			—			3,448

Net income (loss) available to common stockholders	$	10,210		$	19,788		$	27,435		$	19,650		$	14,582

Net Income (loss) per share before cumulative effect of change in accounting principle:
Basic	$	0.23		$	0.44		$	0.65		$	0.49		$	0.62
Diluted		0.22			0.43			0.63			0.47			0.51
Net income (loss) per share available to common shareholders:
Basic	$	0.23		$	0.44		$	0.65		$	0.49		$	0.63
Diluted		0.22			0.43			0.63			0.47			0.52
Weighted average shares outstanding:
Basic		45,110			45,017			42,481			40,445			23,363
Diluted		45,531			45,597			43,728			41,616			34,354


	At December 31,
	2007			2006			2005			2004			2003
	(In thousands)
Statement of Cash Flows Data:
Net cash provided (used) by:
Operating activities	$	90,449		$	88,687		$	64,379		$	56,381		$	41,691
Investing activities		(99,093	)		(171,747	)		(113,220	)		(84,645	)		(46,089	)
Financing activities		18,207			83,385			50,535			24,766			(5,141	)
Balance Sheet Data:
Cash and cash equivalents	$	13,863		$	4,300		$	3,975		$	2,281		$	5,779
Oil and natural gas properties, using the full cost method of accounting, net		510,207			485,525			347,329			261,979			198,490
Total assets		548,428			522,587			380,427			286,307			224,982
Long-term debt		168,492			149,334			63,100			41,000			39,000
Series A preferred stock, mandatorily redeemable		10,101			10,101			10,101			9,520			8,794
Total stockholders’ equity		279,027			266,015			241,640			183,276			139,111

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 up to 80% of our PDP volumes 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, and fuel; and 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 capital cost 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 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 prospect generation and our exploration activities.

Interest. We rely on 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 with both fluctuations in interest rates and the amount outstanding under the facility. 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. In 2006, the state of Texas passed a new franchise tax (referred to as the “Margin Tax”). The Margin Tax applies a 1% tax on operating margin beginning in 2007 and payable in 2008. We anticipate that the bulk of the associated Margin Tax will be deferred. Through 2007, 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, the unused committed borrowing capacity under our senior credit agreement and the sale of interests in projects and properties will fund our future financial obligations and liquidity.

Capital Expenditures

The timing of most of our capital expenditures is discretionary because we operate the majority of our wells and 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 2008 are as follows:


	2008
	(In millions)
Drilling	$	102.6
Net land and seismic		18.3
Capitalized interest and G&A		12.8
Other non-oil & gas assets		0.7

Total	$	134.4

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.

Over the past three years, we have spent approximately $330.0 million to drill 45 exploratory wells and 63 development wells. For 2008, we currently plan to spend approximately $102.6 million to drill nine exploratory wells with an average approximate working interest of 70% and to drill 24 development wells with an average approximate working interest of 46%. 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 $68.8 million on land and seismic activities. For 2008, we expect to spend approximately $18.3 million, or 14%, of our total planned capital expenditure budget on land and seismic activities.

Additionally, we currently plan to capitalize approximately $12.8 million of our forecasted general and administrative cost and forecasted interest in 2008.

The final determination with respect to our 2008 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 2007 capital expenditures see “Item 2. Properties.”

Contractual Obligations

The following schedule summarizes our known contractual cash obligations at December 31, 2007 and the effect these obligations are expected to have on our future cash flow and liquidity.


	Payments Due by Year
							2010-		2012 and
	Total		2008		2009		2011		Thereafter
	(In thousands)
Debt:
Senior Notes	$	160,000	$	—	$	—	$	—	$	160,000
Senior credit agreement		10,000		—		—		10,000		—
Mandatorily redeemable, Series A preferred stock		10,101		—		—		10,101		—

Total	$	180,101	$	—	$	—	$	20,101	$	160,000
Other commitments:
Interest, Senior Notes(a)	$	98,817		15,400		15,400		30,800		37,217
Interest, senior credit agreement(b)	$	1,470	$	588	$	588	$	294	$	—
Dividend Mandatorily redeemable, Series A preferred stock(c)		1,716		606		606		504		—
Non-cancelable operating leases		3,235		694		704		1,459		378

Total	$	285,339	$	17,288	$	17,298	$	53,158	$	197,595


(a)		Calculated assuming $160 million of Senior Notes outstanding and an interest rate of 9.625%. The payments are made in May and November until maturity in May 2014.

(b)		Calculated assuming $10.0 million outstanding under our senior credit agreement, an interest rate of 5.88% and maturity in June 2010. This interest rate assumes that we utilize approximately 10% of the available borrowing base during the period and a Eurodollar rate of 4.63% plus a margin of 1.25%. The Eurodollar rate used for the calculation is the one month Eurodollar rate on December 31, 2007. 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)		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, 2007. 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 6.”

Results of Operations

Comparison of the twelve-month periods ended December 31, 2007, 2006 and 2005

Production volumes


	Year Ended December 31,
	2007		% Change			2006		% Change			2005
Oil (MBbls)		392		(11	%)		442		(2	%)		450
Natural gas (MMcf)		12,626		19	%		10,603		15	%		9,213
Total (MMcfe)(1)		14,978		13	%		13,254		11	%		11,913
Average daily production (MMcfe/d)		41.6					36.8					33.1


(1)		MMcfe is defined as 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 2007 increased by 13% to 15.0 Bcfe (41.6 MMcfe/d) from 13.3 Bcfe (36.8 MMcfe/d) in 2006. Our production volumes for 2007 increased because 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 84% and 80% of our total production in 2007 and 2006, respectively.

The following is additional information regarding our 2007 production.

	•		Production from our Onshore Gulf Coast province for 2007 increased 36% when compared to 2006, which was largely driven by our Bayou Postillion project in Southern Louisiana. Production from this province represented 73% of our total production in 2007 versus 61% in 2006. Approximately 89% of our 2007 production from this province was natural gas compared to 82% in 2006.

	•		Production from our Anadarko Basin province for 2007 decreased 29% when compared to 2006. The decrease in our production volumes was due to the natural decline of the wells as well as the temporary abandonment of our Mills Ranch 98-2 because of mechanical difficulties. Production from this province represented 20% of our total production in 2007 versus 31% in 2006. Approximately 94% of our 2007 production from this province was natural gas compared to 92% in 2006.

	•		Production from our Rocky Mountains province for 2007 increased 167% when compared to 2006. The production increase is attributable to our wells in North Dakota being on line for a full year as well as our increased level of activity in the Mowry during 2007. Production from this province represented 2% of our total production in 2007 versus 1% in 2006. Approximately 90% of our 2007 production from this province was oil compared to 92% in 2006.

	•		Production from our West Texas & Other province for 2007 decreased 12% when compared to 2006. The decrease in production was attributable to the natural decline in our wells. Production from this province represented 6% of our total production in 2007 versus 7% in 2006. Approximately 86% of our 2007 production from this province was oil compared to 83% in 2006.

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 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 & Other 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.

Revenue, commodity prices and hedging

The following table shows our revenue from the sale of oil and natural gas for 2007, 2006 and 2005. On October 1, 2006, we de-designated all derivatives that were previously classified as cash flow hedges and, as a result, we now mark-to-market these derivatives. In addition, all subsequent derivatives are 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. Since October 1, 2006, we include both derivative settlements and unrealized gains (losses) within revenue. As such, unrealized gains (losses) on derivatives are no longer included within either other comprehensive income or other income (expense) and are therefore 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,
	2007			% Change			2006		% Change			2005
	(In thousands, except per unit measurements)
Oil revenue:
Oil revenue	$	28,347			0	%	$	28,291		15	%	$	24,628
Oil derivative settlement gains (losses)		(311	)	NM				157	NM				(1,249	)

Oil revenue including oil derivative settlements	$	28,036			(1	%)	$	28,448		22	%	$	23,379
Oil derivative unrealized gains (losses)		(2,328	)	NM				175	NM			NA

Oil revenue including derivative settlements and unrealized gains (losses)		25,708			(10	%)		28,623		22	%		23,379
Natural gas revenue:
Natural gas revenue	$	92,210			29	%	$	71,503		(6	%)	$	76,366
Natural gas derivative settlement gains (losses)		4,478			23	%		3,639	NM				(2,925	)

Natural gas revenue including derivative settlements	$	96,688			29	%	$	75,142		2	%	$	73,441
Natural gas derivative unrealized gains (losses)		(3,503	)	NM				2,405	NM			NA

Natural gas revenue including derivative settlements and unrealized gains (losses)		93,185			20	%		77,547		6	%		73,441
Oil and natural gas revenue:
Oil and natural gas revenue	$	120,557			21	%	$	99,794		(1	%)	$	100,994
Oil and natural gas derivative settlement gains (losses)		4,167			10	%		3,796	NM				(4,174	)

Oil and natural gas revenue including derivative settlement gains (losses)		124,724			20	%		103,590		7	%	$	96,820
Oil and natural gas derivative unrealized gains (losses)		(5,831	)	NM				2,580	NM			NA

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		118,893			12	%		106,170		10	%		96,820
Other revenue		88			(31	%)		127		(42	%)		220

Total revenue	$	118,981			12	%	$	106,297		10	%	$	97,040

Average oil prices:
Oil price (per Bbl)	$	72.30			13	%	$	64.04		17	%	$	54.73
Oil price including derivative settlement gains (losses) (per Bbl)	$	71.51			11	%	$	64.39		24	%	$	51.95
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	65.57			1	%	$	64.79	NM			NA
Average natural gas prices:
Natural gas price (per Mcf)	$	7.30			8	%	$	6.74		(19	%)	$	8.29


	Year Ended December 31,
	2007		% Change			2006		% Change			2005
	(In thousands, except per unit measurements)
Natural gas price including derivative settlement gains (losses) (per Mcf)	$	7.66		8	%	$	7.09		(11	%)	$	7.97
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	7.38		1	%	$	7.31	NM			NA
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	8.05		7	%	$	7.53		(11	%)	$	8.48
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)	$	8.33		7	%	$	7.82		(4	%)	$	8.13
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	7.94		(1	%)	$	8.01	NM			NA


	2006			2005
	to 2007			to 2006
Change in revenue from the sale of oil
Price variance impact	$	3,240		$	4,112
Volume variance impact		(3,184	)		(449	)
Cash settlement of derivative hedging contracts		(468	)		1,406
Unrealized gains (losses) due to derivative hedging contracts		(2,503	)		175

Total change	$	(2,915	)	$	5,244


Change in revenue from the sale of natural gas
Price variance impact	$	7,110		$	(16,400	)
Volume variance impact		13,597			11,537
Cash settlement of derivative hedging contracts		839			6,564
Unrealized gains (losses) due to derivative hedging contracts		(5,908	)		2,405

Total change	$	15,638		$	4,106


Change in revenue from the sale of oil and natural gas
Price variance impact	$	10,350		$	(12,288	)
Volume variance impact		10,413			11,088
Cash settlement of derivative hedging contracts		371			7,970
Unrealized gains (losses) due to derivative hedging contracts		(8,411	)		2,580

Total change	$	12,723		$	9,350

Our 2007 oil and natural gas revenue including derivative settlements and unrealized gains (losses) increased $12.7 million, or 12% when compared to 2006. The following were the primary reasons for the increase in our revenue:

	•		A 13% increase in our production volumes increased revenue by $10.4 million;

	•		A 7% increase in the average natural gas equivalent price increased revenue by $10.4 million;

	•		A $4.2 million gain from the settlement of derivative contracts in 2007 versus a $3.8 million settlement gain in 2006 increased revenue by $0.4 million; and

	•		A $5.8 million unrealized loss due to derivative hedging contracts in 2007 versus a $2.6 million unrealized gain due to derivative hedging contracts in 2006 decreased revenue by $8.4 million.

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; and

	•		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.

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 2007 was $88,000 compared to $127,000 in 2006 and $220,000 in 2005. 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 2007, 2006 and 2005 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,
	2007			% Change			2006		% Change			2005
*Oil collars and three way costless collars*
Volumes (Bbls)		263,000			59	%		165,000		40	%		118,105
Average floor price (per Bbl)	$	56.82			2	%	$	55.86		49	%	$	37.40
Average ceiling price (per Bbl)	$	81.50			7	%	$	76.23		62	%	$	47.20
Gain /(loss) upon settlement (in thousands)	$	(311	)	NM			$	157	NM			$	(1,249	)
*Total oil*
Volumes (Bbls)		263,000			59	%		165,000		40	%		118,105
Gain /(loss) upon settlement (in thousands)	$	(311	)	NM			$	157	NM			$	(1,249	)
*Natural gas collars and three way costless collars*
Volumes (MMbtu)		7,425,000			82	%		4,070,000		54	%		2,643,000
Average floor price (per MMbtu)	$	7.34			(7	%)	$	7.90		33	%	$	5.93
Average ceiling price (per MMbtu)	$	12.40			(13	%)	$	14.33		82	%	$	7.86
Gain /(loss) upon settlement (in thousands)	$	4,478			23	%	$	3,639	NM			$	(2,925	)
*Total natural gas*
Volumes (MMbtu)		7,425,000			82	%		4,070,000		54	%		2,643,000
Gain /(loss) upon settlement (in thousands)	$	4,478			23	%	$	3,639	NM			$	(2,925	)

Operating costs and expenses

Production costs. We believe that per unit of production measures are the most effective basis for evaluating 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,
	2007		% Change			2006		% Change			2005
Production costs:

Operating & maintenance	$	0.54		(14	%)	$	0.63		34	%	$	0.47
Expensed workovers		0.07		17	%		0.06		50	%		0.04
Ad valorem taxes		0.10		(17	%)		0.12		33	%		0.09

Lease operating expenses	$	0.71		(12	%)	$	0.81		35	%	$	0.60

Production taxes		0.17		(43	%)		0.30		7	%		0.28

Production costs	$	0.88		(21	%)	$	1.11		26	%	$	0.88


	Amount
	(In thousands)
	Year Ended December 31,
	2007		% Change			2006		% Change			2005
Production costs:

Operating & maintenance	$	8,153		(1	%)	$	8,267		48	%	$	5,568
Expensed workovers		1,097		38	%		797		62	%		492
Ad valorem taxes		1,454		(11	%)		1,637		49	%		1,101

Lease operating expenses	$	10,704		0	%	$	10,701		49	%	$	7,161

Production taxes		2,541		(37	%)		4,021		20	%		3,353

Production costs	$	13,245		(10	%)	$	14,722		40	%	$	10,514

For 2007, our per unit production cost decreased 21% when compared to 2006. The following were the primary reasons for the decrease in our 2007 per unit production costs relative to 2006:

	•		Production taxes decreased 43%, or by $0.13 per Mcfe, due to an increase in tax credits associated with high cost gas production tax abatements. The increase in tax credits is partially attributable to the fact that we are recording credits immediately upon commencing production from our Vicksburg and Mills Ranch wells given our 100% success rate in applying for credits rather than deferring recognition until receiving approval from the relevant government authority;

	•		O&M expenses decreased 14%, or by $0.09 per Mcfe. Decreases in salt water disposal, chemical treating, and equipment rental accounted for approximately 85% of the per unit change. The divestiture of our Granite Wash assets in September 2007 reduced salt water disposal and chemical treating costs. In South Texas, we elected to purchase production equipment thereby reducing our equipment rental costs;

	•		Ad valorem taxes decreased 17%, or by $0.02 per Mcfe, due to a decrease in property valuations for our oil and natural gas properties because of lower commodity prices at year-end 2006, which were the basis for determining property tax rates for 2007; and

	•		Expensed workovers increased 17%, or by $0.01 per Mcfe, due to a higher level of workover activity in 2007.

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

	•		O&M expenses increased 34%, or by $0.16 per Mcfe. Increases in salt water disposal, equipment rental, chemical treating, and well service and repair accounted for approximately 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;

	•		Expensed workovers increased 50%, or by $0.02 per Mcfe, due to a higher level of workover activity in 2006;

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

	•		Production taxes increased 7%, or by $0.02 per Mcfe, due to $0.5 million less in severance tax refunds received in 2006 as compared to 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 our prospect generation and exploration activities and a portion of our associated technical organization costs such as supervision, telephone and postage.


	Year Ended December 31,
	2007			% Change			2006			% Change			2005
	(In thousands, except per unit measurements)
General and administrative costs	$	17,442			21	%	$	14,439			39	%	$	10,380
Capitalized general and administrative costs		(8,166	)		25	%		(6,552	)		35	%		(4,847	)

General and administrative expenses	$	9,276			18	%	$	7,887			43	%	$	5,533

General and administrative expenses (per Mcfe)	$	0.62			3	%	$	0.60			30	%	$	0.46

Our general and administrative expenses in 2007 increased $1.4 million, or by $0.02 per Mcfe, over those in 2006. Before capitalization, our general and administrative costs increased by $3.0 million. The following were primary reasons for the increase in general and administrative costs:

	•		Increases in payroll, benefits expense, bonuses and FICA tax totaled $1.4 million. This increase was primarily because of an increase in employee salaries for retention purposes; and

	•		Increases in non-cash stock compensation costs increased general and administrative costs by $1.1 million.

Our general and administrative expenses in 2006 increased $2.4 million, or by $0.14 per Mcfe, over those in 2005. Before capitalization, our general and administrative costs increased by $4.1 million. The following were primary reasons for the increase in general and administrative costs:

	•		Increases in payroll, benefits expense, bonuses and FICA tax totaled $2.1 million. This increase was primarily because of an increase in employee salaries for retention purposes and to a lesser extent an increase in the number of employees;

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

	•		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.

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,
	2007		% Change			2006		% Change			2005
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	59,079		27	%	$	46,386		39	%	$	33,268
Depletion of oil and natural gas properties (per Mcfe)	$	3.94		13	%	$	3.50		25	%	$	2.79

Our depletion expense for 2007 was $12.7 million higher than 2006. Approximately $6.7 million of the increase in our depletion expense for 2007 was due to an increase in the depletion rate, while the remaining $6.0 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 and an increase in future development costs associated with our year-end 2007 proved reserves.

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.

Net interest expense. Interest on our Senior Notes, our senior credit facility, dividends that we pay on our Series A mandatorily redeemable preferred stock and our senior subordinated notes, which were terminated in April 2006, 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,
	2007			% Change			2006			% Change			2005
	(In thousands)
Interest on Senior Notes	$	14,483			68	%	$	8,632		NM			$	—
Interest on senior credit facility		1,900			156	%		743			(67	%)		2,267
Interest on senior subordinated notes(a)		—			(100	%)		699			(64	%)		1,948
Commitment fees		166			(5	%)		174			31	%		133
Dividend on mandatorily redeemable preferred stock		606			0	%		606			(17	%)		734
Amortization of deferred loan and debt issuance cost		932			(44	%)		1,665			239	%		491
Other general interest expense		2			(60	%)		5			(55	%)		11
Capitalized interest expense		(3,467	)		22	%		(2,836	)		77	%		(1,604	)

Net interest expense	$	14,622			51	%	$	9,688			143	%	$	3,980

Weighted average debt outstanding	$	189,080			54	%	$	123,031			53	%	$	80,180
Average interest rate on outstanding indebtedness(b)		9.1	%					8.8	%					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 $0.8 million 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 2007 was 51% higher than 2006. The primary drivers behind the increase in our net interest expense were a 54% increase in our weighted average debt outstanding and a higher average interest rate due to our Senior Notes issuances in April 2006 and 2007.

Our net interest expense for 2006 was 143% higher than 2005. The primary drivers behind the increase in our net interest expense were a 53% increase in our weighted average debt outstanding, a higher average interest rate associated with our April 2006 Senior Notes issuance and the $1.0 million 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.

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 are marking-to-market these derivatives. In addition, all subsequent derivatives are 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. Since October 1, 2006, we have included both derivative settlements and unrealized gains (losses) within revenue. As such, amounts that were previously recorded in other comprehensive income and other income (expense) are now incorporated within revenue.


	Year Ended December 31,
	2007		% Change			2006			% Change			2005
	(In thousands)
Derivative:
Non-cash gain (loss) due to change in fair market value of undesignated hedges	$	NA	NM			$	NA		NM			$	(92	)
Non-cash gain (loss) for ineffective portion of cash flow hedges		NA		(100	%)		3,213		NM				(722	)
Cash settlement of undesignated hedges		NA	NM				NA		NM				—

Derivative other income		—		(100	%)		3,213		NM				(814	)

Other:
Gain (loss) on sale of inventory or assets		71	NM				(64	)		(52	%)		(134	)
Other income (loss)		951		(33	%)		1,416			281	%		372

Miscellaneous other income (loss)		1,022		(24	%)		1,352			468	%		238

Total other income (loss)	$	1,022		(78	%)	$	4,565		NM			$	(576	)

The following table shows the volumes and the weighted average NYMEX reference price for our undesignated derivative contracts under SFAS 133 in 2007, 2006 and 2005 prior to the change to mark-to-market accounting.


	Year Ended December 31,
	2007		% Change	2006		% Change			2005
*Written oil puts*
Volumes (Bbls)		NA	NM		40,500		(44	%)		72,000
Average price ($ per Bbl)	$	NA	NM	$	43.56		26	%	$	34.67
*Total oil hedges*
Volumes (Bbls)		NA	NM		40,500		(44	%)		72,000
Average price ($ per Bbl)	$	NA	NM	$	43.56		26	%	$	34.67
*Written natural gas puts*
Volumes (MMbtu)		NA	NM		1,510,000		21	%		1,250,000
Average price ($ per MMbtu)	$	NA	NM	$	6.81		16	%	$	5.88
*Written natural gas basis swaps*
Volumes (MMbtu)		NA	NM		1,260,000	NM				—
Average price ($ per MMbtu)	$	NA	NM	$	0.20	NM			$	—
*Total natural gas hedges*
Volumes (MMbtu)		NA	NM		2,770,000		122	%		1,250,000
Average price ($ per MMbtu)	$	NA	NM	$	3.80		(35	%)	$	5.88

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, 2007.

Income taxes: We utilize the asset and liability approach to measuring differed tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

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, which became effective beginning in 2007. 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 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. 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.

In 2005, we recognized a current year net deferred tax liability of $14.3 million, which consisted of a $15.0 million increase in our 2005 deferred income tax expense and a $0.8 million 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 $0.6 million. The $4.1 million increase in our 2005 deferred tax expense was primarily due to increased capital expenditures and an $11.9 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 our inability to deduct dividends for federal tax purposes.

In 2006, we recognized a current year net deferred federal tax liability of $12.3 million, which consisted of an $11.5 million increase in our 2006 deferred federal income tax expense and a $0.8 million 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, which consisted of a $1.3 million Margin Tax ($0.9 million after-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 Margin Tax and our inability to deduct dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.

In 2007, we recognized a current year net deferred federal tax liability of $5.5 million,which consisted of a $5.9 million increase in our 2007 deferred federal income tax expense and a $0.4 million tax effect of unrealized hedging gains. The $5.9 million increase in our 2007 deferred federal tax expense was primarily due to a $15.6 million decrease in pre-tax income. We also recognized a current year net deferred state tax liability of $0.9 million, which consisted of the Margin Tax and other state taxes. The primary reasons for the difference between our effective tax rate of 39.7% and the federal statutory rate of 35% were due to state income taxes in Texas, North Dakota, and Louisiana and our inability to deduct dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.

Liquidity and Capital Resources

Sources of Capital

In 2008, 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, 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 9.875% 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”) dated April 20, 2006, among us, the Guarantors and Wells Fargo Bank, N.A., as trustee, relating to the Senior Notes.

In April 2007, we issued $35 million in Senior Notes. The Senior Notes were issued as an add-on to our existing $125 million of Senior Notes under the indenture dated April 20, 2006. The add-on notes were priced at 99.50% of face value to yield 9.721%.

Both the April 2006 Senior Notes and the April 2007 Senior Notes add-on were originally issued pursuant to the Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933. We have completed exchange offerings to exchange all of the unregistered Senior Notes for registered Senior Notes for both the April 2006 and April 2007 issuances.

We are obligated to pay $160 million in cash upon maturity of the Senior Notes in May 2014. Beginning November 2006, we paid 9 5/8% interest on the $125 million outstanding. Since May 2007, we have paid interest on the $160 million outstanding. Future interest payments are due semi-annually in arrears in May and November of each year.

The Senior Notes are 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.

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, 2007.

Senior Credit Agreement

Our senior credit agreement provides for revolving credit borrowings up to $200 million and matures June 2010. In conjunction with the issuance of our Senior Notes in April 2006, 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 2007, in conjunction with the issuance of our Senior Notes add-on, the borrowing base was reset to $101 million. As a result of our September 2007 Anadarko Basin Granite Wash asset sale, we conducted our semi-annual redetermination at the time of the asset sale and the borrowing base was reaffirmed at $101 million.

In April 2006, a portion of the proceeds from the Senior Notes issuance were used to repay the $48.4 million balance outstanding under the senior credit agreement. In April 2007, proceeds from the Senior Notes add-on issuance were used to repay a portion of the balance outstanding under the senior credit agreement.

As of December 31, 2007, we had $10.0 million outstanding and therefore had $91.0 million of unused committed borrowing capacity available. As of March 3, 2008, we had $14.5 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	Eurodollar
Borrowing Base	Rate			Base Rate
Utilized	Advances			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	Quarterly
Utilized	Commitment Fee
< 50%		0.250	%
50% and < 75%		0.250	%
75% and < 90%		0.375	%
90%		0.375	%

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, 2007 and interest coverage ratio for the twelve-month period ended December 31, 2007 were 3.1 to 1 and 7.2 to 1, respectively. As of December 31, 2007, 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 2007, we calculate that we can incur up to $136 million of debt 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 and an expansion in our borrowing base should give us the flexibility to incur debt under the senior credit agreement up to and beyond the $136 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.

Mandatorily Redeemable Preferred Stock

As of December 31, 2007, 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.

Analysis of Changes In Cash and Cash Equivalents

The table below summarizes our sources and uses of cash during 2007, 2006 and 2005.


	Year Ended December 31,
	2007			% Change			2006			% Change			2005
	(In thousands)
Net income	$	10,210			(48	%)	$	19,788			(28	%)	$	27,435
Non-cash charges		82,004			42	%		57,555			11	%		51,723
Changes in working capital and other items		(1,765	)	NM				11,344		NM				(14,779	)

Cash flows provided by operating activities	$	90,449			2	%	$	88,687			38	%	$	64,379
Cash flows used by investing activities		(99,093	)		(42	%)		(171,747	)		52	%		(113,220	)
Cash flows provided (used) by financing activities		18,207			(78	%)		83,385			65	%		50,535

Net increase (decrease) in cash and cash equivalents	$	9,563			2,842	%	$	325			(81	%)	$	1,694

Analysis of net cash provided by operating activities

Net cash provided by operating activities for 2007 was $1.8 million higher than 2006. The following are the primary reasons for the increase:

	•		A 13% increase in our production volumes from 2006 to 2007 combined with a 7% increase in prices including hedge settlements from 2006 to 2007 increased net cash provided by operating activities by $21.1 million.

	•		The change in working capital reduced operating cash flow by $13.1 million.

	•		An increase in net interest expense reduced cash provided by operating activities by $4.9 million

	•		A reduction in interest income and other income reduced operating cash flow by $0.9 million.

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.

	•		The change in working capital increased cash by $26.1 million.

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.

Our working capital deficit at December 31, 2007 was $9.2 million compared to a working capital deficit of $26.2 million at December 31, 2006. Our working capital deficit at December 31, 2007, included an asset of $1.4 million and a liability of $1.8 million related to the fair value our derivative contracts. Our working capital deficit at December 31, 2006, included an asset of $5.7 million related to the fair value our derivative contracts.

Analysis of changes in cash flows used by investing activities

Net cash used by investing activities decreased by $72.7 million from 2006 to 2007. The primary drivers for the decrease were a $45.5 million decrease in our drilling capital expenditures, a $14.2 million decrease in our land and seismic capital expenditures and $36.1 million in proceeds and ARO reduction from the sale of our Anadarko Basin Granite Wash assets. These reductions were offset by a $19.6 million increase in cash used in investing activities associated with the change in our accrued drilling costs.

Net cash used by investing activities increased by $58.5 million from 2005 to 2006. The primary drivers for the increase were a $51.5 million increase in our drilling capital expenditures and a $12.0 million increase in our land and seismic capital expenditures. These increases were offset by a $5.0 million decrease in cash used in investing activities associated with the change in our accrued drilling costs.

The following is a detailed breakout of our net cash used in investing activities for 2007, 2006 and 2005 in thousands.


	2007			% Change			2006			% Change			2005
Capital expenditures for oil and natural gas activities:
Drilling	$	96,833			(32	%)	$	142,338			57	%	$	90,873
Land and seismic		17,527			(45	%)		31,683			61	%		19,641
Capitalized cost		11,631			17	%		9,954			47	%		6,789
Capitalized asset retirement obligation		325			(47	%)		609			(54	%)		1,324

Total	$	126,316			(32	%)	$	184,584			56	%	$	118,627


Reconciling Items:
Granite Wash proceeds & ARO reduction	$	(36,050	)		100	%	$	—			0	%	$	—
Other property and equipment		378		NM				(213	)		(81	%)		(1,122	)
Change in accrued drilling costs		8,469		NM				(11,092	)		81	%		(6,119	)
Other		(20	)		(99	%)		(1,532	)	NM				1,834

Total Reconciling Items		(27,223	)		112	%		(12,837	)		137	%		(5,407	)

Net cash used in investing activities	$	(99,093	)		(42	%)	$	(171,747	)		52	%	$	(113,220	)

Analysis of changes in cash flows from financing activities

Over the three year period ended December 31, 2007, 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 2007 was $65.2 million lower than in 2006. The majority of the decrease is due to the issuance of our Senior Notes in April 2006. Net cash provided by financing activities in 2006 was $32.9 million higher than that in 2005. The increase was due to our issuance of our Senior Notes in April 2006.

Common Stock Transactions

Our net proceeds from the sale of common stock and employee stock option exercises were $5,000 higher in 2007 than they were in 2006. This compares to net proceeds that were $29.2 million lower in 2006 than in 2005.

The following is a list of common stock transactions that occurred in 2007, 2006 and 2005 in thousands except share data.


	Shares Issued		Net Proceeds
*2007 common stock transactions:*
Sale of common stock under universal shelf registration statement		—	$	—
Exercise of employee stock options		123,500		472
*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	$	28,321
Exercise of employee stock options		340,467		1,314


(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.

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.

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 quarter ended December 31, 2007, our average depletion expense per unit of production was $4.30 per Mcfe. A 10% decrease in our estimated net proved reserves at December 31, 2007, would result in a $0.47 per Mcfe increase in our per unit depletion expense and a $7.0 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 31, 2007 ($7.10 per MMBtu for Henry Hub gas and $96.01 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties did not exceed the ceiling limit.

As a result, we were not required to write-down the net capitalized costs of its oil and gas properties. In contrast, at the end of June 2007, the unamortized cost of our oil and gas properties exceeded the ceiling limit based on oil and gas prices in effect ($6.80 per MMBtu for Henry Hub gas and $70.47 per barrel for West Texas Intermediate oil, adjusted for differentials). Therefore, we recorded a $6.5 million ($4.1 million after tax) impairment to our oil and gas properties at June 30, 2007. 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.”

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 7.”

Revenue Recognition

We derive revenue primarily from the sale of the oil and natural gas that 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.

Derivative Instruments and Hedging Activities

Periodically, 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 $0.8 million gain on termination was recorded to other income (expense). The swap is more fully described in “Item 8. Financial Statements and Supplementary Data — Note 10.”

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. We elected to include all derivative settlement and unrealized gains (losses) within revenue.

New Accounting Pronouncements

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for our fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on our 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 for financial assets and liabilities, as well as other assets and liabilities that are carried at fair value on a recurring basis in financial statements. Implementation for other non-financial assets and liabilities was deferred for one year. We do not expect the adoption of SFAS 157 to have a material impact on our financial statements.

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. We are currently evaluating the impact on the financial statements.

In February 2007, the Financial Accounting Standard Board issued Statement No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. Companies are required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. It does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. We have not elected the fair value option for any eligible items.

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements – an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. We are currently evaluating the impact on the financial statements.

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.

The prices we receive for our oil production are based on global market conditions. Our average pre-hedged sales price for oil in 2007 was $72.30 per barrel, which was 13% higher than the prices we received in 2006. Significant factors that will impact 2008 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 2007 was $7.30 per Mcf, which was 8% higher than the price we received in 2006. Natural gas prices in 2008 will be dependent upon many factors including 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 and recession 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.

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. Subsequently entered into hedges are undesignated. At the end of each quarter, our derivatives are marked-to-market to reflect the current fair value and both derivative settlements and unrealized gains (losses) are recorded on the consolidated statement of operations. We elected to include all derivative settlement and unrealized gains (losses) within revenue and are therefore no longer including 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, 2007. The following table reconciles the changes that occurred in the fair values of our open derivative contracts during 2007.


	Fair Value of
	Undesignated
	Derivative
	Contracts

Estimated fair value of open contracts at December 31, 2006	$	6,575

Changes in fair values of derivative contracts:
Natural gas collars	$	(9,316	)
Oil collars		(2,054	)
Settlements of derivative contracts that were open at December 31, 2006:
Natural gas collars	$	4,478
Oil collars		(310	)

Estimated fair value of open contracts at December 31, 2007	$	(627	)

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 2007, we were party to natural gas costless collars, natural gas three-way costless collars and oil costless collars. See “Notes to the Consolidated Financial Statements — Note 10” for additional information regarding our derivative contracts.

We use costless collars to establish floor (purchased put option) and ceiling prices (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, 2007, the associated volumes and the corresponding weighted average NYMEX reference price.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
01/01/08 - 01/31/08		30,000	$	8.00	$	10.20
01/01/08 - 03/31/08		150,000	$	8.00	$	13.40
01/01/08 - 03/31/08		180,000	$	8.85	$	15.00
01/01/08 - 03/31/08		180,000	$	9.30	$	15.00
01/01/08 - 03/31/08		300,000	$	7.50	$	13.30
01/01/08 - 03/31/08		150,000	$	8.00	$	12.65
01/01/08 - 03/31/08		150,000	$	8.00	$	13.15
01/01/08 - 03/31/08		240,000	$	6.75	$	8.50
02/01/08 - 02/29/08		20,000	$	8.00	$	10.20
03/01/08 - 03/31/08		10,000	$	8.00	$	10.20
04/01/08 - 05/31/08		140,000	$	7.00	$	8.35
04/01/08 - 06/30/08		120,000	$	7.00	$	9.00
04/01/08 - 07/30/08		120,000	$	7.00	$	9.25
04/01/08 - 09/30/08		420,000	$	6.75	$	9.75
04/01/08 - 09/30/08		540,000	$	7.00	$	9.68
04/01/08 - 10/31/08		350,000	$	7.25	$	10.40
06/01/08 - 09/30/08		120,000	$	7.00	$	8.35
07/01/08 - 09/30/08		90,000	$	6.75	$	9.62
10/01/08 - 03/31/09		300,000	$	7.75	$	9.82
04/01/09 - 09/30/09		300,000	$	7.00	$	9.73

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMbtu)

(Nymex)

Natural Gas Three Way Costless Collars

10/01/08 - 03/31/09

300,000

8.00

10.35

5.50


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars*
01/01/08 - 03/31/08		9,000	$	56.00	$	89.95
01/01/08 - 03/31/08		3,000	$	65.00	$	80.25
01/01/08 - 04/31/08		8,000	$	60.00	$	74.75
01/01/08 - 03/31/08		6,000	$	68.40	$	90.00
01/01/08 - 01/31/08		3,000	$	65.00	$	82.10
01/01/08 - 03/31/08		7,500	$	57.60	$	90.00
01/01/08 - 12/31/08		24,000	$	57.50	$	75.50
02/01/08 - 02/29/08		1,000	$	65.00	$	82.10
02/01/08 - 06/30/08		5,000	$	65.00	$	82.60
04/01/08 - 06/30/08		9,000	$	62.00	$	81.60
04/01/08 - 10/31/08		21,000	$	65.70	$	90.00
04/01/08 - 12/31/08		18,000	$	57.50	$	76.00
07/01/08 - 08/31/08		4,000	$	65.00	$	80.60
11/01/08 - 06/31/09		24,000	$	62.00	$	81.75

The following table reflects commodity derivative contracts entered into subsequent to December 31, 2007, the associated volumes and the corresponding weighted average NYMEX reference price.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
02/01/08 - 02/29/08		80,000	$	6.75	$	9.10
03/01/08 - 05/31/08		90,000	$	7.00	$	8.70
04/01/08 - 04/30/08		60,000	$	7.25	$	9.00
04/01/08 - 07/31/08		200,000	$	7.50	$	10.20
05/01/08 - 05/31/08		30,000	$	8.50	$	10.40
06/01/08 - 06/30/08		40,000	$	8.50	$	10.40
06/01/08 - 09/30/08		80,000	$	7.25	$	9.53
07/01/08 - 07/31/08		20,000	$	8.50	$	10.40
10/01/08 - 03/31/09		180,000	$	8.00	$	10.20
10/01/08 - 03/31/09		300,000	$	8.00	$	11.20
04/01/09 - 09/30/09		120,000	$	7.25	$	9.80

Crude

Purchased

Written

Oil

Put

Call

Settlement Period

(Bbls)

(Nymex)

Oil Costless Collars

03/01/08 - 12/31/08

20,000

85.00

117.00

Interest Rate Risk

At December 31, 2007, we had $178.6 million of debt, of which $168.6 million was fixed rate debt. Our fixed rate debt consists of our $158.5 million Senior Notes and $10.1 million in Series A preferred stock. The remaining $10.0 million of debt we had outstanding at December 31, 2007, 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 31, 2007, which was 4.6%. 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, 2007, the borrowing base for our senior credit agreement was $101 million. Since the amount that we had borrowed under our senior credit at December 31, 2007 was $10.0 million, we were utilizing approximately 10% of our available borrowing base. At this level of utilization, our senior credit agreement requires us to pay a margin of 1.25%. Our all-in interest rate that we would be required to pay on the amounts borrowed under our senior credit facility would be 5.88%. A 10% increase in the Eurodollar rate would equal approximately 46 basis points. Such an increase in the Eurodollar rate would change our annual interest expense by approximately $46,000, assuming borrowed amounts under our senior credit facility remained constant at $10.0 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, 2007 was approximately $9.2 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

None.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2007, 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.

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, 2007.

The effectiveness of our internal control over financial reporting as of December 31, 2007 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 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to the 2008 Proxy Statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2007.

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


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 2008 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2007. 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

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)

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.

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.

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.

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 3, 2008.


	BRIGHAM EXPLORATION COMPANY

	By	/s/ BEN M. BRIGHAM
		Ben 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 3, 2008.


/s/ BEN M. BRIGHAM Ben M. Brigham		Chief Executive Officer, President and Chairman of the Board (Principal Executive Officer)
/s/ EUGENE B. SHEPHERD, JR. Eugene B. Shepherd, Jr.		Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
/s/ DAVID T. BRIGHAM David T. Brigham		Executive Vice President — Land and Administration and Director
/s/ HAROLD D. CARTER Harold D. Carter		Director
/s/ STEPHEN C. HURLEY Stephen C. Hurley		Director
/s/ STEPHEN P. REYNOLDS Stephen P. Reynolds		Director
/s/ HOBART A. SMITH Hobart A. Smith		Director
/s/ SCOTT W. TINKER Scott W. Tinker		Director

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Brigham Exploration Company:

We have audited the accompanying consolidated balance sheets of Brigham Exploration Company and subsidiaries (the Company) as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2007. 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 audits 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 audits provide 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in note 2 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. 123(R), Share-Based Payment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Brigham Exploration Company’s internal control over financial reporting as of December 31, 2007, 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 4, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Dallas, Texas
March 4, 2008

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Brigham Exploration Company:

We have audited Brigham Exploration Company’s internal control over financial reporting as of December 31, 2007, 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 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Brigham Exploration Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Brigham Exploration Company and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2007, and our report dated March 4, 2008 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Dallas, Texas
March 4, 2008

F-3

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated statements of operations, of stockholders’ equity, and of cash flows for the year ended December 31, 2005 listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the results of operations and cash flows of Brigham Exploration Company and its subsidiaries (the “Company”) for the year 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 audit. We conducted our audit 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 audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 27, 2006

F-4

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)


	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	13,863		$	4,300
Accounts receivable		14,609			18,352
Derivative assets		1,416			5,676
Other current assets		2,617			2,390
Property held for sale		—			500

Total current assets		32,505			31,218

Oil and natural gas properties, using the full cost method of accounting
Proved		728,607			631,339
Unproved		61,544			75,051
Accumulated depletion		(279,944	)		(220,865	)

		510,207			485,525

Other property and equipment, net		1,034			936
Deferred loan fees		3,687			3,420
Other noncurrent assets		995			1,488

Total assets	$	548,428		$	522,587

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	12,301		$	19,464
Royalties payable		5,978			5,012
Accrued drilling costs		14,841			23,310
Participant advances received		2,095			3,990
Other current liabilities		6,503			5,677

Total current liabilities		41,718			57,453

Senior Notes		158,492			123,434
Senior credit facility		10,000			25,900
Series 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, 2007 and 2006, respectively		10,101			10,101
Deferred income taxes		41,625			34,609
Other taxes payable		2,162			—
Other noncurrent liabilities		5,303			5,075
Commitments and contingencies (Note 9)		—			—
Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,304,139 and 45,090,398 shares issued and 45,197,303 and 45,011,362 shares outstanding at December 31, 2007 and 2006, respectively		453			451
Additional paid-in capital		207,526			203,643
Treasury stock, at cost; 106,836 and 79,036 shares at December 31, 2007 and 2006, respectively		(854	)		(662	)
Accumulated other comprehensive income (loss)		115			1,006
Retained earnings		71,787			61,577

Total stockholders’ equity		279,027			266,015

Total liabilities and stockholders’ equity	$	548,428		$	522,587

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

F-5

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)


	Year Ended December 31,
	2007			2006			2005
Revenues:
Oil and natural gas sales	$	120,557		$	102,835		$	96,820
Gain (loss) on derivatives, net		(1,664	)		3,335			—
Other revenue		88			127			220

		118,981			106,297			97,040

Costs and expenses:
Lease operating		10,704			10,701			7,161
Production taxes		2,541			4,021			3,353
General and administrative		9,276			7,887			5,533
Depletion of oil and natural gas properties		59,079			46,386			33,268
Impairment of oil and natural gas properties		6,505			—			—
Depreciation and amortization		613			537			762
Accretion of discount on asset retirement obligations		379			317			180

		89,097			69,849			50,257

Operating income		29,884			36,448			46,783

Other income (expense):
Interest income		654			1,207			245
Interest expense, net		(14,622	)		(9,688	)		(3,980	)
Other income (expense)		1,022			4,565			(576	)

		(12,946	)		(3,916	)		(4,311	)

Income before income taxes		16,938			32,532			42,472
Income tax benefit (expense):
Current		—			—			—
Deferred		(6,728	)		(12,744	)		(15,037	)

		(6,728	)		(12,744	)		(15,037	)

Net Income	$	10,210		$	19,788		$	27,435


Net income (loss) per share available to common stockholders:
Basic	$	0.23		$	0.44		$	0.65

Diluted	$	0.22		$	0.43		$	0.63

Weighted average common shares outstanding:
Basic		45,110			45,017			42,481
Diluted		45,531			45,597			43,728

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

F-6

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)


																Accumulated
																Other			Retained
							Additional						Unearned			Comprehensive			Earnings		Total
	Common Stock						Paid In			Treasury			Stock			Income			(Accumulated		Stockholders’
	Shares			Amounts			Capital			Stock			Compensation			(Loss)			Deficit)		Equity
Balance, December 31, 2004		43,231		$	432		$	175,270		$	(4,707	)	$	(1,570	)	$	(503	)	$	14,354	$	183,276
Comprehensive income (loss):
Net income		—			—			—			—			—			—			27,435		27,435
Unrealized losses on cash flow hedges		—			—			—			—			—			(603	)		—		(603	)
Tax provisions related to cash flow hedges		—			—			—			—			—			(43	)		—		(43	)
Net losses included in net income		—			—			—			—			—			723			—		723

Comprehensive income																						27,512
Issuance of common stock		2,500			25			28,206			—			—			—			—		28,231
Issuance of restricted stock		—			—			1,435			—			(1,435	)		—			—		—
Vesting of restricted stock		65			1			(1	)		—			—			—			—		—
Exercise of employee stock options		340			3			1,311			—			—			—			—		1,314
Tax benefit from the exercise of stock options		—			—			791			—			—			—			—		791
Repurchases of common stock		—			—			—			(190	)		—			—			—		(190	)
Retirement of treasury stock		(1,218	)		(12	)		(4,885	)		4,897			—			—			—		—
Amortization of unearned stock compensation		—			—			—			—			706			—			—		706

Balance, December 31, 2005		44,918		$	449		$	202,127		$	—		$	(2,299	)	$	(426	)	$	41,789	$	241,640
Comprehensive income (loss):
Net income		—			—			—			—			—			—			19,788		19,788
Unrealized gains (losses) on cash flow hedges		—			—			—			—			—			8,016			—		8,016
Tax provisions related to cash flow hedges		—			—			—			—			—			(770	)		—		(770	)
Net (gains) losses included in net income		—			—			—			—			—			(5,814	)		—		(5,814	)

Comprehensive income																						21,220
Issuance of common stock		—			—			37			—			—			—			—		37
Vesting of restricted stock		77			1			(1	)		—			—			—			—		—
Exercise of employee stock options		95			1			468			—			—			—			—		469
Repurchases 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			—			—			—			—		2,879

Balance, December 31, 2006		45,090		$	451		$	203,643		$	(662	)	$	—		$	1,006		$	61,577	$	266,015
Comprehensive income (loss):
Net income		—			—			—			—			—			—			10,210		10,210
Tax provisions related to cash flow hedges		—			—			—			—			—			480			—		480
Net (gains) losses included in net income		—			—			—			—			—			(1,371	)		—		(1,371	)

Comprehensive income																						9,319
Issuance of common stock		—			—			—			—			—			—			—		—
Vesting of restricted stock		90			1			(1	)		—			—			—			—		—
Exercise of employee stock options		124			1			441			—			—			—			—		442
Repurchases of common stock		—			—			—			(192	)		—			—			—		(192	)
Vesting of share-based payments		—			—			3,443			—			—			—			—		3,443

Balance, December 31, 2007		45,304		$	453		$	207,526		$	(854	)	$	—		$	115		$	71,787	$	279,027

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

F-7

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


	Year Ended December 31,
	2007			2006			2005
Cash flows from operating activities:
Net income	$	10,210		$	19,788		$	27,435
Adjustments to reconcile net income to cash provided (used) by operating activities:
Depletion of oil and natural gas properties		59,079			46,386			33,268
Impairment of oil and natural gas properties		6,505			—			—
Depreciation and amortization		613			537			762
Interest paid through issuance of additional mandatorily redeemable preferred stock		—			—			581
Stock based compensation		1,905			1,571			—
Write-off of deferred loan costs		—			965			—
Amortization of discount and deferred loan fees		968			717			491
Accretion of discount on asset retirement obligations		379			317			180
Market value adjustment for derivative instruments		5,831			(5,794	)		814
Deferred income taxes		6,728			12,744			15,037
Provision for doubtful accounts		—			48			456
Other noncash items		(4	)		64			134
Changes in working capital and other items:
Accounts receivable		3,743			4,425			(3,766	)
Other current assets		1,183			(1,874	)		(61	)
Accounts and royalties payable		(6,197	)		7,336			(9,456	)
Other current liabilities		(890	)		1,803			(989	)
Noncurrent assets		514			—			(514	)
Noncurrent liabilities		(118	)		(346	)		7

Net cash provided by operating activities		90,449			88,687			64,379

Cash flows from investing activities:
Additions to oil and natural gas properties		(132,932	)		(171,597	)		(112,856	)
Proceeds from sale of oil and natural gas properties		35,446			25			9
Additions to other property and equipment		(707	)		(510	)		(345	)
(Increase) decrease in drilling advances paid		(900	)		335			(28	)

Net cash used by investing activities		(99,093	)		(171,747	)		(113,220	)

Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		—			37			28,231
Proceeds from issuance of senior subordinated notes and warrants		—			—			10,000
Proceeds from exercise of employee stock options		472			469			1,314
Proceeds from Senior Notes offering		34,825			123,286			—
Repurchases of common stock		(192	)		(230	)		(190	)
Increase in senior credit facility		58,800			55,800			63,100
Repayment of senior credit facility		(74,700	)		(63,000	)		(51,000	)
Principal payments on senior subordinated notes		—			(30,000	)		—
Deferred loan fees paid and equity costs		(998	)		(2,977	)		(920	)

Net cash provided (used) by financing activities		18,207			83,385			50,535

Net increase (decrease) in cash and cash equivalents		9,563			325			1,694
Cash and cash equivalents, beginning of year		4,300			3,975			2,281

Cash and cash equivalents, end of year	$	13,863		$	4,300		$	3,975

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

F-8

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, 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 that are 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.

F-9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 may 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 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.

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


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

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

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.

F-10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 was determined that the derivative was 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 became ineffective remained unchanged until the related production was delivered. If Brigham determined that it was probable that a hedged forecasted transaction would not occur, deferred gains or losses on the derivative were recognized in earnings immediately. See Note 10 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 portions of the cash flow hedges were 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 occured. The resulting cash flows from derivatives were reported as cash flows from operating 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. 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, 2007, 2006 and 2005 (in thousands):


	2007			2006			2005
Balance, beginning of year	$	1,006		$	(426	)	$	(503	)
Current period settlements reclassified to earnings		—			(3,042	)		4,174
Current period change in fair value of hedges		—			11,058			(4,777	)
Tax benefits (provisions) related to cash flow hedges		480			(770	)		(43	)
Net (gains) losses included in earnings		(1,371	)		(5,814	)		723

Balance, end of year	$	115		$	1,006		$	(426	)

F-11

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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.

F-12

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

New Pronouncements

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for the fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on the Company’s 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 for financial assets and liabilities, as well as other assets and liabilities that are carried at fair value on a recurring basis in financial statements. Implementation for other non-financial assets and liabilities was deferred for one year. The Company does not expect the adoption of SFAS 157 to have a material impact on the financial statements.

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. The Company is currently evaluating the impact on the financial statements.

In February 2007, the Financial Accounting Standard Board issued Statement No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. Companies are required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. It does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. The Company has not elected the fair value option for any eligible items.

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements – an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company is currently evaluating the impact on the financial statements.

3. Property and Equipment

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


	December 31,
	2007			2006
Oil and natural gas properties	$	790,151		$	706,390
Accumulated depletion		(279,944	)		(220,865	)

		510,207			485,525
Other property and equipment:
3-D seismic interpretation workstations and software		1,442			1,357
Office furniture and equipment		3,110			2,817
Accumulated depreciation		(3,518	)		(3,238	)

		1,034			936

	$	511,241		$	486,461

F-13

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Depletion expense is based on units-of-production. Production volumes used to determine depletion expense were 14,978 MMcfe for 2007 and 13,254 MMcfe for 2006.

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, 2007, 2006 and 2005 (in thousands):


	Year Ended December 31,
	2007		2006		2005
Capitalized certain payroll and other internal costs	$	8,164	$	7,118	$	4,847
Capitalized interest costs		3,467		2,836		1,604

	$	11,631	$	9,954	$	6,451

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, 2007, 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 and, as a result, the Company was not required to writedown the net capitalized costs of its oil and gas properties.

Based on oil and gas prices in effect at the end of June 2007 ($6.80 per MMBtu for Henry Hub gas and $70.47 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 $4.1 million, net of tax. As a result, the Company was required to record a writedown of the net capitalized costs of its oil and gas properties in the amount of $4.1 million, net of tax, at June 30, 2007.

Based on oil and gas prices in effect on December 31, 2007 ($7.095 per MMBtu for Henry Hub natural gas and $96.01 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of the Company’s oil and gas properties would not have exceeded the ceiling limit. Therefore, the Company was not required to writedown the net capitalized costs of its oil and gas properties.

During the third quarter 2007, Brigham sold its Anadarko Basin Granite Wash oil and gas properties for net proceeds of $35.4 million with an effective date of September 1, 2007. The proceeds for the sale were applied to reduce the capitalized costs of oil and natural gas properties.

F-14

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table reflects the outstanding balances of the senior credit facility and senior notes for the years ended December 31, 2007 and 2006:


	December 31,
	2007			2006
	(In thousands)
Senior Credit Facility	$	10,000		$	25,900
Senior Notes		160,000			125,000
Discount on Senior Notes		(1,508	)		(1,566	)

Total Debt	$	168,492		$	149,334
Less: Current Maturities		—			—

Total Long-Term Debt	$	168,492		$	149,334

Senior Credit Facility

In June 2005, Brigham amended and restated the $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 the Senior Notes, the borrowing base was reset to $50 million. In November 2006, Brigham concluded its semi-annual redetermination process and at that time the borrowing base was reset to $110 million. In April 2007, in conjunction with the issuance of the Senior Notes add-on, the borrowing base was reset to $101 million. As a result of the September 2007 Anadarko Basin Granite Wash asset sale, Brigham conducted its semi-annual redetermination at the time of the sale and the borrowing base was reaffirmed at $101 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. In April 2007, proceeds from the Senior Notes add-on issuance were used to repay a portion of the balance outstanding under the senior credit agreement. As of December 31, 2007, Brigham had $10 million in borrowings outstanding under its senior credit 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 (4.6% at December 31, 2007), plus in each case an applicable margin that is reset quarterly (1.25% at December 31, 2007). 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, 2007, Brigham was in compliance with all covenants under the 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.

F-15

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

In April 2007, Brigham issued $35 million of 9 5/8% Senior Notes due 2014. The notes were issued as an add-on to the existing $125 million of 9 5/8% Senior Notes due 2014 under the indenture dated April 20, 2006 (the “Indenture”). The add-on notes were priced at 99.50% of face value to yield 9.721% and were issued under a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”). Brigham completed the offering to exchange the unregistered notes for registered notes on July 6, 2007. Brigham used the proceeds from the add-on offering to repay amounts outstanding under the existing senior credit agreement and for general corporate purposes. Upon completion of the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes due 2014 (collectively the “Senior Notes”).

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, 2007, 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, 2007 and 2006 (in thousands, except share amounts):


	Year Ended				Year Ended
	December 31, 2007				December 31, 2006
	Shares		Amounts		Shares		Amounts
Balance, beginning of year		505,051	$	10,101		505,051	$	10,101

Balance, 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.

F-16

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6. 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.

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, 2007 and 2006 (in thousands):


	Year Ended
	December 31,
	2007			2006
Beginning asset retirement obligations	$	5,002		$	4,390
Liabilities incurred for new wells placed on production		326			608
Liabilities settled		(45	)		(313	)
Revisions to estimates due to sale of oil and gas properties		(615	)		—
Accretion of discount on asset retirement obligations		379			317

	$	5,047		$	5,002

7. Income Taxes

Brigham utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS 109). Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

The total provision for income taxes consists of the following (Dollar amounts are in thousands):


	Year Ended December 31,
	2007		2006		2005
Current income taxes	$	—	$	—	$	—
Deferred income taxes:
Federal		5,827		11,528		15,037
State		901		1,216		—

	$	6,728	$	12,744	$	15,037

F-17

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to net income before taxes. The sources of the tax effects of the differences are as follows (Dollar amounts are in thousands):


	Year Ended December 31,
	2007			2006			2005
Tax at statutory rate	$	5,929		$	11,386		$	14,865
Add the effect of:
Nondeductible expenses		6			27			—
Deductible stock compensation		—			—			(91	)
Preferred stock dividends		212			212			257
Incentive stock options not exercised		34			252			—
State income taxes, net of federal deduction		586			872			—
Change in valuation allowance		(61	)		—			—
Other		22			(5	)		6

	$	6,728		$	12,744		$	15,037

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


	December 31,
	2007			2006
Deferred tax assets
Current:
Unrealized hedging and other derivative losses	$	138		$	—
State deferred taxes		741			—
Other		36			—

Current		915			—

Non-current:
Net operating loss carryforwards (NOLs)		53,039			40,338
Capital loss carryforwards		—			61
Percentage depletion carryforwards		3,448			2,971
Stock compensation		2,263			1,516
Asset retirement obligations		1,766			1,751
Other		49			(85	)

Non-current		60,565			46,552

		61,480			46,552
Valuation allowance		(3,448	)		(3,032	)

Total net deferred tax assets		58,032			43,520


Deferred tax liabilities
Current:
Unrealized derivative gains	$	—		$	(1,986	)

Current		—			(1,986	)

Non-current:
Depreciable and depletable property		(96,698	)		(76,713	)
Other		74			(200	)

Non-current		(96,624	)		(76,913	)

Total net deferred tax liabilities		(96,624	)		(78,899	)

Total federal deferred tax asset (liability)		(38,592	)		(35,379	)
Total state deferred tax asset (liability)		(2,117	)		(1,216	)

Total deferred tax asset (liability)	$	(40,709	)	$	(36,595	)

F-18

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2007, Brigham had regular U. S. Federal tax NOLs of approximately $153 million available as a deduction against future taxable income. Additionally, Brigham had approximately $129 million of U. S. Federal alternative minimum tax (“AMT”) NOLs. The NOLs expire from 2012 through 2027. The value of these NOLs depends on the ability of Brigham to generate taxable income. Brigham also has U. S. State NOLs of approximately $36 million and a Texas Margin tax credit carryover of approximately $300,000.

Brigham establishes a valuation allowance on deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Brigham has percentage depletion carryforwards of approximately $9.9 million on which Brigham has established a valuation allowance. In addition, Brigham’s valuation allowance decreased due to the utilization of its capital loss carryforwards of approximately $175,000.

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. Limitations on the utilization of Brigham’s NOLs may result from the March 2001 and November 2005 ownership changes. The limitations 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.

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement 109” (FIN 48), which 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. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is greater than 50% likely of being recognized upon ultimate settlement with the taxing authority is recorded. Brigham adopted the provisions of FIN 48 on January 1, 2007. Brigham has examined the tax positions taken in its tax returns or expected to be taken in its future tax returns and has determined that the full values of the uncertain tax positions have been recorded as part of the deferred tax liabilities. Therefore, no additional liabilities should be created and no incremental current or deferred income tax expenses should be recognized. However, consistent with the view of the FASB, Brigham has reclassified the liability for unrecognized tax benefits related to these uncertain tax positions from deferred tax liabilities to other tax liabilities on the consolidated balance sheet.

The following table sets forth the reconciliation of unrecognized tax benefits:


	(In thousands)
Increases (decreases) resulting from adoption of FIN 48	$	2,139
Increases (decreases) resulting from tax positions taken in the current period		23
Decreases relating to settlements with taxing authorities		—
Reductions resulting from the lapse of applicable statutes of limitations		—

Unrecognized tax benefits at December 31, 2007	$	2,162

None of the above unrecognized benefits would affect Brigham’s effective tax rate. Brigham classifies interest on uncertain tax positions as interest expense. Penalties are included in general administrative expense on the consolidated statement of operations. There are no tax interest and penalties recognized in the consolidated statement of operations or in the consolidated balance sheet due to the existence of Brigham’s NOLs.

F-19

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 2006, 2005, and 2004. In addition, Brigham is open to examination for the years 1997 through 2003, resulting from NOLs generated and available for carryforward.

8. 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,
	2007		2006		2005
	(In thousands, except per share amounts)

Basic EPS:
Income (loss) available to common stockholders	$	10,210	$	19,788	$	27,435

Weighted average common shares outstanding — basic		45,110		45,017		42,481

Basic EPS:
Income (loss) available to common stockholders	$	0.23	$	0.44	$	0.65


Diluted EPS:
Income (loss) available to common stockholders — diluted	$	10,210	$	19,788	$	27,435

Common shares outstanding		45,110		45,017		42,481
Effect of dilutive securities:
Stock options and restricted stock		421		580		1,247

Potentially dilutive common shares		421		580		1,247

Adjusted common shares outstanding — diluted		45,531		45,597		43,728


Diluted EPS:
Income (loss) available to common stockholders	$	0.22	$	0.43	$	0.63

At December 31, 2007, 2006, and 2005, potential dilution of approximately 2.8 million, 1.7 million, and 330,000 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.

9. 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-20

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2007, 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, 2007 are as follows (in thousands):


2008	$	694
2009		704
2010		721
2011		738
2012		378

	$	3,235

Rental expense for the years ended December 31, 2007, 2006 and 2005 was approximately $801,000, $651,000, and $596,000, 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, 2007, 2006 and 2005:


	2007			2006			2005
Purchaser A		—			15	%		20	%
Purchaser B		13	%		14	%		—
Purchaser C		27	%		—			—
Purchaser D		13	%		—			—
Purchaser E		11	%		—			—

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.

10. 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.

F-21

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Natural Gas and Crude Oil Derivative Contracts

Cash flow hedges

Historically, 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). For the years ended December 31, 2006 and 2005, ineffectiveness associated with Brigham’s derivative contracts designated as cash flow hedges increased (decreased) earnings by approximately $3.2 million and $(0.7) million, respectively.

Derivative positions also included written put options that were not designated as cash flow hedges which were entered into in conjunction with a costless collar to offset the cost of other option positions that were designated as cash flow hedges. The value of these positions was marked-to-market at the end of each period and any realized and unrealized gains or losses were recorded as an increase or decrease to other income (expense). For the year ended December 31, 2005, the impact on other income (expense) related to changes in the fair values of these derivative contracts was $(92,000).

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 cash flow hedges for accounting purposes 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).

Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham’s oil and natural gas prices including and excluding the 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, 2007:


	Year Ended December 31,
	2007			2006		2005
Natural gas
Average price per Mcf realized excluding gas hedging results	$	7.30		$	6.74	$	8.29
Average price per Mcf including gas hedging settlement results	$	7.66		$	7.09	$	7.97
Increase (decrease) in revenue, in thousands	$	4,478		$	3,639	$	(2,925	)
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	7.38		$	7.31	NA
Increase (decrease) in revenue, in thousands	$	975		$	6,044	NA

Oil
Average price per Bbl realized excluding oil hedging results	$	72.30		$	64.04	$	54.73
Average price per Bbl including oil hedging settlement results	$	71.51		$	64.39	$	51.95
Increase (decrease) in revenue, in thousands	$	(311	)	$	157	$	(1,249	)
Average price per Mcf including oil hedging settlement results and any unrealized gains (losses)	$	65.57		$	64.79	NA
Increase (decrease) in revenue, in thousands	$	(2,639	)	$	332	NA

F-22

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables reflect Brigham’s open commodity derivative contracts at December 31, 2007, the associated volumes and the corresponding weighted average NYMEX reference price.


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
01/01/08 - 03/31/08		240,000			$	6.75	$	8.50
01/01/08 - 03/31/08		150,000			$	8.00	$	13.40
01/01/08 - 03/31/08		180,000			$	8.85	$	15.00
01/01/08 - 03/31/08		180,000			$	9.30	$	15.00
01/01/08 - 03/31/08		300,000			$	7.50	$	13.30
01/01/08 - 03/31/08		60,000			$	8.00	$	10.20
01/01/08 - 03/31/08		150,000			$	8.00	$	12.65
01/01/08 - 03/31/08		150,000			$	8.00	$	13.15
04/01/08 - 07/31/08		120,000			$	7.00	$	9.25
04/01/08 - 06/30/08		120,000			$	7.00	$	9.00
04/01/08 - 09/30/08		420,000			$	6.75	$	9.75
04/01/08 - 09/30/08		260,000			$	7.00	$	8.35
04/01/08 - 09/30/08		540,000			$	7.00	$	9.68
04/01/08 - 10/31/08		350,000			$	7.25	$	10.40
07/01/08 - 09/30/08		90,000			$	6.75	$	9.62
10/01/08 - 03/31/09		300,000			$	7.75	$	9.82
04/01/09 - 09/30/09		300,000			$	7.00	$	9.73
*Oil Costless Collars*
01/01/08 - 04/30/08				8,000	$	60.00	$	74.75
01/01/08 - 02/29/08				4,000	$	65.00	$	82.10
01/01/08 - 03/31/08				9,000	$	56.00	$	89.95
01/01/08 - 03/31/08				3,000	$	65.00	$	80.25
01/01/08 - 03/31/08				6,000	$	68.40	$	90.00
01/01/08 - 03/31/08				7,500	$	57.60	$	90.00
01/01/08 - 12/31/08				24,000	$	57.50	$	75.50
02/01/08 - 06/30/08				5,000	$	65.00	$	82.60
04/01/08 - 06/30/08				9,000	$	62.00	$	81.60
04/01/08 - 10/31/08				21,000	$	65.70	$	90.00
04/01/08 - 12/31/08				18,000	$	57.50	$	76.00
07/01/08 - 08/31/08				4,000	$	65.00	$	80.60
11/01/08 - 06/30/09				24,000	$	62.00	$	81.75

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMBTU)

Nymex

Natural Gas Three Way Costless Collars

10/01/08 - 03/31/09

300,000

8.00

10.35

5.50

F-23

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reflects commodity derivative contracts entered subsequent to December 31, 2007, the associated volumes and the corresponding weighted average NYMEX reference price.


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
02/01/08 - 02/29/08		80,000			$	6.75	$	9.10
03/01/08 - 05/31/08		90,000			$	7.00	$	8.70
04/01/08 - 04/30/08		60,000			$	7.25	$	9.00
04/01/08 - 07/31/08		200,000			$	7.50	$	10.20
05/01/08 - 07/31/08		90,000			$	8.50	$	10.40
06/01/08 - 09/30/08		80,000			$	7.25	$	9.53
10/01/08 - 03/31/09		180,000			$	8.00	$	10.20
10/01/08 - 03/31/09		300,000			$	8.00	$	11.20
04/01/09 - 09/30/09		120,000			$	7.25	$	9.80
*Oil Costless Collars*
03/01/08 - 12/31/08				20,000	$	85.00	$	117.00

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,
	2007			2006
Other current liabilities	$	(1,812	)	$	(5	)
Other noncurrent liabilities		(256	)		—
Current derivative assets		1,416			5,676
Other noncurrent assets		25			904

Net fair value of derivative contracts	$	(627	)	$	6,575

F-24

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11. 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 Notes at December 31, 2007 and 2006 was $148.2 million and $125.5 million, respectively. The fair value of the Series A mandatorily redeemable preferred stock at December 31, 2007 and 2006 was approximately $9.2 million and $8.8 million, respectively.

Brigham’s accounts receivable relate to oil and natural gas sold to various industry companies, and amounts due from industry participants for expenditures made by Brigham on their behalf. Credit terms, typical of industry standards, are of a short-term nature and Brigham does not require collateral. Brigham’s accounts receivable at December 31, 2007 and 2006 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.

12. 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 123R. 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 4%. 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 2007 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 Black-Scholes model for each of the three years ended December 31, 2007:


	2007			2006			2005
Risk-free interest rate		3.88	%		4.7	%		4.29	%
Expected life (in years)		5.0			5.0			4.2
Expected volatility		47	%		52	%		43	%
Expected dividend yield		—			—			—
Weighted average fair value per share of stock compensation	$	3.21		$	3.33		$	4.78

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.

F-25

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 or 2007.

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 year ended December 31, 2005 would have been the pro forma amounts as indicated below (in thousands, except per share amounts):


	Twelve Months
	Ended
	Dec 31, 2005
Net income, as reported	$	27,435
Add back: Stock compensation expense previously included in net income		462
Effect of total employee stock-based compensation expense, determined under fair value method for all awards		(1,330	)

Pro forma	$	26,567


Net income per share:
Basic, as reported	$	0.65
Basic, pro forma		0.63

Diluted, as reported	$	0.63
Diluted, pro forma		0.61

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,
	2007			2006			2005
Pre-tax stock based compensation expense	$	3,443		$	2,879		$	706
Capitalized stock based compensation		(1,538	)		(1,308	)		(337	)
Tax benefit		(667	)		(550	)		(129	)

Stock based compensation expense, net	$	1,238		$	1,021		$	240

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

F-26

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2007, approximately 655,823 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 1,000,000 shares to non-employee directors and approximately 580,300 remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for each of the three years ended December 31, 2007:


	2007					2006					2005
				Weighted-					Weighted-					Weighted-
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Options outstanding at beginning of year		3,243,566		$	7.08		2,946,333		$	6.96		2,977,600		$	6.01
Granted		105,000		$	7.06		608,000		$	6.57		350,000		$	12.13
Forfeited or cancelled		(178,900	)	$	8.19		(215,667	)	$	4.96		(40,800	)	$	6.92
Exercised		(123,500	)	$	3.82		(95,100	)	$	4.93		(340,467	)	$	3.88

Options outstanding at end of year		3,046,166		$	7.14		3,243,566		$	7.08		2,946,333		$	6.96

Options exercisable at end of year		1,869,066		$	6.62		1,439,866		$	6.18		1,085,133		$	5.31

The weighted-average grant-date fair value of share options granted during the years ended December 31, 2007, 2006, and 2005 was $3.21, $3.33, and $4.78, respectively. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was $161,702, $401,667, and $2.3 million, respectively.

The following table summarizes information about stock options outstanding at December 31, 2007:


	Options Outstanding					Options Exercisable
			Weighted-					Weighted-
	Number		Average	Weighted-		Number		Average	Weighted-
	Outstanding at		Remaining	Average		Exercisable at		Remaining	Average
	December 31,		Contractual	Exercise		December 31,		Contractual	Exercise
Exercise Price	2007		Life	Price		2007		Life	Price
$ 3.05 to $ 3.41		207,366	0.9 years	$	3.35		207,366	0.9 years	$	3.35
3.66 to 5.08		388,900	1.7 years	$	4.30		385,400	1.7 years	$	4.29
6.10 to 6.73		1,255,000	3.9 years	$	6.49		709,000	3.2 years	$	6.62
7.22 to 8.84		828,900	4.2 years	$	8.47		419,300	3.7 years	$	8.65
8.93 to 12.31		366,000	4.7 years	$	11.54		148,000	4.7 years	$	11.51

3.05 to 12.31		3,046,166	3.6 years	$	7.14		1,869,066	2.9 years	$	6.62

F-27

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The aggregate intrinsic value of options outstanding and exercisable at December 31, 2007 was $3.4 million and $2.7 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 2007 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, 2007. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of December 31, 2007 there was approximately $4.1 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 5 years.

Restricted Stock

During the years ended December 31, 2007 and 2006, Brigham issued 379,550 and 129,595, 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, 2007, there was approximately $3.2 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 4.7 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.

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


	Year Ended					Year Ended
	December 31, 2007					December 31, 2006
				Weighted-					Weighted-
	Number of			Average		Number of			Average
	Shares			Price		Shares			Price
Restricted Stock Awards:
Restricted shares outstanding at the beginning of the year		391,367		$	8.60		397,650		$	7.22
Shares granted		379,550		$	5.78		129,595		$	10.84
Lapse of restrictions		(90,241	)	$	7.24		(77,530	)	$	6.37
Forfeitures		(27,053	)	$	8.35		(58,348	)	$	8.16

Restricted shares outstanding at the end of the year		653,623		$	7.16		391,367		$	8.60

13. 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 2007, 2006, and 2005, 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 100%, 45%, and 41% of eligible employee contributions made during 2007, 2006 and 2005, respectively. Brigham contributed approximately $628,000, $230,000, and $303,000 to the 401(k) plan for the years ended December 31, 2007, 2006 and 2005, respectively, to match eligible contributions by employees.

F-28

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

14. Related Party Transactions

During the years ended December 31, 2007, 2006, and 2005, Brigham incurred costs of approximately $3.3 million, $4.1 million and $2.3 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, 2007, 2006 and 2005, Brigham had a liability recorded in accounts payable of approximately $10,000, $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, 2007, 2006, and 2005. Additional payments totaling approximately $12,000 were made during each of the years ended December 31, 2007, 2006 and 2005, for the reimbursement of certain expenses. At December 31, 2007, 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 former directors, owns stock and serves on the board of directors. There were no payments to the drilling company during 2007 and 2006. Total payments to the drilling company during 2005 were $3.5 million. Brigham did not owe the drilling company any amounts at December 31, 2007, 2006 and 2005. At December 31, 2007, 2006 and 2005, Brigham had short-term accounts receivable from Mr. Webster of approximately $2,900, zero, and $1,500, 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, 2007, 2006 and 2005, Carrizo owed Brigham $35,000, $71,000, and $175,000, respectively, for exploration and production activities. Brigham had no accounts payable owed to Carrizo at December 31, 2007 and 2006. Brigham owed Carrizo $20,000 at December 31, 2005. Mr. Webster is also chairman of the board of directors for a well services company that Brigham made payments totaling approximately $1.3 million, $1.1 million, and $560,000 during 2007, 2006 and 2005, respectively. Brigham owed the well services company approximately $48,000, zero, and $43,000 at December 31 2007, 2006 and 2005, respectively.

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 2007, 2006 and 2005 were $1.2 million, $1.9 million, and $1.2 million, respectively. At December 31, 2007, 2006, and 2005, Brigham owed the service company approximately $55,000, $77,000, and $61,000, respectively.

15. Supplemental Cash Flow Information

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


	Year Ended December 31,
	2007			2006		2005
Cash paid for interest, net of capitalized amounts	$	14,059		$	5,893	$	2,575
Noncash investing and financing activities:
Dividends and accretion on mandatorily redeemable preferred stock		—			—		581
Capitalized asset retirement obligations		325			610		1,324
Accrued drilling costs		(8,469	)		11,092		6,119
Capitalized stock compensation		1,538			1,308		337
Issuance of restricted stock		—			—		1,435

F-29

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,
	2007		2006		2005
Costs incurred for the year:
Exploration (including geological and geophysical costs)	$	37,324	$	77,704	$	54,338
Property acquisition		18,554		15,846		15,701
Development		69,851		91,058		48,588

	$	125,729	$	184,608	$	118,627

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, 2007 by year incurred.


	December 31,						Prior
	2007		2006		2005		Years		Total
Property acquisition	$	5,028	$	2,008	$	5,522	$	7,566	$	20,124
Exploration (including geological and geophysical costs)		3,088		16,719		3,625		11,386		34,818
Drilling		1,759		—		—		—		1,759
Capitalized interest		3,009		1,834		—		—		4,843

Total	$	12,884	$	20,561	$	9,147	$	18,952	$	61,544

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 approximations 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-31

BRIGHAM EXPLORATION COMPANY

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) — (Continued)


	Natural
	Gas			Oil
	(MMcf)			(MBbls)
Proved reserves at December 31, 2004		101,875			3,236
Revisions of previous estimates		(595	)		(11	)
Purchases of reserves in place		4,054			65
Extensions, discoveries and other additions		17,143			486
Production		(9,213	)		(450	)

Proved reserves at December 31, 2005		113,264			3,326

Revisions of previous estimates		(861	)		97
Extensions, discoveries and other additions		17,687			1,513
Production		(10,603	)		(442	)

Proved reserves at December 31, 2006		119,487			4,494

Revisions of previous estimates		7,926			172
Extensions, discoveries and other additions		14,349			1,546
Sales of mineral in place		(22,493	)		(227	)
Production		(12,626	)		(392	)

Proved reserves at December 31, 2007		106,643			5,593


Proved developed reserves at December 31:
2004		47,494			2,124
2005		55,664			2,069
2006		64,401			2,752
2007		49,367			3,321

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.

F-32

BRIGHAM EXPLORATION COMPANY

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) — (Continued)


	December 31,
	2007			2006			2005
Future cash inflows	$	1,319,011		$	900,982		$	1,259,009
Future production costs		(248,116	)		(186,440	)		(220,499	)
Future development costs		(160,506	)		(145,949	)		(122,419	)
Future income tax expense		(219,748	)		(83,591	)		(237,268	)

Future net cash inflows		690,641			485,002			678,823
10% annual discount for estimated timing of cash flows		(296,127	)		(182,328	)		(282,482	)

Standardized measure of discounted future net cash flows	$	394,514		$	302,674		$	396,341

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		Oil
	(MMbtu)		(Bbl)
December 31, 2007	$	7.10	$	96.01
December 31, 2006		5.48		61.06
December 31, 2005		9.44		61.04

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


	December 31,
	2007			2006			2005
Beginning of period	$	302,674		$	396,341		$	239,709
Sales of oil and natural gas produced, net of production costs		(107,221	)		(85,070	)		(90,480	)
Previously estimated development costs incurred during the period		24,502			51,373			17,524
Extensions and discoveries		66,342			55,020			78,184
Net change of prices and production costs		164,728			(243,607	)		171,764
Change in future development costs		(31,586	)		(27,214	)		(32,838	)
Changes in production rates (timing)		(33,995	)		5,905			32,284
Revisions of previous quantity estimates		41,017			(883	)		(2,871	)
Accretion of discount		33,730			51,981			29,447
Change in income taxes		(62,161	)		88,842			(68,711	)
Purchases of reserves in place		—			—			14,221
Sales of reserves in place		(2,923	)		—			—
Other		(593	)		9,986			8,108

End of period	$	394,514		$	302,674		$	396,341

F-33

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).

4.10	—	Notations of Guarantees dated as of April 9, 2007, 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 filed on April 13, 2007 and incorporated in by reference).

4.11	—	Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference).

4.12	—	Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 on Form 8-K filed to Brigham’s Current Report on April 13, 2007 and incorporated in 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).


Number		Description

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 3, 2007. (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 reference).

10.18	—	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).

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 February 20, 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).



Number		Description

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 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 Generale 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	—	Second Amendment to Fourth Amended and Restated Credit Agreement, between Brigham Exploration Company and the banks named therein, dated March 27, 2007 (filed as Exhibit 10.3 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference).

10.38	—	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).

10.39	—	Purchase Agreement dated March 30, 2007, among Brigham Exploration Company, the Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 10.1 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference).

10.40	—	Registration Rights Agreement dated April 9, 2007, 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 filed on April 13, 2007 and incorporated in by reference).

21†	—	Subsidiaries of the Registrant.

23.1†	—	Consent of KPMG LLP, Independent Registered Public Accounting Firm.


	Page

Part I

Item 1. Business		2

Item 1A. Risk Factors		9

Item 1B. Unresolved Staff Comments		20

Item 2. Properties		21

Item 3. Legal Proceedings		32

Item 4. Submission of Matters to a Vote of Security Holders		33

Executive Officers of the Registrant		33

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		34

Item 6. Selected Consolidated Financial Data		36

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		38

Item 7A. Quantitative and Qualitative Disclosures about Market Risk		61

Item 8. Financial Statements and Supplementary Data		64

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		64

Item 9A. Controls and Procedures		65

Item 9B. Other Information		65

Part III

Item 10. Directors, Executive Officers and Corporate Governance		65

Item 11. Executive Compensation		65

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		66

Item 13. Certain Relationships and Related Transactions, and Director Independence		66

Item 14. Principal Accounting Fees and Services		66

Part IV

Item 15. Exhibits, Financial Statement Schedules		66

Glossary of Oil and Gas Terms		67

Signatures		69

Index to Financial Statements		F-1

Exhibit 21
Exhibit 23.1
Exhibit 23.2
Exhibit 23.3
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

	•		market conditions in the oil and gas industry;

	•		our ability to make and integrate acquisitions; and

	•		the impact of governmental regulation.


		Page

Reports of Independent Registered Public Accounting Firms		F-2

Consolidated Balance Sheets as of December 31, 2007 and 2006		F-5

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005		F-6

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005		F-7

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		F-8

Notes to the Consolidated Financial Statements		F-9

Supplemental Oil and Gas Information (Unaudited)		F-31

Supplemental Quarterly Financial Information (Unaudited)		F-34


	December 31
	2007		2006
Prepayments	$	949	$	932
Deferred taxes		914		—
Other		754		1,458

	$	2,617	$	2,390


	Year Ended December 31, 2007
	Quarter		Quarter		Quarter		Quarter
	1		2		3		4
Revenue	$	25,021	$	36,576	$	31,146	$	26,238
Operating income		5,964		7,050		10,107		6,763
Net income		1,873		2,310		4,183		1,844
Net income per share:
Basic	$	0.04	$	0.05	$	0.09	$	0.04
Diluted	$	0.04	$	0.05	$	0.09	$	0.04


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


Number		Description

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 2002

31.2†	—	Certification of Chief Financial Officer pursuant to Sec. 302 of the Sarbanes-Oxley Act of 2002

32.1†	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. SECTION 1350

32.2†	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. SECTION 1350


*		Management contract or compensatory plan.

†		Filed herewith.