Item 1B.
Unresolved Staff Comments
None.
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 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.
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
*
Rough Rider drilling participation agreement wells where our working interest is anticipated to increase upon payout.
**
Excludes any days well was down for remediation.
2011 Williston Basin Drilling and Completion Activity / 2011 Capital Budget
*
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.
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
(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.
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.
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).
Drilling Activities
We drilled and completed, or participated in the drilling and completion of, the following wells during the periods indicated.
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.
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.
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.
(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.
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.
Sales Volumes, Prices and Production Costs
The following table sets forth our sales volumes for the Williston Basin.
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.
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.
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.
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.
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.
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.
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
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.
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.
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.
Item 6.
Selected Consolidated Financial Data
This section presents our selected consolidated financial data and should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included in “Item 8. Financial Statements and Supplementary Data.” The selected consolidated financial data in this section is not intended to replace our consolidated financial statements.
We derived the statement of operations data and statement of cash flows data for the years ended December 31, 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.
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.
•
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.
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.
The final determination with respect to our 2011 budgeted expenditures will depend on a number of factors, including:
•
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:
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.
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.
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.
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.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
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.
None.
PART III
Item 10.
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.
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.
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.
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.
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.
Item 15.
Exhibits, Financial Statement Schedules
(a)
1. Consolidated Financial Statements: See Index to Financial Statements on page.
2.
No schedules are required.
The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by reference as part of the annual report.
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to 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.
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.
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.
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
BRIGHAM EXPLORATION COMPANY
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
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
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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.
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:
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.
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.
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):
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.
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):
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):
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.
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:
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.
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):
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.
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):
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):
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):
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):
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.
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.
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.
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):
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:
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.
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.
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables reflect commodity derivative contracts entered subsequent to December 31, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.
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:
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:
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.
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.
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.
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.
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.
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:
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.
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:
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):
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.
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:
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:
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.
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:
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.
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):
18. Other Assets and Liabilities
Other current assets consist of the following (in thousands):
Other current liabilities consist of the following (in thousands):
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):
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.
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.
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.
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.
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:
Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION
Quarterly Financial Data (Unaudited)
*
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.
INDEX TO EXHIBITS
*
Management contract or compensatory plan.

Filed herewith