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EX-21 - EXHIBIT 21 - BRIGHAM EXPLORATION COc13309exv21.htm
EX-32.2 - EXHIBIT 32.2 - BRIGHAM EXPLORATION COc13309exv32w2.htm
EX-31.1 - EXHIBIT 31.1 - BRIGHAM EXPLORATION COc13309exv31w1.htm
EX-23.1 - EXHIBIT 23.1 - BRIGHAM EXPLORATION COc13309exv23w1.htm
EX-23.2 - EXHIBIT 23.2 - BRIGHAM EXPLORATION COc13309exv23w2.htm
EX-12.1 - EXHIBIT 12.1 - BRIGHAM EXPLORATION COc13309exv12w1.htm
EX-32.1 - EXHIBIT 32.1 - BRIGHAM EXPLORATION COc13309exv32w1.htm
EX-31.2 - EXHIBIT 31.2 - BRIGHAM EXPLORATION COc13309exv31w2.htm
EX-99.1 - EXHIBIT 99.1 - BRIGHAM EXPLORATION COc13309exv99w1.htm
Table of Contents

 
 
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, 2010
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. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark 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). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b of the Act). Yes o No þ
As of June 30, 2010, the registrant had 116,596,688 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, 2010 of $15.38 per share as reported on The NASDAQ Global Select Market, was $1.7 billion. 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 23, 2011, the registrant had 116,968,942 shares of voting common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant’s 2011 Annual Meeting of Stockholders to be held on June 21, 2011, 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, 2010.
 
 

 

 


 

BRIGHAM EXPLORATION COMPANY
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 Exhibit 12.1
 Exhibit 21
 Exhibit 23.1
 Exhibit 23.2
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2
 Exhibit 99.1

 

 


Table of Contents

BRIGHAM EXPLORATION COMPANY
2010 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 crude 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 our Onshore Gulf Coast, the Anadarko Basin and West Texas and Other provinces. However, in late 2007, the majority of our drilling capital expenditures shifted from our historically active areas to the Williston Basin, where we are currently targeting the Bakken, Three Forks and Red River objectives. As of December 31, 2010, we had approximately 600,601 gross and 364,309 net leasehold acres in the Williston Basin. Through year-end 2010, we have invested in excess of $625 million on drilling, land and support infrastructure in this province.
At December 31, 2010, our proved reserves totaled 66.8 million barrels of oil equivalent (MMBoe) and had a standardized measure of $866.1 million and a pre-tax PV10% value of $1.1 billion. Approximately 78% of our proved reserves are crude oil and we operate approximately 81% of our proved reserves. Our average production volumes for 2010 were 8,267 barrels of oil equivalent per day (Boepd), which represents a 64% increase from 2009.
The following table provides information regarding our assets and operations located in our core areas.
                                                 
    At December 31, 2010     2010  
                            Productive     Average  
    Proved     Pre-Tax     %     Wells     Daily Production  
Province   Reserves(a)     PV10%(b)(c)     Oil     Gross     Net     Volumes (d)  
    (MMBoe)     (Millions)                       (Boe)  
Williston Basin
    55.5     $ 939.4       89 %     237       61.0       6,146  
Onshore Gulf Coast
    7.6       127.7       21 %     85       44.5       1,394  
Anadarko Basin
    2.6       22.1       7 %     89       23.6       558  
West Texas and Other
    1.1       19.5       87 %     31       7.6       169  
 
                                     
Total
    66.8     $ 1,108.7       78 %     442       136.7       8,267  
 
                                     
 
     
(a)   MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
 
(b)   The prices used to calculate this measure were $79.43 per barrel of crude oil and $4.376 per MMbtu of natural gas. The prices represent the average prices per barrel of crude 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, 2010 was $866.1 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. Average daily production volumes include approximately 29,654 barrels of oil produced during 2010 and recorded as inventory at year-end 2010. Total oil inventory at year-end 2010 and 2009 was 46,129 and 16,475 barrels of crude oil, respectively. Total crude oil inventory at year-end 2008 was not material. Adjusting production volumes for amounts included in inventory would result in average daily sales volumes in 2010 and 2009 of 8,185 and 4,988 barrels of oil per day.

 

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Since inception we have drilled and completed, or are currently in the process of drilling or completing 1,075 gross wells, consisting of 525 exploration and 550 development wells with an average completion rate of 77%. Over the three year period ended December 31, 2010, we drilled and completed, or were in the process of drilling or completing 315 gross wells, consisting of 10 exploratory and 305 development wells with an average completion rate of 99%. Our improved completion rate over the past three years is attributable to our increased level of activity in the Williston Basin, which is an unconventional resource play that generally provides more predictable drilling results. During 2010, we drilled and completed or were currently in the process of drilling or completing 193 gross wells, consisting of one exploratory well and 192 development wells with a completion rate of 100%. Both our higher levels of development drilling and completion rate in 2010, as compared to prior years, are also attributable to our increased level of activity in the Williston Basin.
Over the three year period ended December 31, 2010, we spent approximately $474.5 million on drilling capital expenditures, $162.9 million on land, prior to proceeds from asset sales, and $33.2 million on support infrastructure. Approximately 88% of our total drilling, land, seismic and support infrastructure spending over this three year period, prior to proceeds from asset sales, was spent in the Williston Basin.
In 2010, we spent approximately $280.1 million on drilling capital expenditures, which represents a 381% increase from that in 2009. The increase was a result of our limited drilling activity during the first half of 2009 as a result of the global financial recession that severely depressed commodity prices. As economic conditions improved, we issued equity in October 2009 and April 2010 to increase our operated drilling activity in the Williston Basin to four operated drilling rigs by year-end 2009 and to seven operated drilling rigs by year-end 2010. This increase in our operated drilling rig count resulted in higher levels of drilling capital expenditures during 2010. In 2010, we spent approximately $113.5 million on land, prior to proceeds from asset sales, which represents a 1,002% increase from that in 2009. Our higher level of land expenditures was primarily driven by the acquisition of approximately 81,725 net acres in the Williston Basin during 2010. In 2010, we spent approximately $33.2 million on support infrastructure, which includes oil, natural gas, produced water and fresh water gathering lines primarily in Williams and Mountrail Counties, North Dakota. We also drilled two water disposal wells and began construction on a regional office in Williston, North Dakota. These expenditures were incurred in order to more effectively and efficiently manage our rapidly growing operations in the Williston Basin. In earlier periods, we did not incur material support infrastructure costs.
In 2011, we anticipate spending approximately $582.1 million on drilling capital expenditures, $27.4 million on land and $83.2 million on support infrastructure. The increase in our drilling capital expenditure budget is a result of our continued acceleration of drilling activity in the Williston Basin. We began 2011 with seven operated drilling rigs and anticipate adding an eighth operated drilling rig in May 2011 and another operated drilling rig in September 2011. Further, our plans are to add an additional operated rig every four months until we reach 12 rigs by September 2012.
Lower land and seismic costs are anticipated as acquisition activity is expected to be more competitive in 2011 as compared to 2010. Our support infrastructure costs are anticipated to increase in 2011, as we expand construction of gathering lines in Williams County and begin to construct gathering lines in McKenzie County, North Dakota and drill additional water disposal wells.
Our 2011 budget is anticipated to be funded with cash and short term investments on hand as of year-end 2010, cash flow from operations, the proceeds from potential conventional oil and gas asset sales and availability under our Fifth Amended and Restated Credit Agreement that closed on February 23, 2011, which had no amounts outstanding and a $325 million borrowing base.
Business Strategy
Our business strategy is to create value for our stockholders by growing reserves, production and cash flow utilizing advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore crude oil and natural gas reserves. Key elements of our business strategy include:
    Focus on Net Asset Value Creation in our Provinces. We plan to concentrate the majority of our near term capital expenditures in the Williston Basin, where we believe our approximately 364,309 net acres and the application of advanced drilling and completion techniques provide us with a significant competitive advantage in developing the significant net asset value associated with both the Bakken and Three Forks producing horizons. In addition to the Williston Basin, we have a multi-year drilling prospect inventory 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.

 

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    Leverage our Engineering and Operational Expertise. Our staff is highly proficient with state-of-the-art drilling and completion techniques, 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 and completing long lateral wells with 20 isolated fracture stimulation stages in early 2009. During 2010, we typically drilled and completed our long lateral wells with between 30 and 38 isolated fracture stimulation stages and made other changes to our drilling and completion formula. We will continue to refine our drilling and completion techniques in order to attempt to enhance the performance and the associated estimated ultimate recoveries and net asset value of our wells.
    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 20 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 and the Vicksburg and Hunton plays in our Onshore Gulf Coast province 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, development and production activities. Furthermore, retaining operational control gives us the ability to control the financing, construction and operation of infrastructure related to our production operations such as crude oil, natural gas and wastewater gathering and processing, which in certain situations can enhance our well and project economics.
Exploration and Land Staff
Our experienced exploration staff includes 12 geologists, five 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 20 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 six landmen with an average of more than 17 years of experience, primarily within our core provinces, and seven 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 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 approximately 29% of the gross wells and 81% of the net wells that we drilled during 2010, as compared with 10% of the gross wells and 17% of the net wells we drilled during 1996. In 2011, we anticipate we will operate an increased number of wells as we currently have seven operated drilling rigs running in the Williston Basin and, subject to commodity price risk, service costs and other factors, anticipate increasing our operated drilling rig count to nine rigs by September 2011. As a result of our increased operational control, wells operated by us constituted 81% of our proved reserves at year-end 2010, as compared to only 5% at year-end 1996.

 

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Our operations staff includes ten engineers with an average of more than 13 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. As of year-end 2010, we had three employees located in North Dakota and anticipate opening a regional office in Williston, North Dakota in the second quarter 2011 in order to more effectively and efficiently manage our operations in the Williston Basin.
Crude Oil and Natural Gas Market and Major Customers
In an effort to improve price realizations from the sale of our crude oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude 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 crude oil or natural gas customer would have a material adverse effect on our results of operations or cash flows.
We sell our crude 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. See “Item 2. Properties — Delivery Commitments.”
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. See “Item 2. Properties — Delivery Commitments.”
Since most of our crude 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 crude oil and natural gas. The price we receive for our crude 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 crude 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 — Crude 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 crude 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 crude 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 crude oil or natural gas production, market, economic and regulatory factors may in the future materially affect our ability to sell our crude oil or natural gas production. See “Item 1A. Risk Factors — The marketability of our crude 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.”

 

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Competition
The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, including the acquisition of seismic and leasing options on oil and natural gas properties to the exploration and development of those properties. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for seismic and lease options on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Item 1A. Risk Factors — We face significant competition and many of our competitors have resources in excess of our available resources.”
Operating Hazards and Uninsured Risks
Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost and timing of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including low crude 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 crude 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 crude 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 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, 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 crude oil and natural gas. These governmental authorities also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of crude 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 crude oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of crude 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 (CAA) 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 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 crude oil and natural gas, and pipelines for the gathering, transportation or transmission of crude 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 crude 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.
Climate change legislation and regulations have been adopted by many states in the US. However, legislation has not been enacted at the federal level in the US. The 111th Congress considered a number of bills designed to regulate green house gas emissions, but did not pass any of those bills. It is unclear whether the current Congress or a future Congress will take further action on green house gasses. But, 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.

 

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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 crude 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.
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 36,621 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730. We also have a field office in Ross, North Dakota and plan to open a regional office in Williston, North Dakota in 2011.
Employees
As of December 31, 2010, we had 87 full-time employees and 2 part-time employees. As of the end of 2010, 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 or furnished to the Securities and Exchange Commission (SEC). 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.
Crude 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 crude oil and natural gas production. Historically, the markets for crude 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 crude oil contract during 2010 ranged from a high of $91.51 per barrel to a low of $68.01 per barrel. The NYMEX daily settlement price for the prompt month crude oil contract in 2009 ranged from a high of $81.37 per barrel to a low of $33.98 per barrel. In 2008, the same index ranged from a high of $145.29 per barrel to a low of $33.87 per barrel.
The NYMEX daily settlement price for the prompt month natural gas contract during 2010 ranged from a high of $7.51 per MMBtu to a low of $3.18 per MMBtu. The NYMEX daily settlement price for the prompt month natural gas contract in 2009 ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu. In 2008, the same index ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu.

 

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The markets and prices for crude oil and natural gas depend on numerous factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuate with changes in market and economic conditions and other factors, including:
    worldwide and domestic supplies of crude oil and natural gas;
    actions taken by foreign crude oil and natural gas producing nations;
    political conditions and events (including instability or armed conflict) in crude oil-producing or natural gas producing regions;
    the level of global and domestic crude oil and natural gas inventories;
    the price and level of foreign imports including liquefied natural gas imports;
    the level of consumer demand;
    the price and availability of alternative fuels;
    the availability of pipeline or other takeaway capacity;
    weather conditions;
    domestic and foreign governmental regulations and taxes; and
    the overall worldwide and domestic economic environment.
Significant declines in crude 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 crude 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 crude oil and natural gas properties; and
    limit our access to sources of capital, such as equity and long-term debt.
The ongoing economic uncertainty could negatively impact the prices for crude 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 economic 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 crude oil and natural gas may deteriorate and result in lower prices for crude 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 hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
In an attempt to reduce our sensitivity to energy price volatility and in particular to downward price movements, we enter into hedging arrangements with respect to a portion of expected production, such as the use of derivative contracts that generally result in a range of minimum and maximum price limits or a fixed price over a specified time period. Our current strategy is to hedge up to 100% of our proved developed producing reserves and up to 50% of the incremental oil volumes associated with our Williston Basin drilling program over the next 24 months with costless collars and puts.

 

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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 crude 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 crude 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, highly volatile crude oil and natural gas prices and future rules and regulations to be promulgated by the Commodities Futures Trading Commission (the “CFTC”) pursuant to the mandate of the United States Congress under the Dodd-Frank Wall Street Reform and Consumer Protection Act. See “— Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity 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 the net asset value and recoveries from the Bakken and Three Forks objectives involves drilling horizontal wells using completion techniques that have proven successful in other shale formations. Our experience with drilling horizontal wells in 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 crude oil and natural gas prices are depressed, 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 lack of availability or high cost of drilling rigs, fracture stimulation crews, 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, fracture stimulation crews, 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 levels of exploration and production increase in response to strong crude oil and natural gas prices, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while at the same time 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 proposed United States federal budgets for fiscal years 2011 and 2012 and proposed 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.
The Obama administration’s budget proposals for fiscal years 2011 and 2012 each contain numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. 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 crude oil and gas properties; repeal of the domestic 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. 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 drilling and completion techniques to explore for and to develop crude 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 crude 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 crude 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 crude oil and natural gas investments. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of crude 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 crude 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 crude oil and natural gas prices are depressed or if we have substantial downward revisions in estimated proved reserves. Based on crude oil and natural 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 crude oil, adjusted for differentials), the unamortized cost of our crude oil and natural gas properties exceeded the ceiling limit. As such, we recorded a $114.8 million ($71.9 million after tax) impairment to our crude oil and gas properties at March 31, 2009. Based on crude oil and natural 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 crude oil, adjusted for differentials), the unamortized cost of our crude oil and natural gas properties exceeded the ceiling limit. As such, we recorded a $237.2 million ($148.6 million after tax) impairment to our crude oil and natural 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 crude 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.

 

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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, 2010, we had mineral leases on approximately 364,309 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, crude 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.
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 crude 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 crude oil and natural gas, costs associated with producing crude 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 crude 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, fracture stimulation crews or other types of equipment necessary in the oil and gas industry.
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 somewhat depends on the success of our exploratory drilling program. Exploratory drilling involves a higher degree of risk that we will not encounter commercially productive crude 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 crude 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. (“CGA”), a registered independent petroleum consulting firm. In conducting its evaluation, the engineers and geologists of CGA evaluate our properties and independently develop proved reserve estimates. There are numerous uncertainties and risks that are inherent in estimating quantities of crude oil and natural gas reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. There are many factors and assumptions incorporated into our reserve 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 crude oil and gas prices and quality and location differentials; and
    future development and operating costs.
Although we believe the CGA 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 crude 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 crude 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, 2010, approximately 65% of our estimated proved reserves were classified as undeveloped. At December 31, 2010, we estimated that it would require additional capital expenditures of approximately $738.9 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 crude 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 crude 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 crude 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 Williston Basin 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 crude oil and natural gas and our success in finding and producing new reserves. If our revenues were to decrease as a result of lower crude 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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We may not drill all of our potential drilling locations and drilling locations that we decide to drill may not yield crude 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 potential locations that will require substantial additional evaluation and interpretation. Most of our potential drilling locations have not been attributed proved undeveloped reserves. A decision to drill any specific well on our large inventory of potential well locations may not be made for many years, if at all. If a decision is made to drill, there is no way to conclusively predict in advance of drilling and testing whether any particular drilling location will yield crude 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 crude oil and natural gas will be present or, if present, whether crude 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 crude oil and natural gas and, therefore, we may not achieve a targeted rate of return or have a positive return on investment.
The marketability of our crude 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 crude oil and natural gas production depends in part upon the availability of, proximity to and capacity of crude oil and natural gas gathering and transportation systems, crude oil and natural gas pipelines and processing facilities. We generally deliver crude 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 crude 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, 2010, approximately 19% of our crude oil and natural gas proved reserves were operated by other companies. Our dependence on other operators 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 crude 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 crude 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 crude 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 crude 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 crude 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, FERC, the EPA, the BLM, the TRRC, the TCEQ, the OCC, the LDNR, the NDIC and the MBOGC relating to the exploration for, and the development, production and marketing of, crude 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 crude 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 the CERCLA, the Resource Conservation and Recovery Act, the OPA, and the Clean Water Act. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm us. For example, in the 111th Congress, companion bills were introduced in the United States Senate and House of Representatives. These bills would have repealed the exemption for hydraulic fracturing from the federal Safe Drinking Water Act, which would have had the effect of allowing the EPA to promulgate regulations requiring permits and imposing new restrictions 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 have required persons 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, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. If legislation similar to that introduced in the 111th Congress becomes law, it could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 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. In addition, in March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Preliminary results of the study are expected in 2012. Thus, even if the pending legislation is not adopted, the EPA study, depending on its results, could spur further initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act.
Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.
Last year, the United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which contains comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation contains significant derivatives regulation, including provisions requiring certain transactions to be cleared on exchanges and containing a requirement to post cash collateral (commonly referred to as “margin”) for such transactions as well as certain clearing and trade-execution requirements in connection with our derivative activities. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. However, we do not know the definitions that the CFTC will actually promulgate nor how these definitions will apply to us. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

 

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Depending on the rules and definitions adopted by the CFTC, we could be required to post cash collateral with our dealer counterparties for our commodities hedging transactions. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post cash collateral which could adversely affect our available liquidity, thereby reducing our ability to use cash for investment or other corporate purposes, or could require us to increase our level of debt), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. In addition, a requirement for our counterparties to post cash collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the crude oil and natural gas we produce.
In the 111th Congress, two climate change bills were introduced that would have established 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 current or a future Congress could enact similar legislation. In addition to the possible 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. On November 8, 2010, the EPA finalized a rule that sets forth reporting requirements for the petroleum and natural gas industry and requires persons that hold state drilling permits and that emit 25,000 metric tons or more of carbon dioxide equivalent per year to annually report carbon dioxide, methane and nitrous oxide emissions from certain sources. 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 regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules in 2011. 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 crude oil and natural gas we produce, depending on the applicability to company operations and the refining, processing, and use of crude oil and gas.
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 February 25, 2011, we had $300 million in outstanding indebtedness, as well as $325 million of borrowing capacity under our Senior Credit Facility. 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;

 

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    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;
    our flexibility in planning for or reacting to changes in market conditions may be limited; and
    it may place us at a competitive disadvantage compared to our competitors that have less debt.
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 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.
The indenture governing our Senior Notes contains certain incurrence-based covenants that will 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 2011 will depend, in part, on prices for oil and natural gas utilized in our year-end 2010 reserve report. Our Senior Credit Facility also requires us to meet a minimum current ratio and a net leverage ratio. 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 notes and the documents governing our Senior Credit Facility have customary cross-default provisions, if the indebtedness under the 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 $325 million until the next borrowing base redetermination provided for in the Senior Credit Facility, which is scheduled for November 2011. We have no borrowings drawn on our Senior Credit Facility.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Senior Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
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 that will govern the 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.

 

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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 notes and the documents governing our Senior Credit Facility have customary cross-default provisions, if the indebtedness under the 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.
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 crude 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, 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, 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 crude oil and natural 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.

 

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Item 2.   Properties
Historically, our exploration and development activities have been focused in our Onshore Gulf Coast, the Anadarko Basin and West Texas provinces. However, in late 2007, the majority of our capital expenditures shifted from our historically active areas to the Williston Basin, where we are primarily targeting the Bakken and Three Forks producing horizons. As of December 31, 2010, we had approximately 600,601 gross and 364,309 net leasehold acres in the Williston Basin. In 2010, we drilled and completed or were in the process of completing 151 gross (38.9 net) wells on our Williston Basin acreage investing a total of $404.8 million on drilling, land and support infrastructure, before the impact of asset sale proceeds. At year-end 2010, we were also drilling 21 gross (2.7 net) wells. Since entering the Williston Basin in late 2005, we have invested in excess of $625 million on drilling, land, seismic and support infrastructure.
In 2010, we spent a total of approximately $426.8 million on drilling, land and support infrastructure in our operating areas. During 2011, we plan to spend approximately $582.1 million on drilling 68.1 net wells as well as to complete wells that were in progress at December 31, 2010. We currently expect to spend approximately $27.4 million on land. Finally, we expect to spend $83.2 million on support infrastructure to continue to expand gathering lines and add water disposal wells. 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, 2010, unless otherwise noted.
                                         
    Williston     Onshore     Anadarko     West Texas        
    Basin     Gulf Coast     Basin     and Other     Total  
Capital expenditures for drilling, land and support infrastructure in 2010 (in millions) (a)
  $ 404.8     $ 16.4     $ 0.7     $ 4.9     $ 426.8  
 
                                       
Proved Reserves at December 31, 2010
                                       
Pre-tax PV10% (in millions) (b)
  $ 939.4     $ 127.7     $ 22.1     $ 19.5     $ 1,108.7  
Crude oil (MMBbls)
    49.5       1.6       0.2       0.9       52.2  
Natural gas (Bcf)
    36.3       36.2       14.5       0.8       87.8  
Oil equivalents (MMBoe) (c)
    55.5       7.6       2.6       1.1       66.8  
% Oil
    89 %     21 %     7 %     87 %     78 %
 
                                       
Average daily production volumes (MBoe) (d)
    6,146       1,394       558       169       8,267  
Average daily sales volumes (MBoe)(d)
    6,064       1,394       558       169       8,185  
 
                                       
Productive wells at December 31, 2010
                                       
Gross
    237       85       89       31       442  
Net
    61.0       44.5       23.6       7.6       136.7  
 
     
(a)   Onshore Gulf Coast, Anadarko Basin and West Texas & Other capital expenditures are before the impact of proceeds from the sale of assets.
 
(b)   The standardized measure for our proved reserves at December 31, 2010, was $866.1 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 $79.43 per barrel of oil and $4.376 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 barrel of crude oil, condensate or natural gas liquids.
 
(d)   Average daily production volumes calculated based on 360 day year. Average daily production volumes include approximately 29,654 barrels of oil produced during 2010 and recorded as inventory at year-end 2010. Total oil inventory at year-end 2010 and 2009 was 46,129 and 16,475 barrels of crude oil, respectively. Total crude oil inventory at year-end 2008 was not material. Adjusting production volumes for amounts included in inventory would result in average daily sales volumes in 2010 and 2009 of 8,185 and 4,988 barrels of oil per day.

 

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Williston Basin Province
In late 2005, we began accumulating acreage in the Williston Basin located in North Dakota and Montana. During 2010, we invested approximately $404.8 million in drilling, land and support infrastructure. During 2010, we drilled and completed or were in the process of completing 151 gross wells (38.9 net) in the Williston Basin. At year-end 2010, there were 21 gross wells (2.7 net) drilling.
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 125,000 square miles. The basin produces oil and gas from numerous horizons including, but not limited to, the Bakken and Three Forks, which are currently our primary horizontal objectives.
The Bakken is an unconventional oil shale play at depths of approximately 10,000 to 10,500 feet that is primarily exploited via advanced drilling and completion techniques. The Bakken interval is comprised, from top to bottom, of the Upper Bakken Shale, Middle Bakken and Lower Bakken Shale. The Upper and Lower Bakken Shales are lithologically similar world class source rocks with total organic content of approximately 11%. Both the Upper and Lower Bakken Shales serve as the source rock for the Middle Bakken, which is a dolomite and is the zone targeted for our horizontal well bores. The dolomitic nature of the Middle Bakken allows us to propagate fractures during our multi-stage fracture stimulations and we retain long-term conductivity to the well bore via the use of ceramic proppants. During 2010, industry activity greatly increased west of the Nesson Anticline in Williams and McKenzie Counties, North Dakota. Industry activity is also increasing westward into Eastern Montana in both Richland and Roosevelt Counties.
The upper Three Forks is an unconventional carbonate play that lies just below the Bakken and is charged by the Lower Bakken Shale. Similar to the Middle Bakken, the upper Three Forks is primarily exploited using advanced drilling and completion techniques, which include multi-stage fracture stimulations. Drilling in the upper Three Forks began in mid-2008 and a number of operators, including us, are targeting this formation as a parallel objective to the Bakken formation. Drilling in this formation is early, but initial results appear to indicate that the upper Three Forks is a separate reservoir from the Bakken, which increases our exposure to crude oil reserves in the basin.
Overview of Williston Basin Acreage Position
Our acreage position in the Williston Basin is comprised of approximately 364,309 net acres. Approximately 95,011 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 5,319 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 34,960 net acres in our Ross Project area in Mountrail County where we both operate and participate in non-operated Bakken and Three Forks wells.
Approximately 155,065 net acres are 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.
Our remaining 114,233 net acres are located in eastern Montana in Roosevelt, Richland and Sheridan Counties in our Eastern Montana project area. Industry activity in Montana has been increasing with a number of operators drilling and permitting wells in and around our acreage.

 

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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 15 wells under the agreement have been drilled or were in the process of being drilled at year-end. 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 exercised its option to participate in the additional nine wells and we 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.
2010 Williston Basin Drilling and Completion Activity
                                                 
                            FRAC     IP     30 DAY  
WELL NAME   County     OBJECTIVE     ~WI     STAGES     (Boe/d)     Average (Boe/d)**  
 
                                               
Arvid Anderson 14-11 #1H
  Mountrail   Bakken     68 %     38       3,191       1,330  
Roger Sorenson 8-5 #1H
  Mountrail   Bakken     54 %     38       2,658       1,120  
Heen 26-35 #1H
  Williams   Bakken     76 %     38       3,791       1,379  
Brakken 30-31 #1H
  Williams   Bakken     56 %     30       3,573       1,277  
Lippert 1-12 #1H
  Williams   Bakken     66 %     31       2,214       942  
Brad Olson 9-16 #2H
  Williams   Bakken     56 %*     32       2,717       773  
Smith Farms 23-14 #1H
  Williams   Bakken     82 %     32       2,417       1,041  
Abelmann 23-14 #1H
  McKenzie   Bakken     53 %     33       4,169       1,407  
Clifford Bakke 26-35 #1H
  Mountrail   Bakken     43 %     38       5,061       2,328  
Boots 13-24 #1H
  Williams   Bakken     74 %     31       1,946       662  
Larsen 3-10 #1H
  Williams   Bakken     72 %     31       3,090       1,034  
Domaskin 30-31 #1H
  Mountrail   Bakken     65 %     38       4,675       1,882  
State 36-1 #2H
  Williams   Three Forks     30 %*     31       2,356       874  
Sukut 28-33 #1H
  Williams   Bakken     42 %*     32       1,959       801  
Abe Owan 21-16 #1H
  Williams   Bakken     57 %     37       2,213       900  
Weisz 11-14 #1H
  Williams   Bakken     52 %     37       2,278       1,014  
Wright 4-33 #1H
  Mountrail   Bakken     88 %     38       3,660       1,322  
Michael Owan 26-35 #1H
  Williams   Bakken     87 %     33       2,931       889  
Sedlacek Trust 33-4 #1H
  McKenzie   Bakken     48 %*     30       2,695       826  
Rogney 17-8 #1H
  Roosevelt   Bakken     100 %     30       909       355  
Ross Alger 6-7 #1H
  Mountrail   Bakken     47 %     32       3,070       1,465  
Owan 29-32 #1H
  Williams   Bakken     78 %     31       2,302       868  
Abe 30-31 #1H
  Williams   Bakken     97 %     31       1,847       731  
Jack Cvancara 19-18 #1H
  Mountrail   Bakken     83 %     36       5,035       1,800  
Tjelde 29-32 #1H
  McKenzie   Bakken     77 %     30       3,171       931  
Abelmann State 21-16 #1H
  McKenzie   Bakken     64 %     31       3,301       1,044  
Mortenson 5-32 #1H
  Williams   Bakken     77 %     23       2,314       584  
Arnson 13-24 #1H
  Williams   Bakken     93 %     30       1,339       480  
Sorenson 29-32 #1H
  Mountrail   Bakken     95 %     27       5,133       1,909  
Jack Erickson 6-31 #1H
  Williams   Bakken     21 %*     30       2,652       833  
Jerome Anderson 15-10 #1H
  Mountrail   Bakken     50 %     30       3,115       1,146  
Papineau Trust 17-20 #1H
  Williams   Bakken     43 %*     29       3,042       971  
Kalil 25-36 #1H
  Williams   Bakken     38 %*     30       1,586       650  
Liffrig 29-20 #1H
  Mountrail   Three Forks     72 %     29       2,477       1,082  
Owan-Nehring 27-34
  Williams   Bakken     49 %     30       2,513       1,089  
Jackson 35-34 #1H
  Williams   Bakken     62 %     30       3,540       907  
State 36-1 #1H
  Williams   Bakken     16 %*     30       3,807       1,516  
 
                          Averages     2,939       1,085  
     
*   Rough Rider drilling participation agreement wells where our working interest is anticipated to increase upon payout.
 
**   Excludes any days well was down for remediation.

 

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2011 Williston Basin Drilling and Completion Activity / 2011 Capital Budget
                                                 
                            FRAC     IP     30 DAY  
WELL NAME   County     OBJECTIVE     ~WI     STAGES     (Boe/d)     Average (Boe/d)**  
Knoshaug 14-11 #1H
  Williams   Bakken     50 %     36       4,443     NA  
Gibbins 1-12 #1H
  McKenzie   Bakken     55 %     33       2,582     NA  
Swindle 16-9 #1H
  Roosevelt   Bakken     52 %     19       1,065     NA  
Lloyd 34-3 #1H
  McKenzie   Bakken     29 %*     31       4,030       1,456  
Bratcher 10-3 #1H
  McKenzie   Bakken     91 %     30       3,667       1,129  
M. Macklin 15-22 #1H
  Williams   Bakken     89 %     38       2,534       1,062  
M. Olson 20-29 #1H
  Williams   Bakken     91 %     38       2,080       1,007  
 
                          Averages     2,914       1,164  
     
*   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 2011, we anticipate spending approximately $582.1 million to drill and complete an anticipated 65.7 net wells. Additionally, we anticipate spending approximately $27.4 million on land. Finally, we anticipate spending approximately $83.2 million on support infrastructure to expand our gathering systems in Williams and McKenzie Counties, North Dakota and to add additional water disposal wells. 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.
Since 2009, activity in the onshore Gulf Coast province has been significantly reduced due to depressed natural gas prices and our allocation of capital to the Williston Basin, which is predominately crude oil. During 2010, we completed two gross wells (2.0 net) in two attempts for a completion rate of 100%. In 2010, we spent $16.4 million on drilling and land in our Onshore Gulf Coast province, before the impact of asset sale proceeds. In 2011, we have no current plans to drill in the Onshore Gulf Coast province.
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. 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.
As with our Onshore Gulf Coast province, our activity in the Anadarko Basin has been significantly reduced since 2009. In 2010, we spent $0.7 million in the Anadarko Basin before the impact of asset sale proceeds. In 2011, we anticipate spending $1.6 million to drill 6 gross (0.6 net) wells in the Anadarko Basin.
West Texas and Other Province
The Permian Basin of West Texas and Eastern New Mexico is a predominantly crude oil producing province with generally longer life reserves than that of our onshore Gulf Coast.

 

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During 2010, we completed 15 gross (2.6 net) Wolfberry wells in West Texas at a 100% completion rate and spent a total of $4.8 million on drilling and land, before the impact of asset sale proceeds. In the second quarter 2010, we completed the sale of a portion of our proved developed reserves totaling approximately 0.6 MMboe. The primary assets remaining in our West Texas province are approximately 2,050 net acres prospective for the Wolfberry. In 2011, we anticipate spending $3.1 million to drill 15 gross (1.8 net) wells in West Texas.
In the fourth quarter of 2010, we divested all of our acreage in the Powder River Basin in Wyoming for proceeds totaling approximately $4.0 million.
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 crude 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 — Senior Notes.”
Crude Oil and Natural Gas Reserves
Our estimated total net proved reserves of crude oil and natural gas as of December 31, 2010 are as follows:
Summary of Crude Oil and Natural Gas Reserves as of Fiscal-Year-End Based on Average Fiscal-Year Prices
                         
    Reserves  
    Crude oil     NaturalGas     Total  
    (MMBbls)     (Bcf)     (MMBoe)(a)  
PROVED
                       
Developed:
                       
United States
    17.5       36.5       23.6  
Undeveloped:
                       
United States
    34.7       51.3       43.2  
 
                 
TOTAL PROVED
    52.2       87.8       66.8  
     
(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 internal control procedures require that our reserve report is prepared by a third party engineering firm at the end of every year based on information provided by our Reservoir Engineering Department. Our Chief Reservoir and Acquisitions Engineer reviews and approves the reserve information compiled by our internal staff and is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a degree in Petroleum Engineering from Texas A&M University and over 26 years experience in the industry, including SEC compliance with respect to proved reserves. He is licensed professional engineer in the State of Texas (PE 76121). Our internal staff of petroleum engineers, geoscience professionals and petroleum landmen work closely with CGA, our third party reserve engineers, to ensure the integrity, accuracy and timeliness of data furnished to CGA in their reserves estimation process. 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).
All key parameters in the reserve information are reviewed and approved by our executive officers. Our technical team meets regularly with representatives of CGA to review properties and discuss the methods and assumptions used by CGA in their preparation of the year-end reserves estimates. Our technical team and Chief Reservoir and Acquisitions Engineer also meets regularly with our Executive Vice President — Operations and our Executive Vice President — Exploration to review the methods and assumptions used by CGA in their preparation of the year-end reserves estimates. A copy of the CGA reserve report and detailed reserve analysis are reviewed by our audit committee with representatives of CGA and our internal technical staff before dissemination of the information.

 

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In accordance with applicable requirements of the 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 crude 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 crude 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 crude 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 crude 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 crude 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 crude 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, 2010 were 43.2 MMBoe, or 65% of our total proved reserves. Our PUD reserves as of December 31, 2009 were 17.5 MMBoe and represented 63% of our total proved reserves.
The increase in our year-end 2010 PUD reserves is attributable to both the increased level of our drilling activity and the continued application of advance drilling and completion techniques in the Williston Basin. During 2010, we had drilled and completed, were completing or were drilling 41.6 net wells versus 6.9 net wells in 2009. Our advanced techniques incorporate drilling long lateral horizontal wellbores approximately 10,000’ in length and completing wells with multi-stage fracture stimulations ranging typically from 30 to 38 fracture stimulations, which has improved our estimated ultimate recoveries. During 2010, we implemented widespread application of our advanced drilling and completion techniques in Mountrail, Williams and McKenzie Counties, North Dakota and drilled our initial well in Roosevelt County, Montana. In these areas, we were able to increase our level of PUD reserves.
Partially offsetting the above Williston Basin PUD reserve increases, we eliminated multiple PUD reserve locations in the Onshore Gulf Coast province that were primarily conventional natural gas targets that we currently do not anticipate drilling within the next five years. The PUD reserve locations that we eliminated totaled 0.8 MMBoe.
Our PUD reserves also decreased due to the drilling of 33 gross PUD wells (13.2 net) during 2010. During the year, we spent approximately $95.9 million dollars converting 5.5 MMBoe from PUD to proved developed producing reserves.

 

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Reconciliation of Standardized Measure to Pre-tax PV10%
Pre-tax PV10% is the estimated present value of the future net revenues from our proved crude 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 crude 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,  
    2010     2009     2008  
Standardized measure of discounted future net cash flows
  $ 866.1     $ 246.5     $ 279.3  
Add present value of future income tax discounted at 10%
    242.6       7.6       8.7  
 
                 
Pre-tax PV10%
  $ 1,108.7     $ 254.1     $ 288.0  
 
                 

 

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Drilling Activities
We drilled and completed, or participated in the drilling and completion of, the following wells during the periods indicated.
                                                 
    Year Ended December 31,  
    2010     2009     2008  
    Gross     Net     Gross     Net     Gross     Net  
Exploratory wells:
                                               
Natural gas
    0       0.0       0       0.0       4       1.3  
Crude oil
    1       1.0       1       0.1       1       0.8  
Non-productive
    0       0.0       1       0.2       2       1.0  
 
                                   
Total
    1       1.0       2       0.3       7       3.1  
 
                                   
 
                                               
Development wells:
                                               
Natural gas
    7       2.1       1       0.6       9       4.5  
Crude oil
    125       31.1       51       6.9       52       7.8  
Non-productive
    0       0.0       0       0.0       0       0.0  
 
                                   
Total
    132       33.2       52       7.5       61       12.3  
 
                                   
Present Activities
As of December 31, 2010, we had seven operated drilling rigs in the Williston Basin. Four drilling rigs were drilling development locations representing 2.2 net wells, two drilling rigs were in the process of rigging down and one drilling rig was in the process of rigging up. At year-end, we also had 17 non-operated wells drilling in the Williston Basin representing 0.5 net wells. We had 11 operated wells in the Williston Basin waiting on completion representing 7.6 net wells and one operated well in the Williston Basin fracing representing 0.3 net wells. Finally, we had 24 non-operated Williston Basin wells waiting on completion representing 1.4 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
We have committed to deliver all of our natural gas from our lands and leases in Williams County, North Dakota for the next seven years to a single purchaser. We must deliver a minimum of 2,500 mcf per day for the first year and 5,000 mcf per day for the subsequent four years. We will pay a penalty for volume deficiencies except in certain circumstances. We will receive 70% of the purchaser’s proceeds minus certain adjustments. The purchaser is required to pay for all facilities required to receive our gas from existing wells and the entire cost to connect for subsequent wells located within two miles of the purchaser’s gathering system. For subsequent wells located more than two miles from the purchaser’s gathering system, the purchaser may elect to either pay the cost to connect for the first two miles and require us to pay the cost to connect for the remainder or not to connect the well. If the purchaser elects not to connect the subsequent well, we can request the well and any others within that spacing unit be released from the terms of the agreement. Additionally, contingent upon completion of pipelines from the Williston Basin to Guernsey, Wyoming and Cushing, Oklahoma, we have entered into agreements with a marketing company to deliver an average of 5,000 barrels of oil per day and 10,000 barrels of oil per day, respectively for five years. We have the right to terminate this agreement if the pipelines are not in service by December 31, 2012 and December 31, 2013, respectively. We will pay a penalty for volume deficiencies except in certain circumstances. We will receive NYMEX near month WTI minus certain adjustments and a marketing fee. We have determined that we will have sufficient production to meet these commitments.

 

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Productive Wells and Acreage
Productive Wells
The following table sets forth our ownership interest at December 31, 2010 in productive crude oil and natural gas wells in the areas indicated. Wells are classified as crude 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     Crude oil     Total  
    Gross     Net     Gross     Net     Gross     Net  
Williston Basin
    0       0.0       237       61.0       237       61.0  
Onshore Gulf Coast
    68       40.4       17       4.1       85       44.5  
Anadarko Basin
    79       22.1       10       1.5       89       23.6  
West Texas and Other
    0       0.0       31       7.6       31       7.6  
 
                                   
Total
    147       62.5       295       74.2       442       136.7  
 
                                   
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.
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 crude 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, 2010.
                                                 
    Developed(a)     Undeveloped(a)     Total  
    Gross     Net     Gross     Net     Gross     Net  
Williston Basin
    131,531       87,273       469,070       277,036       600,601       364,309  
Onshore Gulf Coast
    21,627       9,077       5,016       2,985       26,643       12,062  
Anadarko Basin
    61,529       17,498       7,136       5,110       68,665       22,608  
West Texas and Other
    11,928       2,316       6,508       756       18,436       3,072  
 
                                   
Total
    226,615       116,164       487,730       285,887       714,345       402,051  
 
                                   
 
     
(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, 2011
    110,129       54,477  
December 31, 2012
    159,025       95,979  
December 31, 2013
    155,224       81,771  
December 31, 2014
    36,045       28,806  
December 31, 2015
    7,358       4,928  
Thereafter
    19,949       19,926  
 
           
Total
    487,730       285,887  
 
           
In addition, as of December 31, 2010, we had mineral interests covering approximately 13,408 gross and 2,100 net acres including 264 net acres in the Williston Basin. 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 for the Williston Basin.
                         
    Year Ended December 31,  
    2010     2009     2008  
Sales volumes(a):
                       
Crude oil volumes (MBbls)
                       
Williston Basin
    2,026       607       285  
 
                       
Natural gas volumes (MMcf)
                       
Williston Basin
    940       163       50  
 
The following table sets forth 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 crude 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.
                         
 
                       
Average crude oil prices based on sales volumes:
                       
Crude oil price (per Bbl)
  $ 71.08     $ 54.79     $ 89.06  
Crude oil price including derivative settlement gains (losses) (per Bbl)
  $ 70.87     $ 53.99     $ 84.63  
Crude oil price including derivative settlements and unrealized gains (losses) (per Bbl)
  $ 64.55     $ 48.65     $ 89.79  
 
                       
Average natural gas prices based on sales volumes:
                       
Natural gas price (per Mcf)
  $ 5.23     $ 4.01     $ 9.21  
Natural gas price including derivative settlement gains (losses) (per Mcf)
  $ 6.02     $ 5.71     $ 9.08  
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)
  $ 6.16     $ 5.21     $ 9.48  
 
                       
Average equivalent prices based on sales volumes:
                       
Oil equivalent price (per Boe)
  $ 60.84     $ 37.97     $ 65.50  
Oil equivalent price including derivative settlement gains (losses) (per Boe)
  $ 61.90     $ 43.19     $ 63.62  
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)
  $ 57.43     $ 39.12     $ 66.84  
 
                       
Average production costs (per Boe) based on sales volumes:
                       
Lease operating expenses (includes costs for operating and maintenance and expensed workovers)
  $ 6.03     $ 7.61     $ 5.89  
Ad valorem taxes
  $ 0.30     $ 0.56     $ 0.58  
Production taxes
  $ 5.88     $ 2.84     $ 2.81  
 
     
(a)   Sales volumes for 2010 and 2009 exclude 29,654 and 16,475 barrels of crude oil produced during the year and added to inventory during the respective period. Ending inventory at year end 2008 was not material.

 

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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, 2010, 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.   Removed and Reserved.
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
  51   Chief Executive Officer, President and Chairman
Eugene B. Shepherd, Jr.
  52   Executive Vice President and Chief Financial Officer
David T. Brigham
  50   Executive Vice President — Land and Administration and Director
A. Lance Langford
  48   Executive Vice President — Operations
Jeffery E. Larson
  52   Executive Vice President — Exploration
Ben M. “Bud” Brigham has served as our Chief Executive Officer, President and Chairman of the Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas at Austin. Mr. Brigham is the brother of David T. Brigham, Executive Vice President — Land and Administration.
Eugene B. Shepherd, Jr. has served as Executive Vice President and Chief Financial Officer since October 2003, and previously served as Chief Financial Officer from June 2002 to October 2003. Mr. Shepherd has approximately 27 years of financial and operational experience in the energy industry. Prior to joining us, Mr. Shepherd served as Integrated Energy Managing Director for the investment banking division of ABN AMRO Bank, where he executed merger and acquisition advisory, capital markets and syndicated loan transactions for energy companies. Prior to joining ABN AMRO, Mr. Shepherd spent fourteen years as an investment banker for Prudential Securities Incorporated, Stephens Inc. and Merrill Lynch Capital Markets. Mr. Shepherd worked as a petroleum engineer for over four years for both Amoco Production Company and the Railroad Commission of Texas. He holds a B.S. in Petroleum Engineering and an MBA, both from the University of Texas at Austin.
David T. Brigham joined us in 1992 and has served as a Director since May 2003 and as Executive Vice President — Land and Administration since June 2002. Mr. Brigham served as Senior Vice President — Land and Administration from March 2001 to June 2002, Vice President — Land and Administration from February 1998 to March 2001, as Vice President — Land and Legal from 1994 until February 1998 and as Corporate Secretary from February 1998 to September 2002. From 1987 to 1992, Mr. Brigham worked as an attorney in the energy section with Worsham, Forsythe, Sampels & Wooldridge. For a brief period of time before attending law school, Mr. Brigham was a landman for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board.

 

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A. Lance Langford joined us in 1995 as Manager of Operations, served as Vice President - Operations from January 1997 to March 2001, served as Senior Vice President — Operations from March 2001 to September 2003 and has served as Executive Vice President — Operations since September 2003. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University.
Jeffery E. Larson joined us in 1997 and was Vice President — Exploration from August 1999 to March 2001, Senior Vice President — Exploration from March 2001 to September 2003 and has served as Executive Vice President — Exploration since September 2003. Prior to joining us, Mr. Larson was an explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in various roles of responsibility. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and Research Scientist. He holds a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana.
PART II
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Common Stock, Performance Graph, and Dividend Policy
Our common stock commenced trading on the NASDAQ Global 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  
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  
2010:
               
First Quarter
  $ 18.00     $ 12.58  
Second Quarter
    21.15       13.45  
Third Quarter
    19.15       14.18  
Fourth Quarter
    28.15       18.55  
The closing market price of our common stock on February 23, 2011 was $33.86 per share. As of February 23, 2011, there were an estimated 145 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 Exploration and Production Index at the end of 2005 and remained invested through year-end 2010. The Indices 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 Exploration and Production 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
(LINE GRAPH)
     
*   $100 invested on 12/31/05 in stock or index, including reinvestment of dividends. Fiscal years 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 and our Senior Notes restrict our ability to pay dividends on our common 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, 2010.
                         
                    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)
    741,037     $ 8.41       2,262,815  
Equity compensation plans not approved by security holders
                 
 
                 
Total
    741,037     $ 8.41       2,262,815  
 
                 
 
     
(a)   Does not include 530,883 shares of restricted stock issued and outstanding at December 31, 2010.
Issuer Purchases of Equity Securities
In 2010, 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 2010
    2,520     $ 21.01  
 
           
Total
    2,520       21.01  
 
           
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, 2010, 2009 and 2008, and balance sheet data as of December 31, 2010 and 2009 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, 2007 and 2006 and the balance sheet data as of December 31, 2008, 2007 and 2006, from our accounting books and records.
                                         
    Year Ended December 31,  
    2010     2009     2008     2007     2006  
    (In thousands, except per share information)  
Statement of Operations Data:
                                       
Revenues:
                                       
Crude oil and natural gas sales
  $ 179,279     $ 68,192     $ 125,108     $ 120,557     $ 102,835  
Gain (loss) on derivatives, net
    (10,066 )     2,064       2,548       (1,664 )     3,335  
Support infrastructure revenue
    489                          
Other revenue
    20       88       132       88       127  
 
                             
Total revenues
    169,722       70,344       127,788       118,981       106,297  
 
                             
 
                                       
Costs and expenses:
                                       
Lease operating
    18,651       14,655       12,363       10,704       10,701  
Production taxes
    17,313       5,098       5,374       2,541       4,021  
Support infrastructure expenses
    50                          
General and administrative
    12,943       9,243       9,557       9,276       7,887  
Depletion of crude oil and natural gas properties
    58,195       32,054       53,498       59,079       46,386  
Impairment of crude oil and natural gas properties
          114,781       237,180       6,505        
Depreciation and amortization
    1,704       812       629       613       537  
Loss on inventory valuation
          2,196                    
Accretion of discount on asset retirement obligations
    422       421       361       379       317  
 
                             
Total costs and expenses
    109,278       179,260       318,962       89,097       69,849  
 
                             
 
                                       
Operating income (loss)
    60,444       (108,916 )     (191,174 )     29,884       36,448  
 
                             
Other income (expense):
                                       
Interest income
    1,198       578       191       654       1,207  
Interest expense, net
    (11,448 )     (16,431 )     (14,495 )     (14,622 )     (9,688 )
Gain loss on derivatives, net
                            3,213  
Loss on early redemption of Senior Notes
    (11,308 )                        
Other income (expense)
    5,094       1,544       530       1,022       1,352  
 
                             
Total other income (expense)
    (16,464 )     (14,309 )     (13,774 )     (12,946 )     (3,916 )
 
                             
Income (loss) before income taxes and cumulative effect of change in accounting principle
    43,980       (123,225 )     (204,948 )     16,938       32,532  
Income tax benefit (expense):
                                       
Current
                             
Deferred
    (1,084 )     233       42,701       (6,728 )     (12,744 )
 
                             
 
    (1,084 )     233       42,701       (6,728 )     (12,744 )
Net income (loss) available to common stockholders
  $ 42,896     $ (122,992 )   $ (162,247 )   $ 10,210     $ 19,788  
 
                             
Net income (loss) per share available to common shareholders:
                                       
Basic
  $ 0.39     $ (1.74 )   $ (3.57 )   $ 0.23     $ 0.44  
Diluted
    0.38       (1.74 )     (3.57 )     0.22       0.43  
Weighted average shares outstanding:
                                       
Basic
    111,355       70,569       45,441       45,110       45,017  
Diluted
    113,308       70,569       45,441       45,531       45,597  

 

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    At December 31,  
    2010     2009     2008     2007     2006  
    (In thousands)  
Statement of Cash Flows Data:
                                       
Net cash provided (used) by:
                                       
Operating activities
  $ 144,520     $ 51,750     $ 69,630     $ 90,449     $ 88,687  
Investing activities
    (556,211 )     (164,620 )     (179,866 )     (99,093 )     (171,747 )
Financing activities
    394,653       113,608       136,416       18,207       83,385  
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 23,743     $ 40,781     $ 40,043     $ 13,863     $ 4,300  
Investments
    223,991       80,093                    
Crude oil and natural gas properties, using the full cost method of accounting, net
    669,356       330,733       404,839       510,207       485,525  
Total assets
    1,085,401       498,256       489,056       548,428       522,587  
Long-term debt
    300,000       158,968       303,730       168,492       149,334  
Series A preferred stock, mandatorily redeemable (a)
          10,101       10,101       10,101       10,101  
Total stockholders’ equity
    593,270       264,283       121,269       279,027       266,015  
     
(a)   At year-end 2009, our Series A preferred stock was classified as a current liability as it was scheduled to be redeemed in 2010. Our Series A preferred stock was redeemed in the second quarter 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 crude 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 100% of our proved developed producing (PDP) oil volumes and up to 50% of the forecasted oil volumes associated with our Williston Basin drilling program for the upcoming 24 months. The use of certain types of derivative instruments may prevent us from realizing the benefit of upward price movements. See “Item 1A. Risk Factors — Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.”
Components of Our Cost Structure
Production Costs are the day-to-day costs we incur to bring hydrocarbons out of the ground and to the market combined with the daily costs we incur to maintain our producing properties. This includes lease operating expenses and production taxes.
    Lease operating expenses are generally comprised of several components including: the cost of labor and supervision to operate our wells and related equipment; repairs and maintenance; 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.
    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 crude 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 crude 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 crude oil and gas prices rise or when production from an area increases.
    Historically, taxing authorities have occasionally encouraged the oil and natural gas industry to explore for new crude oil and natural gas reserves, or to develop high cost reserves, through reduced tax rates or tax credits. These incentives have been narrow in scope and short-lived. A small number of our wells have qualified for reduced production taxes because they were discoveries based on the use of 3-D seismic or they are high cost wells.
Depreciation, Depletion and Amortization is the systematic expensing of the capital costs incurred to acquire, explore and develop crude oil and natural gas. As a full cost company, we capitalize all direct costs associated with our exploration and development efforts, including a portion of our interest and certain general and administrative costs, and apportion these costs to each unit of production sold through depletion expense. Generally, if reserve quantities are revised up or down, our depletion rate per unit of production will change inversely. When the depreciable capital cost base increases or decreases, the depletion rate will move in the same direction.
Asset Retirement Accretion Expense is the systematic, monthly accretion of future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities.
General and Administrative Expense includes payroll and benefits for our corporate staff, costs of maintaining our headquarters, managing our production and development operations and legal compliance. We capitalize general and administrative costs directly related to prospect generation and our exploration activities.
Interest. We have relied 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 our Senior Notes. We expect to continue to incur interest expense as we continue to use debt to fund a portion of our capital expenditures. 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 2010, 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 crude oil and natural gas reserves. Funding for our exploration and development of crude 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.

 

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Overview of Capital Activity
The application of advanced drilling and completion technologies in the Williston Basin and the associated improvements in well economics as well as the commodity price advantage of crude oil relative to natural gas has led us to increase both the total amount of capital expended and the percentage allocation of our capital budget to the Williston Basin and to decrease our spending in our other conventional natural gas focused provinces.
In October 2009, we completed a public offering of common stock and raised $168.3 million in net proceeds 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. We estimated that we would have four drilling rigs running throughout 2010 in the Williston Basin and would drill 24 net Bakken and Three Forks wells.
In April 2010, we completed a public offering of common stock and raised $277.5 million in net proceeds in order to pre-fund a further acceleration in the Williston Basin. Our revised 2010 capital budget announced concurrent with the equity offering, was estimated to be $293.9 million. We estimated that we would add an incremental operated drilling rig every four months beginning May 2010 and would have eight operated rigs running in the Williston Basin by May 2011 and would therefore drill 31 net wells in the basin during 2010. Approximately $37.8 million of the aforementioned capital budget would be used to fund the construction of support infrastructure.
In August 2010, we revised our 2010 capital budget largely as a result of several large acreage acquisitions, which increased our acreage in the Williston Basin by approximately 52,800 net acres. Our revised capital budget announced in August 2010 was estimated to be approximately $404.0 million and included approximately 38 net Williston Basin wells and $95.7 million for land.
In September 2010, we issued $300 million in Senior Notes due 2018 to fund the tender offer for and redemption of our 9 5/8% Senior Notes due in 2014 and to pre-fund our 2011 capital budget and for general corporate purposes.
In November 2010, we revised our 2010 capital budget to $466.1 million largely as a result of the expectation of drilling and completing 45 net Williston Basin wells. We also increased our land budget and our support infrastructure budget by approximately $19 million and $3 million, respectively. See “Capital Expenditures” for a discussion of our 2011 budget.
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we operate the majority of our wells. During 2010, we executed an agreement with a drilling contractor to enter into commitments for two walking drilling rigs for a three year period beginning upon their delivery date, which is anticipated to be in the first quarter 2012. Other than the aforementioned obligations, 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 crude oil and natural gas wells;
    cost of installing and maintaining new support infrastructure;
    cost of maintaining, repairing and enhancing existing crude 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.
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 our planned expenditures include the level of production from our existing crude 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.

 

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The final determination with respect to our 2011 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 crude oil or natural gas.
Factors that could cause us to further increase our level of activity and capital budget in 2011 include an improvement in commodity prices or well performance that exceeds our risked forecasts, the divestiture of non-strategic conventional assets, a reduction in service and material costs, or the formation of joint ventures with other exploration and production companies outside of our core de-risked acreage positions in the Williston Basin, all of which would positively impact our operating cash flow.
Factors that would cause us to reduce our capital budget in 2011 include, but are not limited to, reductions in commodity prices or underperformance of wells relative to our risked forecasts or increases in service and materials costs, all of which would negatively impact our operating cash flow.
Our budgeted oil and gas capital expenditures for 2011 are as follows:
         
    2011  
    (In millions)  
Drilling
  $ 582.1  
Support infrastructure
    83.2  
Land
    27.4  
 
     
Total oil and gas capital expenditures
  $ 692.7  
 
     
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 $162.9 million on land, excluding proceeds from asset sales, to expand our acreage position primarily in the Williston Basin.
For a more in depth discussion of our 2010 and 2011 capital expenditures see “Item 2. Properties.”

 

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Contractual Obligations
The following schedule summarizes our known contractual cash obligations at December 31, 2010 and the effect these obligations are expected to have on our future cash flow and liquidity.
                                         
    Payments Due by Year  
                            2013-     2015 and  
    Total     2011     2012     2014     Thereafter  
    (In thousands)  
Debt:
                                       
Senior Notes
  $ 300,000     $     $     $     $ 300,000  
Senior Credit Facility
                             
 
                             
Total
  $ 300,000     $     $     $     $ 300,000  
Other commitments:
                                       
Interest, Senior Notes(a)
  $ 210,000     $ 26,250     $ 26,250     $ 52,500     $ 105,000  
Interest, Senior Credit Facility(b)
                             
Drilling rigs(c)
    42,582       9,432       10,785       21,900       465  
Non-cancelable operating leases
    1,199       793       406              
 
                             
Total
  $ 553,781     $ 36,475     $ 37,441     $ 74,400     $ 405,465  
 
                             
 
     
(a)   Calculated assuming $300 million of Senior Notes outstanding and an interest rate of 8.75%. The payments are made in April and October until maturity in October 2018.
 
(b)   Calculated assuming no amounts outstanding under our Senior Credit Facility. 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, 2010. 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)   Contractual agreements with third-party service providers to procure drilling rigs for exploratory and development activities. See “Item 8. Financial Statements and Supplementary Data — Note 10 — Contingencies, Commitments and Factors Which May Affect Future Obligations.”
We also have liabilities of $5.9 million related to asset retirement obligations on our Consolidated Balance Sheet as of December 31, 2010. 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.”
Crude Oil and Natural Gas Reserves
Our estimated total net proved reserves of crude oil and natural gas as of December 31, 2010, 2009 and 2008 were as follows.
                         
    At December 31,  
    2010     2009     2008  
Estimated Net Proved Reserves:
                       
Crude oil (MMBbls)
    52.2       16.6       7.1  
Natural gas (Bcf)
    87.8       66.4       94.7  
Oil equivalent (MMBoe)(a)
    66.8       27.7       22.8  
Proved developed reserves as a percentage of net proved reserves
    35 %     37 %     46 %
     
(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.

 

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Our estimated total net proved reserves increased 141% from 2009 to 2010. The increase in our year-end 2010 proved reserves is attributable to both the increased level of our drilling activity and the continued application of advance drilling and completion techniques in the Williston Basin. During 2010, we drilled and completed, were completing or were drilling 41.6 net wells versus 6.9 net wells in 2009. Our advanced techniques incorporate drilling long lateral horizontal wellbores approximately 10,000’ in length and completing wells with multi-stage fracture stimulations ranging typically from 30 to 38 fracture stimulations, which has improved our rates of return. During 2010, we implemented widespread application of our advanced drilling and completion techniques in Mountrail, Williams and McKenzie Counties, North Dakota and drilled our initial well in Roosevelt County, Montana and drilled economic wells. In the Williston Basin, our reserves increased 260% to 55.4 MMBoe.
Partially offsetting our proved reserve increases, we eliminated multiple PUD reserve locations in our onshore Gulf Coast province where we currently do not anticipate drilling the locations within the next five years. The PUD reserve locations that we eliminated were primarily natural gas drilling locations in our South Texas acreage positions and totaled 0.8 MMBoe.
Results of Operations
Comparison of the twelve-month periods ended December 31, 2010, 2009 and 2008
Production volumes
                                         
    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
Crude oil (MBbls)(a)
    2,216       167 %     830       44 %     578  
Natural gas (MMcf)
    4,562       (23 %)     5,892       (26 %)     7,996  
Total (MBoe)(b)
    2,976       64 %     1,812       (5 %)     1,910  
Average daily production volumes (Boe/d)(c)
    8,267       64 %     5,034       (5 %)     5,306  
 
     
(a)   Includes approximately 29,654 and 16,475 barrels of oil produced in 2010 and 2009, respectively, and added to inventory in the respective year. Ending inventory at year end 2008 and was not material.
 
(b)   Boe is defined as one barrel equivalent of crude 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.
Increase in Inventory During the Year
                                         
    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
Crude oil (Bbls)
    29,654       80 %     16,475     NM        
Natural gas (Mcf)
                             
Total (Boe)
    29,654       80 %     16,475     NM        
Sales volumes (Production volumes less increase in Inventory)
                                         
    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
Crude oil (MBbls)(a)
    2,186       169 %     814       41 %     578  
Natural gas (MMcf)
    4,562       (23 %)     5,892       (26 %)     7,996  
Total (MBoe)(b)
    2,947       64 %     1,796       (6 %)     1,910  
Average daily sales volumes (Boepd)(c)
    8,185       64 %     4,988       (6 %)     5,306  
 
     
(a)   Excludes approximately 29,654 and 16,475 barrels of oil produced in 2010 and 2009, respectively, and recorded as inventory at year-end. Ending inventory at year end 2008 was not material.
 
(b)   Boe is defined as one barrel equivalent of crude 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.

 

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Our net equivalent sales volumes for 2010 increased by 64% to 2,947 MBoe (8,185 Boepd) from 1,796 MBoe (4,988 Boepd) in 2009. Our sales volumes for 2010 increased primarily due to our increased activity level in the Williston Basin, which drove crude oil sales volume growth of 169% from 2009 to 2010. This increase was partially offset by a 23% decrease in our natural gas volumes due to the natural decline of our wells. Crude oil as a percent of total production increased to 74% from 45% of our total production in 2010 and 2009, respectively, also as a result of our increased level of drilling activity in the Williston Basin.
The following is additional information regarding our 2010 sales volumes:
    Sales volumes from our Williston Basin province for 2010 increased 244% when compared to 2009. The increase was attributable to the rapid acceleration of our drilling activities in the Williston Basin. Sales volumes from this province represented 74% of our total sales volumes in 2010 versus 35% in 2009. Approximately 93% of our 2010 sales volumes from this province were oil compared to 96% in 2009.
    Sales volumes from our Onshore Gulf Coast province for 2010 decreased 36% when compared to 2009. 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 17% of our total sales volumes in 2010 versus 44% in 2009. Approximately 82% of our 2010 sales volumes from this province were natural gas compared to 89% in 2009.
    Sales volumes from our Anadarko Basin province for 2010 decreased 23% when compared to 2009. 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, limited new volumes were brought on line to offset the natural decline of our wells. Sales volumes from this province represented 7% of our volumes in 2010 versus 15% in 2009. Approximately 92% of our 2010 sales volumes from this province were natural gas compared to 92% in 2009.
    Sales volumes from our West Texas & Other province for 2010 decreased 45% when compared to 2009. 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 and the sale of producing properties in the second quarter 2010. 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 2% of our total volumes in 2010 versus 6% in 2009. Approximately 87% of our 2010 sales volumes from this province were oil compared to 89% in 2009.
The following is additional information regarding our 2009 sales volumes.
    Sales volumes from our Williston Basin province for 2009 increased 116% when compared to 2008. The increase was attributable to the rapid escalation of our drilling activities in the Williston Basin. Sales volumes from this province represented 35% of our total 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.
    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 17% 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 88% of our 2009 sales volumes from this province were oil compared to 88% in 2008.

 

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Revenue, commodity prices and hedging
The following table shows our revenue from the sale of crude oil and natural gas for 2010, 2009 and 2008. 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,  
    2010     % Change     2009     % Change     2008  
    (In thousands, except per unit measurements)  
Crude oil revenue:
                                       
Crude oil revenue
  $ 155,403       249 %   $ 44,580       (13 %)   $ 51,449  
Crude oil derivative settlement gains (losses)
    (468 )     (28 %)     (654 )     (74 %)     (2,564 )
 
                                 
Crude oil revenue including derivative settlements
  $ 154,935       253 %   $ 43,926       (10 %)   $ 48,885  
Crude oil derivative unrealized gains (losses)
    (13,808 )     218 %     (4,343 )   NM       2,983  
 
                                 
Crude oil revenue including derivative settlements and unrealized gains (losses)
    141,127       257 %     39,583       (24 %)     51,868  
Natural gas revenue:
                                       
Natural gas revenue
  $ 23,876       1 %   $ 23,612       (68 %)   $ 73,659  
Natural gas derivative settlement gains (losses)
    3,577       (64 %)     10,031     NM       (1,028 )
 
                                 
Natural gas revenue including derivative settlements
  $ 27,453       (18 %)   $ 33,643       (54 %)   $ 72,631  
Natural gas derivative unrealized gains (losses)
    633     NM       (2,970 )   NM       3,157  
 
                                 
Natural gas revenue including derivative settlements and unrealized gains (losses)
    28,086       (8 %)     30,673       (60 %)     75,788  
Crude oil and natural gas revenue:
                                       
Crude oil and natural gas revenue
  $ 179,279       163 %   $ 68,192       (45 %)   $ 125,108  
Crude oil and natural gas derivative settlement gains (losses)
    3,109       (67 %)     9,377     NM       (3,592 )
 
                                 
Crude oil and natural gas revenue including derivative settlement gains (losses)
    182,388       135 %     77,569       (36 %)     121,516  
Crude oil and natural gas derivative unrealized gains (losses)
    (13,175 )     80 %     (7,313 )   NM       6,140  
 
                                 
Crude oil and natural gas revenue including derivative settlements and unrealized gains (losses)
    169,213       141 %     70,256       (45 %)     127,656  
Support infrastructure revenue
    489     NM           NM        
Other revenue
    20       (77 %)     88       (33 %)     132  
 
                                 
Total revenue
  $ 169,722       141 %   $ 70,344       (45 %)   $ 127,788  
 
                                       
Average crude oil prices (based on sales volumes):
                                       
Crude oil price (per Bbl)
  $ 71.08       30 %   $ 54.79       (38 %)   $ 89.06  
Crude oil price including derivative settlement gains (losses) (per Bbl)
  $ 70.87       31 %   $ 53.99       (36 %)   $ 84.63  
Crude oil price including derivative settlements and unrealized gains (losses) (per Bbl)
  $ 64.55       33 %   $ 48.65       (46 %)   $ 89.79  

 

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    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
    (In thousands, except per unit measurements)  
Average natural gas prices:
                                       
Natural gas price (per Mcf)
  $ 5.23       30 %   $ 4.01       (56 %)   $ 9.21  
 
                                       
Natural gas price including derivative settlement gains (losses) (per Mcf)
  $ 6.02       5 %   $ 5.71       (37 %)   $ 9.08  
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)
  $ 6.16       18 %   $ 5.21       (45 %)   $ 9.48  
Average oil equivalent prices (based on sales volumes):
                                       
Oil equivalent price (per Bbl)
  $ 60.84       60 %   $ 37.97       (42 %)   $ 65.46  
Oil equivalent price including derivative settlement gains (losses) (per bbl)
  $ 61.90       43 %   $ 43.19       (32 %)   $ 63.60  
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Bbl)
  $ 57.43       47 %   $ 39.12       (41 %)   $ 66.84  
                 
    2009     2008  
    to 2010     to 2009  
Change in revenue from the sale of crude oil
               
Price variance impact
  $ 35,622     $ (27,885 )
Sales volume variance impact
    75,201       21,016  
Cash settlement of derivative hedging contracts
    186       1,910  
Unrealized gains (losses) due to derivative hedging contracts
    (9,465 )     (7,326 )
 
           
Total change
  $ 101,544     $ (12,285 )
 
           
 
               
Change in revenue from the sale of natural gas
               
Price variance impact
  $ 5,581     $ (30,657 )
Sales volume variance impact
    (5,317 )     (19,390 )
Cash settlement of derivative hedging contracts
    (6,454 )     11,059  
Unrealized gains (losses) due to derivative hedging contracts
    3,603       (6,127 )
 
           
Total change
  $ (2,587 )   $ (45,115 )
 
           
 
               
Change in revenue from the sale of crude oil and natural gas
               
Price variance impact
  $ 41,203     $ (58,542 )
Volume variance impact
    69,884       1,626  
Cash settlement of derivative hedging contracts
    (6,268 )     12,969  
Unrealized gains (losses) due to derivative hedging contracts
    (5,862 )     (13,453 )
 
           
Total change
  $ 98,957     $ (57,400 )
 
           
Our 2010 crude oil and natural gas revenue including derivative settlements and unrealized gains (losses) increased $99.0 million, or 141% when compared to 2009. The following were the primary reasons for the increase in our revenue:
    a 169% increase in our crude oil sales volumes, which was partially offset by a 23% decrease in our natural gas sales volumes, increased revenue by $69.9 million;
    a 60% increase in the average crude oil equivalent price increased revenue by $41.2 million;
    a $3.1 million gain from the settlement of derivative contracts in 2010 versus a $9.4 million settlement gain in 2009 decreased revenue by $6.3 million; and
    a $13.2 million unrealized loss due to derivative hedging contracts in 2010 versus a $7.3 million unrealized loss due to derivative hedging contracts in 2009 decreased revenue by $5.9 million.

 

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Our 2009 crude 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 crude 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.
Support infrastructure. Revenue from support infrastructure comes from fees related to our support infrastructure assets in North Dakota, including fees from oil, natural gas, waste water and fresh water gathering lines. Our produced water disposal wells in our Ross and Rough Rider project areas became operational early in the fourth quarter 2010 and late in the fourth quarter 2010, respectively.
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 2010 was $20,000 compared to $88,000 in 2009 and $132,000 in 2008. Costs related to our gas gathering systems are recorded in lease operating expenses.
Hedging. We utilize costless collars, swaps, puts, 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.

 

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The following table details derivative contracts that settled during 2010, 2009 and 2008 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,  
    2010     % Change     2009     % Change     2008  
Crude oil collars and three way costless collars
                                       
Volumes (Bbls)
    1,056,500       321 %     251,000       38 %     182,500  
Average floor price (per Bbl)
  $ 62.51       5 %   $ 59.43       (15 %)   $ 69.55  
Average ceiling price (per Bbl)
  $ 93.02       16 %   $ 80.12       (15 %)   $ 93.82  
Gain /(loss) upon settlement (in thousands)
  $ (468 )   NM     $ 902     NM     $ (2,564 )
Crude oil swaps
                                       
Volumes (Bbls)
          (100 %)     90,000     NM        
Average swap price (per Bbl)
  $       (100 %)   $ 50.75     NM     $  
Gain /(loss) upon settlement (in thousands)
  $       (100 %)   $ (1,556 )   NM     $  
Total crude oil gain / (loss) upon settlement (in thousands)
  $ (468 )     (100 %)   $ (654 )     (75 %)   $ (2,564 )
Natural gas collars and three way costless collars
                                       
Volumes (MMbtu)
    2,730,000       39 %     1,960,000       (60 %)     4,850,000  
Average floor price (per MMbtu)
  $ 5.79       (19 %)   $ 7.19       (6 %)   $ 7.65  
Average ceiling price (per MMbtu)
  $ 7.36       (17 %)   $ 8.83       (18 %)   $ 10.75  
Gain /(loss) upon settlement (in thousands)
  $ 3,577       (56 %)   $ 8,133     NM     $ (1,028 )
Natural gas swaps
                                       
Volumes (MMbtu)
          (100 %)     2,490,000     NM        
Average swap price (per MMbtu)
  $       (100 %)   $ 4.359     NM     $  
Gain /(loss) upon settlement (in thousands)
  $       (100 %)   $ 1,898     NM     $  
Total natural gas gain /(loss) upon settlement (in thousands)
  $ 3,577       (64 %)   $ 10,031     NM     $ (1,028 )

 

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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,  
    2010     % Change     2009     % Change     2008  
Production costs:
                                       
 
                                       
Operating & maintenance
  $ 4.65       (23 %)   $ 6.02       22 %   $ 4.92  
Expensed workovers
    1.38       (13 %)     1.58       65 %     0.96  
Ad valorem taxes
    0.30       (46 %)     0.56       (7 %)     0.60  
 
                                 
Lease operating expenses
  $ 6.33       (22 %)   $ 8.16       26 %   $ 6.48  
Production taxes
    5.88       107 %     2.84       1 %     2.82  
 
                                 
Production costs
  $ 12.21       11 %   $ 11.00       18 %   $ 9.30  
                                         
    Amount  
    (In thousands)  
    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
Production costs:
                                       
 
                                       
Operating & maintenance
  $ 13,698       27 %   $ 10,823       15 %   $ 9,399  
Expensed workovers
    4,055       43 %     2,832       53 %     1,851  
Ad valorem taxes
    898       (10 %)     1,000       (10 %)     1,113  
 
                                 
Lease operating expenses
  $ 18,651       27 %   $ 14,655       19 %   $ 12,363  
Production taxes
    17,313       240 %     5,098       (5 %)     5,374  
 
                                 
Production costs
  $ 35,964       82 %   $ 19,753       11 %   $ 17,737  
For 2010, our per unit production cost increased 11% when compared to 2009. The following were the primary reasons for the increase in our 2010 per unit production costs relative to 2009:
    production taxes increased 107% due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to an 11.5% tax rate; and
    higher production taxes were partially offset by 23% lower per unit lease operating expense, which was attributable to 64% higher sales volumes in 2010 as compared to that in 2009.
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.
Support infrastructure. We incur costs to operate our support infrastructure assets in North Dakota. Our produced water disposal wells in our Ross and Rough Rider project areas became operational early in the fourth quarter 2010 and late in the fourth quarter 2010, respectively.

 

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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,  
    2010     % Change     2009     % Change     2008  
    (In thousands, except per unit measurements which are based on sales volumes)  
General and administrative costs
  $ 25,495       50 %   $ 16,961       (3 %)   $ 17,551  
Capitalized general and administrative costs
    (12,552 )     63 %     (7,718 )     (4 %)     (7,994 )
 
                                 
General and administrative Expenses
  $ 12,943       40 %   $ 9,243       (3 %)   $ 9,557  
 
                                 
General and administrative expenses (per Boe)
  $ 4.39       (15 %)   $ 5.15       3 %   $ 4.98  
Our general and administrative expenses in 2010 increased $3.7 million from those in 2009. Before capitalization, our general and administrative costs increased by $8.5 million. The following were the primary reasons for the increase in our 2010 general and administrative costs relative to 2009:
    total compensation expense increased by $7.9 million due to the reinstatement of full salaries in late 2009 due to improved economic conditions, the reinstatement of our bonus plan in 2010, higher levels of employee salaries in 2010 to ensure competitive compensation levels with other oil and gas companies, and a higher number of employees due to our increased activity level in the Williston Basin; and
    other office expense increased by $0.6 million due to higher information technology costs.
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. The following were the primary reasons for the decrease 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.
Depletion of crude 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 crude 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,  
    2010     % Change     2009     % Change     2008  
    (In thousands, except per unit measurements which are based on sales volumes)  
Depletion of crude oil and natural gas properties
  $ 58,195       82 %   $ 32,054       (40 %)   $ 53,498  
Depletion of crude oil and natural gas properties (per Boe)
  $ 19.75       11 %   $ 17.85       (36 %)   $ 28.02  
Our depletion expense for 2010 was $26.1 million higher than 2009. An increase in production volumes in 2010 increased depletion expense by approximately $20.5 million and our higher depletion rate increased depletion expense $5.6 million.
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.

 

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Impairment of crude oil and natural gas properties. We use the full cost method of accounting for crude 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 crude 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.
Capitalized costs of crude 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 crude oil and natural gas reserves, based on the average of crude 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 crude 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 crude 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 crude oil and natural gas prices in effect on the balance sheet date. Based on crude 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 crude oil, adjusted for differentials), the unamortized cost of our crude oil and gas properties exceeded the ceiling limit and we recorded a $114.8 million impairment to our crude oil and gas properties. Based on crude 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 crude oil, adjusted for differentials), the unamortized cost of our crude oil and gas properties exceeded the ceiling limit and we recorded a $237.2 million impairment to our crude 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 paid 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,  
    2010     % Change     2009     % Change     2008  
    (In thousands)  
Interest on Senior Notes
  $ 18,240       18 %   $ 15,400       0 %   $ 15,401  
Interest on Senior Credit Facility
    26       (99 %)     3,375       72 %     1,960  
Commitment fees
    636       226 %     195       (24 %)     256  
Dividend on mandatorily redeemable preferred stock
    269       (56 %)     606       0 %     608  
Amortization of deferred loan and debt issuance cost
    1,939       26 %     1,538       49 %     1,032  
Other general interest expense
    108       260 %     30     NM        
Capitalized interest expense
    (9,770 )     107 %     (4,713 )     (1 %)     (4,762 )
 
                                 
Net interest expense
  $ 11,448       (30 %)   $ 16,431       13 %   $ 14,495  
 
                                 
Weighted average debt outstanding
  $ 201,447       (27 %)   $ 274,211       25 %   $ 220,116  
Average interest rate on outstanding indebtedness(a)
    9.57 %             7.15 %             8.28 %
 
     
(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 2010 was $5.0 million lower than that in 2009 primarily due to a $5.1 million increase in capitalized interest expense associated with our higher level of activity in the Williston Basin. Interest expense also decreased $3.3 million due to lower levels of debt outstanding on our Senior Credit Facility subsequent to its repayment in October 2009 in conjunction with our common stock offering. These decreases were partially offset by a $2.8 million increase in interest expense associate with the September 2010 issuance of our $300 million Senior Notes due 2018.
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.
Loss on early redemption of Senior Notes. In September 2010, we issued $300 million in Senior Notes due 2018 which funded the tender offer for and redemption of our 9 5/8% Senior Notes due in 2014. As a result of the redemption process, we incurred a loss on the Senior Notes due in 2014.
Other income (expense). Other income (expense) included:
                                         
    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
    (In thousands)  
Other:
                                       
Gain (loss) on sale of inventory or assets
    831       105 %     405     NM        
Other income (loss)
    4,263       274 %     1,139       115 %     530  
 
                                 
Total other income (loss)
  $ 5,094       230 %   $ 1,544       191 %   $ 530  
 
                                 
Other income increased in 2010 as a result of higher levels of field general equipment income in the Williston Basin, which was driven by accelerated development in the basin.
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 2010, we recognized a current year net deferred tax expense of $1.1 million. The $1.1 million in tax expense was mainly attributable to the state of North Dakota’s deferred tax expense. The primary reasons for the difference between our effective tax rate of 2.5% and the federal statutory rate of 35% were decreases 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 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.

 

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Liquidity and Capital Resources
Sources of Capital
In 2011, we intend to fund our capital expenditure program and contractual commitments with cash, cash equivalents and short term investments on hand as of year-end 2010, cash flows from operations, reimbursements of prior land and seismic costs by third parties who participate in our projects, the potential sale of interests in projects and properties, availability under our Senior Credit Facility or alternative financing sources.
Senior Notes
As of December 31, 2010, we had outstanding $300 million of 8 3/4% Senior Notes due 2018, which were issued in September 2010. In connection with the issuance of the 8 3/4% Senior Notes, we tendered for and purchased or redeemed $160 million of our 9 5/8% Senior Notes due 2014 in September and October 2010.
Our 8 3/4% Senior Notes are fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. Beginning April 2011, we will pay 8 3/4% interest on the $300 million outstanding. Future interest payments are due semi-annually in arrears in October and April of each year.
The 8 3/4% Senior Notes are our unsecured senior obligations, and:
    rank equally in right of payment with all our existing and future senior indebtedness;
    rank senior to all of our future subordinated indebtedness; and
    are effectively junior in right of payment to all of our and our guarantors’ existing and future secured indebtedness, including debt of our Senior Credit Facility.
The Indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon the occurrence of certain events of default, the trustee or the holders of the 8 3/4% Senior Notes may declare all outstanding 8 3/4% Senior Notes to be due and payable immediately.
Additionally, the Indenture governing the 8 3/4% Senior Notes 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 8 3/4% Senior Notes as of December 31, 2010.
Senior Credit Facility
As of December 31, 2010, our Senior Credit Facility provided for revolving credit borrowings up to $200 million and had a borrowing base of $110 million. Subsequent to December 31, 2010, we entered into our Fifth Amended and Restated Credit Facility in February 2011, which provides for revolving credit borrowings up to $600 million, a current borrowing base of $325 million and a five year maturity. As of December 31, 2010 and as of the date of the filing of this report, we had no amounts outstanding under our Senior Credit Facility.
The borrowing base under the new Senior Credit Facility will be redetermined at least semi-annually and the amount of borrowing capacity available to us under the new 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.”

 

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Borrowings under our new Senior Credit Facility bear interest at a base rate or a Eurodollar rate, at our election, plus in each case an applicable margin. These margins are reset quarterly and are subject to increase if the total amount borrowed under our new Senior Credit Facility reaches certain percentages of the available borrowing base, as shown below:
                         
Percent of   Eurodollar              
Borrowing Base   Rate     Base Rate     Commitment  
Utilized   Advances     Advances(1)     Fee  
< 50%
    2.00 %     1.00 %     0.50 %
≥ 50%
    2.25 %     1.25 %     0.50 %
≥ 75%
    2.50 %     1.50 %     0.50 %
≥ 90%
    2.75 %     1.75 %     0.50 %
 
     
(1)   Base Rate means for any day a fluctuating rate per annum equal to the highest of the following: (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 1.00% 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.
Our new 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 and net leverage ratio must not be greater than 4.00 to 1.
Mandatorily Redeemable Preferred Stock
In June 2010, we exercised our option to redeem all of our Series A mandatorily redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC.
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 2010, 2009 and 2008.
                                         
    Year Ended December 31,  
    2010     % Change     2009     % Change     2008  
    (In thousands)  
Net income
  $ 42,896     NM     $ (122,992 )     24 %   $ (162,247 )
Non-cash charges
    90,735       (43 %)     159,132       (35 %)     245,545  
Changes in working capital and other items
    10,889       (30 %)     15,610     NM       (13,668 )
 
                                 
Cash flows provided by operating activities
  $ 144,520       179 %   $ 51,750       (26 %)   $ 69,630  
Cash flows used by investing activities
    (556,211 )     238 %     (164,620 )     (8 %)     (179,866 )
Cash flows provided (used) by financing activities
    394,653       247 %     113,608       (17 %)     136,416  
 
                                 
Net increase (decrease) in cash and cash equivalents
  $ (17,038 )   NM     $ 738       (97 %)   $ 26,180  
 
                                 

 

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Analysis of net cash provided by operating activities
Net cash provided by operating activities for 2010 was $92.8 million higher than 2009. The following are the primary reasons for the increase:
    higher crude oil volumes, which were partially offset by lower natural gas volumes, increased operating cash flow by $69.9 million;
    higher oil equivalent sales prices increased operating cash flow by $41.2 million;
    higher production taxes decreased operating cash flow by $12.2 million;
    lower realized hedge settlements decreased operating cash flow by $6.3 million;
    the change in working capital decreased operating cash flow by $4.7 million;
    higher lease operating costs decreased operating cash flow by $4.0 million; and
    higher general and administrative expense reduced operating cash flow by $3.7 million.
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;
    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; and
    higher crude oil volumes partially offset by lower natural gas volumes decreased revenue by $1.6 million.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. At the end of 2010, as a result of our April 2010 equity offering and our September 2010 Senior Notes offering 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 2010. At year-end 2009, we also had a working capital surplus as a result of our May and October 2009 equity offerings. 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 working capital surplus at December 31, 2010, December 31, 2009 and December 31, 2008 was $184.3 million, $90.7 million and $30.3 million, respectively. Our working capital surplus at December 31, 2010 and December 31, 2009 included a current asset of $224.0 million and $80.1 million, respectively, related to short term investments.
Analysis of changes in cash flows used by investing activities
Net cash used by investing activities increased by $391.6 million from 2009 to 2010. The primary driver for the increase was a $375.0 million increase in capital expenditures for crude oil and natural gas activities due to higher levels of drilling activity, lease acquisition, and support infrastructure in the Williston Basin. Net cash used in investing activities also increased $63.8 million due to the change in short term investments and $12.8 million due to the change in inventory. These increases were partially offset by a $49.9 million decrease in cash used associated with our increase in accrued drilling costs and $17.7 million in asset sale proceeds which also decreased cash used during the period.
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.

 

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The following is a detailed breakout of our net cash used in investing activities for 2010, 2009 and 2008 in thousands.
                                         
    2010     % Change     2009     % Change     2008  
Capital expenditures for crude oil and natural gas activities:
                                       
Drilling
  $ 280,080       381 %   $ 58,209       (57 %)   $ 136,248  
Support infrastructure (a)
    33,226     NM             0 %      
Land
    112,153       6,269 %     1,761       (95 %)     35,796  
Capitalized cost
    21,470       73 %     12,432       (3 %)     12,852  
Capitalized asset retirement obligation
    814       149 %     327       (21 %)     412  
 
                                 
Total
  $ 447,743       516 %   $ 72,729       (61 %)   $ 185,308  
 
                                 
 
                                       
Reconciling Items:
                                       
Asset sale proceeds including ARO reduction liability
  $ (17,698 )   NM     $       0 %   $  
Change in short term investments
    143,898       80 %     80,093     NM        
Change in other property and equipment (b)
    6,235       280 %     1,642       249 %     470  
Change in accrued drilling costs
    (45,569 )   NM       4,270     NM       (4,927 )
Change in drilling advances paid
    794     NM             0 %      
Change in inventory
    20,709       163 %     7,881     NM        
Other
    99       NM       (1,995 )     103 %     (985 )
 
                                 
Total Reconciling Items
    108,468       18 %     91,891     NM       (5,442 )
 
                                       
Net cash used in investing activities
  $ 556,211       238 %   $ 164,620       (8 %)   $ 179,866  
 
                                 
     
(a)   Support infrastructure costs are recorded on our balance sheet in Other Property and Equipment.
 
(b)   Excludes approximately $33.2 million in support infrastructure costs, which are included in capital expenditures for crude oil and natural gas activities above.
Analysis of changes in cash flows from financing activities
Over the three year period ended December 31, 2010, 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 crude oil and natural gas properties.
Our net cash provided by financing activities in 2010 was $281.0 million higher than in 2009. In 2010, we received net proceeds of $277.5 million from our April common stock offering and net proceeds of $118 million from our September 8 3/4% Senior Notes offering after both tendering for and redeeming our 9 5/8 Senior Notes due 2014.
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.
Common Stock Transactions
Our net proceeds from the sale of common stock and employee stock option exercises were $18.5 million higher in 2010 than they were in 2009 due to our April 2010 equity offering. This compares to net proceeds that were $260.9 million higher in 2009 than in 2008 due to our May and October 2009 equity offerings.
The following is a list of common stock transactions that occurred in 2010, 2009 and 2008.
                 
    Shares Issued     Net Proceeds  
          (in thousands)  
2010 common stock transactions:
               
April 2010 common stock offering
    16,100,000     $ 277,547  
Exercise of employee stock options
    741,037     $ 3,884  
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  

 

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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 crude oil and natural gas reserves, future development costs, production expense, revenue and deferred income taxes are the most critical to our financial statements.
Crude oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on our crude oil and natural gas properties are highly dependent on the estimates of the proved crude oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of crude 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 crude 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 crude oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated crude 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 crude 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 crude oil and natural gas reserves used in the preparation of our consolidated financial statements were prepared by CGA, our registered independent petroleum consultants, and were prepared in accordance with the rules promulgated by the SEC.
Crude Oil and Natural Gas Property
The method of accounting we use to account for our crude 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 crude 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 crude 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 crude 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 crude 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, 2010, our average depletion expense per unit of production was $18.64 per Boe. A 10% decrease in our estimated net proved reserves at December 31, 2010 would result in a $2.04 per Boe increase in our per unit depletion expense and a $3.5 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 crude oil and natural gas prices) of the estimated future net cash flows from our proved crude 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 crude oil and natural gas properties. The risk that we will be required to write down the carrying value of our crude oil and natural gas properties increases when crude 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 crude oil and natural gas properties cannot be reversed at a later date. The risk that we will experience a ceiling test writedown increases when crude oil and gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves.
Based on crude 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 crude oil, adjusted for differentials), the unamortized cost of our crude oil and gas properties exceeded the ceiling limit and we recorded a $114.8 million ($71.9 million after tax) impairment to our crude oil and gas properties. Also, at December 31, 2008, the unamortized cost of our crude oil and gas properties exceeded the ceiling limit based on crude oil and gas prices in effect ($5.71 per MMBtu for Henry Hub gas and $44.60 per barrel for West Texas Intermediate crude oil, adjusted for differentials). Therefore, we recorded a $237.2 million ($148.6 million after tax) impairment to our crude 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 crude 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 crude 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 “- Crude oil and Natural Gas Property.” Additionally, increases in the discounted asset retirement liability resulting from the passage of time are reported as accretion of discount on asset retirement obligations expense on our Consolidated Statement of Operations.
Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments, which include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of our existing asset retirement obligation liability, a corresponding adjustment will be made to the carrying cost of the related asset.

 

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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 deferred tax asset.
Estimating the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum taxable 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 net deferred tax asset associated with net operating loss carryforwards (NOLs). Based on estimates of the reversal of our temporary differences, 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. 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 crude oil and natural gas that we produce, hence our revenue recognition policy for these sales is significant.
We recognize revenue from the sale of crude oil using the sales method of accounting. Under this method, we recognize revenue when we deliver crude 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 crude 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
We use derivative instruments to manage our market risks associated with fluctuations in crude oil and natural gas prices. We enter into derivative contracts, including costless collars, swaps, ceilings and floors, which upon settlement require payments to (or receipts from) counterparties based on the difference between a fixed price and a variable price for fixed quantities of crude oil and natural gas without exchanging underlying volumes. The notional amounts of these financial instruments are based on expected production from existing and future wells.
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 have elected to include all derivative settlement and unrealized gains (losses) within revenues.

 

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New Accounting Pronouncements
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 required 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.
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 crude 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 crude oil production are based on global market conditions. Our average pre-hedged sales price for crude oil in 2010 was $71.08 per barrel, which was 30% higher than the prices we received in 2009. Significant factors that will impact 2011 crude oil prices include the pace at which the domestic and global economies continue to recover, the extent to which members of the Organization of Petroleum Exporting Countries and other crude oil exporting nations are able to manage crude oil supply through export quotas and geopolitical developments in African and 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 2010 was $5.23 per Mcf, which was 30% higher than the price we received in 2009. Natural gas prices in 2011 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 crude oil and gas. We believe the use of derivative instruments, although not free of risk, allows us to reduce our exposure to crude 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.”

 

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Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing crude oil and natural gas prices. If the price of crude 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 crude oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe that we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity. See “Item 1A. Risk Factors — We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs” and “Item 1. Business — Governmental Regulation” and “Item 1. Business — Environmental Matters.”
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
Management Opinion Concerning Derivative Instruments
We use derivative instruments to manage exposure to commodity prices. 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 settlements and unrealized gains (losses) within revenue.
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, 2010. The following table reconciles the changes that occurred in the fair values of our open derivative contracts during 2010.
         
    Fair Value of  
    Undesignated  
    Derivative  
    Contracts  
Estimated fair value of open contracts at December 31, 2009
  $ (1,975 )
 
     
Changes in fair values of derivative contracts:
       
Natural gas collars
  $ 4,210  
Crude oil collars
    (14,276 )
Settlements of derivative contracts that were open at December 31, 2009:
       
Natural gas collars
  $ (3,578 )
Crude oil collars
    468  
 
     
Estimated fair value of open contracts at December 31, 2010
  $ (15,151 )
 
     

 

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Derivative Instruments and Hedging Activities
Our primary commodity market risk exposure is to changes in the prices that we receive for our crude oil and natural gas production. The market prices for crude 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 crude 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 2010, we were party to crude oil costless collars, crude oil swaps, crude oil puts, natural gas costless collars, natural gas three-way costless collars, and natural gas 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 crude 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 also use put options to establish floor prices (purchased put option) on our anticipated future crude oil production. We pay an initial premium when we enter into these option arrangements. These contracts are settled monthly. 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.
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. All hedges are accounted for using mark-to-market accounting.
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. Crude 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, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.
                         
    Crude     Purchased     Written  
    Oil     Put     Call  
Settlement Period   (Bbls)     (Nymex)     (Nymex)  
Crude Oil Costless Collars
                       
01/01/11 – 12/31/11
    84,000     $ 65.00     $ 88.25  
01/01/11 – 12/31/11
    60,000     $ 60.00     $ 97.25  
01/01/11 – 12/31/11
    60,000     $ 65.00     $ 108.00  
01/01/11 – 06/30/11
    18,000     $ 65.00     $ 97.50  
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 – 12/31/11
    12,000     $ 75.00     $ 103.00  
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  
01/01/11 – 07/31/11
    21,000     $ 70.00     $ 94.80  
01/01/11 – 03/31/11
    9,000     $ 75.00     $ 93.50  
07/01/11 – 12/31/11
    12,000     $ 75.00     $ 95.15  
01/01/11 – 12/31/11
    36,000     $ 75.00     $ 104.30  
01/01/12 – 06/30/12
    60,000     $ 75.00     $ 106.90  
01/01/11 – 02/28/11
    8,000     $ 75.00     $ 103.50  
03/01/11 – 04/30/11
    16,000     $ 75.00     $ 104.50  
01/01/11 – 12/31/11
    36,000     $ 65.00     $ 100.00  
01/01/11 – 07/31/12
    289,000     $ 65.00     $ 97.20  
01/01/11 – 07/31/12
    289,000     $ 65.00     $ 98.55  
01/01/11 – 07/31/12
    289,000     $ 65.00     $ 100.00  
01/01/11 – 07/31/12
    289,000     $ 65.00     $ 100.40  
03/01/11 – 08/31/11
    46,000     $ 65.00     $ 94.80  
09/01/11 – 12/31/11
    61,000     $ 65.00     $ 97.40  
01/01/12 – 06/30/12
    182,000     $ 65.00     $ 99.25  
09/01/11 – 12/31/11
    61,000     $ 65.00     $ 99.00  
03/01/11 – 08/31/11
    46,000     $ 65.00     $ 96.75  
01/01/12 – 06/30/12
    91,000     $ 65.00     $ 101.00  
01/01/12 – 06/30/12
    182,000     $ 65.00     $ 100.75  
01/01/12 – 06/30/12
    91,000     $ 65.00     $ 102.75  
07/01/12 – 07/31/12
    62,000     $ 65.00     $ 102.25  
05/01/11 – 12/31/11
    122,500     $ 65.00     $ 100.00  
07/01/12 – 07/31/12
    31,000     $ 65.00     $ 105.25  
05/01/11 – 12/31/11
    122,500     $ 65.00     $ 106.50  
01/01/11 – 02/28/11
    29,500     $ 65.00     $ 98.75  
01/01/11 – 12/31/11
    182,500     $ 65.00     $ 100.00  
01/01/12 – 06/30/12
    136,500     $ 65.00     $ 107.25  
07/01/12 – 09/30/12
    92,000     $ 65.00     $ 109.40  
08/01/12 – 09/30/12
    61,000     $ 65.00     $ 110.25  
08/01/12 – 09/30/12
    61,000     $ 65.00     $ 112.00  
10/01/12 – 10/31/12
    62,000     $ 65.00     $ 112.65  
01/01/12 – 07/31/12
    106,500     $ 65.00     $ 110.00  
01/01/11 – 06/30/11*
    90,500     $ 65.00     $ 95.00  
01/01/11 – 06/30/11*
    90,500     $ 65.00     $ 97.50  
08/01/12 – 10/31/12
    92,000     $ 70.00     $ 110.90  
10/01/12 – 10/31/12
    31,000     $ 70.00     $ 110.90  
08/01/12 – 10/31/12
    92,000     $ 70.00     $ 106.50  
11/01/12 – 12/31/12
    122,000     $ 70.00     $ 107.70  
11/01/12 – 12/31/12
    122,000     $ 70.00     $ 110.00  
     
*   Crude oil collar was completed in two phases. First, the put option (floor) was purchased. Subsequently, the call option (ceiling) was sold thereby converting the position into a collar.

 

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    Crude     Purchased  
    Oil     Put  
Settlement Period   (Bbls)     (Nymex)  
Crude Oil Floors
               
01/01/12 – 06/30/12
    91,000     $ 65.00  
01/01/12 – 06/30/12
    91,000     $ 65.00  
01/01/12 – 06/30/12
    45,500     $ 65.00  
01/01/12 – 06/30/12
    45,500     $ 65.00  
                         
    Natural     Purchased     Written  
    Gas     Put     Call  
Settlement Period   (MMbtu)     (Nymex)     (Nymex)  
Natural Gas Costless Collars
                       
01/01/11 – 03/31/11
    120,000     $ 6.50     $ 8.25  
01/01/11 – 03/31/11
    210,000     $ 6.40     $ 7.80  
01/01/11 – 12/31/11
    360,000     $ 5.75     $ 7.65  
01/01/11 – 12/31/11
    480,000     $ 5.75     $ 7.40  
04/01/11 – 12/31/11
    360,000     $ 5.00     $ 6.55  
The following table reflects commodity derivative contracts entered into subsequent to December 31, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.
                         
    Crude     Purchased     Written  
    Oil     Put     Call  
Settlement Period   (Bbls)     (Nymex)     (Nymex)  
Crude oil Costless Collars
                       
07/01/11 – 12/31/11**
    276,000     $ 65.00     $ 100.00  
08/01/12 – 10/31/12
    276,000     $ 75.00     $ 112.50  
11/01/12 – 12/31/12
    244,000     $ 75.00     $ 112.50  
07/01/12 – 07/31/12
    62,000     $ 75.00     $ 114.00  
01/01/13 – 02/28/13
    118,000     $ 75.00     $ 113.05  
01/01/13 – 03/31/13
    180,000     $ 80.00     $ 120.00  
03/01/13 – 03/31/13
    62,000     $ 80.00     $ 120.00  
                 
    Crude     Purchased  
    Oil     Put  
Settlement Period   (Bbls)     (Nymex)  
Crude Oil Floors
               
07/01/12 – 12/31/12
    276,000     $ 80.00  
     
**   Crude oil collar was completed in two phases. First, the put option (floor) was purchased prior to December 31, 2010. Subsequently, the call option (ceiling) was sold in January 2011 thereby converting the position into a collar.
Interest Rate Risk
At December 31, 2010, we had $300 million of long term debt, all of which was fixed rate. Our fixed rate long-term debt consists entirely of our $300 million 8 3/4% Senior Notes due 2018.
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, 2010, 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, 2010, 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, 2010, 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 have been 2.82%. A 10% increase in the Eurodollar rate would equal approximately three basis points. Such an increase in the Eurodollar rate would change our annual interest expense by approximately $33,000, assuming amounts borrowed under our Senior Credit Facility equaled our total potential borrowing base of $110 million as of December 31, 2010. At year-end 2010, we had no amounts outstanding under our Senior Credit Facility.

 

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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, 2010, 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 in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework in Internal Control — Integrated Framework issued by the COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2010.
The effectiveness of our internal control over financial reporting as of December 31, 2010 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 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.   Other Information
None.

 

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PART III
Item 10.   Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated by reference to the 2011 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.
Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to our 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 2011 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.
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 2011 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010. 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 2011 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.
Item 14.   Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2010.
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.

 

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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 crude 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 crude 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 crude 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 crude oil or natural gas in sufficient quantities to justify completion of an crude oil or gas well.
Early 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.
Exploratory Well. A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of crude oil or gas in another reservoir, or to extend a known reservoir.
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 crude 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.
Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
    MBoe. One thousand barrels of crude oil equivalent.
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

 

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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.
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%.
Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce crude oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

 

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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 28, 2011.
         
  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 28, 2011.
     
/s/ BEN M. BRIGHAM
 
Ben M. Brigham
  Chief Executive Officer, President and Chairman of the Board
(Principal Executive Officer)
 
   
/s/ EUGENE B. SHEPHERD, JR.
 
Eugene B. Shepherd, Jr.
  Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
 
   
/s/ DAVID T. BRIGHAM
 
David T. Brigham
  Executive Vice President — Land and Administration and Director
 
   
/s/ HAROLD D. CARTER
 
Harold D. Carter
  Director 
 
   
/s/ STEPHEN C. HURLEY
 
Stephen C. Hurley
  Director 
 
   
/s/ STEPHEN P. REYNOLDS
 
Stephen P. Reynolds
  Director 
 
   
/s/ HOBART A. SMITH
 
Hobart A. Smith
  Director 
 
   
/s/ SCOTT W. TINKER
 
Scott W. Tinker
  Director 

 

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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, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, 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, 2010, based on criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
(signed) KPMG LLP
Dallas, Texas
March 1, 2011

 

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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, 2010, based on criteria established in Internal Control — Integrated Framework issued 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, included in the accompanying Management’s Report on 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, 2010, based on criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Brigham Exploration Company and subsidiaries as of December 31, 2010 and 2009, 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, 2010, and our report dated March 1, 2011 expressed an unqualified opinion on those consolidated financial statements.
(signed) KPMG LLP
Dallas, Texas
March 1, 2011

 

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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
                 
    December 31,  
    2010     2009  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 23,743     $ 40,781  
Accounts receivable
    70,368       21,194  
Short term investments
    223,991       80,093  
Inventory
    34,959       14,087  
Other current assets
    7,796       2,284  
 
           
Total current assets
    360,857       158,439  
 
           
Oil and natural gas properties, using the full cost method of accounting
               
Proved
    910,114       619,920  
Unproved
    182,933       76,309  
Accumulated depletion
    (423,691 )     (365,496 )
 
           
 
    669,356       330,733  
 
           
Other property and equipment, net
    42,837       3,025  
Deferred loan fees
    9,064       5,213  
Other noncurrent assets
    3,287       846  
 
           
Total assets
  $ 1,085,401     $ 498,256  
 
           
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 50,023     $ 19,251  
Royalties payable
    42,155       8,268  
Accrued drilling costs
    61,067       15,498  
Participant advances received
    3,037       6,949  
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  
Derivative liabilities
    9,442       2,405  
Other current liabilities
    10,821       5,301  
 
           
Total current liabilities
    176,545       67,773  
 
           
Senior Notes
    300,000       158,968  
Deferred income taxes
    1,088        
Other noncurrent liabilities
    14,498       7,232  
Commitments and contingencies (Note 10)
               
Stockholders’ equity:
               
Common stock, $.01 par value, 180 million shares authorized, 116,564,182 and 99,593,075 shares issued and 116,289,180 and 99,351,825 shares outstanding at December 31, 2010 and 2009, respectively
    1,166       996  
Additional paid-in capital
    765,326       479,077  
Treasury stock, at cost; 275,002 and 241,250 shares at December 31, 2010 and 2009, respectively
    (2,657 )     (2,133 )
Accumulated other comprehensive income (loss)
    (9 )     (205 )
Retained earnings (deficit)
    (170,556 )     (213,452 )
 
           
Total stockholders’ equity
    593,270       264,283  
 
           
Total liabilities and stockholders’ equity
  $ 1,085,401     $ 498,256  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

 

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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
                         
    Year Ended December 31,  
    2010     2009     2008  
Revenues:
                       
Oil and natural gas sales
  $ 179,279     $ 68,192     $ 125,108  
Gain (loss) on derivatives, net
    (10,066 )     2,064       2,548  
Support infrastructure
    489              
Other revenue
    20       88       132  
 
                 
 
    169,722       70,344       127,788  
 
                 
Costs and expenses:
                       
Lease operating
    18,651       14,655       12,363  
Production taxes
    17,313       5,098       5,374  
Support infrastructure
    50              
General and administrative
    12,943       9,243       9,557  
Depletion of oil and natural gas properties
    58,195       32,054       53,498  
Impairment of oil and natural gas properties
          114,781       237,180  
Depreciation and amortization
    1,704       812       629  
Accretion of discount on asset retirement obligations
    422       421       361  
Loss on inventory valuation
          2,196        
 
                 
 
    109,278       179,260       318,962  
 
                 
Operating income (loss)
    60,444       (108,916 )     (191,174 )
 
                 
Other income (expense):
                       
Interest income
    1,198       578       191  
Interest expense, net
    (11,448 )     (16,431 )     (14,495 )
Loss on early redemption of Senior Notes
    (11,308 )            
Other income (expense)
    5,094       1,544       530  
 
                 
 
    (16,464 )     (14,309 )     (13,774 )
 
                 
Income (loss) before income taxes
    43,980       (123,225 )     (204,948 )
Income tax benefit (expense):
                       
Current
                 
Deferred
    (1,084 )     233       42,701  
 
                 
 
    (1,084 )     233       42,701  
 
                 
Net Income (loss)
  $ 42,896     $ (122,992 )   $ (162,247 )
 
                 
 
                       
Net income (loss) per share available to common stockholders:
                       
Basic
  $ 0.39     $ (1.74 )   $ (3.57 )
 
                 
Diluted
  $ 0.38     $ (1.74 )   $ (3.57 )
 
                 
Weighted average common shares outstanding:
                       
Basic
    111,355       70,569       45,441  
Diluted
    113,308       70,569       45,441  
The accompanying notes are an integral part of these consolidated financial statements.

 

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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, 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
                                  (122,992 )     (122,992 )
Tax provisions related to cash flow hedges
                            (205 )           (205 )
Net (gains) losses included in net income
                                         
 
                                                     
Comprehensive income
                                                    (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  
Comprehensive income (loss):
                                                       
Net income (loss)
                                  42,896       42,896  
Unrealized gains (loss) on investments
                            196             196  
Tax benefits (provisions)
                                         
 
                                                     
Comprehensive income (loss)
                                                    43,092  
Issuance of common stock
    16,100       161       277,386                         277,547  
Vesting of restricted stock
    130       1       (1 )                        
Exercise of employee stock options
    741       8       3,876                         3,884  
Repurchases of common stock
                      (524 )                 (524 )
Vesting of share-based payments
                4,988                         4,988  
 
                                         
Balance, December 31, 2010
    116,564     $ 1,166     $ 765,326     $ (2,657 )   $ (9 )   $ (170,556 )   $ 593,270  
 
                                         
The accompanying notes are an integral part of these consolidated financial statements.

 

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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                         
    Year Ended December 31,  
    2010     2009     2008  
Cash flows from operating activities:
                       
Net income (loss)
  $ 42,896     $ (122,992 )   $ (162,247 )
Adjustments to reconcile net income (loss) to cash provided (used) by operating activities:
                       
Depletion of oil and natural gas properties
    58,195       32,054       53,498  
Impairment of oil and natural gas properties
          114,781       237,180  
Depreciation and amortization
    1,704       812       629  
Stock based compensation
    2,676       2,278       1,592  
Amortization of discount and deferred loan fees
    2,025       1,635       1,105  
Loss on early redemption of Senior Notes
    11,308              
Accretion of discount on asset retirement obligations
    422       421       361  
Market value adjustment for derivative instruments
    13,175       7,313       (6,140 )
Deferred income taxes
    1,084       (233 )     (42,701 )
Provision for doubtful accounts
    146       (19 )     17  
Other noncash items
          90       4  
Changes in working capital and other items:
                       
Accounts receivable
    (49,320 )     3,383       (9,966 )
Other current assets
    (4,106 )     803       (6,521 )
Accounts and royalties payable
    64,659       6,363       2,877  
Other current liabilities
    1,608       4,964       500  
Noncurrent assets
    (1,524 )     114       (330 )
Noncurrent liabilities
    (428 )     (17 )     (228 )
 
                 
Net cash provided by operating activities
    144,520       51,750       69,630  
 
                 
Cash flows from investing activities:
                       
Additions to oil and natural gas properties
    (367,245 )     (74,668 )     (178,637 )
Proceeds from sale of oil and natural gas properties
    17,918              
Changes in inventory
    (20,872 )     (7,881 )      
Additions to other property and equipment
    (41,516 )     (2,054 )     (1,472 )
Purchases of short term investments
    (331,624 )     (86,575 )      
Sales of short term investments
    187,922       6,277        
(Increase) decrease in drilling advances paid
    (794 )     (274 )     798  
Changes to restricted cash
          555       (555 )
 
                 
Net cash used by investing activities
    (556,211 )     (164,620 )     (179,866 )
 
                 
Cash flows from financing activities:
                       
Proceeds from issuance of common stock, net of issuance costs
    277,547       261,725        
Proceeds from exercise of employee stock options
    3,884       1,219       2,066  
Proceeds from Senior Notes offering
    300,000              
Redemption of Senior Notes offering
    (168,683 )            
Redemption of Series A Preferred Stock
    (10,101 )            
Repurchases of common stock
    (524 )     (931 )     (348 )
Increase in senior credit facility
                139,500  
Repayment of senior credit facility
          (145,000 )     (4,500 )
Deferred loan fees paid and equity costs
    (7,470 )     (3,405 )     (302 )
 
                 
Net cash provided by financing activities
    394,653       113,608       136,416  
 
                 
Net increase (decrease) in cash and cash equivalents
    (17,038 )     738       26,180  
Cash and cash equivalents, beginning of year
    40,781       40,043       13,863  
 
                 
Cash and cash equivalents, end of year
  $ 23,743     $ 40,781     $ 40,043  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

 

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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 Williston Basin, the Gulf Coast, the Anadarko Basin, and West Texas and Other.
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.
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.

 

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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 barrels of crude oil that was produced in the Williston Basin during operations but not yet sold at year-end in the amount of 46,129 barrels and 16,475 barrels at December 31, 2010 and 2009, respectively. 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 $299,000 and $136,000 at December 31, 2010 and 2009, respectively.
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 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 at December 31, 2008. Under new rules issued by the Securities and Exchange Commission, the estimated future net cash flows for at December 31, 2010 and 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, 2010 and 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 water disposal wells and gathering systems, 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:
         
Support infrastructure wells and gathering systems
  15 years
Furniture and fixtures
  10 years
Machinery and equipment
  3 – 10 years
3-D seismic interpretation workstations and software
  3 years
Pipeyard equipment and improvements
  7 – 15 years
Field general equipment
  3 – 15 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.

 

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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.
Brigham recognizes revenue from its support infrastructure operations, which provide the usage of its oil, natural gas, waste water and fresh water gathering lines. Brigham also provides water disposal services for certain operated wells currently drilling or that have been placed on production. Any intercompany revenues and expenses have been eliminated for financial statement presentation.
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, ceilings 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.

 

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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, 2010, 2009 and 2008 (in thousands):
                         
    2010     2009     2008  
Balance, beginning of year
  $ (205 )   $     $ 115  
Unrealized (gains) losses on investments
    196       (205 )      
Tax benefits (provisions) related to cash flow hedges
                61  
Net (gains) losses included in earnings
                (176 )
 
                 
 
                       
Balance, end of year
  $ (9 )   $ (205 )   $  
 
                 
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.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
New Pronouncements
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 required 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.
3. Property and Equipment
Property and equipment, at cost, are summarized as follows (in thousands):
                 
    December 31,  
    2010     2009  
Oil and natural gas properties
  $ 1,093,047     $ 696,229  
Accumulated depletion
    (423,691 )     (365,496 )
 
           
 
    669,356       330,733  
                 
    December 31,  
    2010     2009  
Other property and equipment:
               
Support infrastructure wells and gathering systems
    32,543        
3-D seismic interpretation workstations and software
    1,627       1,619  
Office furniture and equipment
    3,646       3,307  
Pipeyard equipment and improvements
    3,686       832  
Field general equipment
    6,655       1,739  
Land
    1,264       409  
Accumulated depreciation
    (6,584 )     (4,881 )
 
           
 
    42,837       3,025  
 
           
 
  $ 712,193     $ 333,758  
 
           

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Depletion expense is based on units-of-production. Production volumes used to determine depletion expense were 2,976 MBoe, 1,796 MBoe, and 1,910 MBoe for 2010, 2009, and 2008 respectively. The depletion rate used to calculate depletion expense was $19.56, $17.88, and $28.02 for 2010, 2009, and 2008, 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, 2010, 2009 and 2008 (in thousands):
                         
    Year Ended December 31,  
    2010     2009     2008  
Capitalized certain payroll and other internal costs
  $ 12,552     $ 7,718     $ 7,994  
Capitalized interest costs
    9,770       4,713       4,761  
 
                 
 
  $ 22,322     $ 12,431     $ 12,755  
 
                 
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 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 the 12-month 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.
Based on the 12-month average oil and gas prices for the year ended December 31, 2010 ($4.38 per MMBtu for Henry Hub natural gas and $79.43 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, 2010.
During the second quarter 2010, Brigham sold a portion of its proved developed producing West Texas assets for $14 million with an effective date of January 1, 2010. The proceeds for the sale were applied to reduce the capitalized costs of oil and gas properties
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 per share and received net proceeds of $93.4 million after underwriting fees and offering expenses.
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 per share 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 this equity offering. Brigham issued 837,523 additional shares of common stock and received net proceeds of $8.4 million after underwriting fees and offering expenses.
In April 2010, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 16,100,000 shares of its common stock at a price of $18.00 per share and received net proceeds of approximately $277.5 million after deducting underwriting fees and offering expenses.

 

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Table of Contents

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
5. Senior Credit Facility and Senior Notes
The following table reflects the outstanding balances of the senior credit facility and senior notes for the years ended December 31, 2010 and 2009:
                 
    December 31,  
    2010     2009  
    (In thousands)  
Senior Credit Facility
  $     $  
Senior Notes
    300,000       160,000  
Discount on Senior Notes
          (1,032 )
 
           
Total Debt
  $ 300,000     $ 158,968  
Less: Current Maturities
           
 
           
Total Long-Term Debt
  $ 300,000     $ 158,968  
 
           
Senior Credit Facility
In May 2009, in conjunction with Brigham’s regularly scheduled semi-annual redetermination and Brigham’s common stock offering, the borrowing base was reset to $110 million. 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. Brigham had no borrowings outstanding under its Senior Credit Facility at December 31, 2010 and 2009.
Borrowings under the Senior Credit Facility bear interest, at Brigham’s election, at a base rate (as the term was defined in the Senior Credit Facility) or Eurodollar rate, plus in each case an applicable margin that was reset quarterly (2.5% at December 31, 2010). The applicable interest rate margin varied from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term was 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 was required to pay a commitment fee on the unused portion of its borrowing base (0.50% at December 31, 2010). Borrowings under the Senior Credit Facility were collateralized by substantially all of Brigham’s oil and natural gas properties under first liens.
The Senior Credit Facility contained various covenants, including among other 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 required Brigham to maintain a current ratio (as defined) of at least 1 to 1. The Senior Credit Facility also required Brigham to maintain an interest coverage ratio for the four most recent quarters as of December 31, 2010 of at least 2.5 to 1. The Senior Credit Facility also required Brigham to maintain a net leverage ratio 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, 2010, Brigham was in compliance with all covenants under the Senior Credit Facility.
Subsequent to December 31, 2010, Brigham amended and restated its Senior Credit Facility to provide for revolving credit borrowings up to $600 million, with an initial borrowing base of $325 million. Borrowings under the new Senior Credit Facility cannot exceed its borrowing base, which is determined at least semi-annually. Brigham also extended the maturity of its Senior Credit Facility from July 2012 to February 2016. As part of the new Senior Credit Facility, the requirement to maintain a minimum interest coverage ratio was removed. See Note 16 “Subsequent Events.”
Senior Notes
On September 27, 2010, Brigham issued $300 million of 8 3/4% Senior Notes due October 2018 (collectively the “ 8 3/4% Senior Notes”). The notes were priced at 100% of their face value and are fully and unconditionally guaranteed by Brigham and its wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. Brigham does not have any independent assets or operations.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In connection with the issuance of the 8 3/4% Senior Notes, Brigham tendered for and purchased $154.4 million of its 9 5/8% Senior Notes due 2014 and previously issued in 2006 and 2007 on September 27, 2010. Brigham recorded a $10.9 million loss upon the purchase of the 9 5/8% Senior Notes. Brigham redeemed the remaining $5.6 million of the 9 5/8% Senior Notes on October 8, 2010. Brigham recorded a $360,000 loss upon the redemption of the remaining 9 5/8% Senior Notes.
The indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon the occurrence of certain events of default, the trustee or the holders of the 8 3/4% Senior Notes may declare all outstanding 8 3/4% Senior Notes to be due and payable immediately. The indenture also contains customary restrictions and covenants which could potentially limit Brigham’s flexibility to manage and fund its business. At December 31, 2010, 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, 2010 and 2009 (in thousands, except share amounts):
                                 
    Year Ended     Year Ended  
    December 31, 2010     December 31, 2009  
    Shares     Amounts     Shares     Amounts  
Balance, beginning of year
    505,051     $ 10,101       505,051     $ 10,101  
 
                       
Balance, end of year
        $       505,051     $ 10,101  
 
                       
Brigham had designated 2,250,000 shares of preferred stock as Series A Preferred Stock. The Series A Preferred Stock had a par value of $0.01 per share and a stated value of $20 per share. The Series A Preferred Stock was cumulative and paid dividends quarterly at a rate of 6% per annum of the stated value in cash. The Series A Preferred Stock was set to mature on October 31, 2010 and was 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 did not generally have any voting rights, except for certain approval rights and as required by law.
In June 2010, Brigham exercised its option to redeem all of its Series A mandatorily redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC.
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.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410 during the years ended December 31, 2010 and 2009 (in thousands):
                 
    Year Ended  
    December 31,  
    2010     2009  
Beginning asset retirement obligations
  $ 6,323     $ 5,592  
Liabilities incurred for new wells placed on production
    814       327  
Liabilities settled
    (428 )     (17 )
Revisions to estimates due to sale of oil and gas properties
    (1,208 )      
Accretion of discount on asset retirement obligations
    422       421  
 
           
 
  $ 5,923     $ 6,323  
 
           
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. During 2010, Brigham’s deferred tax asset decreased for federal and state purposes. After testing to determine if the deferred tax assets would meet the more likely than not criteria, Brigham decreased its federal valuation allowance to $62.3 million and its state valuation allowance to $5.2 million.
The total provision for income taxes consists of the following (dollar amounts are in thousands):
                         
    Year Ended December 31,  
    2010     2009     2008  
Current income taxes
  $     $     $  
Deferred income taxes (benefits):
                       
Federal
    14,805       (43,029 )     (71,445 )
State
    1,655       (1,141 )     (5,745 )
Federal and state valuation allowances
    (15,376 )     43,937       34,489  
 
                 
 
  $ 1,084     $ (233 )   $ (42,701 )
 
                 
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,  
    2010     2009     2008  
Tax (benefit) at statutory rate
  $ 15,393     $ (43,129 )   $ (71,732 )
Add the effect of:
                       
Nondeductible expenses, net of tax exempt income
    7       1       6  
Preferred stock dividends
    129       212       212  
Incentive stock options not exercised
    93       26       47  
State income taxes (benefits), net of federal deduction
    1,076       (741 )     (3,734 )
State valuation allowance, net of federal deduction
    (369 )     644       2,455  
Federal valuation allowance
    (15,303 )     42,719       30,002  
Other
    58       35       43  
 
                 
 
  $ 1,084     $ (233 )   $ (42,701 )
 
                 

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The components of deferred income tax assets and liabilities are as follows (dollar amounts are in thousands):
                 
    December 31,  
    2010     2009  
Deferred tax assets
               
Current:
               
Unrealized hedging and other derivative losses
  $ 3,504     $ 913  
State deferred taxes
    381        
Other
    82       36  
 
           
Current
    3,967       949  
 
           
Non-current:
               
Net operating loss carryforwards (NOLs)
    82,394       84,706  
Percentage depletion carryforwards
    4,896       4,433  
Stock compensation
    4,115       3,328  
Asset retirement obligations
    2,073       2,213  
Unrealized derivative losses
    3,100       318  
Other
    784       81  
 
           
Non-current
    97,362       95,079  
 
           
 
    101,329       96,028  
Valuation allowance
    (62,309 )     (77,153 )
 
           
Total net deferred tax assets
    39,020       18,875  
 
           
 
               
Deferred tax liabilities
               
Current:
               
Unrealized derivative gains
  $ (1,630 )   $ (403 )
 
           
Current
    (1,630 )     (403 )
 
           
Non-current:
               
Depreciable and depletable property
    (36,851 )     (18,392 )
Other
    (539 )     (80 )
 
           
Non-current
    (37,390 )     (18,472 )
 
           
Total net deferred tax liabilities
    (39,020 )     (18,875 )
 
           
Total federal deferred tax asset (liability)
           
Total state deferred tax asset (liability)
    (1,088 )      
 
           
Total deferred tax asset (liability)
  $ (1,088 )   $  
 
           
At December 31, 2010, Brigham has regular U. S. Federal tax NOLs of approximately $249 million available as a deduction against future taxable income. Additionally, Brigham has approximately $234 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 $93.7 million (of which $19.5 million relates to the Williston Basin) and a Texas Franchise tax credit carryover of approximately $1.4 million. The decreases 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.

 

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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, 2010, 2009, 2008, and 2007. In addition, Brigham is open to examination for the years 1997 through 2006, 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,  
    2010     2009     2008  
    (In thousands, except per share amounts)  
Basic EPS:
                       
Income (loss) available to common stockholders
  $ 42,896     $ (122,992 )   $ (162,247 )
 
                 
Weighted average common shares outstanding — basic
    111,355       70,569       45,441  
 
                 
Basic EPS:
                       
Income (loss) available to common stockholders
  $ 0.39     $ (1.74 )   $ (3.57 )
 
                 
 
                       
Diluted EPS:
                       
Income (loss) available to common stockholders — diluted
  $ 42,896     $ (122,992 )   $ (162,247 )
 
                 
Common shares outstanding
    111,355       70,569       45,441  
Effect of dilutive securities:
                       
Stock options and restricted stock
    1,953              
 
                 
Potentially dilutive common shares
    1,953              
 
                 
Adjusted common shares outstanding — diluted
    113,308       70,569       45,441  
 
                 
Diluted EPS:
                       
Income (loss) available to common stockholders
  $ 0.38     $ (1.74 )   $ (3.57 )
 
                 
At December 31, 2010, 2009, and 2008, potential dilution of approximately 1.0 million, 4.7 million, and 3.7 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 and Brigham is unable to estimate a range of possible loss, 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, 2010, 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.

 

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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 subject to early termination fees for four drilling rigs under a contract that is quarter-to-quarter through May 2011. Brigham is also subject to early termination fees for each day remaining under the primary term for five drilling rigs with renewable terms of a maximum of six months. Additionally, Brigham is subject to early termination fees for each day remaining under the primary term for one drilling rig with a renewable quarterly term. Finally, Brigham is subject to early termination fees for each day remaining under the contract for two walking rigs. Both of these contracts contain three year terms and begin once Brigham receives the rigs. The future minimum annual rental payments under the noncancelable terms of these leases and potential fees for early termination of the drilling rig contracts at December 31, 2010 are as follows (in thousands):
         
2011
    10,225  
2012
    11,191  
2013
    10,950  
2014
    10,950  
2015
    465  
Thereafter
       
 
     
 
  $ 43,781  
 
     
Rental expense for the years ended December 31, 2010, 2009 and 2008 was approximately $789,000, $804,000, and $770,000, 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, 2010, 2009 and 2008:
                         
    2010     2009     2008  
Purchaser A
                21 %
Purchaser B
          31 %     19 %
Purchaser C
    17 %     13 %      
Purchaser D
    19 %            
Purchaser E
    18 %            
Purchaser F
    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 costless collars (purchased put options and written call options), three-way collars (a standard collar plus a sold put below the floor price of the collar), purchased put options, written call options, and swaps. 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.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following tables reflect Brigham’s open commodity derivative contracts at December 31, 2010, 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 – 03/31/11
    120,000             $ 6.50     $ 8.25  
01/01/11 – 03/31/11
    210,000             $ 6.40     $ 7.80  
01/01/11 – 12/31/11
    360,000             $ 5.75     $ 7.65  
01/01/11 – 12/31/11
    480,000             $ 5.75     $ 7.40  
04/01/11 – 12/31/11
    360,000             $ 5.00     $ 6.55  
Oil Costless Collars
                               
01/01/11 – 07/31/12
            289,000     $ 65.00     $ 97.20  
01/01/11 – 07/31/12
            289,000     $ 65.00     $ 98.55  
01/01/11 – 07/31/12
            289,000     $ 65.00     $ 100.40  
01/01/11 – 07/31/12
            289,000     $ 65.00     $ 100.00  
01/01/11 – 02/28/11
            29,500     $ 65.00     $ 98.75  
01/01/11 – 02/28/11
            10,000     $ 70.00     $ 92.00  
01/01/11 – 02/28/11
            8,000     $ 75.00     $ 103.50  
01/01/11 – 03/31/11
            9,000     $ 75.00     $ 93.50  
01/01/11 – 06/30/11
            18,000     $ 65.00     $ 97.50  
01/01/11 – 06/30/11
            24,000     $ 70.00     $ 92.50  
01/01/11 – 07/31/11
            21,000     $ 70.00     $ 94.80  
01/01/11 – 12/31/11
            84,000     $ 65.00     $ 88.25  
01/01/11 – 12/31/11
            60,000     $ 60.00     $ 97.25  
01/01/11 – 12/31/11
            60,000     $ 65.00     $ 108.00  
01/01/11 – 12/31/11
            48,000     $ 70.00     $ 106.80  
01/01/11 – 12/31/11
            48,000     $ 75.00     $ 102.60  
01/01/11 – 12/31/11
            36,000     $ 65.00     $ 100.00  
01/01/11 – 12/31/11
            36,000     $ 75.00     $ 104.30  
01/01/11 – 12/31/11
            182,500     $ 65.00     $ 100.00  
03/01/11 – 04/30/11
            16,000     $ 75.00     $ 104.50  
03/01/11 – 08/31/11
            46,000     $ 65.00     $ 96.75  
03/01/11 – 08/31/11
            46,000     $ 65.00     $ 94.80  
05/01/11 – 12/31/11
            122,500     $ 65.00     $ 100.00  
05/01/11 – 12/31/11
            122,500     $ 65.00     $ 106.50  
07/01/11 – 09/30/11
            9,000     $ 70.00     $ 95.00  
07/01/11 – 12/31/11
            12,000     $ 75.00     $ 103.00  
07/01/11 – 12/31/11
            12,000     $ 75.00     $ 95.15  
09/01/11 – 12/31/11
            61,000     $ 65.00     $ 99.00  
09/01/11 – 12/31/11
            61,000     $ 65.00     $ 97.40  
10/01/11 – 12/31/11
            6,000     $ 70.00     $ 96.35  
01/01/12 – 06/30/12
            60,000     $ 75.00     $ 106.90  
01/01/12 – 06/30/12
            182,000     $ 65.00     $ 100.75  
01/01/12 – 06/30/12
            91,000     $ 65.00     $ 101.00  
01/01/12 – 06/30/12
            182,000     $ 65.00     $ 99.25  
01/01/12 – 06/30/12
            91,000     $ 65.00     $ 102.75  
01/01/12 – 06/30/12
            136,500     $ 65.00     $ 107.25  
01/01/12 – 07/31/12
            106,500     $ 65.00     $ 110.00  
07/01/12 – 07/31/12
            62,000     $ 65.00     $ 102.25  
07/01/12 – 07/31/12
            31,000     $ 65.00     $ 105.25  
07/01/12 – 09/30/12
            92,000     $ 65.00     $ 109.40  
08/01/12 – 09/30/12
            61,000     $ 65.00     $ 110.25  
08/01/12 – 09/30/12
            61,000     $ 65.00     $ 112.00  
08/01/12 – 10/31/12
            92,000     $ 70.00     $ 110.90  
08/01/12 – 10/31/12
            92,000     $ 70.00     $ 106.50  
10/01/12 – 10/31/12
            62,000     $ 65.00     $ 112.65  
10/01/12 – 10/31/12
            31,000     $ 70.00     $ 110.90  
11/01/12 – 12/31/12
            122,000     $ 70.00     $ 107.70  
11/01/12 – 12/31/12
            122,000     $ 70.00     $ 110.00  

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                 
    Natural             Purchased     Written  
    Gas     Oil     Put     Call  
Settlement Period   (MMBTU)     (Barrels)     Nymex     Nymex  
Crude Oil Calls
                               
01/01/11 – 06/30/11
            90,500             $ 95.00  
01/01/11 – 06/30/11
            90,500             $ 97.50  
Crude Oil Puts
                               
01/01/11 – 06/30/12
            273,500     $ 65.00          
01/01/11 – 06/30/12
            273,500     $ 65.00          
07/01/11 – 06/30/12
            91,500     $ 65.00          
07/01/11 – 06/30/12
            91,500     $ 65.00          
The following tables reflect commodity derivative contracts entered subsequent to December 31, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.
                                 
    Natural             Purchased     Written  
    Gas     Oil     Put     Call  
Settlement Period   (MMBTU)     (Barrels)     Nymex     Nymex  
Oil Costless Collars
                               
07/01/12 – 07/31/12
            62,000     $ 75.00     $ 114.00  
08/01/12 – 10/31/12
            276,000     $ 75.00     $ 112.50  
11/01/12 – 12/30/12
            244,000     $ 75.00     $ 112.50  
01/01/13 – 02/28/13
            118,000     $ 75.00     $ 113.05  
01/01/13 – 03/31/13
            180,000     $ 80.00     $ 120.00  
03/01/13 – 03/31/13
            62,000     $ 80.00     $ 120.00  
Crude Oil Calls
                               
07/01/11 – 12/31/11
            276,000             $ 100.00  
Crude Oil Puts
                               
07/01/12 – 12/31/12
            276,000     $ 80.00          
Additional Disclosures about Derivative Instruments and Hedging Activities
At December 31, 2010 and 2009, Brigham had derivative financial instruments under FASB ASC 815 recorded on the consolidated balance sheet as set forth below:
                     
        Dec 31, 2010     Dec 31, 2009  
        Estimated     Estimated  
Type of Contract   Balance Sheet Location   Fair Value     Fair Value  
        (in thousands)     (in thousands)  
Derivatives Not Designated as Hedging Instruments
                   
 
                   
Derivative Assets:
                   
Natural gas and oil contracts
  Other current assets   $ 2,557     $ 1,152  
Natural gas and oil contracts
  Other non-current assets     309       186  
 
               
Total Derivative Assets
      $ 2,866     $ 1,338  
 
                   
Derivative Liabilities:
                   
Natural gas and oil contracts
  Derivative liabilities — current   $ (9,442 )   $ (2,405 )
Natural gas and oil contracts
  Other non-current liabilities     (8,575 )     (909 )
 
               
Total Derivative Liabilities
      $ (18,017 )   $ (3,314 )

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the three years ended December 31, 2010 and 2009, the effect on income in the consolidated statement of operations for derivative financial instruments under FASB ASC 815 was as follows:
                     
        Year     Year  
        Ended     Ended  
        Dec 31, 2010     Dec 31, 2009  
    Statement of Operations   Amount of     Amount of  
Type of Contract   Location of Gain (Loss)   Gain (Loss)     Gain (Loss)  
        (in thousands)     (in thousands)  
Derivatives Not Designated as Hedging Instruments
                   
 
                   
Natural gas contracts
  Gain (loss) on derivatives, net   $ 4,210     $ 7,061  
Oil contracts
  Gain (loss) on derivatives, net     (14,276 )     (4,997 )
 
               
 
Total Derivative Gain (loss)
      $ (10,066 )   $ 2,064  
 
                 
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.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As such, 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, 2010 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    December 31,     for Identical Assets     Inputs     Inputs  
Description   2010     (Level 1)     (Level 2)     (Level 3)  
Current derivative liabilities
  $ (9,442 )   $     $ (9,442 )   $  
Other non-current liabilities
    (8,575 )           (8,575 )      
Other current assets
    2,557             2,557        
Other non-current assets
    309             309        
 
                       
 
  $ (15,151 )   $     $ (15,151 )   $  
 
                       
                                 
            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)  
Current derivative liabilities
  $ (2,405 )   $     $ (2,405 )   $  
Other non-current liabilities
    (909 )           (909 )      
Current derivative assets
    1,152             1,152        
Other non-current assets
    186             186        
 
                       
 
  $ (1,976 )   $     $ (1,976 )   $  
 
                       
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, 2010 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    December 31,     for Identical Assets     Inputs     Inputs  
Description   2010     (Level 1)     (Level 2)     (Level 3)  
Other non-current liabilities
    (5,923 )                 (5,923 )
 
                       
 
  $ (5,923 )   $     $     $ (5,923 )
 
                       
                                 
            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 )
 
                       

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
See Note 7 for a rollforward of the asset retirement obligation.
As of December 31, 2010 and 2009, Brigham held $224.0 and $80.1 million, respectively, of investments in certificates of deposit, corporate debt, and government securities. The fair value of the investments is reflected on the balance sheet as detailed below.
                                 
            Fair Value Measurements at December 31, 2010 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    December 31,     for Identical Assets     Inputs     Inputs  
Description     2010   (Level 1)     (Level 2)     (Level 3)  
Investments
    223,991       223,991              
 
                       
 
  $ 223,991     $ 223,991     $     $  
 
                       
 
            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  
Description of   Fair     Gains     Fair     Gains     Fair     Gains  
Securities   Value     (Losses)     Value     (Losses)     Value     (Losses)  
Certificates of deposit
  $ 241     $ 1     $     $     $ 241     $ 1  
Corporate debt
    183,391       68       26,324       (86 )     209,715       (18 )
Government securities
    14,035       8                   14,035       8  
 
                                   
Total
  $ 197,667     $ 77     $ 26,324     $ (86 )   $ 223,991     $ (9 )
 
                                   
The cost basis of Brigham’s investments in certificates of deposit, corporate bonds and notes, and government securities (in thousands) is $240, $212,464, and $14,103, respectively
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, 2010     December 31, 2009  
    (in millions)     (in millions)  
    Carrying     Fair     Carrying     Fair  
    Amount     Value     Amount     Value  
Senior Notes
  $ 300,000     $ 325,500     $ 160,000     $ 160,000  
Series A Preferred Stock
  $     $     $ 10,101     $ 10,166  
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.

 

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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 twelve months ended December 31, 2010, 2009, and 2008 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, 2010:
                         
    2010     2009     2008  
Risk-free interest rate
    2.46 %     2.64 %     2.78 %
Expected life (in years)
    5.0       5.0       5.0  
Expected volatility
    81 %     78 %     56 %
Expected dividend yield
                 
Weighted average fair value per share of stock compensation
  $ 12.38     $ 3.41     $ 2.52  
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, 2010 and 2009.
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,  
    2010     2009     2008  
Pre-tax stock based compensation expense
  $ 4,992     $ 4,282     $ 2,926  
Capitalized stock based compensation
    (2,316 )     (2,003 )     (1,334 )
Tax benefit
    (937 )     (798 )     (557 )
 
                 
Stock based compensation expense, net
  $ 1,739     $ 1,481     $ 1,035  
 
                 
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, 2010, approximately 1,746,015 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.
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 516,800 remain available for grant under the director stock option plan.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes option activity under the incentive plans for each of the three years ended December 31, 2010:
                                                 
    2010     2009     2008  
            Weighted-             Weighted-             Weighted-  
            Average             Average             Average  
            Exercise             Exercise             Exercise  
    Shares     Price     Shares     Price     Shares     Price  
Options outstanding at beginning of year
    4,170,137     $ 5.14       3,128,651     $ 7.00       3,046,166     $ 7.14  
Granted
    1,029,500     $ 19.27       2,846,975     $ 4.80       534,000     $ 5.08  
Forfeited or cancelled
    (22,200 )   $ 4.32       (1,549,675 )   $ 8.30       (65,300 )   $ 7.79  
Exercised
    (741,037 )   $ 5.20       (255,814 )   $ 4.89       (386,215 )   $ 5.35  
 
                                         
Options outstanding at end of year
    4,436,400     $ 8.41       4,170,137     $ 5.14       3,128,651     $ 7.00  
 
                                         
Options exercisable at end of year
    675,620     $ 5.83       691,962     $ 6.17       1,954,851     $ 7.17  
 
                                         
The weighted-average grant-date fair value of share options granted during the years ended December 31, 2010, 2009, and 2008 was $12.38, $3.41, and $2.52, respectively. The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008 was $10.2 million, $1.5 million, and $2.4 million, respectively.
The following table summarizes information about stock options outstanding at December 31, 2010:
                                                 
    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   2010     Life     Price     2010     Life     Price  
$2.20 to $3.11
    1,089,000     8.2 years     $ 2.24       137,000     8.1 years     $ 2.26  
5.08 to 5.08
    371,320     4.8 years     $ 5.08       101,320     4.8 years     $ 5.08  
5.96 to 6.23
    1,599,580     8.0 years     $ 5.98       301,300     6.7 years     $ 6.02  
7.22 to 8.84
    111,000     3.9 years     $ 7.52       42,000     3.5 years     $ 7.47  
8.93 to 13.86
    236,000     6.5 years     $ 11.66       94,000     3.0 years     $ 10.47  
14.43 to 16.85
    62,000     9.4 years     $ 15.24                 $  
18.36 to 27.15
    967,500     9.3 years     $ 19.53                 $  
 
                                           
2.20 to 27.15
    4,436,400     7.9 years     $ 8.41       675,620     6.0 years     $ 5.83  
 
                                           
The aggregate intrinsic value of options outstanding and exercisable at December 31, 2010 was $83.5 million and $15.2 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 2010 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, 2010. 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 is being recognized over the five year vesting period of the new options.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of December 31, 2010 there was approximately $15.6 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 4.8 years.
Restricted Stock
During the year ended December 31, 2010, Brigham issued 105,363, restricted shares of common stock as compensation to officers and employees of Brigham. Restrictions lapsed on 20,363 of these shares in 2010, resulting in recognition of approximately $334,000 in compensation expense. Restrictions on 85,000 restricted shares lapse in 2015. As of December 31, 2010, there was approximately $2 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4 years. Brigham has assumed a 3% 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, 2010     December 31, 2009  
            Weighted-             Weighted-  
    Number of     Average     Number of     Average  
    Shares     Price     Shares     Price  
Restricted Stock Awards:
                               
Restricted shares outstanding at the beginning of the year
    556,990     $ 7.04       593,260     $ 7.58  
Shares granted
    105,363     $ 14.45       342,574     $ 4.99  
Lapse of restrictions
    (130,070 )   $ 7.71       (377,844 )   $ 6.02  
Forfeitures
    (1,400 )   $ 5.26       (1,000 )   $ 9.49  
 
                           
Restricted shares outstanding at the end of the year
    530,883     $ 8.35       556,990     $ 7.04  
 
                           
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 2010, 2009, and 2008, Brigham provided a base match equal to 25% of eligible employee contributions. Based on attainment of performance goals established at the beginning of each fiscal year, Brigham matched an additional 200% of eligible employee contributions made during 2010. There was no additional match for employee contributions made during 2009 and 2008. Brigham contributed approximately $1.7 million, $143,000, and $159,000 to the 401(k) plan for the years ended December 31, 2010, 2009 and 2008, respectively, to match eligible contributions by employees.
15. Related Party Transactions
During the years ended December 31, 2010, 2009 and 2008, Brigham incurred costs of approximately $9.7 million, $2.3 million, and $7.3 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, 2010, 2009 and 2008, Brigham had a liability recorded in accounts payable of approximately $1,000, $30,000, and $129,000, 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. Fees paid for these services by Brigham were approximately $30,000 for the year ended December 31, 2008. During each of the years ended December 31, 2009 and 2008, additional payments of approximately $2,500 and $12,000, respectively, were made for the reimbursement of certain expenses. At December 31, 2010, 2009 and 2008, there were no payables related to these services recorded by Brigham.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 2010, 2009 and 2008 were $2 million, $420,000, and $1.1 million, respectively. At December 31, 2010, 2009 and 2008, Brigham owed the service company approximately $219,000, $102,000, and $76,000, respectively.
During the year ended December 31, 2010, Brigham incurred costs of $68,000 for design and development services related to the Brigham regional office located in Williston, North Dakota. The services are being provided by Decker Design & Development PC. The owner is married to a sister of Brigham’s Chairman, President and Chief Executive Officer and its Executive Vice President — Land and Administration. At December 31, 2010, Brigham had a liability recorded in accounts payable of approximately $3,000 related to the services provided by this company.
16. Subsequent Events
During February 2011, Brigham amended and restated its Senior Credit Facility to provide for revolving credit borrowings up to $600 million, with an initial borrowing base of $325 million. Borrowings under the new Senior Credit Facility cannot exceed its borrowing base, which is determined at least semi-annually. Brigham also extended the maturity of its new Senior Credit Facility from July 2012 to February 2016.
17. Supplemental Cash Flow Information
Supplemental cash flow information consists of the following (in thousands):
                         
    Year Ended December 31,  
    2010     2009     2008  
Cash paid for interest, net of capitalized amounts
  $ 4,726     $ 14,545     $ 12,382  
Noncash investing and financing activities:
                       
Capitalized asset retirement obligations
    814       327       412  
Accrued drilling costs
    45,569       (4,270 )     4,927  
Capitalized stock compensation
    2,316       2,003       1,334  
18. Other Assets and Liabilities
Other current assets consist of the following (in thousands):
                 
    December 31  
    2010     2009  
Prepayments
  $ 2,490     $ 767  
Derivative assets
    2,557       1,152  
Other
    2,749       365  
 
           
 
  $ 7,796     $ 2,284  
 
           
Other current liabilities consist of the following (in thousands):
                 
    December 31  
    2010     2009  
Accrued interest
  $ 6,971     $ 2,660  
Other accrued liabilities
    3,850       2,641  
 
           
 
  $ 10,821     $ 5,301  
 
           

 

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BRIGHAM EXPLORATION 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,  
    2010     2009     2008  
Costs incurred for the year:
                       
Exploration (including geological and geophysical costs)
  $ 20,906     $ 10,566     $ 43,229  
Property acquisition
    121,058       15,416       35,299  
Development
    273,158       54,261       110,155  
 
                 
 
  $ 415,122     $ 80,243     $ 188,683  
 
                 
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, 2010 by year incurred.
                                         
    December 31,     Prior        
    2010     2009     2008     Years     Total  
Property acquisition
  $ 79,308     $ 5,680     $ 11,851     $ 2,775     $ 99,614  
Exploration (including geological and geophysical costs)
    1,679       37       3,256       13,146       18,118  
Drilling
    50,981                         50,981  
Capitalized interest
    7,876       3,902       1,902       540       14,220  
 
                             
Total
  $ 139,844     $ 9,619     $ 17,009     $ 16,461     $ 182,933  
 
                             

 

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BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) — (Continued)
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.
Oil and Natural Gas Reserve Data
The following tables present estimates of Brigham’s proved oil and natural gas reserves prepared by independent petroleum consultants. 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, 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
    2,055       (28,742 )
Extensions, discoveries and other additions
    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  
 
           
Revisions of previous estimates (a)
    3,588       (856 )
Extensions, discoveries and other additions (b)
    34,523       27,045  
Purchase of mineral in place
    219       211  
Sales of mineral in place
    (528 )     (412 )
Production
    (2,216 )     (4,562 )
 
           
Proved reserves at December 31, 2010
    52,209       87,825  
 
           
 
               
Proved developed reserves at December 31:
               
2007
    3,321       49,367  
2008
    3,583       41,928  
2009
    5,342       29,178  
2010
    17,522       36,537  
     
(a)   Revisions of previous estimates include performance and technical revisions of 3,619 MBoe, economic revisions of 895 MBoe, interest trades of (255) MBoe, and elimination of PUD reserves that will not be developed within 5 years of (813) MBoe.
 
(b)   Extensions, discoveries and other additions include discoveries and associated PUD’s of 39,030 MBoe, primarily in the Williston Basin.
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.

 

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BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) — (Continued)
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 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, 2010 and 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.
                         
    December 31,  
    2010     2009     2008  
Future cash inflows
  $ 4,233,003     $ 1,158,260     $ 899,745  
Future production costs
    (1,117,690 )     (330,837 )     (206,640 )
Future development costs
    (770,356 )     (266,733 )     (160,304 )
Future income tax expense
    (619,145 )     (32,493 )     (32,152 )
 
                 
Future net cash inflows
    1,725,812       528,197       500,649  
10% annual discount for estimated timing of cash flows
    (859,699 )     (281,721 )     (221,353 )
 
                 
Standardized measure of discounted future net cash flows
  $ 866,113     $ 246,476     $ 279,296  
 
                 
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, 2010
  $ 79.43     $ 4.38  
December 31, 2009
    61.18     $ 3.87  
December 31, 2008
    44.60     $ 5.71  
Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
                         
    December 31,  
    2010     2009     2008  
Beginning of period
  $ 246,476     $ 279,296     $ 394,514  
Sales of oil and natural gas produced, net of production costs
    (143,169 )     (48,439 )     (107,144 )
Previously estimated development costs incurred during the period
    69,829       16,574       51,494  
Extensions and discoveries
    643,526       75,803       30,175  
Net change of prices and production costs
    213,101       (41,750 )     (184,497 )
Change in future development costs
    (39,841 )     6,874       (28,901 )
Changes in production rates (timing)
    18,296       (17,557 )     (2,201 )
Revisions of previous quantity estimates
    84,417       (41,726 )     (16,436 )
Accretion of discount
    25,430       28,722       49,130  
Change in income taxes
    (234,529 )     99       88,868  
Purchases of reserves in place
    6,688              
Sales of reserves in place
    (9,877 )     (591 )      
Other
    (14,234 )     (10,829 )     4,294  
 
                 
End of period
  $ 866,113     $ 246,476     $ 279,296  
 
                 

 

F-31


Table of Contents

BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION
Quarterly Financial Data (Unaudited)
                                 
    Year Ended December 31, 2010  
    Quarter     Quarter     Quarter     Quarter  
    1     2     3     4  
Revenue
  $ 32,573     $ 44,930     $ 36,610     $ 55,609  
Operating income (loss)
    13,081       19,336       9,364       18,663  
Net income (loss)*
    11,315       18,473       (676 )     13,784  
Net income (loss) per share:
                               
Basic
  $ 0.11     $ 0.16     $ (0.01 )   $ 0.12  
Diluted
  $ 0.11     $ 0.16     $ (0.01 )   $ 0.12  
                                 
    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  
     
*   Net income (loss) includes the impact from the loss on early redemption of Senior Notes in the amount of $10.9 million for the third quarter of 2010. 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 for the first quarter of 2009.

 

F-32


Table of Contents

INDEX TO EXHIBITS
             
Number       Description
           
 
  3.1      
Certificate of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
           
 
  3.2      
Certificates of Amendment of 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, as amended through May 28, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (filed May 28, 2009) and incorporated herein by reference)
           
 
  3.4      
Certificate of Amendment of 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 of 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 (filed 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 Elimination of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed August 9, 2010 (filed as Exhibit 3.7 to Brigham’s Current Report on Form 8-K (filed August 10, 2010) and incorporated herein by reference)
           
 
  4.5      
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)
           
 
  4.6      
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)
           
 
  4.7      
Certificate of Designations of Series C Junior Participating 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)
           
 
  4.8      
Certificate of Elimination of Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham Exploration Company effective March 9, 2010 (filed as Exhibit 3.6 to Brigham’s Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)
           
 
  4.9      
First Supplemental Indenture, dated September 27, 2010, among the Company, the Guarantors and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.16 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
           
 
  4.10      
Indenture, dated September 27, 2010, among the Company, the Guarantors and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.17 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)

 


Table of Contents

             
Number       Description
           
 
  4.11      
Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.18 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
           
 
  4.12      
Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.19 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
           
 
  10.1      
Amended and Restated Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated December 30, 1997 by and among Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings II, L.L.C. (filed as Exhibit 10.1.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated herein by reference)
           
 
  10.2 *    
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)
           
 
  10.3      
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)
           
 
  10.4      
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)
           
 
  10.5      
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)
           
 
  10.6      
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)
           
 
  10.7 *    
Form of the Amended and Restated Indemnity Agreement (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)
           
 
  10.8      
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)
           
 
  10.9      
Third Amendment to the Fourth Amended and Restated Credit Agreement dated as of November 7, 2008 (filed as Exhibit 10.43 to Brigham’s Current Report on Form 8-K (filed November 12, 2008) and incorporated herein by reference)
           
 
  10.10 *    
Amendment to the 1997 Incentive Plan, dated March 9, 2010 (filed as Exhibit 10.46 to Brigham’s Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)
           
 
  10.11 *    
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)

 


Table of Contents

             
Number       Description
           
 
  10.12 *    
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)
           
 
  10.13 *    
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)
           
 
  10.14 *    
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)
           
 
  10.15 *    
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)
           
 
  10.16 *    
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)
           
 
  10.17 *    
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)
           
 
  10.18      
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)
           
 
  10.19 *    
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)
           
 
  10.20      
Fourth Amendment to the Fourth Amended and Restated Credit Agreement dated as of May 13, 2009 (filed as Exhibit 10.43 to Brigham’s Current Report on Form 8-K (filed May 28, 2009) and incorporated herein by reference)
           
 
  10.21      
Fifth Amendment to the Fourth Amended and Restated Credit Agreement dated as of July 24, 2009 (filed as Exhibit 10.45 to Brigham’s Current Report on Form 8-K (filed July 28, 2009) and incorporated herein by reference)
           
 
  10.22 *    
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)
           
 
  10.23 *    
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)
           
 
  10.24 *    
Form of Non-Qualified Stock Option Agreement (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)
           
 
  10.25 *    
Form of Amendment to Non-Qualified Stock Option Agreements (filed as Exhibit 10.5 to Brigham’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated herein by reference)
           
 
  10.26 *    
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)
           
 
  10.27 *    
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)

 


Table of Contents

             
Number       Description
           
 
  10.28      
Sixth Amendment and Consent to the Fourth Amended and Restated Credit Agreement dated as of May 28, 2010 between the Company and the banks named therein (filed as Exhibit 10.47 to Brigham’s Current Report on Form 8-K (filed June 3, 2010) and incorporated herein by reference)
           
 
  10.29      
Registration Rights Agreement, dated September 27, 2010, among the Company, the Guarantors and the Initial Purchasers (filed as Exhibit 4.20 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
           
 
  10.30      
Seventh Amendment to the Fourth Amended and Restated Credit Agreement dated as of September 10, 2010 between the Company and the banks named therein (filed as Exhibit 10.48 to Brigham’s Current Report on Form 8-K (filed September 13, 2010) and incorporated herein by reference)
           
 
  10.31      
Purchase Agreement dated September 16, 2010 among the Company, the Guarantors and the Initial Purchasers. (filed as Exhibit 10.49 to Brigham’s Current Report on Form 8-K (filed September 20, 2010) and incorporated herein by reference)
           
 
  12.1    
Statement Regarding Computation of Ratios
           
 
  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