Brigham Exploration (BEXP) 10-K 2009 FY Annual report

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, 2009

or

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: 001-34224

Brigham Exploration Company

(Exact name of Registrant as Specified in its Charter)

Delaware	75-2692967
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

6300 Bridge Point Parkway, Building 2, Suite 500, 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. Yesþ Noo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

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. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noo

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.o

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 filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(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). Yeso Noþ

As of June 30, 2009, the registrant had 82,764,420 shares of voting common stock outstanding. The aggregate market value of the registrant’s outstanding shares of voting common stock held by non-affiliates, based on the closing price of these shares on June 30, 2009 of $3.50 per share as reported on The NASDAQ Global Select Market, was $277 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 February 24, 2010, the registrant had 100,125,808 shares of voting common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2010 Annual Meeting of Stockholders to be held on May 26, 2010, 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, 2009.

BRIGHAM EXPLORATION COMPANY

TABLE OF CONTENTS

	Page
Part I
Item 1. Business		2
Item 1A. Risk Factors		10
Item 1B. Unresolved Staff Comments		22
Item 2. Properties		22
Item 3. Legal Proceedings		33
Item 4. Submission of Matters to a Vote of Security Holders		33
Executive Officers of the Registrant		34
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		35
Item 6. Selected Consolidated Financial Data		38
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		40
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		66
Item 8. Financial Statements and Supplementary Data		70
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		70
Item 9A. Controls and Procedures		70
Item 9B. Other Information		70
Part III
Item 10. Directors, Executive Officers and Corporate Governance		71
Item 11. Executive Compensation		71
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		71
Item 13. Certain Relationships and Related Transactions, and Director Independence		71
Item 14. Principal Accounting Fees and Services		71
Part IV
Item 15. Exhibits, Financial Statement Schedules		71
Glossary of Oil and Gas Terms		72
Signatures		75
Index to Financial Statements		F-1
Exhibit 21
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1

BRIGHAM EXPLORATION COMPANY

2009 ANNUAL REPORT ON FORM 10-K

PART I

Item 1. Business

Overview

We are an independent exploration, development and production company that utilizes advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. We focus our activities in provinces where we believe these technologies, including horizontal drilling, multi-stage isolated fracture stimulations and 3-D seismic imaging, can be used to effectively maximize our return on invested capital.

Historically, our exploration and development activities have been focused in the Onshore Gulf Coast, the Anadarko Basin and West Texas. We also regularly evaluate opportunities to expand our activities to areas that may offer attractive exploration and development potential. In response to this strategy, in late 2005 we began acquiring acreage within the Williston Basin in North Dakota and Montana and as of December 31, 2009, we have approximately 453,147 gross and 282,584 net leasehold acres in the Williston Basin. In late 2007, the majority of our drilling capital expenditures shifted from our historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West Texas to the Williston Basin, where we are currently targeting the Bakken, Three Forks and Red River objectives. Through year-end 2009, we have invested in excess of $222 million on drilling, land and seismic in this region.

At December 31, 2009, our estimated proved reserves of 27.7 MMBoe had a standardized measure of $246.5 million and a pre-tax PV10% value of $254.1 million. Approximately 60% of our proved reserves are oil and we operate approximately 74% of our proved reserves. Our average daily production volumes for 2009 were 5,034 Boe, which represents a 5% decrease from those in 2008.

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

	At December 31, 2009													2009
								Productive				3-D		Average
	Proved		Pre-Tax		%			Wells				Seismic		Daily Production
Province	Reserves(a)		PV10%(b)(c)		Oil			Gross		Net		Data		Volumes (d)
	(MMBoe)		(Millions)									(Sq. Miles)		(Boe)
Rocky Mountains		15.4		133.6		89	%		115		22.9		1,402		1,816
Onshore Gulf Coast		8.2	$	87.7		21	%		76		38.3		4,459		2,194
Anadarko Basin		2.9		13.1		6	%		82		21.3		2,381		726
West Texas and Other		1.2		19.7		90	%		83		24.6		4,698		298
Total		27.7	$	254.1		60	%		356		107.1		12,940		5,034

(a)	MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
(b)	The prices used to calculate this measure were $61.18 per barrel of oil and $3.87 per MMbtu of natural gas. The prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. These 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 this date.
(c)	The standardized measure for our proved reserves at December 31, 2009 was $246.5 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.
(d)	Average daily production volumes calculated based on 360 day year. Includes approximately 16,475 barrels of oil produced in the Williston Basin during 2009 and recorded as inventory at year-end 2009. Ending inventory at year end 2008 and 2007 was not material. Adjusting the production volumes for amounts included in inventory would result in average daily sales volumes in the Rocky Mountains and in total of 1,770 and 4,988 barrels of oil equivalent, respectively.

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As a result of our exploration and development activities, since inception we have drilled, completed, or are completing 885 gross wells, consisting of 524 exploration and 361 development wells with an average completion rate of 76%. Over the three year period ended December 31, 2009, we drilled, completed, or were completing 154 gross wells, consisting of 19 exploratory and 135 development wells with an average completion rate of 93%. Our improved completion rate over the past three years compared to that since inception is attributable to our increased level of activity in the Williston Basin, which is an unconventional resource basin generally providing more predictable drilling results. During 2009, we drilled, completed or were completing 57 gross wells, consisting of two exploratory wells and 55 development wells with an average completion rate of 98%. Our higher level of development drilling and higher completion rate in 2009 as compared to 2007 and 2008 is also attributable to our increased level of activity in the Williston Basin.

Since inception, we have retained an average working interest of approximately 34% in our wells. Over the last three years, we have retained an average working interest of approximately 25% in our wells. In 2009, we retained an average working interest of approximately 15% in our wells. The decrease in our working interest retained during 2009 was attributable to the reduction in our operated drilling activity during the first half of 2009 (outlined below) and the increased level of non-operated activity in the Williston Basin, where we participated in a number of lower working interest wells in Mountrail County, North Dakota.

Over the three year period ended December 31, 2009, we have spent approximately $291.2 million on drilling capital expenditures and approximately $55.1 million on land and seismic. In 2009, we spent a total of approximately $58.2 million on drilling capital expenditures and approximately $1.8 million on land and seismic. Our 2009 spending on drilling, land and seismic represents a 65% decrease from that in 2008, as we curtailed our operated drilling and completion activity in the first half of 2009. The decline in operated activity was triggered by the financial crisis and recession, which depressed commodity prices, and high drilling and completion costs, the reduction of which typically lags commodity price decreases as operators must phase in drilling activity reductions. For 2010, we anticipate spending approximately $183.7 million on drilling capital expenditures and approximately $15.6 million on land and seismic. The increase in our 2010 capital expenditure budget as compared to that for 2009 is a result of the improvement in crude oil prices and the reduction in drilling and completion costs, both of which have led to improved rates of return for our Williston Basin drilling program. Our increased level of activity is also attributable to our improved liquidity position, as a result of our May and October 2009 equity offerings, and our improved Williston Basin drilling results, which reflect our recent innovation in how we drill and complete horizontal wells. Our activity in 2010 will largely be focused in the Williston Basin where we are targeting the Bakken and Three Forks formations, which are primarily unconventional oil resource plays.

Business Strategy

Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow utilizing advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. Key elements of our business strategy include:

• Focus on Provinces.We plan to concentrate the majority of our near term capital expenditures in the Williston Basin, where we believe our approximately 282,584 net acres and the application of advanced drilling and completion techniques provide us with a significant competitive advantage in developing both the Bakken and Three Forks formations. In addition to the Williston Basin, we have a multi-year inventory of drilling prospects in the following three provinces: Onshore Gulf Coast, Anadarko Basin and West Texas. Our projects in these provinces provide us with important future drilling investment diversification.

• Leverage our Engineering and Operational Expertise. Our staff is proficient with state-of-the-art drilling and completion technologies, including directional drilling, horizontal drilling and multi-stage isolated fracture stimulations. Our drilling and completion techniques in the Williston Basin have rapidly evolved from drilling and completing long lateral wells with single large uncontrolled fracture stimulations in late 2006 to drilling long lateral wells with 20 isolated fracture stimulation stages in the fourth quarter 2008 and first quarter 2009. Most recently, we have completed long lateral wells with up to 32 isolated fracture stimulation stages. We will continue to refine our drilling and completion techniques in order to attempt to enhance well performance and the associated estimated ultimate recoveries and rates of return.

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• Capitalize on Internally Generated Exploration Successes Through Disciplined Development Activities.From 1990 to 1999, we grew our reserves and production volumes primarily through successful exploration drilling. In recent years, our exploratory drilling success has generated a multi-year inventory of development drilling locations. We have a 19 year track record of successfully generating and drilling exploration wells in 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 inventory of drilling locations in the Williston Basin, Vicksburg and Hunton plays are examples of successful projects where our position in the play was internally identified and originated.

• Enhance Returns Through Operational Control.We typically leverage our technical and operational expertise by seeking to maintain operational control of our exploration and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects, which enhances our ability to maximize our return on invested capital. Since we generate most of our own projects, we generally have the ability to retain operational control over all phases of our exploration and development activities.

Exploration and Development Staff

Our experienced exploration staff includes 11 geologists, six geophysicists, two computer applications specialists and five 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 19 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 four landmen with an average of more than 22 years of experience, primarily within our core provinces, and four 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 attempt to operate as many of the wells we drill as possible. We operated 26% of the gross wells and 83% of the net wells that we drilled during 2009, as compared with 10% of the gross wells and 17% of the net wells we drilled during 1996. In 2010, we anticipate we will operate an increased number of wells as we currently have four operated rigs running in the Williston Basin and, subject to commodity price risk, service costs and other factors, anticipate retaining those rigs throughout the year. As a result of our increased operational control, wells operated by us constituted 74% of our proved reserves at year-end 2009, as compared to only 5% at year-end 1996.

Our operations staff includes seven engineers who have an average of 15 years of experience in drilling, reservoir, operations or environmental 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 a combination of our field and third party contract personnel. We recently opened a field office in Mountrail County, North Dakota in order to more effectively oversee our Williston Basin activities, which we expect to account for the majority of our capital expenditure budget for 2010.

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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 a market based price, which incorporates regional differentials that include but are not limited to transportation costs and adjustments for product quality.

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 thus could be subject to further reduction, which would 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 writedowns, 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 affect market based prices or 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.”

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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 low oil and natural gas prices, 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.”

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, craterings, 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, loss of revenue due to low commodity prices 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.”

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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.

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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.”

Climate Change

Climate change has become the subject of an important public policy debate. Climate change remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. See “Item 1A. Risk Factors — The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.”

Impact of Legislation and Regulation. The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.

8

Climate change legislation and regulations have been adopted by many states in the US; however, legislation and regulations have not been enacted at the federal level in the US or all states, although Congress and several states are considering adopting climate change legislation. The current state of development of many state and federal climate change regulatory initiatives in areas where we operate makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that we may incur.

Indirect Consequences of Regulation or Business Trends.We believe there are risks arising from the global response to climate change. See “Item 1A. Risk Factors — The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.”

Physical Impacts of Climate Change on our Costs and Operations.There has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be fully insured. However, the extent to which climate change may lead to increased storm or weather hazards affecting our operations is difficult to identify at this time.

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Formation

We were 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.

Employees

As of December 31, 2009, we had 71 full-time employees and 1 part-time employee. As of the end of 2009, 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 thus could be subject to further reduction, which would 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 oil contract during 2009 ranged from a high of $81.37 per barrel to a low of $33.98 per barrel. The NYMEX daily settlement price for the prompt month oil contract in 2008 ranged from a high of $145.29 per barrel to a low of $33.87 per barrel. In 2007, the same index ranged from a high of $98.18 per barrel to a low of $50.48 per barrel.

The NYMEX daily settlement price for the prompt month natural gas contract during 2009 ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu. The NYMEX daily settlement price for the prompt month natural gas contract in 2008 ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu. In 2007, the same index ranged from a high of $8.64 per MMBtu to a low of $5.38 per MMBtu.

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;

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• 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:

• adversely affect 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.

The ongoing financial uncertainty could negatively impact the prices for oil and natural gas, limit access to the credit and equity markets, increase the cost of capital, and may have other negative consequences that we cannot predict.

The ongoing financial uncertainty in the U.S. could create financial challenges if conditions do not improve. Our internally generated cash flow, our Senior Credit Facility and cash on hand historically have not been sufficient to fund all of our expenditures, and we have relied on the capital markets and sales of non-core assets to provide us with additional capital. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations is less than anticipated and our access to capital is restricted, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult to consummate and less economic. Additionally, demand for oil and natural gas may deteriorate further and result in lower prices for oil and natural gas, which could have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

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, 2009, we had indebtedness of $160 million outstanding under our 9 5/8% Senior Notes due 2014 (the “Senior Notes”) and $10.1 million of Series A preferred stock. Our level of indebtedness will have several important effects on our operations, including:

• 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;

• our debt 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 outstanding balances under our Senior Credit Facility are subject to variable interest rates, we are vulnerable to increases in interest rates; and

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

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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.

The indenture governing the Senior Notes and the documents governing our Senior Credit Facility impose 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 the documents governing our Senior Credit Facility contain customary restrictions on our activities, including covenants that restrict our and our subsidiaries’ ability to:

• incur additional debt;

• pay dividends on, 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 indenture contains certain incurrence-based covenants that limit our ability to incur debt and engage in other transactions. One of these covenants incorporates the net present value of our proved reserves calculated based on SEC rules. Our ability to increase our borrowings in 2010 will depend, in part, on prices for oil and natural gas utilized in our year-end 2009 reserve report. Our Senior Credit Facility also requires us to meet a minimum current ratio, a minimum interest coverage ratio, a net leverage ratio and a liquidity requirement. We may not be able to maintain or comply with 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 Facility, which would make it difficult for us to operate our business.

The restrictions in the indenture governing the Senior Notes and the documents governing our Senior Credit Facility 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 the documents governing our Senior Credit Facility. 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 such indebtedness, lenders having secured obligations, such as the lenders under our Senior Credit Facility, could proceed against the collateral securing the debt. Because the indenture governing the Senior Notes and the documents governing our Senior Credit Facility have customary cross-default provisions, if the indebtedness under the Senior Notes or under our Senior Credit Facility or any of our other facilities is accelerated, we may be unable to repay or finance the amounts due.

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Availability under our Senior Credit Facility is based on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under our Senior Credit Facility.

Under the terms of our Senior Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination during any 12-month period. Our borrowing base is also subject to reduction if we monetize certain of our hedging transactions. In the event the amount outstanding under our Senior Credit Facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings over a period no longer than six months. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our Senior Credit Facility, sell assets or sell additional shares of common stock. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in a default under our Senior Credit Facility, which could adversely affect our business, financial condition and results or operations. Our borrowing base is currently set at $110 million until the next borrowing base redetermination provided for in the Senior Credit Facility, which is scheduled for May 2010.

We may incur additional indebtedness. This could further exacerbate the risks associated with our substantial leverage.

We may incur substantial additional indebtedness in the future. The indenture governing our senior notes and documents governing our Senior Credit Facility contain restrictions on our ability to incur indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute “Indebtedness” or “Debt” under the indenture and the Senior Credit Facility, respectively. If we incur indebtedness above our current debt levels, the related risks that we now face could intensify and we may not be able to meet all our debt obligations. Failure to meet these obligations could result in a default under our debt documents, which could adversely affect our business, financial condition and results of operations.

To service our indebtedness we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control. Failure to generate sufficient cash to service our indebtedness could adversely affect our business, financial condition and results of operations.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be 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 Facility or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

If we are unable to meet our debt service obligations, we may be required to seek a waiver or amendment from our debt holders, refinance such debt obligations or sell assets or additional shares of common stock. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to meet our debt obligations could result in a default under the agreements governing our indebtedness. 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 such indebtedness, lenders having secured obligations, such as the lenders under our Senior Credit Facility, could proceed against the collateral securing the debt. Because the indenture governing the Senior Notes and the documents governing our Senior Credit Facility have customary cross-default provisions, if the indebtedness under the Senior Notes or under our Senior Credit Facility or any of our other facilities is accelerated, we may be unable to repay or finance the amounts due.

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.

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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 counterparties 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 counterparties if our payment obligations exceeded certain levels. Future collateral requirements are uncertain but will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

The results of our planned drilling in the Bakken and Three Forks objectives, an emerging play with limited drilling and production history, are subject to more uncertainties than our drilling program in the more established formations and may not meet our expectations for reserves or production.

We have recently begun drilling wells in the Bakken and Three Forks objectives. Part of our drilling strategy to maximize recoveries from the Bakken and Three Forks objectives involves the drilling of horizontal wells using completion techniques that have proven to be successful in other shale formations. Our experience with horizontal drilling of the Bakken and Three Forks objectives to date, as well as the industry’s drilling and production history in the formation, is limited. The ultimate success of these drilling and completion strategies and techniques in this formation will be better evaluated over time as more wells are drilled and longer term production profiles are established. In addition, based on reported decline rates in these formations in other areas and in other shale formations, we estimate the average monthly rates of production should decline by approximately 70% during the first twelve months of production. Actual decline rates may differ significantly. Accordingly, the results of our future drilling in the emerging Bakken and Three Forks objectives are more uncertain than drilling results in the other formations with established reserves and production histories.

Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging plays. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and takeaway capacity or otherwise, and/or oil and natural gas prices remain depressed or decline further, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future.

The proposed United States federal budget for fiscal year 2010 and other pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

In February 2009, the Obama administration released its budget proposals for the fiscal year 2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to further these objectives. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new taxes. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law our taxes could increase, potentially significantly, after net operating losses are exhausted, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Although these proposals were made approximately one year ago, none have been voted on or become law, however, it is still the Obama Administration’s stated intention to enact these provisions in 2010. We do not know the ultimate impact these proposed changes may have on our business.

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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 engineers, geologists and geophysicists who have considerable experience in applying advanced horizontal drilling and completion and 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 assist us in improving the performance and 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.

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

We use the full cost method of accounting 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 writedown.” The risk that we will experience a ceiling limitation writedown increases when oil and gas prices are depressed or if we have substantial downward revisions in estimated proved reserves. Based on oil and gas prices in effect on March 31, 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit. As such, we recorded a $114.8 million ($71.9 million after tax) impairment to our oil and gas properties at March 31, 2009. Based on oil and gas prices in effect on December 31, 2008 ($5.71 per MMBtu for Henry Hub gas and $44.60 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit. As such, we recorded a $237.2 million ($148.6 million after tax) impairment to our oil and gas properties at December 31, 2008. We may be required to recognize additional pre-tax non-cash impairment charges in the future reporting periods if market prices for oil or natural gas decline.

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

We make and hope to 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.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended.

As of December 31, 2009, we had mineral leases on approximately 282,584 net acres in the Williston Basin which we believe are prospective for the Bakken and/or Three Forks. A significant portion of the acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their primary terms or we obtain extensions of the leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

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

We require significant amounts of undeveloped leasehold acreage in order to further our development efforts. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon our initial investments. Additionally, we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new wells drilled by us in provinces that we pursue will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. 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. Additionally, we rely to some extent on 3-D seismic data and other advanced technologies in identifying leasehold acreage prospects and in conducting our exploration activities. These 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.

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 advanced horizontal drilling and completion techniques, 3-D seismic and other advanced technologies, exploratory drilling is a speculative activity.

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

Our proved reserve estimates are prepared 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, 2009, approximately 63% of our estimated proved reserves were classified as undeveloped. At December 31, 2009, we estimated that it would require additional capital expenditures of approximately $266.7 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 in our Rocky Mountains province and 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.

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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 conclusively 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. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, 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 North Dakota, Montana, Texas, Southern Louisiana, or Oklahoma, 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 affect market based prices or result in a curtailment of production and revenues.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering and transportation systems, pipelines and processing facilities. We generally deliver oil at our leases under short-term contracts. Counterparties to our short-term contracts rely on access to regional transportation systems and pipelines. If transportation systems or pipeline capacity is constrained, we would be required to find alternative transportation modes, which would impact our market based price, or temporarily curtail production. 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 2008, Hurricanes Gustav and Ike disrupted our Gulf Coast operations forcing us to temporarily curtail production and delayed bringing new wells on line. Hurricane Ike forced us to curtail approximately 1.0 MMcfe per day of production during the third quarter 2008. Furthermore, both Hurricanes Gustav and Ike delayed our completion operations on our Southern Louisiana wells reducing third quarter 2008 production by an estimated 1.8 MMcfe per day.

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.

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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, 2009, approximately 26% 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.

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.

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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 United States Congress, 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. 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.

Our operations are subject to complex federal, state and local environmental laws and regulations, including CERCLA, RCRA, the Oil Pollution Act of 1990, 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. For example, on June 9, 2009, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2009 were introduced in the United States Senate and House of Representatives. These bills would repeal the exemption for hydraulic fracturing from the federal Safe Drinking Water Act, which would have the effect of allowing the federal Environmental Protection Agency, commonly referred to as the EPA, to promulgate regulations requiring permits and implementing potential new requirements on hydraulic fracturing under the federal Safe Drinking Water Act. This could, in turn, require state regulatory agencies in states with programs delegated under the Safe Drinking Water Act to impose additional requirements on hydraulic fracturing operations. In addition, the bills would require person using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas, of their fracturing fluids to a regulatory agency, which would make the information public via the internet. If this or similar legislation becomes law, it could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if the federal or state legislation is enacted into law.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill. The U.S. Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not passed. Although these bills include several differences that require reconciliation before becoming law, both bills contain the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions. Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this legislative initiative remains uncertain. In addition to the pending climate legislation, the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The EPA has proposed regulation that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to company operations and the refining, processing, and use of oil and gas.

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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 are prohibited from paying dividends on our common stock.

We will retain all future earnings and other cash resources for the future operation and development of our business. The documents governing our Senior Credit Facility and the indenture governing our Senior Notes prohibit the payment of dividends. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future.

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, the documents governing our senior credit facility 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 facility and our 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.

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Forward-Looking Statements

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

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

• our growth strategies;

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

• anticipated trends in our business;

• our future results of operations;

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

• market conditions in the oil and gas industry;

• our ability to make and integrate acquisitions; and

• the impact of governmental regulation.

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

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Historically, our exploration and development activities have been focused in the Onshore Gulf Coast, the Anadarko Basin and West Texas. Beginning in late 2005, we began to acquire acreage within the Williston Basin in North Dakota and Montana and as of December 31, 2009, we have approximately 453,147 gross and 282,584 net leasehold acres in the Williston Basin. In late 2007, the majority of our drilling capital expenditures shifted from our historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West Texas to the Williston Basin, where we are currently targeting the Bakken, Three Forks and Red River formations. In 2008, we drilled 53 gross wells on our Williston Basin acreage investing a total of $117.4 million in drilling, land and seismic. In 2009, we drilled 54 gross wells on our Williston Basin acreage investing a total of $53.1 million in drilling, land and seismic. Through year-end 2009, we have invested in excess of $222 million on drilling, land and seismic in the Williston Basin.

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In 2009, we spent a total of approximately $60.0 million on drilling, land and seismic in our operating areas. During 2010, we plan to spend approximately $183.7 million on drilling 60 gross (27.1 net) wells as well as drill and complete wells that were in progress at December 31, 2009. We currently expect to spend approximately $15.6 million on land and seismic and incur $14.8 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, 2009, unless otherwise noted.

	Rocky			Onshore			Anadarko			West Texas
	Mountains (a)			Gulf Coast			Basin			& Other			Total
Capital expenditures for drilling, land and seismic in 2009 (in millions)	$	53.1		$	7.4		$	(1.2	)	$	0.7		$	60.0
Proved Reserves at December 31, 2009
Pre-tax PV10% (in millions) (b)	$	133.6		$	87.7		$	13.1		$	19.7		$	254.1
Oil (MMBbls)		13.7			1.7			0.2			1.1			16.6
Natural gas (Bcf)		10.4			38.9			16.4			0.7			66.4
Oil equivalents (MMBoe) (c)		15.4			8.2			2.9			1.2			27.7
% Oil		89	%		21	%		6	%		90	%		60	%
Average daily production volumes (MBoe) (d)		1,816			2,194			726			298			5,034
Average daily sales volumes (MBoe)(d)		1,770			2,194			726			298			4,988
Productive wells at December 31, 2009
Gross		115			76			82			83			356
Net		22.9			38.3			21.3			24.6			107.1
3-D Seismic Data (square miles)		1,402			4,459			2,381			4,698			12,940

(a)	Includes the Williston Basin located in North Dakota and Montana and the Powder River Basin located in Wyoming.
(b)	The standardized measure for our proved reserves at December 31, 2009, was $246.5 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. The prices used to calculate this measure were $61.18 per barrel of oil and $3.87 per MMbtu of natural gas. These prices represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period. These 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 this date.
(c)	Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
(d)	Average daily production volumes calculated based on 360 day year. Includes approximately 16,475 barrels of oil produced in the Williston Basin during 2009 and recorded as inventory at year-end 2009. Ending inventory at year end 2008 and 2007 was not material. Adjusting the production volumes for amounts included in inventory would result in average daily sales volumes in the Rocky Mountains and in total of 1,770 and 4,988 barrels of oil equivalent, respectively.

Rocky Mountains Province

We regularly evaluate opportunities to expand our activities to areas that may offer attractive exploration and development potential. 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 2009, we invested approximately $53.1 million in drilling, land and seismic in the Williston Basin. During 2009, we spud 54 gross wells in the Williston Basin, with 13 wells completing and three wells drilling at year-end. In 2009, we did not allocate any capital spending to the Powder River Basin.

Overview of Williston Basin

The Williston Basin is spread across North Dakota, Montana and parts of southern 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, Three Forks and Red River formations, which are currently our primary objectives.

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The Bakken is an unconventional oil shale play at depths of approximately 8,500 to 10,500 feet that is primarily exploited via horizontal drilling and advanced completion techniques. Advanced completion techniques include the use of swell packers and multi-stage fracture stimulations, which help to fracture the shales and increase oil flow to the well bore. To date, much of the Bakken drilling in North Dakota has occurred east of the Nesson Anticline in and around Mountrail County, with additional activity south of the Nesson Anticline in Dunn County. In the second half of 2009, activity accelerated west of the Nesson Anticline in Williams and McKenzie Counties, North Dakota.

The Three Forks is an unconventional carbonate play that lies just below the Bakken. Similar to the Bakken, the Three Forks is primarily exploited using horizontal drilling and advanced completion techniques. Drilling in the Three Forks began in mid-2008 and a number of operators, including us, are targeting this objective. Drilling in this objective is early, but initial results appear to indicate that the Three Forks is a separate reservoir from the Bakken, which increases our exposure to oil reserves in the basin. Over time, further drilling of both Bakken and Three Forks wells in the same sections will help to delineate whether the Bakken and Three Forks are separate reservoirs.

The Red River is a conventional oil resource at a depth of approximately 12,000 feet. The Red River is exploited via vertical well bores with minimal completion procedures. Targets are identified using a proprietary 3-D seismic attribute analysis. Since late 2007, we have drilled and completed three Red River discoveries in Sheridan County, Montana.

Overview of Williston Basin Acreage Position

Our acreage position in the Williston Basin is comprised of approximately 282,584 net acres. Approximately 99,215 net acres is east of the Nesson Anticline in Mountrail County, North Dakota and adjoining counties to the north, south and east. Acreage east of the Nesson Anticline includes approximately 5,387 net acres in our Parshall / Austin / Sanish project area in Mountrail County where drilling activities are typically operated by others and we therefore participate in wells in a non-operated role. Acreage east of the Nesson Anticline also incorporates approximately 36,645 net acres in our Ross Project area in Mountrail County where we both operate and participate in non-operated North Dakota wells. Currently, we anticipate drilling 13 operated gross wells (7.4 net) in and around our Mountrail County, North Dakota acreage position in 2010.

Approximately 100,056 net areas is west of the Nesson Anticline in Williams and McKenzie Counties, North Dakota in our Rough Rider project area. Acreage in our Rough Rider project area is subject to the Drilling Participation Agreement outlined below. Typically, because of our higher working interests in spacing units, we operate wells in our Rough Rider area but to a lesser degree will also participate in wells in a non-operated role. Currently, we anticipate drilling 25 operated gross wells (12.7 net) in our Rough Rider project area in 2010. The remaining 83,313 net acres is located in eastern Montana in Roosevelt and Sheridan Counties in our Ghost Rider project area. Activity in Montana has been limited but towards the end of 2009 other operators began drilling and / or permitting wells in the area. Currently, we anticipate drilling one operated gross well (1.0 net) on our Montana acreage in 2010 to test the prospectivity of the Bakken, as well as other conventional or unconventional producing horizons.

Overview of Rough Rider Drilling Participation Agreement

In late August 2009, we entered into a drilling participation agreement in our Rough Rider project area in order to accelerate operations and address near term state lease expirations. The initial group of six wells under the agreement has been drilled. In each of the initial six wells, we have retained 35% of our original working interest and will back in for 35% of our counterparty’s interest in the combined six well group after combined payout (defined as the point in time when the cumulative net receipts from the initial wells equals or exceeds all expenditures for such wells). Our counterparty had the option to participate in an additional nine wells. In December 2009 our counterparty elected to participate in the next group of four wells and in January 2010, our counterparty elected to participate in the final group of five wells. We have elected to retain our maximum interest of 50% of our original working interest in the additional nine wells. Further, we will have the option to keep up to 64% of our original working interest in all subsequent in fill development wells in all 15 drilling units.

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2009 Williston Basin Drilling and Completion Activity

						FRAC		IP		30 DAY
WELL NAME	County	OBJECTIVE	~WI			STAGES		(Boe/d)		Average (Boe/d)**
Williston 25-36 #1H	Williams	Bakken		33	%*		32		3,394		1,505
Strand 16-9 #1H	Williams	Bakken		22	%*		26		2,264		948
Lee 16-21 #1H	Williams	Bakken		31	%*		28		1,544		698
BCD Farms 16-21 #1H	Williams	Bakken		25	%*		28		1,776		702
Brad Olson 9-16 #1H	Williams	Bakken		33	%*		28		2,112		811
Figaro 29-32 #1H	McKenzie	Bakken		95	%		19		1,895		831
Anderson 28-33 #1H	Mountrail	Bakken		66	%		24		2,154		1,346
Strobeck 27-34 #1H	Mountrail	Three Forks		77	%		18		2,021		989
Olson 10-15 #1H	Williams	Bakken		100	%		20		1,433		730
			Averages						2,066		951

*	Rough Rider drilling participation agreement wells where our working interest is anticipated to increase upon payout.
**	Excludes any days well was down for remediation.

2010 Williston Basin Drilling and Completion Activity / 2010 Capital Budget

						FRAC		IP		30 DAY
WELL NAME	County	OBJECTIVE	~WI			STAGES		(Boe/d)		Average (Boe/d)**
Liffrig 29-20 #1H	Mountrail	Three Forks		72	%		29		2,477	NA
Owan-Nehring 27-34	Williams	Bakken		49	%		30		2,513	NA
Jackson 35-34 #1H	Williams	Bakken		62	%		30		3,540	907
State 36-1 #1H	Williams	Bakken		16	%*		30		3,807	1,516
			Averages						3,084	1,212

*	Rough Rider drilling participation agreement wells where our working interest is anticipated to increase upon payout.
**	Excludes any days well was down for remediation.

During 2010, we anticipate spending approximately $175.8 million to drill and complete 39 gross (21.1 net) operated wells and 4.6 net non-operated wells in the Williston Basin. Additionally, we anticipate spending approximately $14.2 million on land and seismic. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Commitments — Overview of Capital Activity.”

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. 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 Miocene and Upper Oligocene trends in Southern Louisiana and the Frio trend in and around Matagorda County, Texas.

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During 2009, activity in the onshore Gulf Coast province was significantly reduced due to depressed natural gas prices and our allocation of capital to the Williston Basin. During the year, we completed one gross well (0.6 net) in one attempt for a completion rate of 100%. In 2009, we spent $7.4 million on drilling, land and seismic in our Onshore Gulf Coast province. Our capital expenditures were allocated 45% to Southern Louisiana, 32% to the Frio and 15% to the Vicksburg.

For 2010, we currently plan to spend $6.2 million in our Onshore Gulf Coast province. Approximately $5.3 million of this spending has been allocated to drilling, with the remaining $0.9 million allocated to land and seismic activities. We anticipate that approximately 74% of the drilling, land and seismic will be allocated to the Vicksburg trend with the remaining 26% allocated to other areas in the province.

Vicksburg Trend

Our Vicksburg activity is focused principally in Brooks County, Texas, in our Home Run, Triple Crowne, and Floyd Fields. We discovered these fields in 1999, 2001 and 2002, respectively. Since 1999, we have drilled 43 Vicksburg wells and we have completed 41 of those wells. We believe we have a multi-year inventory of proved, probable and possible drilling locations in our Home Run, Triple Crown and Floyd Fields.

In 2009, we spent approximately $1.1 million establishing production from zones that were classified as proved developed not producing at year end 2008.

In 2010, we anticipate drilling one operated gross (1.0 net) well in the Vicksburg trend in the first half of 2010 depending upon both favorable natural gas prices and service costs.

Southern Louisiana Trend

In Southern Louisiana, we have utilized our geophysical, geological and operational expertise to explore for hydrocarbon bearing Miocene and Oligocene reservoirs. These reservoirs are generally on trend with the Texas Gulf Coast Frio and are therefore logical extensions of our drilling activities.

In December 2007, we entered into a joint venture to operate the drilling of at least five prospects over the subsequent 18 months, earning a 50% working interest. In February 2009, the remaining joint venture well, the Chandeleur Sound SL 19312 #1, was brought on line at an initial production rate of approximately 2.9 MMcfe per day. We maintain a 50% working interest in the well. During 2009, we spent $3.3 million in Southern Louisiana primarily to complete wells in progress at year-end 2008.

In 2010, we have no current plans to drill in Southern Louisiana.

Frio Trend

During 2009, we drilled one operated gross well (0.6 net) in Matagorda County, Texas. The G.S. Harrison Unit #2 was completed in March 2009 and was production tested at an early rate of 3.0 MMcfe per day from the lowest 20 feet of pay.

In 2010, we have no current plans to drill in the Frio Trend.

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.

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.

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In 2009, we received proceeds of $1.4 million related to the sale of mineral interests. Because of the sale, we spent a ($1.2) million in the Anadarko Basin during 2009. In 2010, we have no current plans to drill in the Anadarko Basin.

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 5 of New Mexico, and the Mississippian Reef of the Hardeman Basin, at depths ranging from 7,000 to 13,000 feet.

During 2009, 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.

We anticipate spending $1.1 million to drill 3 gross (0.4 net) wells in West Texas in 2010.

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 Facility. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - - Liquidity and Capital Resources — Senior Credit Facility” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — 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, 2009 are as follows:

Summary of Oil and Gas Reserves as of Fiscal-Year-End Based on Average Fiscal-Year Prices

	Reserves
	Oil		NaturalGas		Total
	(MMBbls)		(Bcf)		(MMBoe)(a)
PROVED
Developed:
United States		5.3		29.2		10.2
Undeveloped:
United States		11.3		37.2		17.5
TOTAL PROVED		16.6		66.4		27.7

(a) Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

The preparation of our reserve report is outlined in our Sarbanes Oxley Act Section 404 internal control procedures. Our procedures require that our reserve report is prepared by a registered independent engineering firm at the end of every year based on information provided by our Reservoir Engineering Department.

Our Reservoir Engineering Department accumulates historical production data for our wells, calculates historical lease operating expenses and differentials, updates working interests and net revenue interests, obtains updated Authorizations for Expenditure from our Operational Engineering Department and obtains logs, 3-D seismic and other geological and geophysical information from our Geological and Geophysical Department. This data is forwarded to Cawley, Gillespie & Associates, Inc. (CGA), our registered independent petroleum consultants.

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CGA prepares a report of our estimated proved reserves in their entirety based on the information provided to them. CGA is a Texas Registered Engineering Firm (F-693). Our primary contact at CGA is Mr. W. Todd Brooker, Vice President. Mr. Brooker is a State of Texas Licensed Professional Engineer (License #83462). See Exhibit 99.1 Report of Cawley, Gillespie & Associates, Inc.

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 average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of net proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — New Accounting Pronouncements.”

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 CGA 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 natural 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.

Proved Undeveloped Reserves

Our total proved undeveloped (PUD) reserves as of December 31, 2009 were 17.5 MMBoe. PUD reserves represented 63% of our total proved reserves in 2009 versus 54% in 2008. The increase in our PUD reserves as a percentage of our total proved reserves was attributable to the application of advanced drilling and completion techniques, improved oil prices, reduced service costs and the modernization of SEC reserve reporting rules.

The application of advance drilling and completion techniques, which incorporates drilling long laterals and completing wells with swell packers and between 18 and 32 fracture stimulation stages in 2009, appears to have enhanced our estimated ultimate recoveries (EURs) and thereby improved our rates of return. During 2009, we applied these advanced drilling and completion techniques to areas that had previously experienced minimal drilling activity and drilled apparently economic wells. In these areas, we were able to increase our level of PUD reserves.

Oil prices used in our year-end 2009 reserve report increased 37% relative to 2008. During 2009, service costs decreased approximately 40% as the pace of drilling activity in the United States decreased due to the economic crisis, resulting recession and scarcity of available capital. Enhanced oil prices and reduced service costs improved our rates of return and allowed us to book PUD reserves in previously uneconomic locations. Enhanced oil prices also typically lengthens the time that a well can be economically produced and therefore increases the amount of economically recoverable reserves over the life of the well.

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The modernization of SEC oil and gas reporting rules also enhanced our level of PUD reserves. Effective with years ending on or after December 31, 2009, the SEC modernized its rules with respect to oil and gas reserves for the first time since 1982. The new rules increased the number of offsetting PUD locations we were able to book in unconventional resource plays such as the Williston Basin from two in 2008 to four in 2009. The increased number of offsetting locations we are able to book allowed us to increase our level of PUD reserves and, therefore, also increased our level of total proved reserves. Approximately 4.0 MMBoe in reserves were booked at year-end 2009 related to the SEC rules changes.

Partially offsetting the above PUD reserve increases, we eliminated multiple PUD reserve locations in areas that we currently do not anticipate drilling within the next five years. The PUD reserve locations that we eliminated were primarily natural gas drilling locations in areas outside of our core Williston Basin and South Texas acreage positions and totaled 2.9 MMBoe.

Our PUD reserves also decreased due to the drilling of 18 gross PUD wells (2.8 net) during 2009. During the year, we spent approximately $14.3 million dollars converting 0.98 MMBoe from PUD to proved developed producing reserves.

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 (in millions).

	At December 31,
	2009		2008		2007
Standardized measure of discounted future net cash flows	$	246.5	$	279.3	$	394.5
Add present value of future income tax discounted at 10%		7.6		8.7		97.1
Pre-tax PV10%	$	254.1	$	288.0	$	491.6

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Drilling Activities

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

	Year Ended December 31,
	2009				2008				2007
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells:
Natural gas		0		0.0		4		1.3		0		0
Oil		1		0.1		1		0.8		3		1.1
Non-productive		1		0.2		2		1.0		7		3.8
Total		2		0.3		7		3.1		10		4.9
Development wells:
Natural gas		1		0.6		9		4.5		8		5.7
Oil		38		4.8		52		7.8		11		4.2
Non-productive		0		0.0		0		0.0		0		0.0
Total		39		5.4		61		12.3		19		9.9

Present Activities

As of December 31, 2009, we had four operated rigs in the Williston Basin. Two of the rigs were drilling locations representing 0.6 net wells. The remaining two drilling rigs were in the process of moving to their next drilling location. At year-end, we also had one non-operated well drilling in the Williston Basin representing 0.05 net wells. Finally, we had 13 wells in the Williston Basin waiting on completion representing 2.1 net wells. Three of the wells waiting on completion were operated locations representing 1.8 net wells.

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.

Delivery Commitments

As of December 31, 2009, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements.

Productive Wells and Acreage

Productive Wells

The following table sets forth our ownership interest at December 31, 2009 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
Rocky Mountains		0		0		115		22.9		115		22.9
Onshore Gulf Coast		60		34.1		16		4.2		76		38.3
Anadarko Basin		71		19.6		11		1.7		82		21.3
West Texas and Other		10		1.3		73		23.3		83		24.6
Total		141		55.0		215		52.1		356		107.1

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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 as leasehold interest at December 31, 2009.

	Developed(a)				Undeveloped(a)				Total
	Gross		Net		Gross		Net		Gross		Net
Rocky Mountains		55,657		31,791		499,600		297,854		555,257		329,645
Onshore Gulf Coast		22,385		9,558		9,387		5,430		31,772		14,988
Anadarko Basin		62,086		17,629		11,748		7,826		73,834		25,455
West Texas & Other		20,326		5,729		10,000		1,940		30,326		7,669
Total		160,454		64,707		530,735		313,050		691,189		377,757

(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, 2010		55,071		29,151
December 31, 2011		118,412		73,978
December 31, 2012		138,174		89,781
December 31, 2013		103,532		61,500
December 31, 2014		26,764		21,035
Thereafter		88,782		37,605
Total		530,735		313,050

In addition, as of December 31, 2009, we had mineral interests covering approximately 11,488 gross and 1,854 net acres. The mineral acres will continue into perpetuity and will not expire.

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Sales Volumes, Prices and Production Costs

The following table sets forth our sales 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. We account for our hedges using mark-to-market accounting, which 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.

	Year Ended December 31,
	2009		2008		2007
Sales volumes(a):
Oil volumes (MBbls)
Rocky Mountains		610		292		44
Onshore Gulf Coast		88		151		200
Anadarko Basin		21		24		32
West Texas & Other		95		111		116
Total oil		814		578		392
Natural gas volumes (MMcf)
Rocky Mountains		169		53		28
Onshore Gulf Coast		4,211		6,032		9,716
Anadarko Basin		1,441		1,821		2,766
West Texas & Other		71		90		116
Total natural gas		5,892		7,996		12,626
Total oil equivalent (MBoe)		1,796		1,911		2,496
Average oil prices based on sales volumes:
Oil price (per Bbl)	$	54.79	$	89.06	$	72.30
Oil price including derivative settlement gains (losses) (per Bbl)	$	53.99	$	84.63	$	71.51
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	48.65	$	89.79	$	65.57
Average natural gas prices based on sales volumes:
Natural gas price (per Mcf)	$	4.01	$	9.21	$	7.30
Natural gas price including derivative settlement gains (losses) (per Mcf)	$	5.71	$	9.08	$	7.66
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	5.21	$	9.48	$	7.38
Average equivalent prices based on sales volumes:
Oil equivalent price (per Boe)	$	37.97	$	65.50	$	48.30
Oil equivalent price including derivative settlement gains (losses) (per Boe)	$	43.19	$	63.62	$	49.98
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)	$	39.12	$	66.84	$	47.64
Average production costs (per Boe) based on sales volumes:
Lease operating expenses (includes costs for operating and maintenance and expensed workovers)	$	7.61	$	5.89	$	3.66
Ad valorem taxes	$	0.56	$	0.58	$	0.60
Production taxes	$	2.84	$	2.81	$	1.02

(a) Sales volumes for 2009 exclude 16,475 barrels of oil produced during the year but held in inventory. Ending inventory at year end 2008 and 2007 was not material. During 2009, production volumes for crude oil were 830 MBbls and total oil equivalent production volumes were 1,812 MBoe.

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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, 2009, 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

(a)	We convened a Special Meeting of Stockholders on Wednesday, October 7, 2009, in Austin, Texas at 9:00 a.m. local time.
(b)	N/A

(c) Out of the total 82,862,476 shares of our common stock outstanding and entitled to vote, 73,600,146 shares were present in person or by proxy at the special meeting, representing approximately 89% of our common stock outstanding. The only matters voted on by our stockholders, as fully described in the definitive proxy materials for the special meeting, are set forth below. The results were as follows:

1. To approve an amendment to our Certificate of Incorporation to increase the number of authorized shares of common stock from 90 million shares to 180 million shares.

For	66,363,106
Against	6,976,123
Abstained	260,917
Broker non-votes	0

2. To approve an amendment to the 1997 Incentive Plan to increase the number of shares of common stock available under the plan.

For	40,626,366
Against	10,202,489
Abstained	113,391
Broker non-votes	22,657,900

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Executive Officers of the Registrant

Pursuant to Instruction 3 to Item 401(b) of 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 February 25, 2010.

Name	Age		Position
Ben M. Brigham		50	Chief Executive Officer, President and Chairman
Eugene B. Shepherd, Jr.		51	Executive Vice President and Chief Financial Officer
David T. Brigham		49	Executive Vice President — Land and Administration and Director
A. Lance Langford		47	Executive Vice President — Operations
Jeffery E. Larson		51	Executive Vice President — Exploration

Ben M. “Bud” Brighamhas served as our Chief Executive Officer, President and Chairman of the Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas 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 26 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. Brighamjoined 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 Langfordjoined 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. Larsonjoined 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.

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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 Select 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 Select 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
2008:
First Quarter	$	8.16	$	4.86
Second Quarter		18.29		5.76
Third Quarter		17.62		10.00
Fourth Quarter		10.91		2.30
2009:
First Quarter	$	4.25	$	1.04
Second Quarter		4.30		1.60
Third Quarter		10.61		2.50
Fourth Quarter		14.93		7.99

The closing market price of our common stock on February 23, 2010 was $15.55 per share. As of February 23, 2010, there were an estimated 155 record owners of our common stock.

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The following graph is a comparison of cumulative total returns. It assumes that $100 was invested in our common stock, the NASDAQ Composite Index, and the S&P Oil & Gas E&P Select Industry Index at the end of 2004 and remained invested through year-end 2009. The Indexes and the graph were prepared by an independent third party. The NASDAQ Composite Index is calculated using the over 3,000 companies which trade on The NASDAQ Stock Market, including both domestic and foreign companies. The S&P Oil & Gas E&P Select Industry Index (SPSIOP) represents the oil and gas exploration and production sub-industry portion of the S&P Total Market Index.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN
Among Brigham Exploration Company, The NASDAQ Composite Index
And The S&P Oil & Gas Exploration & Production Index

*	$100 invested on 12/31/04 in stock or index, including reinvestment of dividends.
	Fiscal year ending December 31.

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

We are obligated to pay cash dividends on our Series A preferred stock. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Mandatorily Redeemable Preferred Stock.”

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Securities Authorized for Issuance under Equity Compensation Plans

The following table includes information regarding our equity compensation plans as of the year ended December 31, 2009.

					Number of
					Securities
	Number of				Remaining
	Securities to be				Available for
	Issued upon		Weighted-		Future Issuance
	Exercise of		Average Price of		Under Equity
	Outstanding		Outstanding		Compensation
Plan Category	Options		Options		Plans
Equity compensation plans approved by security holders(a)		4,170,137	$	5.14		566,800
Equity compensation plans not approved by security holders		—		NA		—
Total		4,170,137	$	5.14		566,800

(a) Does not include 556,990 shares of restricted stock issued and outstanding at December 31, 2009.

Issuer Purchases of Equity Securities

In 2009, 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 2009		2,597	$	9.55
December 2009		37,433	$	13.86
Total		40,030		13.58

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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.

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We derived the statement of operations data and statement of cash flows data for the years ended December 31, 2009, 2008 and 2007, and balance sheet data as of December 31, 2009 and 2008 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, 2006 and 2005 and the balance sheet data as of December 31, 2007, 2006 and 2005, from our accounting books and records.

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(In thousands, except per share information)
Statement of Operations Data:
Revenues:
Oil and natural gas sales	$	68,192		$	125,108		$	120,557		$	102,835		$	96,820
Gain (loss) on derivatives, net		2,064			2,548			(1,664	)		3,335			—
Other revenue		88			132			88			127			220
Total revenues		70,344			127,788			118,981			106,297			97,040
Costs and expenses:
Lease operating		14,655			12,363			10,704			10,701			7,161
Production taxes		5,098			5,374			2,541			4,021			3,353
General and administrative		9,243			9,557			9,276			7,887			5,533
Depletion of oil and natural gas properties		32,054			53,498			59,079			46,386			33,268
Impairment of oil and natural gas properties		114,781			237,180			6,505			—			—
Depreciation and amortization		812			629			613			537			762
Loss on inventory valuation		2,196			—			—			—			—
Accretion of discount on asset retirement obligations		421			361			379			317			180
Total costs and expenses		179,260			318,962			89,097			69,849			50,257
Operating income (loss)		(108,916	)		(191,174	)		29,884			36,448			46,783
Other income (expense):
Interest income		578			191			654			1,207			245
Interest expense, net		(16,431	)		(14,495	)		(14,622	)		(9,688	)		(3,980	)
Gain loss on derivatives, net		—			—			—			3,213			(814	)
Other income (expense)		1,544			530			1,022			1,352			238
Total other income (expense )		(14,309	)		(13,774	)		(12,946	)		(3,916	)		(4,311	)
Income (loss) before income taxes and cumulative effect of change in accounting principle		(123,225	)		(204,948	)		16,938			32,532			42,472
Income tax benefit (expense):
Current		—			—			—			—			—
Deferred		233			42,701			(6,728	)		(12,744	)		(15,037	)
		233			42,701			(6,728	)		(12,744	)		(15,037	)
Net income (loss) available to common stockholders	$	(122,992	)	$	(162,247	)	$	10,210		$	19,788		$	27,435
Net income (loss) per share available to common shareholders:
Basic	$	(1.74	)	$	(3.57	)	$	0.23		$	0.44		$	0.65
Diluted		(1.74	)		(3.57	)		0.22			0.43			0.63
Weighted average shares outstanding:
Basic		70,569			45,441			45,110			45,017			42,481
Diluted		70,569			45,441			45,531			45,597			43,728

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	At December 31,
	2009			2008			2007			2006			2005
	(In thousands)
Statement of Cash Flows Data:
Net cash provided (used) by:
Operating activities	$	51,750		$	69,630		$	90,449		$	88,687		$	64,379
Investing activities		(164,620	)		(179,866	)		(99,093	)		(171,747	)		(113,220	)
Financing activities		113,608			136,416			18,207			83,385			50,535
Balance Sheet Data:
Cash and cash equivalents	$	40,781		$	40,043		$	13,863		$	4,300		$	3,975
Oil and natural gas properties, using the full cost method of accounting, net		330,733			404,839			510,207			485,525			347,329
Total assets		498,256			489,056			548,428			522,587			380,427
Long-term debt		158,968			303,730			168,492			149,334			63,100
Series A preferred stock, mandatorily redeemable (a)		10,101			10,101			10,101			10,101			10,101
Total stockholders’ equity		264,283			121,269			279,027			266,015			241,640

(a) At year-end 2009, our Series A preferred stock was classified as a current liability as it will be redeemed in October 2010.

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 production volumes sold 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 Costsare 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; fluid treatment and disposal; 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.

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• 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 Amortizationis 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 Expenseis the systematic, monthly accretion of future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities.

General and Administrative Expenseincludes 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. 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 pay a fixed interest rate on both our Senior Notes and our preferred stock. We expect to continue to incur interest expense as we continue to grow. We capitalize interest directly related to our unevaluated properties and certain properties under development, which are not being amortized.

Income Taxes.We are generally subject to a 35% federal income tax rate. For income tax purposes, we are allowed deductions for accelerated depreciation, depletion, intangible drilling costs, and state taxes. Through 2009, all of our federal and state 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 and also to hold acreage that would otherwise expire if not drilled. 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 Facility, 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 Facility fund our working capital obligations.

41

Overview of Capital Activity

Our improving operational results in the Williston Basin Bakken and Three Forks plays during 2008, largely attributable to increasing the number of fracture stimulation stages in each horizontal wellbore, led us to increase our capital expenditure budget in the Williston Basin in 2008 and reduce our conventional portfolio activity in the Onshore Gulf Coast, the Anadarko Basin and West Texas. We added a second Williston Basin drilling rig during the last half of 2008 to accelerate drilling east of the Nesson Anticline in Mountrail County, North Dakota as well as to begin development of acreage west of the Nesson Anticline in Williams and McKenzie Counties, North Dakota.

Unfortunately, as we added our second drilling rig, commodity prices rapidly deteriorated during the last half of 2008 because of the financial crisis and recession experienced both in the United States and internationally. Crude oil and natural gas prices, which had peaked at approximately $145.29 per barrel and $13.58 per Mcf in July 2008, reached a 2008 low of $33.87 per barrel and $5.29 per Mcf in December 2008. Despite decreasing prices, continued high levels of drilling activity by operators sustained the elevated drilling and completion costs and overall project returns were negatively impacted because of the mismatch that existed between commodity prices and the cost to drill and complete wells.

In early 2009, to combat the reduction in our rates of return and the general deteriorating availability of capital, we elected to cease drilling and completion operations post completion of the Olson 10-15 #1H, which was our first long lateral well with 20 fracture stimulation stages. In March 2009, we announced a 2009 capital budget of $37.1 million, which was largely comprised of costs to complete the Olson 10-15 #1H and costs related to several other wells that we ceased operations prior to reaching the completion stage.

In March 2009, crude oil prices began to rebound and prices averaged $48.06 per barrel. During the first half of 2009, other operators reduced or ceased drilling activity and the number of rigs operating in the Williston Basin rapidly declined from a peak rate of 93 rigs running in November 2008 to 31 rigs running in May 2009. As a result of the reduction in drilling rigs at work in the Williston Basin and elsewhere in the United States, it is estimated that costs to drill and complete wells in the Williston Basin were reduced 30 to 40% relative to the peak rates seen in late 2008 and early 2009.

In May 2009, commodity prices continued to improve and crude oil averaged $59.21 per barrel during the month. Also during this period, economic conditions began to stabilize due to actions taken by governments around the world and capital markets availability improved. In order to restart our Williston Basin drilling program, we elected to raise approximately $93.4 million in net proceeds from the May 2009 equity offering and announced an increase to our 2009 capital budget to $64.5 million.

Shortly thereafter, we commenced completion operations on the wells that we had deferred completing in February 2009. In addition, we picked up a rig to begin drilling operations west of the Nesson Anticline in our Rough Rider project area. In August, we announced entry into a drilling participation agreement, which allowed us to drill additional locations in Rough Rider subject to state lease expirations. We were able to maintain a relatively flat capital expenditure profile for the second half of 2009 even after increasing the number of gross wells drilled, as we reduced our working interest in wells to 35% of our original working interest as a result of the drilling participation agreement.

In October 2009, we raised an additional $168.3 million in net proceeds from an equity offering in order to pre-fund an increased level drilling activity in 2010. Our preliminary 2010 capital budget announced in October 2009, concurrent with the equity offering, was estimated to be $175.8 million and we estimated that we would drill 24 net wells in the Williston Basin and two net wells in our South Texas Vicksburg play.

In 2010, we estimate that we will have four rigs running in the Williston Basin and drill 39 gross (21.1 net) operated wells and 4.6 net non-operated wells. Overall, we currently estimate that we will spend approximately $199.3 million on drilling, land and seismic capital expenditures during 2010. We anticipate funding our 2010 capital expenditure budget through cash on our balance sheet, which was a result of our May and October 2009 equity offerings, cash flow from operations, availability under our Senior Credit Facility, which at year-end 2009 had a borrowing base of $110 million, and through potential divestiture transactions in our conventional asset portfolio.

42

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.

In 2010, as a result of our May and October 2009 equity offerings and improved operational results, we are increasing our level of activity in the Williston Basin and currently estimate that we will spend $216.3 million on capital expenditures during 2010, which includes $199.3 million on drilling, land and seismic capital expenditures and $17.0 million for capitalized costs and other assets.

Factors that could cause us to further increase our level of activity and capital budget in 2010 include a further reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, and a further improvement in commodity prices or well performance that exceeds our risked forecasts, all of which would positively impact our operating cash flow.

Factors that would cause us to reduce our capital budget in 2010 include, but are not limited to, increases in service and materials costs, reductions in commodity prices or underperformance of wells relative to our risked forecasts, all of which would negatively impact our operating cash flow.

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Our budgeted capital expenditures for 2010 are as follows:

	2010
	(In millions)
Drilling	$	183.7
Net land and seismic		15.6
Capitalized costs		14.8
Other non-oil & gas assets		2.2
Total	$	216.3

The final determination with respect to our 2010 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 conditions at the time of drilling;

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

• our liquidity and the availability of external sources of financing; 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.

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.

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 $55.1 million on land and seismic activities.

For a more in depth discussion of our 2009 capital expenditures see “Item 2. Properties.”

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Contractual Obligations

The following schedule summarizes our known contractual cash obligations at December 31, 2009 and the effect these obligations are expected to have on our future cash flow and liquidity.

	Payments Due by Year
							2012-		2014 and
	Total		2010		2011		2013		Thereafter
	(In thousands)
Debt:
Senior Notes	$	160,000	$	—	$	—	$	—	$	160,000
Senior Credit Facility		—		—		—		—		—
Mandatorily redeemable, Series A preferred stock		10,101		10,101				—		—
Total	$	170,101	$	10,101	$	—	$	—	$	160,000
Other commitments:
Interest, Senior Notes(a)	$	69,300	$	15,400	$	15,400	$	30,800	$	7,700
Interest, Senior Credit Facility(b)		—		—		—		—		—
Dividend Mandatorily redeemable, Series A preferred stock(c)		504		504		—		—		—
Drilling rigs(d)		800		800		—		—		—
Non-cancelable operating leases		1,837		721		738		378		—
Total	$	242,542	$	27,526	$	16,138	$	31,178	$	167,700

(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 no amounts outstanding under our Senior Credit Facility. In October 2009, we repaid amounts outstanding under our Senior Credit Facility subsequent to our equity offering. The interest rate under our facility is dependent upon Eurodollar borrowing rates plus a margin that fluctuates dependent upon the amount outstanding under the facility. The Eurodollar rate for one month borrowings was 0.32% on December 31, 2009. The amount of interest that we pay on amounts borrowed under our Senior Credit Facility 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.
(d)	Early termination fee of $200,000 per rig if terminated during the quarter. Contract is quarter-to-quarter evergreen through May 31, 2011.

We also have liabilities of $6.3 million related to asset retirement obligations on our Consolidated Balance Sheet as of December 31, 2009. Due to the nature of these obligations, we cannot determine precisely when payments will be made to settle these obligations. See “Item 8. Financial Statements and Supplementary Data — Note 7. Asset Retirement Obligations.”

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Oil and Natural Gas Reserves

Our estimated total net proved reserves of oil and natural gas as of December 31, 2009, 2008 and 2007 were as follows.

	At December 31,
	2009			2008			2007
Estimated Net Proved Reserves:
Oil (MMBbls)		16.6			7.1			5.6
Natural gas (Bcf)		66.4			94.7			106.6
Oil equivalent (MMBoe)(a)		27.7			22.8			23.4
Proved developed reserves as a percentage of net proved reserves		37	%		46	%		49	%

(a) Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Our estimated total net proved reserves increased 21% from 2008 to 2009. The increase in our proved reserves was attributable to the application of advanced drilling and completion techniques, improved oil prices, reduced service costs and the modernization of SEC reserve reporting rules.

The application of advance drilling and completion techniques, which incorporates drilling long laterals and completing wells with swell packers and between 18 and 32 fracture stimulation stages in 2009, appears to have enhanced our estimated ultimate recoveries (EURs) and thereby improved our rates of return. During 2009, we applied these advanced drilling and completion techniques to areas that had previously experienced minimal drilling activity and drilled apparently economic wells. In these areas, we were able to increase our level of both proved developed (PD) and proved undeveloped (PUD) reserves.

Oil prices used in our year-end 2009 reserve report increased 37% relative to 2008. During 2009, service costs decreased approximately 40% as the pace of drilling activity in the United States decreased due to the economic crisis, resulting recession and scarcity of available capital. Enhanced oil prices and reduced service costs improved our rates of return and allowed us to book reserves in previously uneconomic locations. Enhanced oil prices also typically lengthen the time that a well can be economically produced and therefore increase the amount of economically recoverable reserves over the life of the well.

The modernization of SEC oil and gas reporting rules also enhanced our level of reserves. The new rules increased the number of offsetting PUD locations we were able to book in unconventional resource plays such as the Williston Basin from two in 2008 to four in 2009. The increased number of offsetting locations we are able to book allowed us to increase our level of PUD reserves and therefore also increase our level of total proved reserves. As a result of the increase in the level of our PUD reserves, our overall percentage of PUD reserves to total net proved reserves increased from 54% in 2008 to 63% in 2009.

Partially offsetting the above PUD reserve increases, we eliminated multiple PUD reserve locations in areas that we currently do not anticipate drilling within the next five years. The PUD reserve locations that we eliminated were primarily natural gas drilling locations in areas outside of our core Williston Basin and South Texas acreage positions and totaled 2.9 MMBoe.

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Results of Operations

Comparison of the twelve-month periods ended December 31, 2009, 2008 and 2007

Production volumes

	Year Ended December 31,
	2009		% Change			2008		% Change			2007
Oil (MBbls)(a)		830		44	%		578		47	%		392
Natural gas (MMcf)		5,892		(26	%)		7,996		(37	%)		12,626
Total (MBoe)(b)		1,812		(5	%)		1,910		(23	%)		2,496
Average daily production volumes (Boe/d)(c)		5,034		(5	%)		5,306		(23	%)		6,933

(a)	Includes approximately 16,475 barrels of oil produced in the Williston Basin during 2009 and recorded as inventory at year-end 2009. Ending inventory at year end 2008 and 2007 was not material.
(b)	Boe is defined as one barrel equivalent of oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
(c)	Average daily production volumes calculated based on 360 day year.

Inventory

	Year Ended December 31,
	2009		% Change		2008		% Change		2007
Oil (Bbls)		16,475		NM		—		NM		—
Natural gas (Mcf)		—		NM		—		NM		—
Total (Boe)		16,475		NM		—		NM		—

Sales volumes (Production volumes less Inventory)

	Year Ended December 31,
	2009		% Change			2008		% Change			2007
Oil (MBbls)(a)		814		41	%		578		47	%		392
Natural gas (MMcf)		5,892		(26	%)		7,996		(37	%)		12,626
Total (MBoe)(b)		1,796		(6	%)		1,910		(23	%)		2,496
Average daily sales volumes (Boe/d)(c)		4,988		(6	%)		5,306		(23	%)		6,933

(a)	Excludes approximately 16,475 barrels of oil produced in the Williston Basin during 2009 and recorded as inventory at year-end 2009. Ending inventory at year end 2008 and 2007 was not material.
(b)	Boe is defined as one barrel equivalent of oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
(c)	Average daily sales volumes calculated based on 360 day year.

Our net equivalent sales volumes for 2009 decreased by 6% to 1,796 MBoe (4,988 Boe/d) from 1,910 MBoe (5,306 Boe/d) in 2008. Our sales volumes for 2009 decreased primarily due to our reduction in activity in the onshore Gulf Coast and the Anadarko Basin in response to low natural gas prices. This decrease was partially offset by a 116% increase in our sales volumes in the Williston Basin. Oil represented 45% and 30% of our total production in 2009 and 2008, respectively. The increase in our oil sales volumes was due to our increased activity in the Williston Basin, which is primarily a crude oil basin.

The following is additional information regarding our 2009 sales volumes:

• Sales volumes from our Rocky Mountains province for 2009 increased 112% when compared to 2008. The increase was attributable to the rapid escalation of our drilling activities in the Williston Basin, where we completed 38 gross (4.8 net) wells during 2009. Sales volumes from this province represented 35% of our total sales volumes in 2009 versus 15% in 2008. Approximately 96% of our 2009 sales volumes from this province were oil compared to 97% in 2008.

• Sales volumes from our Onshore Gulf Coast province for 2009 decreased 32% when compared to 2008. The decrease in volumes was attributable to the reduction in our drilling activity in this province in order to focus our activities in the Williston Basin. Because of our limited drilling program, only limited new volumes were brought on line to offset the natural decline of our wells. Sales volumes from this province represented 44% of our total sales volumes in 2009 versus 61% in 2008. Approximately 89% of our 2009 sales volumes from this province were natural gas compared to 87% in 2008.

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• Sales volumes from our Anadarko Basin province for 2009 decreased 20% when compared to 2008. The decrease in volumes was attributable to the reduction in drilling activity in this province in order to focus our activities in the Williston Basin. Because of the reduction in our drilling program in this province, no new volumes were brought on line to offset the natural decline of our wells. Sales volumes from this province represented 15% of our volumes in 2009 versus 17% in 2008. Approximately 92% of our 2009 sales volumes from this province were natural gas compared to 93% in 2008.

• Sales volumes from our West Texas & Other province for 2009 decreased 15% when compared to 2008. The decrease in volumes was attributable to the reduction in our drilling activity in this province in order to focus our activities in the Williston Basin. Because of our limited drilling program, only limited new volumes were brought on line to offset the natural decline of our wells. Sales volumes from this province represented 6% of our total volumes in 2009 versus 7% in 2008. Approximately 89% of our 2009 sales volumes from this province were oil compared to 88% in 2008.

Our net equivalent sales volumes for 2008 decreased by 23% to 1,910 MBoe (5,306 Boe/d) from 2,496 MBoe (6,933 Boe/d) in 2007. Our sales volumes for 2008 decreased primarily due to the natural decline of production from our wells in the Vicksburg and Southern Louisiana. Additionally, sales volumes decreased as a result of our reallocation of capital expenditures from our conventional portfolio to the Williston Basin. Our Williston Basin wells are longer life production wells and do not have the initial production impact that our shorter reserve life conventional portfolio has on our production. Oil represented 30% and 16% of our total sales volumes in 2008 and 2007, respectively.

The following is additional information regarding our 2008 sales volumes.

• Sales volumes from our Rocky Mountains province for 2008 increased 513% when compared to 2007. The increase was attributable to the rapid escalation of our drilling activities in the Williston Basin, where we drilled 56 gross (11 net wells) during 2008. Sales volumes from this province represented 15% of our total volumes in 2008 versus 2% in 2007. Approximately 97% of our 2008 sales volumes from this province were oil compared to 90% in 2007.

• Sales volumes from our Onshore Gulf Coast province for 2008 decreased 36% when compared to 2007. The decrease in volumes was attributable to the lower activity levels in the Vicksburg where we drilled five wells in 2007 versus three wells in 2008. The decrease was also attributable to the natural decline in our Southern Louisiana wells. Despite drilling three successful wells in Southern Louisiana in 2008, we did not hook up to production the first of these wells until December 2008. Our attempts to hook up these wells were negatively impacted by both Hurricanes Gustav and Ike, which impacted the Southern Louisiana area and affected the service providers that we utilize to hook up our wells. Sales volumes from this province represented 61% of our total volumes in 2008 versus 73% in 2007. Approximately 87% of our 2008 sales volumes from this province were natural gas compared to 89% in 2007.

• Sales volumes from our Anadarko Basin province for 2008 decreased 33% when compared to 2007. The decrease in our volumes was due to the natural decline in our wells and a lower activity level as we completed three wells in the province during 2007 versus only two in 2008. Sales volumes from this province represented 17% of our total sales volumes in 2008 versus 20% in 2007. Approximately 93% of our 2008 sales volumes from this province were natural gas compared to 94% in 2007.

• Sales volumes from our West Texas & Other province for 2008 decreased 7% when compared to 2007. The decrease in volumes was attributable to natural well production declines. Sales volumes from this province represented 7% of our total sales volumes in 2008 versus 6% in 2007. Approximately 88% of our 2008 sales volumes from this province were oil compared to 86% in 2007.

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Revenue, commodity prices and hedging

The following table shows our revenue from the sale of oil and natural gas for 2009, 2008 and 2007. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to record both derivative settlements and unrealized derivative gains (losses) to the consolidated statement of operations within a single income statement line item. We include both derivative settlements and unrealized derivative gains (losses) within revenue.

	Year Ended December 31,
	2009			% Change			2008			% Change			2007
				(In thousands, except per unit measurements)
Oil revenue:
Oil revenue	$	44,580			(13	%)	$	51,449			81	%	$	28,347
Oil derivative settlement gains (losses)		(654	)		(74	%)		(2,564	)		724	%		(311	)
Oil revenue including oil derivative settlements	$	43,926			(10	%)	$	48,885			74	%	$	28,036
Oil derivative unrealized gains (losses)		(4,343	)		NM			2,983			NM			(2,328	)
Oil revenue including derivative settlements and unrealized gains (losses)		39,583			(24	%)		51,868			102	%		25,708
Natural gas revenue:
Natural gas revenue	$	23,612			(68	%)	$	73,659			(20	%)	$	92,210
Natural gas derivative settlement gains (losses)		10,031			NM			(1,028	)		NM			4,478
Natural gas revenue including derivative settlements	$	33,643			(54	%)	$	72,631			(25	%)	$	96,688
Natural gas derivative unrealized gains (losses)		(2,970	)		NM			3,157			NM			(3,503	)
Natural gas revenue including derivative settlements and unrealized gains (losses)		30,673			(60	%)		75,788			(19	%)		93,185
Oil and natural gas revenue:
Oil and natural gas revenue	$	68,192			(45	%)	$	125,108			4	%	$	120,557
Oil and natural gas derivative settlement gains (losses)		9,377			NM			(3,592	)		NM			4,167
Oil and natural gas revenue including derivative settlement gains (losses)		77,569			(36	%)		121,516			(3	%)		124,724
Oil and natural gas derivative unrealized gains (losses)		(7,313	)		NM			6,140			NM			(5,831	)
Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		70,256			(45	%)		127,656			7	%		118,893
Other revenue		88			(33	%)		132			50	%		88
Total revenue	$	70,344			(45	%)	$	127,788			7	%	$	118,981
Average oil prices (based on sales volumes):
Oil price (per Bbl)	$	54.79			(38	%)	$	89.06			23	%	$	72.30
Oil price including derivative settlement gains (losses) (per Bbl)	$	53.99			(36	%)	$	84.63			18	%	$	71.51
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	48.65			(46	%)	$	89.79			37	%	$	65.57
Average natural gas prices:
Natural gas price (per Mcf)	$	4.01			(56	%)	$	9.21			26	%	$	7.30
Natural gas price including derivative settlement gains (losses) (per Mcf)	$	5.71			(37	%)	$	9.08			19	%	$	7.66
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	5.21			(45	%)	$	9.48			28	%	$	7.38
Average oil equivalent prices (based on sales volumes):
Oil equivalent price (per Bbl)	$	37.97			(42	%)	$	65.46			36	%	$	48.30
Oil equivalent price including derivative settlement gains (losses) (per bbl)	$	43.19			(32	%)	$	63.60			27	%	$	49.98
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Bbl)	$	39.12			(41	%)	$	66.84			40	%	$	47.64

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	2008			2007
	to 2009			to 2008
Change in revenue from the sale of oil
Price variance impact	$	(27,885	)	$	9,684
Sales volume variance impact		21,016			13,418
Cash settlement of derivative hedging contracts		1,910			(2,253	)
Unrealized gains (losses) due to derivative hedging contracts		(7,326	)		5,311
Total change	$	(12,285	)	$	26,160
Change in revenue from the sale of natural gas
Price variance impact	$	(30,657	)	$	15,286
Sales volume variance impact		(19,390	)		(33,837	)
Cash settlement of derivative hedging contracts		11,059			(5,506	)
Unrealized gains (losses) due to derivative hedging contracts		(6,127	)		6,660
Total change	$	(45,115	)	$	(17,397	)
Change in revenue from the sale of oil and natural gas
Price variance impact	$	(58,542	)	$	24,970
Volume variance impact		1,626			(20,419	)
Cash settlement of derivative hedging contracts		12,969			(7,759	)
Unrealized gains (losses) due to derivative hedging contracts		(13,453	)		11,971
Total change	$	(57,400	)	$	8,763

Our 2009 oil and natural gas revenue including derivative settlements and unrealized gains (losses) decreased $57.4 million, or 45% when compared to 2008. The following were the primary reasons for the decrease in our revenue:

• A 42% decrease in the average oil equivalent price decreased revenue by $58.5 million;

• A $7.3 million unrealized loss due to derivative hedging contracts in 2009 versus a $6.1 million unrealized gain due to derivative hedging contracts in 2008 decreased revenue by $13.5 million;

• An 41% increase in our oil sales volumes, which was partially offset by a 26% decrease in our natural gas sales volumes, increased revenue by $1.6 million; and

• A $9.4 million gain from the settlement of derivative contracts in 2009 versus a $3.6 million settlement loss in 2008 increased revenue by $13.0 million.

Our 2008 oil and natural gas revenue including derivative settlements and unrealized gains (losses) increased $8.8 million, or 7% when compared to 2007. The following were the primary reasons for the increase in our revenue:

• A 36% increase in the average oil equivalent price increased revenue by $25.0 million;

• A $6.1 million unrealized gain due to derivative hedging contracts in 2008 versus a $5.8 million unrealized loss due to derivative hedging contracts in 2007 increased revenue by $12.0 million;

• A 23% decrease in our sales volumes decreased revenue by $20.4 million; and

• A $3.6 million loss from the settlement of derivative contracts in 2008 versus a $4.2 million settlement gain in 2007 decreased revenue by $7.8 million.

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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 2009 was $88,000 compared to $132,000 in 2008 and $88,000 in 2007. Costs related to our gas gathering systems are recorded in lease operating expenses.

Hedging.We utilize swaps, collars, and three way costless collars 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 2009, 2008 and 2007 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,
	2009			% Change			2008			% Change			2007
Oil collars and three way costless collars
Volumes (Bbls)		251,000			38	%		182,500			(31	%)		263,000
Average floor price (per Bbl)	$	59.43			(15	%)	$	69.55			22	%	$	56.82
Average ceiling price (per Bbl)	$	80.12			(15	%)	$	93.82			15	%	$	81.50
Gain /(loss) upon settlement (in thousands)	$	902			NM		$	(2,564	)		724	%	$	(311	)
Oil swaps
Volumes (Bbls)		90,000			NM			—			NM			—
Average swap price (per Bbl)	$	50.75			NM		$	—			NM		$	—
Gain /(loss) upon settlement (in thousands)	$	(1,556	)		NM		$	—			NM		$	—
Total oil gain / (loss) upon settlement (in thousands)	$	(654	)		(75	%)	$	(2,564	)		724	%	$	(311	)
Natural gas collars and three way costless collars
Volumes (MMbtu)		1,960,000			(60	%)		4,850,000			(35	%)		7,425,000
Average floor price (per MMbtu)	$	7.19			(6	%)	$	7.65			4	%	$	7.34
Average ceiling price (per MMbtu)	$	8.83			(18	%)	$	10.75			(13	%)	$	12.40
Gain /(loss) upon settlement (in thousands)	$	8,133			NM		$	(1,028	)		NM		$	4,478
Natural gas swaps
Volumes (MMbtu)		2,490,000			NM			—			NM			—
Average swap price (per MMbtu)	$	4.359			NM		$	—			NM		$	—
Gain /(loss) upon settlement (in thousands)	$	1,898			NM		$	—			NM		$	—
Total natural gas gain /(loss) upon settlement (in thousands)	$	10,031			NM		$	(1,028	)		NM		$	4,478

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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 Boe based on Sales Volumes)
	Year Ended December 31,
	2009		% Change			2008		% Change			2007
Production costs:
Operating & maintenance	$	6.02		22	%	$	4.92		52	%	$	3.24
Expensed workovers		1.58		65	%		0.96		129	%		0.42
Ad valorem taxes		0.56		(7	%)		0.60		0	%		0.60
Lease operating expenses	$	8.16		26	%	$	6.48		52	%	$	4.26
Production taxes		2.84		1	%		2.82		176	%		1.02
Production costs	$	11.00		18	%	$	9.30		76	%	$	5.28

	Amount
	(In thousands)
	Year Ended December 31,
	2009		% Change			2008		% Change			2007
Production costs:
Operating & maintenance	$	10,823		15	%	$	9,399		15	%	$	8,153
Expensed workovers		2,832		53	%		1,851		69	%		1,097
Ad valorem taxes		1,000		(10	%)		1,113		(23	%)		1,454
Lease operating expenses	$	14,655		19	%	$	12,363		15	%	$	10,704
Production taxes		5,098		(5	%)		5,374		111	%		2,541
Production costs	$	19,753		11	%	$	17,737		34	%	$	13,245

For 2009, our per unit production cost increased 18% when compared to 2008. The following were the primary reasons for the increase in our 2009 per unit production costs relative to 2008:

• O&M expenses increased 22%, or by $1.10 per Boe, due to increases in salt water disposal, compressor rental and overhead fees; and

• Expensed workovers increased 65%, or by $0.62 per Boe, due to an increase in the number and cost of our workovers in 2009, in particular two workovers associated with our conventional natural gas wells.

For 2008, our per unit production cost increased 76% when compared to 2007. The following were the primary reasons for the increase in our 2008 per unit production costs relative to 2007:

• O&M expenses increased 52%, or by $1.68 per Boe, due to increases in salt water disposal, compressor rental and fuel costs;

• Production taxes increased 176%, or by $1.80 per Boe, due to a $2.7 million decrease in gas production tax abatements in 2008 as compared to 2007; and

• Expensed workovers increased 129%, or by $0.54 per Boe, due to an increase in the number and cost of our workovers in 2008.

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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,
	2009			% Change			2008			% Change			2007
	(In thousands, except per unit measurements which are based on sales volumes)
General and administrative costs	$	16,961			(3	%)	$	17,551			1	%	$	17,442
Capitalized general and administrative costs		(7,718	)		(4	%)		(7,994	)		(2	%)		(8,166	)
General and administrative Expenses	$	9,243			(3	%)	$	9,557			3	%	$	9,276
General and administrative expenses (per Boe)	$	5.15			3	%	$	4.98			34	%	$	3.72

Our general and administrative expenses in 2009 decreased $0.3 million from those in 2008. Before capitalization, our general and administrative costs decreased by $0.6 million. We experienced the following fluctuations in general and administrative costs:

• Total compensation expense decreased by $0.3 million from 2008 to 2009 due to lower levels of employee salaries and bonuses associated with our cost cutting measures implemented in April 2009; and

• Office expenses decreased by $0.3 million from 2008 to 2009 due to our cost containment measures.

Our general and administrative expenses in 2008 increased $0.3 million over those in 2007. Before capitalization, our general and administrative costs increased by $0.1 million. We experienced the following fluctuations in general and administrative costs:

• Total compensation expense decreased by $0.8 million from 2007 to 2008 due to lower levels of employee bonuses; and

• Contract and professional fees increased by $0.6 million from 2007 to 2008 due to higher legal and audit fees.

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,
	2009		% Change			2008		% Change			2007
	(In thousands, except per unit measurements which are based on sales volumes)
Depletion of oil and natural gas properties	$	32,054		(40	%)	$	53,498		(9	%)	$	59,079
Depletion of oil and natural gas properties (per Boe)	$	17.85		(36	%)	$	28.02		19	%	$	23.64

Our depletion expense for 2009 was $21.4 million lower than 2008. A decrease in production volumes in 2009 lowered depletion expense by approximately $3.2 million, while a decrease in our depletion rate decreased depletion expense $18.2 million. The lower depletion rate was due to our fourth quarter 2008 and first quarter 2009 ceiling test writedowns.

Our depletion expense for 2008 was $5.6 million lower than 2007. A decrease in production volumes in 2008 lowered depletion expense by approximately $13.9 million, while an increase in our depletion rate increased depletion expense $8.3 million. The higher depletion rate was due to an increase in finding and development costs in 2008.

Impairment of oil and natural gas properties. We use the full cost method of accounting for oil and 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 and interest capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

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Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved oil and natural gas reserves, based on the average of oil and natural gas prices in effect at the beginning of each month in the twelve month period prior to the end of the reporting period; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of oil and gas properties exceed this ceiling amount, we are subject to a ceiling test writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings and reduces stockholders’ equity in the period of occurrence.

The risk that we will experience a ceiling test writedown increases when oil and gas prices are depressed or if we have a substantial downward revisions in our estimated proved reserves. Prior to December 31, 2009, the ceiling test calculation was based on oil and natural gas prices in effect on the balance sheet date. Based on oil and gas prices in effect on March 31, 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 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 $114.8 million impairment to our oil and gas properties. Based on oil and gas prices in effect on December 31, 2008 ($5.71 per MMBtu for Henry Hub gas and $44.60 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 $237.2 million impairment to our oil and gas properties.

Inventory Valuation.Our $2.2 million inventory valuation loss in 2009 was attributable to the lower of cost or market writedown of oil country tubular goods (OCTG). Market prices of OCTG experienced a substantial reduction in the first quarter of 2009 associated with lower steel costs and the oversupply of OCTG due to reduced drilling activity in the United States.

Net interest expense.Interest on our Senior Notes, our Senior Credit Facility and dividends that we pay on our Series A mandatorily redeemable preferred stock represents the largest portion of our interest expense. Other costs include commitment fees that we pay on the unused portion of the borrowing base for our Senior Credit Facility. 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,
	2009			% Change			2008			% Change			2007
	(In thousands)
Interest on Senior Notes	$	15,400			0	%	$	15,401			6	%	$	14,483
Interest on Senior Credit Facility		3,375			72	%		1,960			3	%		1,900
Commitment fees		195			(24	%)		256			54	%		166
Dividend on mandatorily redeemable preferred stock		606			0	%		608			0	%		606
Amortization of deferred loan and debt issuance cost		1,538			49	%		1,032			11	%		932
Other general interest expense		30			NM			—			(100	%)		2
Capitalized interest expense		(4,713	)		(1	%)		(4,762	)		37	%		(3,467	)
Net interest expense	$	16,431			13	%	$	14,495			(1	)%	$	14,622
Weighted average debt outstanding	$	274,211			25	%	$	220,116			16	%	$	189,080
Average interest rate on outstanding indebtedness(a)		7.15	%					8.28	%					9.1	%

(a) 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.

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Our net interest expense for 2009 was $1.9 million higher than that in 2008 primarily due to a $1.4 million increase in interest expense associated with higher levels of outstanding debt on our Senior Credit Facility and a $0.5 million increase in origination fees also associated with our Senior Credit Facility.

Our net interest expense for 2008 was 1% lower than that in 2007. The primary driver behind the decrease in our net interest expense was an increase in our capitalized interest associated with our higher level of capital spending in 2008 relative to that in 2007. Interest expense on our Senior Credit Facility increased by only 3% despite an increase in our weighted average debt outstanding due to lower interest rates associated with the economic downturn experienced during the second half of 2008.

Other income (expense). Other income (expense) included:

	Year Ended December 31,
	2009		% Change			2008		% Change			2007
	(In thousands)
Other:
Gain (loss) on sale of inventory or assets		405		NM			—		(100	%)		71
Other income (loss)		1,139		115	%		530		(44	%)		951
Total other income (loss)	$	1,544		191	%	$	530		(48	%)	$	1,022

Other income increased in 2009 due to rental income earned on drilling pipe.

Income taxes.We utilize the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 740 “Income Taxes” (FASB ASC 740). Under FASB ASC 740, 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 2009, we recognized a current year net deferred tax benefit of $233,000. The $233,000 tax benefit was mainly due to miscellaneous state tax benefits. The primary reasons for the difference between our effective tax rate of 0.2% and the federal statutory rate of 35% were increases in our valuation allowances on federal and state net operating losses and our inability to deduct dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.

In 2008, we recognized a current year net deferred federal tax benefit of $40.8 million. The $40.8 million tax benefit was due to a $222 million decrease in pre-tax income, which primarily resulted from the ceiling test writedown of $237.2 million. We also recognized a current year net deferred state tax benefit of $2 million, which consisted of the Margin Tax and other state tax benefits. The primary reasons for the difference between our effective tax rate of 20.8% and the federal statutory rate of 35% were increases in our valuation allowances on federal and state net operating losses 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.

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Liquidity and Capital Resources

Sources of Capital

In 2010, we intend to fund our capital expenditure program and contractual commitments with cash on hand, cash flows from operations, borrowings under our Senior Credit Facility, 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. The add-on notes were priced at 99.50% of face value to yield 9.721%.

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 Facility.

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, 2009.

Senior Credit Facility

Our Senior Credit Facility provides for revolving credit borrowings up to $200 million. In May 2009, in conjunction with our regularly scheduled semi-annual redetermination and our common stock offering, the borrowing base was reset to $110 million. On July 24, 2009, our Senior Credit Facility was amended to extend the maturity date from June 2010 to July 24, 2012. Subsequent to completion of our October 2009 equity offering, we repaid the entire $110.0 million balance outstanding under our Senior Credit Facility and both at year-end and as of the date of the filing of this report had and / or have no amounts outstanding.

Covenants under our Senior Notes preclude us from incurring additional debt under the Senior Credit Facility to the extent our total debt under the Senior Credit Facility exceeds the greater of $50 million plus 15% of a calculated proved PV10 value based on SEC prices used in our year-end reserve report, as defined in our Indenture, which is referred to as Adjusted Consolidated Net Tangible Assets, plus, in certain circumstances, an additional 10% of Adjusted Consolidated Net Tangible Assets.

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Since the borrowing base for our Senior Credit Facility is redetermined at least semi-annually, the amount of borrowing capacity available to us under our Senior Credit Facility could fluctuate. 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 pay off the borrowing base deficiency and carry out our planned spending for exploration and development activities. See “Item 1A — Risk Factors — Availability under our Senior Credit Facility is based on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under our Senior Credit Facility.”

Borrowings under our Senior Credit Facility 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 Facility reaches certain percentages of the available borrowing base, as shown below:

Percent of	Eurodollar
Borrowing Base	Rate			Base Rate
Utilized	Advances			Advances(1)
< 25%		2.50	%		1.50	%
25% and < 50%		2.75	%		1.75	%
50% and < 75%		3.00	%		2.00	%
75% and < 90%		3.25	%		2.25	%
≥ 90%		3.50	%		2.50	%

(1) Base rate is defined as for any day a fluctuating rate per annum equal to the highest of the following, in each case, to the extent determinable by the Administrative Agent: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of one month determined as of approximately 11:00 a.m. (London time) on such day plus 1.50% and (c) 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	Annual
Utilized	Commitment Fee
< 25%		0.500	%
25% and < 50%		0.500	%
50% and < 75%		0.500	%
75% and < 90%		0.500	%
≥ 90%		0.500	%

Our Senior Credit Facility 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 Facility, our current ratio must be at least 1.0 to 1. Our current ratio was 4.1 to 1 as of December 31, 2009. Pursuant to our Senior Credit Facility, our interest coverage ratio for the four most recent quarters as of December 31, 2009 and March 31, 2010 must be at least 2.0 to 1, and thereafter must be at least 2.5 to 1. Our interest coverage ratio for the last twelve-month period ended December 31, 2009 was 3.2 to 1. The Senior Credit Facility also requires us to maintain a net leverage ratio for the quarters ending through September 30, 2010 not greater than 4.5 to 1, for the quarters ending December 31, 2010 through March 31, 2011 not greater than 4.25 to 1, and thereafter not greater than 4.0 to 1. Our net leverage ratio as of December 31, 2009 was 0.7 to 1. Finally, our Senior Credit Facility requires that we maintain $10.0 million in liquidity in the form of either unused capacity under our Senior Credit Facility or cash maintained in a deposit account through the date our Mandatorily Redeemable Preferred Stock is redeemed. As of December 31, 2009, we maintained at least $10.0 million in unused capacity under our Senior Credit Facility. As of December 31, 2009, we were in compliance with all covenant requirements in connection with our Senior Credit Facility.

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Mandatorily Redeemable Preferred Stock

As of December 31, 2009, 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. We are 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. We anticipate funding the maturity of our preferred stock with either cash on hand or borrowings under our Senior Credit Facility.

Access to Capital Markets

On October 5, 2009, our universal shelf registration statement covering the sale of $300 million of our common stock, preferred stock, depositary shares, warrants, rights, units and debt securities, or any combination of these securities became effective. Following our October 2009 equity offering and the exercise by the underwriters of a portion of their over-allotment in November 2009, we have approximately $123 million remaining under the shelf registration statement. This shelf registration statement expires in October 2012. Our ability to raise additional capital using our shelf registration statement 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 2009, 2008 and 2007.

	Year Ended December 31,
	2009			% Change			2008			% Change			2007
	(In thousands)
Net income	$	(122,992	)		24	%	$	(162,247	)		NM		$	10,210
Non-cash charges		159,132			(35	%)		245,545			199	%		82,004
Changes in working capital and other items		15,610			NM			(13,668	)		674	%		(1,765	)
Cash flows provided by operating activities	$	51,750			(26	%)	$	69,630			(23	%)	$	90,449
Cash flows used by investing activities		(164,620	)		(8	%)		(179,866	)		82	%		(99,093	)
Cash flows provided (used) by financing activities		113,608			(17	%)		136,416			649	%		18,207
Net increase (decrease) in cash and cash equivalents	$	738			(97	%)	$	26,180			174	%	$	9,563

Analysis of net cash provided by operating activities

Net cash provided by operating activities for 2009 was $17.9 million lower than 2008. The following are the primary reasons for the decrease:

• A 42% decrease in sales prices of crude oil and natural gas decreased operating cash flow by $58.5 million.

• Higher lease operating costs decreased operating cash flow by $2.3 million.

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• The change in working capital increased operating cash flow by $29.3 million.

• Higher realized hedge settlements increased operating cash flow by $13.0 million.

• Higher crude oil volumes partially offset by lower natural gas volumes decreased revenue by $1.6 million.

Net cash provided by operating activities for 2008 was $20.8 million lower than 2007. The following are the primary reasons for the decrease:

• A 23% decrease in production volumes decreased operating cash flow by $20.4 million.

• Lower levels of hedge settlements decreased operating cash flow by $7.8 million.

• Higher lease operating costs, production taxes and general & administrative expense decreased operating cash flow by $4.8 million.

• The change in working capital reduced operating cash flow by $11.9 million.

• These decreases in operating cash flow were partially offset by a 36% increase in prices, which increased operating cash flow by $25.0 million.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. Typically, we report a working capital deficit at the end of a period. However, at the end of 2009, as a result of our May and October 2009 equity offerings we had both cash on hand and short term investments recorded on our balance sheet. This resulted in a working capital surplus at the end of 2009. At year-end 2008, we also had a working capital surplus as we had fully drawn our credit facility and placed the associated cash on deposit. Our 2007 working capital deficit was the result of accounts payable related to lease operating expenses, exploration and development costs, royalties payable and gas imbalances payable. Settlement of these payables is typically funded by cash flows from operations or, if necessary, by additional borrowing under our Senior Credit Facility.

Our working capital surplus at December 31, 2009 and December 31, 2008 was $90.7 million and $30.3 million, respectively, while we had a working capital deficit of $9.2 million at December 31, 2007. Our working capital surplus at December 31, 2009, included a current asset of $80.1 million related to short term investments.

Analysis of changes in cash flows used by investing activities

Net cash used by investing activities decreased by $15.2 million from 2008 to 2009. The primary drivers for the decrease were a $78.0 million decrease in our drilling capital expenditures and a $34.0 million decrease in our land and seismic capital expenditures. These decreases were offset by a $80.1 million increase in cash used associated with our increased level of short term investments and a $9.2 million increase in cash used associated with the change in our accrued drilling costs.

Net cash used by investing activities increased by $80.8 million from 2007 to 2008. The primary drivers for the increase were a $39.4 million increase in our drilling capital expenditures and a $18.3 million increase in our land and seismic capital expenditures. Additionally, in 2008 we received $36 million less in proceeds from asset sales. These increases to cash used in investing activities were offset by a $13.4 million decrease in cash used in investing activities associated with the change in our accrued drilling costs.

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The following is a detailed breakout of our net cash used in investing activities for 2009, 2008 and 2007 in thousands.

	2009			% Change			2008			% Change			2007
Capital expenditures for oil and natural gas activities:
Drilling	$	58,209			(57	%)	$	136,248			41	%	$	96,833
Land and seismic		1,761			(95	%)		35,796			104	%		17,527
Capitalized cost		12,432			(3	%)		12,852			10	%		11,631
Capitalized asset retirement obligation		327			(21	%)		412			27	%		325
Total	$	72,729			(61	%)	$	185,308			47	%	$	126,316
Reconciling Items:
Granite Wash proceeds & ARO reduction	$	—			NM		$	—			100	%	$	(36,050	)
Short term investments		80,093			NM			—			NM			—
Other property and equipment		1,642			249	%		470			24	%		378
Change in accrued drilling costs		4,270			NM			(4,927	)		NM			8,469
Change in inventory		7,881			NM			—			NM			—
Other		(1,995	)		103	%		(985	)		4825	%		(20	)
Total Reconciling Items		91,891			NM			(5,442	)		(80	%)		(27,223	)
Net cash used in investing activities	$	164,620			(8	%)	$	179,866			82	%	$	99,093

Analysis of changes in cash flows from financing activities

Over the three year period ended December 31, 2009, 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 2009 was $22.8 million lower than in 2008. In 2009, we raised $261.7 million in net proceeds from the sale of common stock and repaid the $145.0 million outstanding under our Senior Credit Facility thereby generating net cash provided by financing activities of $113.6 million. In 2008, we generated $135 million in financing proceeds via borrowings under our Senior Credit Facility.

Net cash provided by financing activities in 2008 was $118.2 million higher than that in 2007. The majority of the increase was due to increased borrowings under our Senior Credit Facility.

Common Stock Transactions

Our net proceeds from the sale of common stock and employee stock option exercises were $260.9 million higher in 2009 than they were in 2008 due to our May and October 2009 equity offerings. This compares to net proceeds that were $1.6 million higher in 2008 than in 2007.

The following is a list of common stock transactions that occurred in 2009, 2008 and 2007.

	Shares Issued		Net Proceeds
			(in thousands)
2009 common stock transactions:
May 2009 common stock offering		36,292,117	$	93,407
October 2009 common stock offering		16,837,523	$	168,318
Exercise of employee stock options		256,314	$	1,219
2008 common stock transactions:
Exercise of employee stock options		385,715	$	2,066
2007 common stock transactions:
Exercise of employee stock options		123,500	$	472

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Critical Accounting Policies

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

Use of Estimates

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

Oil and Natural Gas Reserves

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

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

The estimates of our proved oil and natural gas reserves used in the preparation of our consolidated financial statements were prepared by Cawley, Gillespie & Associates, Inc., our registered 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 difference between these two methods is 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.

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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, 2009, our average depletion expense per unit of production was $18.54 per Boe. A 10% decrease in our estimated net proved reserves at December 31, 2009 would result in a $2.03 per Boe increase in our per unit depletion expense and a $0.9 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 writedown increases when oil and gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves. Based on oil and gas prices in effect on March 31, 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 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 $114.8 million ($71.9 million after tax) impairment to our oil and gas properties. Also, at December 31, 2008, the unamortized cost of our oil and gas properties exceeded the ceiling limit based on oil and gas prices in effect ($5.71 per MMBtu for Henry Hub gas and $44.60 per barrel for West Texas Intermediate oil, adjusted for differentials). Therefore, we recorded a $237.2 million ($148.6 million after tax) impairment to our oil and gas properties at December 31, 2008. 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 lives. 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 writedowns, which would reduce our stockholders’ equity.” Additionally, the modernization of SEC oil and gas reporting rules eliminated the ability to use subsequent pricing in assessing the need for a ceiling limitation writedown. This could cause us to record a ceiling limitation writedown that would not be required if subsequent pricing were used.

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.

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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. Significant future taxable income would be required to realize this net tax asset.

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 not use all of these NOLs to offset current tax liabilities in future years. We have, therefore, established a valuation allowance on the portion of the NOLs that may expire unused based on estimates of the reversal of our temporary differences. Our NOLs are more fully described in “Item 8. Financial Statements and Supplementary Data — Note 8. Income Taxes.”

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.

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In the past, we similarly use derivative contracts to manage our risks associated with interest rate fluctuations on long-term debt.

All derivatives are accounted for in accordance with FASB ASC 815 and carried at fair value on the balance sheet. We utilize the mark-to-market methodology to account for our hedges. Mark-to-market accounting requires that 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 revenues.

New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Board Auditing Standard Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820), which provides expanded guidance for using fair value to measure assets and liabilities. FASB ASC 820 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 FASB ASC 820 was 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. The FASB Staff deferred implementation for other non-financial assets and liabilities for one year. Examples of non-financial assets and liabilities are asset retirement obligations and non-financial assets and liabilities initially measured at fair value in a business combination. The adoption of FASB ASC 820 on January 1, 2010 did not have a material impact on the financial statements.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption was not permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932 “Extractive Activities — Oil and Gas” (FASB ASC 932) provides guidance for oil and natural gas reserve related disclosures in the financial statements. Adoption of the new requirements did not have a material impact on Brigham’s financial statements.

In May 2009, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 165 “Subsequent Events” (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 will apply with respect to interim or annual reporting periods ending after June 15, 2009. See Note 16 “Subsequent Events.”

In June 2009, the Financial Accounting Standards Board issued Financial Accounting Standards Board Accounting Standards Codification Topic 105 “Generally Accepted Accounting Principles” (FASB ASC 105). FASB ASC 105 sets forth that the Financial Accounting Standards Board Accounting Standards Codification (ASC) is the exclusive authoritative reference for nongovernmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for SEC rules and interpretive releases, which also are authoritative GAAP for SEC registrants. The change was established by FASB Statement of Financial Accounting Standards No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (FAS 168), which divides nongovernmental U.S. GAAP into the authoritative Codification and guidance that is nonauthoritative, doing away with the previous four-level hierarchy. FASB ASC 105 is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. FASB ASC 105 was not intended to change or alter existing GAAP, and the Company’s adoption did not have any impact on its consolidated financial statements other than to modify certain existing disclosures. Upon adoption, the Company began to use the new guidelines and numbering system prescribed by the FASB ASC when referring to GAAP in the third quarter of fiscal 2009.

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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 2009 was $54.79 per barrel, which was 38% lower than the prices we received in 2008. Significant factors that will impact 2010 oil prices include the pace at which the domestic and global economies recover from the current recession, 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 and developments in the Middle East Countries.

Natural gas prices are primarily driven by North American market forces. However, global LNG shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe to North America. 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 2009 was $4.01 per Mcf, which was 56% lower than the price we received in 2008. Natural gas prices in 2010 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.

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.”

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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

We use the mark-to-market accounting methodology to account for our hedges. 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 include all derivative settlement and unrealized gains (losses) within revenue.

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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, 2009. The following table reconciles the changes that occurred in the fair values of our open derivative contracts during 2009.

	Fair Value of
	Undesignated
	Derivative
	Contracts
Estimated fair value of open contracts at December 31, 2008	$	5,337
Changes in fair values of derivative contracts:
Natural gas collars	$	4,149
Oil collars		(3,216	)
Settlements of derivative contracts that were open at December 31, 2008:
Natural gas collars	$	(7,118	)
Oil collars		(1,127	)
Estimated fair value of open contracts at December 31, 2009	$	(1,975	)

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 2009, we were party to natural gas costless collars, natural gas three-way costless collars, natural gas swaps, oil costless collars and oil swaps. See “Item 8. Financial Statements and Supplementary Data — Note 11 Derivative Instruments and Hedging Activities” 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 neither receive nor pay 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. All hedges are accounted for using mark-to-market accounting.

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 neither receive nor pay 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. All hedges are accounted for using mark-to-market accounting.

We use swaps to fix the sales price for our anticipated future natural gas production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us.

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.

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The following table reflects our open derivative contracts at December 31, 2009, 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
01/01/10 – 03/31/10		210,000	$	5.75	$	7.05
04/01/10 – 09/30/10		420,000	$	5.75	$	7.30
10/01/10 – 03/31/11		240,000	$	6.50	$	8.25
04/01/10 – 09/30/10		240,000	$	5.75	$	7.00
01/01/10 – 12/31/10		840,000	$	5.15	$	7.00
04/01/10 – 09/30/10		300,000	$	5.50	$	6.65
10/01/10 – 03/31/11		420,000	$	6.40	$	7.80
01/01/11 – 12/31/11		360,000	$	5.75	$	7.65

	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMbtu)		(Nymex)		(Nymex)		(Nymex)
Natural Gas Three Way Costless Collars
01/01/10 – 03/31/10		210,000	$	8.00	$	10.00	$	5.50
01/01/10 – 03/31/10		180,000	$	5.75	$	7.00	$	3.50

	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
Oil Costless Collars
01/01/10 – 12/31/10		120,000	$	48.70	$	80.00
01/01/10 – 05/31/10		50,000	$	57.50	$	75.95
06/01/10 – 12/31/10		56,000	$	57.50	$	82.15
01/01/10 – 12/31/10		54,000	$	60.00	$	86.50
01/01/11 – 12/31/11		84,000	$	65.00	$	88.25
01/01/10 – 03/31/10		6,000	$	65.00	$	87.50
07/01/10 – 09/30/10		6,000	$	70.00	$	87.25
10/01/10 – 12/31/10		3,000	$	70.00	$	88.50
01/01/10 – 03/31/10		9,000	$	60.00	$	91.75
04/01/10 – 09/30/10		18,000	$	60.00	$	91.40
01/01/10 – 12/31/10		60,000	$	60.00	$	88.80
01/01/11 – 12/31/11		60,000	$	60.00	$	97.25
01/01/10 – 06/30/10		30,000	$	60.00	$	103.75
01/01/11 – 12/31/11		60,000	$	65.00	$	108.00
01/01/11 – 06/30/11		18,000	$	65.00	$	97.50
01/01/10 – 12/31/10		36,000	$	60.00	$	96.00
01/01/10 – 12/31/10		24,000	$	60.00	$	100.00

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The following table reflects commodity derivative contracts entered into subsequent to December 31, 2009, 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
01/01/11 – 12/31/11		480,000	$	5.75	$	7.40

	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
Oil Costless Collars
07/01/10 – 12/31/10		12,000	$	65.00	$	107.70
01/01/11 – 12/31/11		48,000	$	70.00	$	106.80
03/01/10 – 12/31/10		40,000	$	70.00	$	101.75
03/01/10 – 08/31/10		18,000	$	70.00	$	99.00
01/01/11 – 12/31/11		48,000	$	75.00	$	102.60
07/01/11 – 12/31/11		12,000	$	75.00	$	103.00
04/01/10 – 06/30/10		30,000	$	65.00	$	89.90
07/01/10 – 12/31/10		30,000	$	65.00	$	94.25
01/01/11 – 06/30/11		24,000	$	70.00	$	92.50
07/01/11 – 09/30/11		9,000	$	70.00	$	95.00
10/01/11 – 12/31/11		6,000	$	70.00	$	96.35
01/01/11 – 02/28/11		10,000	$	70.00	$	92.00

Interest Rate Risk

At December 31, 2009, we had $169.1 million of short term and long term debt, all of which was fixed rate debt. Our fixed rate long term debt consists of our $159.0 million in Senior Notes. Our fixed rate short term debt consists of $10.1 million in Series A preferred stock.

The interest rate that we pay on amounts borrowed under our Senior Credit Facility 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, 2009, which was 0.32%. The margin that we pay is based upon the percentage of our available borrowing base that we utilize at the beginning of the quarter. At December 31, 2009, the borrowing base for our Senior Credit Facility was $110 million. Since we had no outstanding balance under our Senior Credit Facility at December 31, 2009, we were utilizing 0% of our available borrowing base. At this level of utilization, our Senior Credit Facility requires us to pay a margin of 2.50%. Our all-in interest rate that we would be required to pay on the amounts borrowed under our Senior Credit Facility would be 2.82%. A 10% increase in the Eurodollar rate would equal approximately 3 basis points. Such an increase in the Eurodollar rate would change our annual interest expense by approximately $33,000, assuming borrowed amounts under our Senior Credit Facility remained constant at $110 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, 2009 was approximately $10.1 million.

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Item 8. Financial Statements and Supplementary Data

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

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

None.

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, 2009, 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 in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Securities and Exchange Act of 1934 is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure..

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 inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework inInternal Control — Integrated Frameworkissued by the COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.

The effectiveness of our internal control over financial reporting as of December 31, 2009 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 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

70

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to the 2010 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2009.

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

Item 11. Executive Compensation

The information required by this item is incorporated herein by reference to the 2010 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2009.

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 2010 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2009. See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” which sets forth certain information with respect to our equity compensation plans.

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

The information required by this item is incorporated herein by reference to the 2010 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2009.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated herein by reference to the 2010 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2009.

PART IV

Item 15. Exhibits, Financial Statement Schedules

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

2. No schedules are required.

3. Exhibits:

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

71

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.

Boe.A barrel of oil equivalent is approximately six thousand cubic feet of typical natural gas.

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.

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.

Hydraulic fracturing. A stimulation treatment routinely performed on oil and gas wells in low-permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation.

IP Rate. Initial Production Rate. The peak 24 hour production rate of a well, usually achieved within the first few days after being brought on line to production.

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.

MBoe. One thousand barrels of oil equivalent.

Mcf.One thousand cubic feet of natural gas.

72

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.

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.

73

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 (or restart) drilling a new well.

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.

74

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 February 26, 2010.

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 February 26, 2010.

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

75

BRIGHAM EXPLORATION COMPANY

INDEX TO FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated Balance Sheets as of December 31, 2009 and 2008		F-4
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007		F-5
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007		F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		F-7
Notes to the Consolidated Financial Statements		F-8
Supplemental Oil and Gas Information (Unaudited)		F-29
Supplemental Quarterly Financial Information (Unaudited)		F-31

F-1

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, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

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, 2009, based on criteria established inInternal Control — Integrated Framework,issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Dallas, Texas
February 26, 2010

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 (the Company) internal control over financial reporting as of December 31, 2009, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The 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, 2009, based on criteria established inInternal 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, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Dallas, Texas
February 26, 2010

F-3

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	40,781		$	40,043
Restricted cash		—			555
Accounts receivable		21,194			24,558
Short term investments		80,093			—
Derivative assets		1,152			5,140
Inventory		14,087			6,070
Other current assets		1,132			2,154
Total current assets		158,439			78,520
Oil and natural gas properties, using the full cost method of accounting
Proved		619,920			632,275
Unproved		76,309			106,006
Accumulated depletion		(365,496	)		(333,442	)
		330,733			404,839
Other property and equipment, net		3,025			1,873
Deferred loan fees		5,213			3,122
Other noncurrent assets		846			702
Total assets	$	498,256		$	489,056
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	19,251		$	14,297
Royalties payable		8,268			6,859
Accrued drilling costs		15,498			19,768
Participant advances received		6,949			2,226
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at December 31, 2009		10,101			—
Other current liabilities		7,706			5,065
Total current liabilities		67,773			48,215
Senior Notes		158,968			158,730
Senior credit facility		—			145,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at December 31, 2008		—			10,101
Deferred income taxes		—			149
Other noncurrent liabilities		7,232			5,592
Commitments and contingencies (Note 10)
Stockholders’ equity:
Common stock, $.01 par value, 180 million shares authorized, 99,593,075 and 45,829,277 shares issued and 99,351,825 and 45,686,295 shares outstanding at December 31, 2009 and 2008, respectively		996			458
Additional paid-in capital		479,077			212,473
Treasury stock, at cost; 241,250 and 142,982 shares at December 31, 2009 and 2008, respectively		(2,133	)		(1,202	)
Accumulated other comprehensive income (loss)		(205	)		—
Retained earnings (deficit)		(213,452	)		(90,460	)
Total stockholders’ equity		264,283			121,269
Total liabilities and stockholders’ equity	$	498,256		$	489,056

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

F-4

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	Year Ended December 31,
	2009			2008			2007
Revenues:
Oil and natural gas sales	$	68,192		$	125,108		$	120,557
Gain (loss) on derivatives, net		2,064			2,548			(1,664	)
Other revenue		88			132			88
		70,344			127,788			118,981
Costs and expenses:
Lease operating		14,655			12,363			10,704
Production taxes		5,098			5,374			2,541
General and administrative		9,243			9,557			9,276
Depletion of oil and natural gas properties		32,054			53,498			59,079
Impairment of oil and natural gas properties		114,781			237,180			6,505
Depreciation and amortization		812			629			613
Accretion of discount on asset retirement obligations		421			361			379
Loss on inventory valuation		2,196			—			—
		179,260			318,962			89,097
Operating income (loss)		(108,916	)		(191,174	)		29,884
Other income (expense):
Interest income		578			191			654
Interest expense, net		(16,431	)		(14,495	)		(14,622	)
Other income (expense)		1,544			530			1,022
		(14,309	)		(13,774	)		(12,946	)
Income (loss) before income taxes		(123,225	)		(204,948	)		16,938
Income tax benefit (expense):
Current		—			—			—
Deferred		233			42,701			(6,728	)
		233			42,701			(6,728	)
Net Income (loss)	$	(122,992	)	$	(162,247	)	$	10,210
Net income (loss) per share available to common stockholders:
Basic	$	(1.74	)	$	(3.57	)	$	0.23
Diluted	$	(1.74	)	$	(3.57	)	$	0.22
Weighted average common shares outstanding:
Basic		70,569			45,441			45,110
Diluted		70,569			45,441			45,531

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

F-5

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

											Accumulated
											Other			Retained
					Additional						Comprehensive			Earnings			Total
	Common Stock				Paid In			Treasury			Income			(Accumulated			Stockholders’
	Shares		Amounts		Capital			Stock			(Loss)			Deficit)			Equity
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
Comprehensive income (loss):
Net income		—		—		—			—			—			(162,247	)		(162,247	)
Tax provisions related to cash flow hedges		—		—		—			—			61			—			61
Net (gains) losses included in net income		—		—		—			—			(176	)		—			(176	)
Comprehensive income																		(162,362	)
Issuance of common stock		—		—		—			—			—			—			—
Vesting of restricted stock		139		1		(1	)		—			—			—			—
Exercise of employee stock options		386		4		2,062			—			—			—			2,066
Repurchases of common stock		—		—		—			(348	)		—			—			(348	)
Vesting of share-based payments		—		—		2,886			—			—			—			2,886
Balance, December 31, 2008		45,829	$	458	$	212,473		$	(1,202	)	$	—		$	(90,460	)	$	121,269
Comprehensive income (loss):
Net income (loss)		—		—		—			—			—			(122,992	)		(122,992	)
Unrealized gains (loss) on investments		—		—		—			—			(205	)		—			(205	)
Tax benefits (provisions)		—		—		—			—			—			—			—
Comprehensive income (loss)																		(123,197	)
Issuance of common stock		53,130		532		261,193			—			—			—			261,725
Vesting of restricted stock		378		4		(4	)		—			—			—			—
Exercise of employee stock options		256		2		1,217			—			—			—			1,219
Repurchases of common stock		—		—		—			(931	)		—			—			(931	)
Vesting of share-based payments		—		—		4,198			—			—			—			4,198
Balance, December 31, 2009		99,593	$	996	$	479,077		$	(2,133	)	$	(205	)	$	(213,452	)	$	264,283

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

F-6

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2009			2008			2007
Cash flows from operating activities:
Net income (loss)	$	(122,992	)	$	(162,247	)	$	10,210
Adjustments to reconcile net income (loss) to cash provided (used) by operating activities:
Depletion of oil and natural gas properties		32,054			53,498			59,079
Impairment of oil and natural gas properties		114,781			237,180			6,505
Depreciation and amortization		812			629			613
Stock based compensation		2,278			1,592			1,905
Write-off of deferred loan costs		—			—			—
Amortization of discount and deferred loan fees		1,635			1,105			968
Accretion of discount on asset retirement obligations		421			361			379
Market value adjustment for derivative instruments		7,313			(6,140	)		5,831
Deferred income taxes		(233	)		(42,701	)		6,728
Provision for doubtful accounts		(19	)		17			—
Other noncash items		90			4			(4	)
Changes in working capital and other items:
Accounts receivable		3,383			(9,966	)		3,743
Other current assets		803			(6,521	)		1,183
Accounts and royalties payable		6,363			2,877			(6,197	)
Other current liabilities		4,964			500			(890	)
Noncurrent assets		114			(330	)		514
Noncurrent liabilities		(17	)		(228	)		(118	)
Net cash provided by operating activities		51,750			69,630			90,449
Cash flows from investing activities:
Additions to oil and natural gas properties		(74,668	)		(178,637	)		(132,932	)
Proceeds from sale of oil and natural gas properties		—			—			35,446
Changes in inventory		(7,881	)		—			—
Additions to other property and equipment		(2,054	)		(1,472	)		(707	)
Short term investments		(80,298	)		—			—
(Increase) decrease in drilling advances paid		(274	)		798			(900	)
Changes to restricted cash		555			(555	)		—
Net cash used by investing activities		(164,620	)		(179,866	)		(99,093	)
Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		261,725			—			—
Proceeds from exercise of employee stock options		1,219			2,066			472
Proceeds from Senior Notes offering		—			—			34,825
Repurchases of common stock		(931	)		(348	)		(192	)
Increase in senior credit facility		—			139,500			58,800
Repayment of senior credit facility		(145,000	)		(4,500	)		(74,700	)
Principal payments on senior subordinated notes		—			—			—
Deferred loan fees paid and equity costs		(3,405	)		(302	)		(998	)
Net cash provided (used) by financing activities		113,608			136,416			18,207
Net increase (decrease) in cash and cash equivalents		738			26,180			9,563
Cash and cash equivalents, beginning of year		40,043			13,863			4,300
Cash and cash equivalents, end of year	$	40,781		$	40,043		$	13,863

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

F-7

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Operations

Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the “Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as “Brigham.” 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. Brigham’s exploration and development of oil and natural gas properties is currently focused in the Rocky Mountains, the Gulf Coast, the Anadarko Basin, 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.

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation. These reclassifications did not impact our net income, stockholders’ equity or cash flows.

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. Restricted cash at December 31, 2008 includes deposits in an interest bearing escrow account under the terms of a turnkey drilling contract executed during the third quarter of 2008. There was no restricted cash at December 31, 2009.

Investments

Investments consist primarily of certificates of deposit, corporate debt, and government securities, all of which are classified as “available-for-sale” and stated at fair value. Accordingly, unrealized gains and losses and any related deferred income tax effects are excluded from earnings and reported as a separate component of stockholders’ equity. Realized gains or losses are computed based on specific identification of the securities sold.

F-8

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Inventory

Inventory, which is included in current assets, includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities. Inventory also includes 16,475 barrels of crude oil that was produced in the Williston Basin during operations but not yet sold at December 31, 2009. Inventories are carried at the lower of cost or market using the specific identification method. Crude oil was valued at Brigham's estimated production cost of $136,000 at December 31, 2009.

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.

Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs, and asset retirement costs under Financial Accounting Standards Board Accounting Standards Codification Topic 410 “Asset Retirement and Environmental Obligations” (FASB ASC 410), 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 for at December 31, 2008 were determined using prices at the end of the year. Under certain specific conditions, companies could elect to use subsequent prices for determining the estimated future net cash flows. Brigham elected to use subsequent pricing for this purpose during 2007 and 2008. Under new rules issued by the Securities and Exchange Commission, the estimated future net cash flows for at December 31, 2009 were determined using a 12-month average price. The average is calculated using the first day of the month price for each of the 12 months that make up the reporting period. The use of subsequent pricing is no longer allowed. See “New Pronouncements” below for additional detail regarding the new rules. 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, 2009, 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
Pipeyard equipment	7 years
Pipeyard improvements	15 years
Rental equipment	3 - 5 years
Land		—

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.

F-9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 crude 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 accounts for its derivative activities under Financial Accounting Standards Board Accounting Standards Codification Topic 815 “Derivatives and Hedging” (FASB ASC 815). FASB ASC 815 establishes accounting and reporting standards requiring that every derivative instrument be recorded on the balance sheet as either an asset or a liability measured at its fair value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Brigham uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil and natural gas. Brigham periodically enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells.

At the inception of a derivative contract, Brigham historically designated the derivative as a cash flow hedge. Derivatives 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. On October 1, 2006, Brigham de-designated all derivates that were previously classified as cash flow hedges and, in addition, Brigham elected not to designate any additional derivative contracts as accounting hedges under FASB ASC Topic 815. 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 Financial Accounting Standards Board Accounting Standards Codification Topic 220 “Comprehensive Income” (FASB ASC 220)”, which establishes standards for reporting comprehensive income. In addition to net income (loss), comprehensive income (loss) includes all changes in equity during a period, except those resulting from investments and distributions to stockholders of Brigham.

F-10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reflects the components of other comprehensive income (loss) for the years ended December 31, 2009, 2008 and 2007 (in thousands):

	2009			2008			2007
Balance, beginning of year	$	—		$	115		$	1,006
Unrealized (gains) losses on investments		(205	)		—			—
Tax benefits (provisions) related to cash flow hedges		—			61			480
Net (gains) losses included in earnings		—			(176	)		(1,371	)
Balance, end of year	$	(205	)	$	—		$	115

Stock Based Compensation

Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic 718 “Compensation — Stock Compensation” (FASB ASC 718) to account for stock based compensation. See Note 13, “Stock Based Compensation,” for a full discussion of our stock-based compensation.

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 Series A Preferred Stock is presented in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 480 “Distinguishing Liabilities from Equity” (FASB ASC 480). FASB ASC 480 requires an issuer to classify certain financial instruments within its scope, such as mandatorily redeemable preferred stock, as liabilities (or assets in some circumstances). FASB ASC 480 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.

F-11

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

New Pronouncements

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Board Auditing Standard Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820), which provides expanded guidance for using fair value to measure assets and liabilities. FASB ASC 820 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 FASB ASC 820 was 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. The FASB Staff deferred implementation for other non-financial assets and liabilities for one year. Examples of non-financial assets and liabilities are asset retirement obligations and non-financial assets and liabilities initially measured at fair value in a business combination. The adoption of FASB ASC 820 on January 1, 2009 did not have a material impact on the financial statements.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption was not permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932 “Extractive Activities — Oil and Gas” (FASB ASC 932) provides guidance for oil and natural gas reserve related disclosures in the financial statements. Adoption of the new requirements did not have a material impact on Brigham’s financial statements.

In May 2009, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 165 “Subsequent Events” (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 will apply with respect to interim or annual reporting periods ending after June 15, 2009. See Note 16 “Subsequent Events.”

In June 2009, the Financial Accounting Standards Board issued Financial Accounting Standards Board Accounting Standards Codification Topic 105 “Generally Accepted Accounting Principles” (FASB ASC 105). FASB ASC 105 sets forth that the Financial Accounting Standards Board Accounting Standards Codification (ASC) is the exclusive authoritative reference for nongovernmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for SEC rules and interpretive releases, which also are authoritative GAAP for SEC registrants. The change was established by FASB Statement of Financial Accounting Standards No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (FAS 168), which divides nongovernmental U.S. GAAP into the authoritative Codification and guidance that is nonauthoritative, doing away with the previous four-level hierarchy. FASB ASC 105 is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. FASB ASC 105 was not intended to change or alter existing GAAP, and the Company’s adoption did not have any impact on its consolidated financial statements other than to modify certain existing disclosures. Upon adoption, the Company began to use the new guidelines and numbering system prescribed by the FASB ASC when referring to GAAP in the third quarter of fiscal 2009.

3. Property and Equipment

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

	December 31,
	2009			2008
Oil and natural gas properties	$	696,229		$	738,281
Accumulated depletion		(365,496	)		(333,442	)
		330,733			404,839

F-12

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	December 31,
	2009			2008
Other property and equipment:
3-D seismic interpretation workstations and software		1,619			1,585
Office furniture and equipment		3,307			3,438
Pipeyard equipment		832			546
Rental equipment		1,739			—
Land		409			408
Accumulated depreciation		(4,881	)		(4,104	)
		3,025			1,873
	$	333,758		$	406,712

Depletion expense is based on units-of-production. Production volumes used to determine depletion expense were 1,796 MBoe, 1,910 MBoe, and 2,496 MBoe for 2009, 2008, and 2007 respectively. The depletion rate used to calculate depletion expense was $17.88, $28.02, and $23.64 for 2009, 2008, and 2007, respectively.

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, 2009, 2008 and 2007 (in thousands):

	Year Ended December 31,
	2009		2008		2007
Capitalized certain payroll and other internal costs	$	7,718	$	7,994	$	8,164
Capitalized interest costs		4,713		4,761		3,467
	$	12,431	$	12,755	$	11,631

The risk that Brigham will experience a ceiling test writedown increases when oil and gas prices are depressed or if Brigham has substantial downward revisions in its estimated proved reserves. Based on oil and natural gas prices in effect at the end of the second quarter 2007, the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit and Brigham was required to record a writedown of its oil and gas properties in the amount of $4.1 million, net of tax.

Based on oil and natural gas prices in effect at the end of the third quarter 2007, the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit by $13.5 million, net of tax. However, subsequent to the end of the quarter, oil and natural gas prices increased and, utilizing these prices, Brigham’s net capitalized costs of oil and natural gas properties would not have exceeded the ceiling limit. As a result of the increase in the ceiling limit using subsequent prices, Brigham 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 December 2008 ($5.710 per MMBtu for Henry Hub natural gas and $44.60 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit by $148.6 million, net of tax. As a result, Brigham was required to record a writedown of the net capitalized costs of its oil and gas properties in the amount of $237.2 million at December 31, 2008.

Based on oil and gas prices in effect at the end of March 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit by $71.9 million, net of tax. As a result, Brigham was required to record a writedown of the net capitalized costs of its oil and gas properties in the amount of $114.8 million at March 31, 2009. Based on average oil and gas prices for the year ended December 31, 2009 ($3.87 per MMBtu for Henry Hub natural gas and $61.18 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties did not exceed the ceiling limit. Therefore, Brigham was not required to writedown the net capitalized costs of its oil and gas properties at December 31, 2009.

F-13

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4. Common Stock

In May 2009, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 36,292,117 shares of its common stock at a price of $2.75 and received net proceeds of $93.4 million after underwriting fees and offering expenses.

In October 2009, the stockholders approved an amendment to Brigham’s Certificate of Incorporation to increase the number of shares of common stock which Brigham is authorized to issue from 90 million shares to 180 million shares. The amendment to the Certificate of Incorporation became effective on October 7, 2009. Additionally, stockholders approved an amendment to the 1997 Incentive Plan that increased the number of shares of common stock available for issuance under the 1997 Incentive Plan to the lesser of (i) 9,966,603 or (ii) 12% of the total number of shares of common stock outstanding at any time.

In October 2009, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 16,000,000 shares of its common stock at a price of $10.50 and received net proceeds of $159.9 million after underwriting fees and offering expenses.

In November 2009, the Underwriters elected to exercise a portion of the over-allotment option associated with the October 2009 equity offering. This resulted in the issuance of 837,523 additional shares of common stock and Brigham received net proceeds of $8.4 million after underwriting fees and offering expenses.

5. 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, 2009 and 2008:

	December 31,
	2009			2008
	(In thousands)
Senior Credit Facility	$	—		$	145,000
Senior Notes		160,000			160,000
Discount on Senior Notes		(1,032	)		(1,270	)
Total Debt	$	158,968		$	303,730
Less: Current Maturities		—			—
Total Long-Term Debt	$	158,968		$	303,730

F-14

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Senior Credit Facility

In November 2008, in conjunction with Brigham’s regularly scheduled semi-annual redetermination, the borrowing base was reset to $145 million. In May 2009, in conjunction with Brigham’s regularly scheduled semi-annual redetermination, the borrowing base was reset to $110 million. Brigham used proceeds from the May stock offering to repay $35 million of outstanding borrowings under its Senior Credit Facility. On July 24, 2009, Brigham amended and restated the Senior Credit Facility to extend the maturity of the agreement from June 2010 to July 2012. During October 2009, Brigham used a portion of the proceeds from the October stock offering to repay borrowings under the Senior Credit Facility of $110 million.

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, plus in each case an applicable margin that is reset quarterly (2.5% at December 31, 2009). The applicable interest rate margin varies from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term is defined in the Senior Credit Facility) and from 2.5% to 3.5% 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 (0.50% at December 31, 2009). 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. The Senior Credit Facility also requires Brigham to maintain an interest coverage ratio for the quarters ending December 31, 2009 and March 31, 2010 of at least 2.0 to 1, and thereafter must be at least 2.5 to 1. The Senior Credit Facility also requires Brigham to maintain a net leverage ratio for the quarters ending December 31, 2009 through September 30, 2010 not greater than 4.5 to 1, for the quarters ending December 31, 2010 and March 31, 2011 not greater than 4.25 to 1, and thereafter not greater than 4.0 to 1. At December 31, 2009, Brigham was in compliance with all covenants under the Senior Credit Facility.

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 and its wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. The guarantees are joint and several. Brigham does not have any independent assets or operations.

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 add-on notes were priced at 99.50% of face value to yield 9.721%. Upon completion of the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes due 2014 (collectively the “Senior Notes”).

The indenture 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. To issue new debt, the indenture 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, 2009, Brigham was in compliance with all covenants under the indenture.

6. 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, 2009 and 2008 (in thousands, except share amounts):

	Year Ended				Year Ended
	December 31, 2009				December 31, 2008
	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

F-15

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 in cash. 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.

7. Asset Retirement Obligations

Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Prior to the adoption of Financial Accounting Standards Board Accounting Standards Codification Topic 410 “Asset Retirement and Environmental Obligations” (FASB ASC 410), 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 FASB ASC 410, 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, 2009 and 2008 (in thousands):

	Year Ended
	December 31,
	2009			2008
Beginning asset retirement obligations	$	5,592		$	5,047
Liabilities incurred for new wells placed on production		327			412
Liabilities settled		(17	)		(228	)
Revisions to estimates due to sale of oil and gas properties		—			—
Accretion of discount on asset retirement obligations		421			361
	$	6,323		$	5,592

8. Income Taxes

Brigham utilizes the asset and liability approach to measure deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 740 “Income Taxes” (FASB ASC 740). Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Under FASB ASC 740, 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. During 2009, Brigham’s deferred tax asset relating to oil and gas properties was increased primarily due to Brigham’s ceiling test writedown in the first quarter of 2009. After testing to determine if the deferred tax assets would meet the more likely than not criteria, Brigham increased its federal valuation allowance to $77.1 million and its state valuation allowance to $5.9 million.

F-16

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	Year Ended December 31,
	2009			2008			2007
Current income taxes	$	—		$	—		$	—
Deferred income taxes (benefits):
Federal		(43,029	)		(71,445	)		5,827
State		(1,141	)		(5,745	)		901
Valuation allowances		43,937			34,489			—
	$	(233	)	$	(42,701	)	$	6,728

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,
	2009			2008			2007
Tax (benefit) at statutory rate	$	(43,129	)	$	(71,732	)	$	5,929
Add the effect of:
Nondeductible expenses, net of tax exempt income		1			6			6
Preferred stock dividends		212			212			212
Incentive stock options not exercised		26			47			34
State income taxes (benefits), net of federal deduction		(741	)		(3,734	)		586
State valuation allowance, net of federal deduction		644			2,455			—
Federal valuation allowance		42,719			30,002			(61	)
Other		35			43			22
	$	(233	)	$	(42,701	)	$	6,728

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

	December 31,
	2009		2008
Deferred tax assets
Current:
Unrealized hedging and other derivative losses	$	913	$	2
State deferred taxes		—		52
Other		36		42
Current		949		96
Non-current:
Net operating loss carryforwards (NOLs)		84,706		75,956
Percentage depletion carryforwards		4,433		4,201
Stock compensation		3,328		2,786
Asset retirement obligations		2,213		1,957
Unrealized derivative losses		318		—
Other		81		73

F-17

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	December 31,
	2009			2008
Non-current		95,079			84,973
		96,028			85,069
Valuation allowance		(77,153	)		(34,202	)
Total net deferred tax assets		18,875			50,867
Deferred tax liabilities
Current:
Unrealized derivative gains	$	(403	)	$	(1,799	)
Current		(403	)		(1,799	)
Non-current:
Depreciable and depletable property		(18,392	)		(48,983	)
Other		(80	)		(85	)
Non-current		(18,472	)		(49,068	)
Total net deferred tax liabilities		(18,875	)		(50,867	)
Total federal deferred tax asset (liability)		—			—
Total state deferred tax asset (liability)		—			(149	)
Total deferred tax asset (liability)	$	—		$	(149	)

At December 31, 2009, Brigham has regular U. S. Federal tax NOLs of approximately $248 million available as a deduction against future taxable income. Additionally, Brigham has approximately $233 million of U. S. Federal alternative minimum tax (“AMT”) NOLs. The NOLs expire from 2012 through 2029. The value of these NOLs depends on the ability of Brigham to generate taxable income. Brigham also has U. S. State tax NOLs of approximately $80 million and a Texas Franchise tax credit carryover of approximately $1.4 million. The increases in the valuation allowances have no impact on Brigham’s NOL positions for federal and state tax purposes.

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.

On January 1, 2007, Brigham adopted additional provisions under FASB ASC 740, 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. In 2006 and 2007, Brigham examined the tax positions taken in its tax returns and determined that the full values of the uncertain tax positions were reflected as part of its deferred tax liabilities and reclassified these liabilities to other tax liabilities on the consolidated balance sheet. In 2008, Brigham received approval from the Internal Revenue Service to change its method of accounting for certain geological and geophysical costs and no longer has a liability for uncertain tax positions. As a result, as of December 31, 2008, Brigham eliminated the other tax liabilities in its consolidated balance sheet.

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

	2009		2008
	(In thousands)
Unrecognized tax benefits at beginning of the year	$	—	$	2,162
Increases (decreases) resulting from adoption		—		—
Increases (decreases) resulting from tax positions taken in the current period		—		(2,162	)
Unrecognized tax benefits at end of the year	$	—	$	—

F-18

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, 2009, 2008, 2007, and 2006. In addition, Brigham is open to examination for the years 1997 through 2005, resulting from NOLs generated and available for carryforward.

9. Net Income Available Per Common Share

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

	Year Ended December 31,
	2009			2008			2007
	(In thousands, except per share amounts)
Basic EPS:
Income (loss) available to common stockholders	$	(122,992	)	$	(162,247	)	$	10,210
Weighted average common shares outstanding — basic		70,569			45,441			45,110
Basic EPS:
Income (loss) available to common stockholders	$	(1.74	)	$	(3.57	)	$	0.23
Diluted EPS:
Income (loss) available to common stockholders — diluted	$	(122,992	)	$	(162,247	)	$	10,210
Common shares outstanding		70,569			45,441			45,110
Effect of dilutive securities:
Stock options and restricted stock		—			—			421
Potentially dilutive common shares		—			—			421
Adjusted common shares outstanding — diluted		70,569			45,441			45,531
Diluted EPS:
Income (loss) available to common stockholders	$	(1.74	)	$	(3.57	)	$	0.22

At December 31, 2009, 2008, and 2007, potential dilution of approximately 4.7 million, 3.7 million, and 2.8 million shares of common stock, respectively, related to mandatorily redeemable preferred stock and options were outstanding, but were not included in the computation of diluted income (loss) per share because the effect of these instruments would have been anti-dilutive.

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

Litigation

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

As of December 31, 2009, 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.

F-19

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Brigham is also subject to early termination fees for four drilling rigs under a contract that is quarter-to-quarter through May 2011. The future minimum annual rental payments under the noncancelable terms of these leases and potential fees for early termination of the drilling rig contract at December 31, 2009 are as follows (in thousands):

2010		1,521
2011		738
2012		378
	$	2,637

Rental expense for the years ended December 31, 2009, 2008 and 2007 was approximately $804,000, $770,000, and $801,000, 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, 2009, 2008 and 2007:

	2009			2008			2007
Purchaser A		—			—			13	%
Purchaser B		—			21	%		27	%
Purchaser C		—			—			13	%
Purchaser D		31	%		19	%		11	%
Purchaser E		13	%		—			—

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

Factors Which May Affect Future Operations

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

11. Derivative Instruments and Hedging Activities

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

Natural Gas and Crude Oil Derivative Contracts
Cash flow hedges

Brigham enters into contracts to hedge against the variability in cash flows associated with the forecasted sale of future oil and gas production. Brigham’s hedges consist of swaps, costless collars (purchased put options and written call options), and three-way collars (a standard collar plus a sold put below the floor price of the collar). The costless collars and three-way collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There are no net premiums paid or received when Brigham enters into these option agreements. Brigham has elected not to designate any of its derivative contracts as cash flow hedges for accounting purposes under Financial Accounting Standards Board Accounting Standards Codification Topic 815 “Derivatives and Hedging” (FASB ASC 815). 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. See Note 12, “Fair Values”, for a discussion of the calculation of the fair values of oil and natural gas derivative contracts. 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.

F-20

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables reflect Brigham’s open commodity derivative contracts at December 31, 2009, 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
01/01/10 – 03/31/10		210,000			$	5.75	$	7.05
01/01/10 – 12/31/10		840,000			$	5.15	$	7.00
04/01/10 – 09/30/10		420,000			$	5.75	$	7.30
04/01/10 – 09/30/10		240,000			$	5.75	$	7.00
04/01/10 – 09/30/10		300,000			$	5.50	$	6.65
10/01/10 – 03/31/11		240,000			$	6.50	$	8.25
10/01/10 – 03/31/11		420,000			$	6.40	$	7.80
01/01/11 – 12/31/11		360,000			$	5.75	$	7.65
Oil Costless Collars
01/01/10 – 03/31/10				9,000	$	60.00	$	91.75
01/01/10 – 05/31/10				50,000	$	57.50	$	75.95
01/01/10 – 03/31/10				6,000	$	65.00	$	87.50
01/01/10 – 12/31/10				120,000	$	48.70	$	80.00
01/01/10 – 12/31/10				54,000	$	60.00	$	86.50
01/01/10 – 12/31/10				60,000	$	60.00	$	88.80
04/01/10 – 09/30/10				18,000	$	60.00	$	91.40
06/01/10 – 12/31/10				56,000	$	57.50	$	82.15
07/01/10 – 09/30/10				6,000	$	70.00	$	87.25
10/01/10 – 12/31/10				3,000	$	70.00	$	88.50
01/01/11 – 12/31/11				84,000	$	65.00	$	88.25
01/01/11 – 12/31/11				60,000	$	60.00	$	97.25
01/01/10 – 06/30/10				30,000	$	60.00	$	103.75
01/01/10 – 12/31/10				24,000	$	60.00	$	100.00
01/01/10 – 12/31/10				36,000	$	60.00	$	96.00
01/01/11 – 06/30/11				18,000	$	65.00	$	97.50
01/01/11 – 12/31/11				60,000	$	65.00	$	108.00

	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMBTU)		Nymex		Nymex		Nymex
Natural Gas Three Way Costless Collars
01/01/10 – 03/31/10		210,000	$	8.00	$	10.00	$	5.50
01/01/10 – 03/31/10		180,000	$	5.75	$	7.00	$	3.50

F-21

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables reflect commodity derivative contracts entered subsequent to December 31, 2009, 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
01/01/11 – 12/31/11		480,000			$	5.75	$	7.40
Oil Costless Collars
03/01/10 – 08/31/10				18,000	$	70.00	$	99.00
03/01/10 – 12/31/10				40,000	$	70.00	$	101.75
04/01/10 – 06/30/10				30,000	$	65.00	$	89.90
07/01/10 – 12/31/10				30,000	$	65.00	$	94.25
07/01/10 – 12/31/10				12,000	$	65.00	$	107.70
01/01/11 – 02/28/11				10,000	$	70.00	$	92.00
01/01/11 – 06/30/11				24,000	$	70.00	$	92.50
01/01/11 – 12/31/11				48,000	$	70.00	$	106.80
01/01/11 – 12/31/11				48,000	$	75.00	$	102.60
07/01/11 – 09/30/11				9,000	$	70.00	$	95.00
07/01/11 – 12/31/11				12,000	$	75.00	$	103.00
10/01/11 – 12/31/11				6,000	$	70.00	$	96.35

Additional Disclosures about Derivative Instruments and Hedging Activities

At December 31, 2009, Brigham had derivative financial instruments under FASB ASC 815 recorded on the consolidated balance sheet as set forth below:

		Estimated
Type of Contract	Balance Sheet Location	Fair Value
		(in thousands)
Derivatives Not Designated as Hedging Instruments
Derivative Assets:
Oil and natural gas contracts	Derivative assets — current	$	1,152
Oil and natural gas contracts	Other non-current assets		186
Total Derivative Assets		$	1,338
Derivative Liabilities:
Oil and natural gas contracts	Other current liabilities	$	(2,404	)
Oil and natural gas contracts	Other non-current liabilities		(909	)
Total Derivative Liabilities		$	(3,313	)

For the twelve months ended December 31, 2009, the effect on income in the consolidated statement of operations for derivative financial instruments under FASB ASC 815 was as follows:

		Twelve Months
		Ended Dec 31,
	Statement of Operations	Amount of
Type of Contract	Location of Gain (Loss)	Gain (Loss)
		(in thousands)
Derivatives Not Designated as Hedging Instruments
Natural gas contracts	Gain (loss) on derivatives, net	$	7,061
Oil contracts	Gain (loss) on derivatives, net		(4,997	)
Total Derivative Gain (loss)		$	2,064

F-22

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Brigham’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty and Brigham has netting arrangements with all of its counterparties that provide for offsetting payables against receivables from separate derivative instruments with that counterparty.

12. Fair Values

Brigham adopted Financial Accounting Standards Board Accounting Standards Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820) on January 1, 2008, as it relates to financial assets and liabilities. Brigham adopted FASB ASC 820 on January 1, 2009, as it relates to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by FASB ASC 820 are as follows:

• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

As such, effective January 1, 2008, the fair values of Brigham’s derivative financial instruments reflect Brigham’s estimate of the default risk of the parties in accordance with FASB ASC 820. Brigham determines the fair value of derivative financial instruments based on counterparties’ valuation models that utilize market-corroborated inputs. The fair value of all derivative contracts is reflected on the balance sheet as detailed in the following schedule. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.

				Fair Value Measurements at December 31, 2009 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2009			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(2,404	)	$	—	$	(2,404	)	$	—
Other non-current liabilities		(909	)		—		(909	)		—
Current derivative assets		1,152			—		1,152			—
Other non-current assets		186			—		186			—
	$	(1,975	)	$	—	$	(1,975	)	$	—

				Fair Value Measurements at December 31, 2008 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2008			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(5	)	$	—	$	(5	)	$	—
Other non-current liabilities		—			—		—			—
Current derivative assets		5,140			—		5,140			—
Other non-current assets		202			—		202			—
	$	5,337		$	—	$	5,337		$	—

F-23

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Brigham’s assessment of the significance of a particular input to the fair value measurement requires judgment and may effect the valuation of the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of Brigham’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of the asset retirement obligations is reflected on the balance sheet as detailed below.

				Fair Value Measurements at December 31, 2009 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	December 31,			for Identical Assets		Inputs		Inputs
Description	2009			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(6,323	)		—		—		(6,323	)
	$	(6,323	)	$	—	$	—	$	(6,323	)

				Fair Value Measurements at December 31, 2008 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	December 31,			for Identical Assets		Inputs		Inputs
Description	2008			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(5,592	)		—		—		(5,592	)
	$	(5,592	)	$	—	$	—	$	(5,592	)

See Note 7 for a rollforward of the asset retirement obligation.

As of December 31, 2009, Brigham held $80.1 million of investments in certificates of deposit, corporate debt, and government securities. There were no investments at December 31, 2008. The fair value of the investments is reflected on the balance sheet as detailed below.

			Fair Value Measurements at December 31, 2009 Using
			Quoted Prices in		Significant Other		Significant
			Active Markets		Observable		Unobservable
	December 31,		for Identical Assets		Inputs		Inputs
Description	2009		(Level 1)		(Level 2)		(Level 3)
Investments		80,093		80,093		—		—
	$	80,093	$	80,093	$	—	$	—

The following table summarizes, by major security type, the fair value and any unrealized gain (loss) of Brigham’s investments. The unrealized gain (loss) is recorded on the consolidated balance sheet as other comprehensive income (loss), a component of stockholders’ equity.

	Less Than 12 Months					12 Months or Greater					Total
			Unrealized					Unrealized					Unrealized
	Fair		Gains			Fair		Gains			Fair		Gains
Description of Securities	Value		(Losses)			Value		(Losses)			Value		(Losses)
Certificates of deposit	$	8,877	$	(15	)	$	239	$	(1	)	$	9,116	$	(16	)
Corporate debt		13,931		(36	)		12,765		(28	)		26,696		(64	)
Government securities		39,762		(117	)		4,519		(8	)		44,281		(125	)
Total	$	62,570	$	(168	)	$	17,523	$	(37	)	$	80,093	$	(205	)

Brigham’s other 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 following are estimated fair values and carrying values of our other financial instruments at each of these dates:

	December 31, 2009				December 31, 2008
	(in millions)				(in millions)
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior Notes	$	160,000	$	160,000	$	160,000	$	84,000
Series A Preferred Stock	$	10,101	$	10,166	$	10,101	$	10,032

The fair value of Brigham’s Senior Notes is based upon current market quotes and is the estimated amount required to purchase the Senior Notes on the open market.

F-24

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13. Stock Based Compensation

Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic 718 “Compensation — Stock Compensation” (FASB ASC 718) to account for stock based compensation. The cost for all stock based awards is based on the grant date fair value estimated in accordance with the provisions of FASB ASC 718 and is amortized 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. The maximum contractual life of stock based awards is ten years.

The estimated fair value of the options granted during the three years months ended December 31, 2009, 2008, and 2007 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, 2009:

	2009			2008			2007
Risk-free interest rate		2.64	%		2.78	%		3.88	%
Expected life (in years)		5.0			5.0			5.0
Expected volatility		78	%		56	%		47	%
Expected dividend yield		—			—			—
Weighted average fair value per share of stock compensation	$	3.41		$	2.52		$	3.21

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.

Prior to the adoption of FASB ASC 718, 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. FASB ASC 718 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 record any excess tax benefits during the twelve months ended December 31, 2009 and 2008.

The following table summarizes the components of stock based compensation included in general and administrative expense (in thousands (in thousands):

	Twelve Months Ended
	December 31,
	2009			2008			2007
Pre-tax stock based compensation expense	$	4,282		$	2,926		$	3,443
Capitalized stock based compensation		(2,003	)		(1,334	)		(1,538	)
Tax benefit		(798	)		(557	)		(667	)
Stock based compensation expense, net	$	1,481		$	1,035		$	1,238

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 9,966,003 or 12% of the total number of shares of common stock outstanding. At December 31, 2009, approximately 2.8 million 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 series of stock option grants 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 maximum contractual life of ten years.

F-25

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 566,800 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, 2009:

	2009					2008					2007
				Weighted-					Weighted-					Weighted-
				Average					Average					Average
				Exercise					Exercise					Exercise
	Shares			Price		Shares			Price		Shares			Price
Options outstanding at beginning of year		3,128,651		$	7.00		3,046,166		$	7.14		3,243,566		$	7.08
Granted		2,846,975		$	4.80		534,000		$	5.08		105,000		$	7.06
Forfeited or cancelled		(1,549,675	)	$	8.30		(65,300	)	$	7.79		(178,900	)	$	8.19
Exercised		(255,814	)	$	4.89		(386,215	)	$	5.35		(123,500	)	$	3.82
Options outstanding at end of year		4,170,137		$	5.14		3,128,651		$	7.00		3,046,166		$	7.14
Options exercisable at end of year		691,962		$	6.17		1,954,851		$	7.17		1,869,066		$	6.62

The weighted-average grant-date fair value of share options granted during the years ended December 31, 2009, 2008, and 2007 was $3.41, $2.52, and $3.21, respectively. The total intrinsic value of options exercised during the years ended December 31, 2009, 2008 and 2007 was $1.5 million, $2.4 million, and $161,702, respectively.

The following table summarizes information about stock options outstanding at December 31, 2009:

	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	2009		Life	Price		2009		Life	Price
$2.21 to $3.41		1,219,000	9.0 years	$	2.26		29,000	2.5 years	$	3.30
3.66 to 5.08		619,900	4.3 years	$	4.86		251,900	2.1 years	$	4.53
5.96 to 6.73		1,906,437	8.4 years	$	6.01		224,262	3.1 years	$	6.26
7.22 to 8.84		187,800	3.7 years	$	7.71		112,800	2.9 years	$	7.81
8.93 to 13.86		237,000	7.4 years	$	11.66		74,000	2.4 years	$	10.15
2.21 to 13.86		4,170,137	7.7 years	$	5.14		691,962	2.6 years	$	6.17

The aggregate intrinsic value of options outstanding and exercisable at December 31, 2009 was $35.1 million and $5.1 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 2009 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, 2009. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

Brigham commenced an exchange offer on July 13, 2009 pursuant to which eligible employees were offered the opportunity to exchange outstanding stock options granted prior to April 21, 2009 for new stock options. On Monday, August 10, 2009, pursuant to the exchange offer, eligible option holders tendered, and Brigham accepted for cancellation, 1,536,975 eligible stock options. After the cancellation of the options accepted by Brigham in the exchange offer, Brigham granted new stock options with an exercise price of $5.955 per share, which was the mean of the high and low sales price per share of Brigham shares as reported by The Nasdaq Global Select Market on August 10, 2009. The exchange of options resulted in incremental compensation expense of $1.3 million that will be recognized over the five year vesting period of the new options.

As of December 31, 2009 there was approximately $7 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be realized over the remaining vesting period of approximately 5 years.

F-26

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Restricted Stock

During the year ended December 31, 2009, Brigham issued 342,574, restricted shares of common stock as compensation to officers and employees of Brigham. Restrictions lapsed on 257,574 of these shares in 2009, resulting in recognition of approximately $1.4 million in compensation expense. Restrictions on 85,000 restricted shares lapse in 2014. As of December 31, 2009, there was approximately $2.1 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 vesting period of approximately 4 years. Brigham has assumed a 6% weighted average forfeiture rate for restricted stock to be used in calculating compensation expense. If actual forfeitures differ from the estimates, 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, 2009					December 31, 2008
				Weighted-					Weighted-
	Number of			Average		Number of			Average
	Shares			Price		Shares			Price
Restricted Stock Awards:
Restricted shares outstanding at the beginning of the year		593,260		$	7.58		653,623		$	7.16
Shares granted		342,574		$	4.99		109,000		$	8.40
Lapse of restrictions		(377,844	)	$	6.02		(139,423	)	$	6.46
Forfeitures		(1,000	)	$	9.49		(29,940	)	$	6.58
Restricted shares outstanding at the end of the year		556,990		$	7.04		593,260		$	7.58

14. Employee Benefit Plans

Brigham has adopted a defined contribution 401(k) plan for substantially all of its employees. The plan provides for Brigham matching of employee contributions to the plan, at Brigham’s discretion. During 2009, 2008, and 2007, 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, there was no additional match for employee contributions made during 2009 and 2008. Brigham matched an additional 100% of eligible employee contributions made during 2007. Brigham contributed approximately $143,000, $159,000, and $628,000 to the 401(k) plan for the years ended December 31, 2009, 2008 and 2007, respectively, to match eligible contributions by employees.

15. Related Party Transactions

During the years ended December 31, 2009, 2008 and 2007, Brigham incurred costs of approximately $2.3 million, $7.3 million, and $3.3 million, respectively, in fees for land acquisition services performed by Brigham Land Management, 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, 2009, 2008 and 2007, Brigham had a liability recorded in accounts payable of approximately $30,000, $129,000, and $10,000, 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 during 2008 and 2007. Fees paid for these services by Brigham were approximately $30,000 for each the years ended December 31, 2008 and 2007. During each of the years ended December 31, 2009, 2008 and 2007, additional payments of approximately $2,500, $12,000, and $12,000, respectively, were made for the reimbursement of certain expenses. At December 31, 2009, 2008 and 2007, there were no payables related to these services recorded by Brigham.

F-27

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2009, 2008 and 2007, Brigham had short-term accounts receivable from Mr. Steve Webster of approximately zero, $2,900, and zero, 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, 2009, 2008 and 2007, Carrizo owed Brigham $24,000, $119,000, and $35,000, respectively, for exploration and production activities. Brigham owed Carrizo $6,000 at December 31, 2008. Brigham had no accounts payable owed to Carrizo at December 31, 2009 and 2007. Mr. Webster is also chairman of the board of directors for a well services company that Brigham made payments totaling approximately $619,000, $470,000, and $1.3 million during 2009, 2008 and 2007, respectively. Brigham owed the well services company approximately $27,000, $65,000, and $48,000 at December 31 2009, 2008 and 2007, 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 2009, 2008 and 2007 were $420,000, $1.1 million, and $1.2 million, respectively. At December 31, 2009, 2008 and 2007, Brigham owed the service company approximately $102,000, $76,000, and $55,000, respectively.

16. Subsequent Events

Management evaluated and determined there were no subsequent events.

17. Supplemental Cash Flow Information

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

	Year Ended December 31,
	2009			2008		2007
Cash paid for interest, net of capitalized amounts	$	14,545		$	12,382	$	14,059
Noncash investing and financing activities:
Capitalized asset retirement obligations		327			412		325
Accrued drilling costs		(4,270	)		4,927		(8,469	)
Capitalized stock compensation		2,003			1,334		1,538

18. Other Assets and Liabilities

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

	December 31
	2009		2008
Prepayments	$	767	$	1,897
Deferred taxes		—		—
Other		365		257
	$	1,132	$	2,154

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

	December 31
	2009		2008
Accrued interest	$	2,660	$	3,044
Derivative liabilities		2,405		5
Other accrued liabilities		2,641		2,016
	$	7,706	$	5,065

F-28

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,
	2009		2008		2007
Costs incurred for the year:
Exploration (including geological and geophysical costs)	$	10,566	$	43,229	$	37,324
Property acquisition		15,416		35,299		18,554
Development		54,641		110,155		69,851
	$	80,243	$	188,683	$	125,729

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, 2009 by year incurred.

	December 31,							Prior
	2009			2008		2007		Years		Total
Property acquisition	$	6,018		$	19,903	$	4,328	$	2,095	$	32,344
Exploration (including geological and geophysical costs)		(24	)		4,877		1,932		19,675		26,460
Drilling		8,333			—		—		—		8,333
Capitalized interest		4,103			3,979		366		724		9,172
Total	$	18,430		$	28,759	$	6,626	$	22,494	$	76,309

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 registered independent petroleum consultants, Cawley, Gillespie and Associates, Inc.

F-29

BRIGHAM EXPORATION COMPANY

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

Oil and Natural Gas Reserve Data

The following tables present Brigham’s independent petroleum consultant’s 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.

				Natural
	Oil			Gas
	(MBbls)			(MMcf)
Proved reserves at December 31, 2006		4,494			119,487
Revisions of previous estimates		172			7,926
Extensions, discoveries and other additions		1,546			14,349
Sales of mineral in place		(227	)		(22,493	)
Production		(392	)		(12,626	)
Proved reserves at December 31, 2007		5,593			106,643
Revisions of previous estimates		413			(7,834	)
Extensions, discoveries and other additions		1,637			3,866
Production		(578	)		(7,996	)
Proved reserves at December 31, 2008		7,065			94,679
Revisions of previous estimates (a)		2,055			(28,742	)
Extensions, discoveries and other additions (b)		8,354			6,367
Sales of mineral in place		(37	)		(13	)
Production		(814	)		(5,892	)
Proved reserves at December 31, 2009		16,623			66,399
Proved developed reserves at December 31:
2006		2,752			64,401
2007		3,321			49,367
2008		3,583			41,928
2009		5,342			29,178

(a)	Revisions of previous estimates include performance and technical revisions of 1,501 MBoe, economic revisions of (296) MBoe, acreage changes of (1,049) MBoe, and elimination of PUD reserves that will not be developed within 5 years of (2,891) MBoe.
(b)	Extensions, discoveries and other additions include discoveries and associated PUD’s of 5,374 MBoe and additions resulting from the modernization of SEC reserve reporting rules of 4,041 MBoe.

Proved reserves are estimated quantities of crude oil and natural gas, 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. For 2007 and 2008, future cash flows were computed by applying year-end prices of crude oil and natural gas relating to Brigham’s proved reserves to the estimated year-end quantities of those reserves. Under new rules issued by the Securities and Exchange Commission, the estimated future net cash flows at December 31, 2009 were determined using a 12-month average price. 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-30

BRIGHAM EXPORATION COMPANY

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

	December 31,
	2009			2008			2007
Future cash inflows	$	1,158,260		$	899,745		$	1,319,011
Future production costs		(330,837	)		(206,640	)		(248,116	)
Future development costs		(266,733	)		(160,304	)		(160,506	)
Future income tax expense		(32,493	)		(32,152	)		(219,748	)
Future net cash inflows		528,197			500,649			690,641
10% annual discount for estimated timing of cash flows		(281,721	)		(221,353	)		(296,127	)
Standardized measure of discounted future net cash flows	$	246,476		$	279,296		$	394,514

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 prices used for Brigham’s reserve estimates were as follows:

			Natural
	Oil		Gas
	(Bbl)		(MMbtu)
December 31, 2009	$	61.18	$	3.87
December 31, 2008		44.60	$	5.71
December 31, 2007		96.01	$	7.10

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

	December 31,
	2009			2008			2007
Beginning of period	$	279,296		$	394,514		$	302,674
Sales of oil and natural gas produced, net of production costs		(48,439	)		(107,144	)		(107,221	)
Previously estimated development costs incurred during the period		16,574			51,494			24,502
Extensions and discoveries		75,803			30,175			66,342
Net change of prices and production costs		(41,750	)		(184,497	)		164,728
Change in future development costs		6,874			(28,901	)		(31,586	)
Changes in production rates (timing)		(17,557	)		(2,201	)		(33,995	)
Revisions of previous quantity estimates		(41,726	)		(16,436	)		41,017
Accretion of discount		28,722			49,130			33,730
Change in income taxes		99			88,868			(62,161	)
Sales of reserves in place		(591	)		—			(2,923	)
Other		(10,829	)		4,294			(593	)
End of period	$	246,476		$	279,296		$	394,514

F-31

Quarterly Financial Data (Unaudited)

	Year Ended December 31, 2009
	Quarter			Quarter			Quarter		Quarter
	1			2			3		4
Revenue	$	18,486		$	10,514		$	19,867	$	21,477
Operating income (loss)*		(115,152	)		(2,787	)		4,750		4,273
Net income (loss)*		(119,071	)		(6,960	)		491		2,548
Net income (loss) per share:
Basic	$	(2.60	)	$	(0.12	)	$	0.01	$	0.03
Diluted	$	(2.60	)	$	(0.12	)	$	0.01	$	0.03

	Year Ended December 31, 2008
	Quarter		Quarter		Quarter		Quarter
	1		2		3		4
Revenue	$	25,071	$	25,026	$	47,191	$	30,500
Operating income (loss)*		5,528		5,789		28,254		(230,745	)
Net income (loss)*		1,527		1,517		15,260		(180,551	)
Net income (loss) per share:
Basic	$	0.03	$	0.03	$	0.34	$	(3.95	)
Diluted	$	0.03	$	0.03	$	0.33	$	(3.93	)

* Operating income (loss) and Net income (loss) include the impact from the writedown of the net capitalized costs of Brigham’s oil and gas properties in the amounts of $114.8 million and $237.2 million for the first quarter of 2009 and the fourth quarter 2008, respectively.

F-32

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 3.5 to Brigham’s Current Report on Form 8-K (dated May 28, 2009) and incorporated herein by reference)
	3.4	—	Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated June 14, 2006, (filed as Exhibit 3.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference)
	3.5	—	Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated October 7, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (dated October 13, 2009) 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, 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, 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	—	Certificate of Designations of Series C Junior Preferred Stock of Brigham Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008), and incorporated herein by reference)
	4.7	—	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)
	4.8	—	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)
	4.9	—	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)
	4.10	—	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)
	4.11	—	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)
	4.12	—	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)
	4.13	—	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)
	4.14	—	Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008), and incorporated herein by reference)

Number				Description
	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		—	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)
	10.3		—	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)
	10.4		—	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)
	10.5		—	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)
	10.6		—	Third Amendment to Two Bridge Point Lease Agreement dated November 1998 between Hub Properties Trust and Brigham Oil & Gas, L.P. (filed as Exhibit 10.13 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference)
	10.7		—	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 10.14 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference)
	10.8		—	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)
	10.9		—	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)
	10.10		—	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)
	10.11	*	—	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)
	10.12		—	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)
	10.13		—	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, and incorporated herein by reference)

Number				Description
	10.14		—	Registration Rights Agreement dated December 20, 2002 between Brigham Exploration Company and Shell Capital Inc. (filed as Exhibit 10.50 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference)
	10.15		—	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)
	10.16		—	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)
	10.17		—	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 fiscal quarter ended June 30, 2005 and incorporated herein by reference)
	10.18		—	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 fiscal quarter ended June 30, 2005 and incorporated herein by reference)
	10.19		—	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)
	10.20		—	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)
	10.21		—	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)
	10.22		—	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)
	10.23	*	—	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)
	10.24		—	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)
	10.25		—	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)
	10.26		—	Amendment to Securities Purchase Agreement dated July 31, 2008, between Brigham Exploration Company and DLJMB Funding III, Inc., DLJ ESC II, LP, DLJ Merchant Banking Partners III, L.P., and other parties (filed as Exhibit 10.41 to Brigham’s Current Report on Form 8-K (filed August 5, 2008) and incorporated herein by reference)

Number				Description
	10.27		—	Agreement Relating to Voting of Shares dated July 31, 2008, between Brigham Exploration Company and DLJ Merchant Banking Partners III, L.P., DLJ Offshore Partners III, C.V., DLJ Offshore Partners III-1, C.V., DLJ Offshore Partners III-2, C.V., DLJ MB Partners III GmbH & Co. KG, Millennium Partners II, L.P., MBP III Plan Investors, L.P., DLJ ESC II, L.P. and DLJMB Funding III, Inc. (filed as Exhibit 10.42 to Brigham’s Current Report on Form 8-K (filed August 5, 2008) and incorporated herein by reference)
	10.28		—	Third Amendment to the Fourth Amended and Restated Credit Agreement dated as of June 29, 2005 (filed as Exhibit 10.43 to Brigham’s Current Report on Form 8-K (filed November 12, 2008) and incorporated herein by reference)
	10.29	*	—	1997 Incentive Plan of Brigham Exploration Company (as amended effective August 19, 2009) (filed as Exhibit 10.50 to Brigham’s Current Report on Form 8-K (filed October 13, 2009) and incorporated herein by reference)
	10.30	*	—	Form of Restricted Stock Agreement under the 1997 Incentive Plan of Brigham Exploration Company (filed as Exhibit 10.45 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.31	*	—	Form of Option Agreement (Non-Qualified Stock Option) under the 1997 Incentive Plan of Brigham Exploration Company (filed as Exhibit 10.46 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.32	*	—	Form of Option Agreement (Incentive Option) under the 1997 Incentive Plan of Brigham Exploration Company (filed as Exhibit 10.47 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.33	*	—	Brigham Exploration Company 1997 Director Stock Option Plan (as amended effective January 1, 2009) (filed as Exhibit 10.48 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.34	*	—	Form of Non-Qualified Stock Option Agreement under the 1997 Director Stock Option Plan (filed as Exhibit 10.49 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.35	*	—	Form of Amendment to the Change of Control Agreement (filed as Exhibit 10.50 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.36	*	—	Amendment to the Employment Agreement between the Company and Ben M. Brigham dated as of December 23, 2008 (filed as Exhibit 10.51 to Brigham’s Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference)
	10.37		—	Confirmation of Notice of Termination of Consulting Agreement with Harold D. Carter, between Brigham Oil & Gas, L.P. and Harold D. Carter, effective as of January 1, 2009 (filed as Exhibit 10.41 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2009 and incorporated herein by reference)
	10.38		—	1997 Incentive Plan Amendment to Option Agreements, effective as of April 22, 2009 (filed as Exhibit 10.42 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2009 and incorporated herein by reference)
	10.39		—	Fourth Amendment to the Fourth Amended and Restated Credit Agreement dated as of June 28, 2005 (filed as Exhibit 10.43 to Brigham’s Current Report on Form 8-K (filed May 28, 2009) and incorporated herein by reference)
	10.40		—	Fifth Amendment to the Fourth Amended and Restated Credit Agreement dated as of June 28, 2005 (filed as Exhibit 10.45 to Brigham’s Current Report on Form 8-K (filed July 28, 2009) and incorporated herein by reference)
	10.41		—	Form of Non-Qualified Stock Option Agreement (filed as Exhibit 10.49 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2009) and incorporated herein by reference)
	10.42		—	Form of Non-Qualified Stock Option Agreement under the 1997 Director Stock Option Plan (filed as Exhibit 10.3 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated herein by reference)

Number				Description
	10.43		—	Form of Amendment to Non-Qualified Stock Option Agreements (filed as Exhibit 10.4 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated herein by reference)
	10.44		—	Amendment to Brigham Exploration Company 1997 Director Stock Option Plan, effective as of September 23, 2009 (filed as Exhibit 10.6 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated herein by reference)
	10.45		—	Amendment to Non-Qualified Stock Option Agreements under the 1997 Director Stock Option Plan, effective as of September 23, 2009 (filed as Exhibit 10.7 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated herein by reference)
	21	†	—	Subsidiaries of the Registrant
	23.1	†	—	Consent of KPMG LLP, Independent Registered Public Accounting Firm
	23.2	†	—	Consent of 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
	99.1	†	—	Report of Cawley, Gillespie & Associates, Inc.

* Management contract or compensatory plan.

† Filed herewith