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Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-34224
Brigham Exploration Company
(Exact name of registrant as specified in its charter)
     
Delaware
(State of other jurisdiction
of incorporation or organization)
  75-2692967
(I.R.S. Employer
Identification No.)
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices) (Zip Code)
(512) 427-3300
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ      No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232 405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes þ      No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large Accelerated Filer þ   Accelerated Filer o   Non-Accelerated Filer o   Smaller Reporting Company o
        (Do not check if smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o      No þ
     
Class   Outstanding
     
Common Stock, par value $.01 per share as of May 2, 2011   117,063,422
 
 

 

 


 

Brigham Exploration Company
First Quarter 2011 Form 10-Q Report
TABLE OF CONTENTS
         
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 Exhibit 10.32
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

 

 


Table of Contents

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
                 
    March 31,     December 31,  
    2011     2010  
 
               
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 20,586     $ 23,743  
Accounts receivable
    88,544       70,368  
Short-term investments
    172,159       223,991  
Inventory
    34,377       34,959  
Other current assets
    7,640       7,796  
 
           
Total current assets
    323,306       360,857  
 
           
Oil and natural gas properties, using the full cost method including Proved, net of accumulated depletion of $442,631 and $423,691
    567,277       486,423  
Unproved
    207,280       182,933  
 
           
 
    774,557       669,356  
 
           
Other property and equipment, net
    47,984       42,837  
Deferred loan fees
    11,899       9,064  
Other noncurrent assets
    3,552       3,287  
 
           
Total assets
  $ 1,161,298     $ 1,085,401  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 51,612     $ 50,023  
Royalties payable
    58,129       42,155  
Accrued drilling costs
    72,671       61,067  
Participant advances received
    4,867       3,037  
Derivative liabilities
    31,610       9,442  
Other current liabilities
    17,858       10,821  
 
           
Total current liabilities
    236,747       176,545  
 
           
 
               
Senior Notes
    300,000       300,000  
 
               
Other noncurrent liabilities
    28,634       15,586  
 
               
Commitments and contingencies (Note 3)
               
 
               
Stockholders’ equity:
               
Common stock, $.01 par value, 180 million shares authorized, 116,659,765 and 116,564,182 shares issued and 116,367,532 and 116,289,180 shares outstanding at March 31, 2011 and December 31, 2010, respectively
    1,168       1,166  
Additional paid-in capital
    766,780       765,326  
Treasury stock, at cost; 292,233 and 275,002 shares at March 31, 2011 and December 31, 2010, respectively
    (3,124 )     (2,657 )
Accumulated other comprehensive income (loss)
    95       (9 )
Retained earnings (deficit)
    (169,002 )     (170,556 )
 
           
Total stockholders’ equity
    595,917       593,270  
 
           
Total liabilities and stockholders’ equity
  $ 1,161,298     $ 1,085,401  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

 

1


Table of Contents

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
                 
    Three Months Ended  
    March 31,  
    2011     2010  
 
Revenues:
               
Oil and natural gas sales
  $ 75,963     $ 28,930  
Gain (loss) on derivatives, net
    (35,958 )     3,634  
Support infrastructure
    594        
Other revenue
    2       9  
 
           
 
    40,601       32,573  
 
           
Costs and expenses:
               
Lease operating
    7,720       4,349  
Production taxes
    7,698       2,508  
Support infrastructure
    190        
General and administrative
    3,382       3,086  
Depletion of oil and natural gas properties
    18,940       9,211  
Depreciation and amortization
    971       233  
Accretion of discount on asset retirement obligations
    110       105  
 
           
 
    39,011       19,492  
 
           
Operating income (loss)
    1,590       13,081  
 
           
Other income (expense):
               
Interest income
    367       453  
Interest expense, net
    (3,378 )     (2,904 )
Other income (expense)
    3,154       685  
 
           
 
    143       (1,766 )
 
           
Income (loss) before income taxes
    1,733       11,315  
 
           
Income tax expense:
               
Current
           
Deferred
    (179 )      
 
           
 
    (179 )      
 
           
 
               
Net income (loss)
  $ 1,554     $ 11,315  
 
           
 
               
Net income (loss) per share available to common stockholders:
               
Basic
  $ 0.01     $ 0.11  
 
           
Diluted
  $ 0.01     $ 0.11  
 
           
 
               
Weighted average shares outstanding:
               
Basic
    116,359       99,444  
 
           
Diluted
    118,522       101,357  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

 

2


Table of Contents

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In thousands)
(Unaudited)
                                                         
                                    Accumulated                
                    Additional             Other             Total  
    Common Stock     Paid In     Treasury     Comprehensive     Retained     Stockholders’  
    Shares     Amounts     Capital     Stock     Income (Loss)     Earnings     Equity  
Balance, December 31, 2010
    116,564     $ 1,166     $ 765,326     $ (2,657 )   $ (9 )   $ (170,556 )   $ 593,270  
Comprehensive income:
                                                       
Net income
                                  1,554       1,554  
Unrealized gains (losses) on investments
                            104             104  
Tax benefit (provisions)
                                         
 
                                                     
Comprehensive income
                                                    1,658  
Issuance of common stock
                                         
Exercises of employee stock options
    10       1       76                         77  
Vesting of restricted stock
    86       1       (1 )                        
Stock based compensation
                1,379                         1,379  
Repurchases of common stock
                      (467 )                 (467 )
 
                                         
 
                                                       
Balance, March 31, 2011
    116,660     $ 1,168     $ 766,780     $ (3,124 )   $ 95     $ (169,002 )   $ 595,917  
 
                                         
The accompanying notes are an integral part of these consolidated financial statements.

 

3


Table of Contents

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Cash flows from operating activities:
               
Net income (loss)
  $ 1,554     $ 11,315  
Adjustments to reconcile net income (loss) to cash provided by operating activities:
               
Depletion of oil and natural gas properties
    18,940       9,211  
Depreciation and amortization
    971       233  
Stock based compensation
    747       427  
Amortization of deferred loan fees and debt issuance costs
    526       506  
Market value and other adjustments for derivative instruments
    36,008       (3,052 )
Accretion of discount on asset retirement obligations
    110       105  
Deferred income taxes
    179        
Other noncash items
          (1 )
Changes in operating assets and liabilities:
               
Accounts receivable
    (18,176 )     (11,122 )
Other current assets
    (759 )     212  
Accounts payable
    1,589       5,874  
Royalties payable
    15,974       6,784  
Participant advances received
    1,830       1,057  
Other current liabilities
    7,037       4,416  
Other noncurrent assets and liabilities
    (319 )     8  
 
           
Net cash provided by operating activities
    66,211       25,973  
 
           
 
               
Cash flows from investing activities:
               
Additions to oil and natural gas properties
    (111,727 )     (39,360 )
Changes to inventory
    276       (275 )
Purchases of short term investments
          (22,839 )
Sales of short term investments
    51,936       19,663  
Additions to other property and equipment
    (6,118 )     (273 )
Decrease (increase) in drilling advances paid
    108       174  
 
           
Net cash provided (used) by investing activities
    (65,525 )     (42,910 )
 
           
 
               
Cash flows from financing activities:
               
Deferred loan fees paid and equity costs
    (3,453 )     (8 )
Proceeds from exercise of employee stock options
    77       844  
Repurchases of common stock
    (467 )     (204 )
 
           
Net cash provided (used) by financing activities
    (3,843 )     632  
 
           
Net increase (decrease) in cash and cash equivalents
    (3,157 )     (16,305 )
Cash and cash equivalents, beginning of year
    23,743       40,781  
 
           
Cash and cash equivalents, end of period
  $ 20,586     $ 24,476  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

 

4


Table of Contents

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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. Basis of Presentation
The accompanying unaudited consolidated 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 partnership in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated.
The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America (U.S. GAAP). The preparation of financial statements in conformity with U.S. GAAP 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. Actual results could differ from those estimates. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham’s 2010 Annual Report on Form 10-K filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
3. Commitments and Contingencies
Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial condition, results of operations or cash flows of Brigham.
As of March 31, 2011, 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.
4. Net Income Available Per Common Share
Basic earnings per share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). 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.

 

5


Table of Contents

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2011 and 2010 are as follows (in thousands):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
 
               
Weighted average common shares outstanding — basic
    116,359       99,444  
Plus: Potential common shares
               
Stock options and restricted stock
    2,163       1,913  
 
           
 
               
Weighted average common shares outstanding — diluted
    118,522       101,357  
 
           
 
               
Stock options excluded from diluted EPS due to the anti-dilutive effect
    183       164  
 
           
5. Income Taxes
Based on estimates of its annual effective tax rate, Brigham has a $0.2 million deferred federal and state income tax expense for the three months ended March 31, 2011. There was no federal or state tax expense (benefit) in 2010.
Brigham has a net deferred tax asset at March 31, 2011, due to its net operating loss carryovers and ceiling test writedowns in the fourth quarter of 2008 and the first quarter of 2009. 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. After testing to determine if the deferred tax assets would meet the more likely than not criteria, Brigham determined that the valuation allowance should be $61.6 million at March 31, 2011.
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. Brigham has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, Brigham has recorded no uncertain tax liabilities in its consolidated balance sheet.
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 net operating losses generated and available for carryforward.
6. 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
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 7, “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.

 

6


Table of Contents

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
The following table reflects open commodity derivative contracts at March 31, 2011, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).
                                 
    Natural     Crude     Purchased     Written  
    Gas     Oil     Put     Call  
Settlement Period   (MMBTU)     (Barrels)     Nymex     Nymex  
Natural Gas Costless Collars
                               
04/01/11 – 12/31/11
    270,000             $ 5.75     $ 7.65  
04/01/11 – 12/31/11
    360,000             $ 5.75     $ 7.40  
04/01/11 – 12/31/11
    360,000             $ 5.00     $ 6.55  
Oil Costless Collars
                               
04/01/11 – 07/31/12
            244,000     $ 65.00     $ 97.20  
04/01/11 – 07/31/12
            244,000     $ 65.00     $ 98.55  
04/01/11 – 07/31/12
            244,000     $ 65.00     $ 100.40  
04/01/11 – 07/31/12
            244,000     $ 65.00     $ 100.00  
04/01/11 – 06/30/11
            9,000     $ 65.00     $ 97.50  
04/01/11 – 06/30/11
            12,000     $ 70.00     $ 92.50  
04/01/11 – 07/31/11
            12,000     $ 70.00     $ 94.80  
04/01/11 – 12/31/11
            63,000     $ 65.00     $ 88.25  
04/01/11 – 12/31/11
            45,000     $ 60.00     $ 97.25  
04/01/11 – 12/31/11
            45,000     $ 65.00     $ 108.00  
04/01/11 – 12/31/11
            36,000     $ 70.00     $ 106.80  
04/01/11 – 12/31/11
            36,000     $ 75.00     $ 102.60  
04/01/11 – 12/31/11
            27,000     $ 65.00     $ 100.00  
04/01/11 – 12/31/11
            27,000     $ 75.00     $ 104.30  
04/01/11 – 12/31/11
            137,500     $ 65.00     $ 100.00  
04/01/11 – 04/30/11
            8,000     $ 75.00     $ 104.50  
04/01/11 – 08/31/11
            38,250     $ 65.00     $ 96.75  
04/01/11 – 08/31/11
            38,250     $ 65.00     $ 94.80  
05/01/11 – 12/31/11
            122,500     $ 65.00     $ 100.00  
05/01/11 – 12/31/11
            122,500     $ 65.00     $ 106.50  
07/01/11 – 09/30/11
            9,000     $ 70.00     $ 95.00  
07/01/11 – 12/31/11
            12,000     $ 75.00     $ 103.00  
07/01/11 – 12/31/11
            12,000     $ 75.00     $ 95.15  
09/01/11 – 12/31/11
            61,000     $ 65.00     $ 99.00  
09/01/11 – 12/31/11
            61,000     $ 65.00     $ 97.40  
10/01/11 – 12/31/11
            6,000     $ 70.00     $ 96.35  
01/01/12 – 06/30/12
            60,000     $ 75.00     $ 106.90  
01/01/12 – 06/30/12
            182,000     $ 65.00     $ 100.75  
01/01/12 – 06/30/12
            91,000     $ 65.00     $ 101.00  
01/01/12 – 06/30/12
            182,000     $ 65.00     $ 99.25  
01/01/12 – 06/30/12
            91,000     $ 65.00     $ 102.75  
01/01/12 – 06/30/12
            136,500     $ 65.00     $ 107.25  
01/01/12 – 07/31/12
            106,500     $ 65.00     $ 110.00  
02/01/12 – 12/31/12
            335,000     $ 80.00     $ 134.25  
07/01/12 – 07/31/12
            62,000     $ 65.00     $ 102.25  
07/01/12 – 07/31/12
            31,000     $ 65.00     $ 105.25  
07/01/12 – 07/31/12
            62,,000     $ 75.00     $ 114.00  
07/01/12 – 09/30/12
            92,000     $ 65.00     $ 109.40  
08/01/12 – 09/30/12
            61,000     $ 65.00     $ 110.25  
08/01/12 – 09/30/12
            61,000     $ 65.00     $ 112.00  
08/01/12 – 10/31/12
            92,000     $ 70.00     $ 110.90  
08/01/12 – 10/31/12
            92,000     $ 70.00     $ 106.50  
08/01/12 – 10/31/12
            276,000     $ 75.00     $ 112.50  
10/01/12 – 10/31/12
            62,000     $ 65.00     $ 112.65  
10/01/12 – 10/31/12
            31,000     $ 70.00     $ 110.90  
11/01/12 – 12/31/12
            122,000     $ 70.00     $ 107.70  
11/01/12 – 12/31/12
            122,000     $ 70.00     $ 110.00  
11/01/12 – 12/31/12
            244,000     $ 75.00     $ 112.50  
01/01/13 – 02/28/13
            118,000     $ 75.00     $ 113.05  
01/01/13 – 03/31/13
            180,000     $ 80.00     $ 120.00  
01/01/13 – 03/31/13
            270,000     $ 80.00     $ 129.45  
03/01/13 – 03/31/13
            62,000     $ 80.00     $ 120.00  

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
                                 
    Natural     Crude     Purchased     Written  
    Gas     Oil     Put     Call  
Settlement Period   (MMBTU)     (Barrels)     Nymex     Nymex  
Crude Oil Calls
                               
04/01/11 – 06/30/11
            45,500             $ 95.00  
04/01/11 – 06/30/11
            45,500             $ 97.50  
07/01/11 –12/31/11
            276,000             $ 100.00  
Crude Oil Puts
                               
04/01/11 – 06/30/12
            228,500     $ 65.00          
04/01/11 – 06/30/12
            228,500     $ 65.00          
07/01/11 – 06/30/12
            91,500     $ 65.00          
07/01/11 – 06/30/12
            91,500     $ 65.00          
07/01/12 – 12/31/12
            276,000     $ 80.00          
 
                               
The following table reflects commodity derivative contracts entered subsequent to March 31, 2011, the associated volumes and the corresponding weighted average NYMEX reference price.
                                 
    Natural     Crude     Purchased     Written  
    Gas     Oil     Put     Call  
Settlement Period   (MMBTU)     (Barrels)     Nymex     Nymex  
Oil Costless Collars
                               
09/01/11 – 12/31/11
            244,000     $ 90.00     $ 144.00  
01/01/12 – 12/31/12
            366,000     $ 85.00     $ 139.50  
01/01/13 – 05/31/13
            302,000     $ 85.00     $ 134.00  
Additional Disclosures about Derivative Instruments and Hedging Activities
At March 31, 2011 and December 31, 2010, Brigham had derivative financial instruments under FASB ASC 815 recorded on the consolidated balance sheet as set forth below:
                     
        Mar 31, 2011     Dec 31, 2010  
        Estimated     Estimated  
Type of Contract   Balance Sheet Location   Fair Value     Fair Value  
        (in thousands)     (in thousands)  
Derivatives Not Designated as Hedging Instruments                
 
                   
Derivative Assets:
                   
Natural gas and crude oil contracts
  Other current assets   $ 1,244     $ 2,557  
Natural gas and crude oil contracts
  Other non-current assets     1,306       309  
 
               
Total Derivative Assets
      $ 2,550     $ 2,866  
 
                   
Derivative Liabilities:
                   
Natural gas and crude oil contracts
  Derivative liabilities - current   $ (31,610 )   $ (9,442 )
Natural gas and crude oil contracts
  Other non-current liabilities     (22,099 )     (8,575 )
 
               
Total Derivative Liabilities
      $ (53,709 )   $ (18,017 )

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
For the three months ended March 31, 2011 and 2010, the effect on income in the consolidated statement of operations for derivative financial instruments under FASB ASC 815 was as follows:
                     
        Three Months        
        Ended     Three Months Ended  
        Mar 31, 2011     Mar 31, 2010  
    Statement of Operations   Amount of     Amount of  
Type of Contract   Location of Gain (Loss)   Gain (Loss)     Gain (Loss)  
        (in thousands)     (in thousands)  
Derivatives Not Designated as Hedging Instruments
                   
 
                   
Natural gas contracts
  Gain (loss) on derivatives, net   $ 111     $ 3,255  
Crude oil contracts
  Gain (loss) on derivatives, net     (36,069 )     379  
 
               
Total Derivative Gain (loss)
      $ (35,958 )   $ 3,634  
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 within its credit facility bank group 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.
7. Fair Values
Brigham follows the provisions under Financial Accounting Standards Board Accounting Standards Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820) as it relates to financial and nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by FASB ASC 820 are as follows:
   
Level 1 – Unadjusted quoted prices are available in active markets for identical assets or liabilities.
   
Level 2 – Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
   
Level 3 – Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.
As such, 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. The fair value of Brigham’s derivative financial instruments is determined 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 (in thousands). The current asset and liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.
                                 
            Fair Value Measurements at March 31, 2011 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    March 31,     for Identical Assets     Inputs     Inputs  
Description   2011     (Level 1)     (Level 2)     (Level 3)  
Derivative liabilities
  $ (31,610 )   $     $ (31,610 )   $  
Other non-current liabilities
    (22,099 )           (22,099 )      
Other current assets
    1,244             1,244        
Other non-current assets
    1,306             1,306        
 
                       
 
  $ (51,159 )   $     $ (51,159 )   $  
 
                       

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
                                 
            Fair Value Measurements at December 31, 2010 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    December 31,     for Identical Assets     Inputs     Inputs  
Description   2010     (Level 1)     (Level 2)     (Level 3)  
Derivative liabilities
  $ (9,442 )   $     $ (9,442 )   $  
Other non-current liabilities
    (8,575 )           (8,575 )      
Other current assets
    2,557             2,557        
Other non-current assets
    309             309        
 
                       
 
  $ (15,151 )   $     $ (15,151 )   $  
 
                       
Brigham’s assessment of the significance of a particular input to the fair value measurement requires judgment and may effect the valuation on 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. These inputs include salvage value, estimated life, working interest, a factor for inflation, and a discount factor. The fair value of the asset retirement obligations is reflected on the balance sheet as detailed below (in thousands).
                                 
            Fair Value Measurements at March 31, 2011 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    March 31,     for Identical Assets     Inputs     Inputs  
Description   2011     (Level 1)     (Level 2)     (Level 3)  
Other non-current liabilities
    (5,269 )                 (5,269 )
 
                       
 
  $ (5,269 )   $     $     $ (5,269 )
 
                       
                                 
            Fair Value Measurements at December 31, 2010 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    December 31,     for Identical Assets     Inputs     Inputs  
Description   2010     (Level 1)     (Level 2)     (Level 3)  
Other non-current liabilities
    (5,923 )                 (5,923 )
 
                       
 
  $ (5,923 )   $     $     $ (5,923 )
 
                       
See Note 13, “Asset Retirement Obligations” for a rollforward of the asset retirement obligation.
Investments held by Brigham include certificates of deposit, corporate debt, and government securities. The fair value of the investments is reflected on the balance sheet as detailed below (in thousands).
                                 
            Fair Value Measurements at March 31, 2011 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    March 31,     for Identical Assets     Inputs     Inputs  
Description   2011     (Level 1)     (Level 2)     (Level 3)  
Investments
    172,159       172,159              
 
                       
 
  $ 172,159     $ 172,159     $     $  
 
                       
                                 
            Fair Value Measurements at December 31, 2010 Using  
            Quoted Prices in     Significant Other     Significant  
            Active Markets     Observable     Unobservable  
    December 31,     for Identical Assets     Inputs     Inputs  
Description   2010     (Level 1)     (Level 2)     (Level 3)  
Investments
    223,991       223,991              
 
                       
 
  $ 223,991     $ 223,991     $     $  
 
                       

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
The following table summarizes, by major security type, the fair value and any unrealized gain (loss) of Brigham’s investments (in thousands). The unrealized gain (loss) is recorded on the consolidated balance sheet as other comprehensive income (loss), a component of stockholders’ equity.
                                                 
    Less Than 12 Months     12 Months or Greater     Total  
            Unrealized             Unrealized             Unrealized  
    Fair     Gains     Fair     Gains     Fair     Gains  
Description of Securities   Value     (Losses)     Value     (Losses)     Value     (Losses)  
Certificates of deposit
  $ 240     $     $     $     $ 240     $  
Corporate bonds and notes
    153,179       88       6,730       4       159,909       92  
Government securities
    12,010       3                   12,010       3  
 
                                   
Total
  $ 165,429     $ 91     $ 6,730     $ 4     $ 172,159     $ 95  
 
                                   
The cost basis of Brigham’s investments in certificates of deposit, corporate bonds and notes, and government securities (in thousands) is $240, $162,337, and $12,076, 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:
                                 
    March 31, 2011     December 31, 2010  
    (in thousands)     (in thousands)  
    Carrying     Fair     Carrying     Fair  
    Amount     Value     Amount     Value  
Senior Notes
  $ 300,000     $ 331,500     $ 300,000     $ 325,500  
The fair value of Brigham’s Senior Notes (as hereinafter defined) is based upon current market quotes and is the estimated amount required to purchase the Senior Notes on the open market.
8. Oil and Gas Properties
Brigham uses the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain payroll, asset retirement costs, other internal costs, and interest incurred for the purpose of finding oil and natural gas reserves, are capitalized. Internal costs and capitalized interest are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.
Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved oil and natural gas reserves, based on the oil and natural gas prices in effect on the balance sheet date including the impact of qualifying cash flow hedging instruments; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of oil and gas properties exceed this ceiling amount, Brigham is subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower depreciation, depletion and amortization expense in future periods.
The risk that Brigham will experience a ceiling test write-down increases when oil and gas prices are depressed or if Brigham has substantial downward revisions in its estimated proved reserves. Based on the 12-month average oil and gas prices at March 31, 2011 ($4.10 per MMBtu for Henry Hub natural gas and $83.41 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 March 31, 2011.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
9. Support Infrastructure
Brigham recognizes revenue and expenses from its support infrastructure operations, which provide the usage of its oil, natural gas, waste water and fresh water gathering lines. Brigham also provides produced 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.
10. Senior Notes
On September 27, 2010, Brigham issued $300 million of unregistered 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.
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 March 31, 2011, Brigham was in compliance with all covenants under the indenture.
11. Senior Credit Facility
In February 2011, Brigham amended and restated the 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. Brigham had no borrowings outstanding under its Senior Credit Facility at March 31, 2011 and December 31, 2010.
Borrowings under the Senior Credit Facility bear interest, at Brigham’s election, at a base rate (as the term is defined in the Senior Credit Facility) or Eurodollar rate, plus in each case an applicable margin that is reset quarterly. The applicable interest rate margin varies from 1.0% to 1.75% in the case of borrowings based on the base rate (as the term is defined in the Senior Credit Facility) and from 2.0% to 2.75% in the case of borrowings based on the Eurodollar rate, depending on percentage of the available borrowing base utilized. In addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base (0.50% at March 31, 2011). Borrowings under the Senior Credit Facility are collateralized by substantially all of Brigham’s oil and natural gas properties under first liens.
The Senior Credit Facility contains various covenants, including among 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 and a net leverage ratio that must be no greater than 4 to 1. At March 31, 2011, Brigham was in compliance with all covenants under the Senior Credit Facility.
12. Preferred Stock
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.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
13. Asset Retirement Obligations
Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Prior to the adoption of Financial Accounting Standards Board Accounting Standards Codification Topic 410 “Asset Retirement and Environmental Obligations” (FASB ASC 410), Brigham assumed salvage value approximated plugging and abandonment costs. As such, estimated salvage value was not excluded from depletion and plugging and abandonment costs were not accrued for over the life of the oil and gas properties. Under the provisions of FASB ASC 410, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations.
The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410 during the three months ended March 31, 2011 and 2010 (in thousands):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
       
Beginning asset retirement obligations
  $ 5,923     $ 6,323  
Liabilities incurred for new wells placed on production
    178       52  
Liabilities settled
    (942 )     (28 )
Accretion of discount on asset retirement obligations
    110       105  
 
           
 
  $ 5,269     $ 6,452  
 
           
14. Stock Based Compensation
Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic 718 “Compensation – Stock Compensation” (FASB ASC 718) to account for stock based compensation. The cost for all stock based awards is based on the grant date fair value estimated in accordance with the provisions of FASB ASC 718 and is amortized on a straight-line basis over the requisite service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods. The maximum contractual life of stock based awards is ten years.
The estimated fair value of the options granted during the three months ended March 31, 2011 and 2010 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 options granted during the three months ended March 31, 2011 and 2010:
                 
    2011     2010  
Risk-free interest rate
    2.02 %     2.63 %
Expected life (in years)
    5.0       5.0  
Expected volatility
    82 %     80 %
Expected dividend yield
           
Weighted average fair value per share of stock compensation
  $ 18.35     $ 9.74  
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 three months ended March 31, 2011 and 2010.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
The following table summarizes the components of stock based compensation included in general and administrative expense (in thousands):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
       
Pre-tax stock based compensation expense
  $ 1,379     $ 763  
Capitalized stock based compensation
    (632 )     (336 )
Tax benefit
    (261 )     (149 )
 
           
Stock based compensation expense, net
  $ 486     $ 278  
 
           
Stock Based Plan Descriptions and Share Information
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. As of March 31, 2011, the number of shares authorized under the plan was equal to the lesser of 9,966,033 or 12% of the total number of shares of common stock outstanding. At March 31, 2011, approximately 1,469,684 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. Options vest over five years and have a maximum contractual life of either seven or 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 shares remain available for grant under the director stock option plan.
The following table summarizes option activity under the incentive plans for the three months ended March 31:
                                 
    2011     2010  
            Weighted-             Weighted-  
            Average             Average  
            Exercise             Exercise  
    Shares     Price     Shares     Price  
 
                               
Options outstanding at the beginning of the year
    4,436,400     $ 8.41       4,170,137     $ 5.14  
Granted
    4,000     $ 28.00       14,000     $ 14.89  
Forfeited or cancelled
    (1,000 )   $ 8.84           $  
Exercised
    (10,220 )   $ 7.41       (129,962 )   $ 6.25  
 
                           
Options outstanding at the end of the quarter
    4,429,180     $ 8.43       4,054,175     $ 5.14  
 
                           
Options exercisable at the end of the quarter
    709,200     $ 6.08       563,000     $ 6.16  
 
                           
The weighted-average grant-date fair value of share options granted during the three months ended March 31, 2011 and 2010 was $18.35 and $9.74, respectively. The total intrinsic value of options exercised during the three months ended March 31, 2011 and 2010 was $0.3 million and $1.1 million, respectively.

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
The following table summarizes information about stock options outstanding and exercisable at March 31, 2011:
                                                 
    Options Outstanding     Options Exercisable  
    Number     Weighted-             Number     Weighted-        
    Outstanding at     Average     Weighted-     Exercisable at     Average     Weighted-  
    March 31,     Remaining     Average     March 31,     Remaining     Average  
Exercise Price   2011     Contractual Life     Exercise Price     2011     Contractual Life     Exercise Price  
$2.20 to $3.11
    1,089,000     8.0 years     $ 2.24       137,000     7.9 years     $ 2.26  
3.66 to 5.08
    368,600     4.5 years     $ 5.08       98,600     4.5 years     $ 5.08  
5.96 to 6.23
    1,595,080     7.8 years     $ 5.98       296,800     6.6 years     $ 6.02  
7.22 to 8.77
    110,000     3.6 years     $ 7.51       64,000     3.4 years     $ 7.46  
8.93 to 13.86
    233,000     6.1 years     $ 11.66       109,000     3.1 years     $ 10.84  
14.43 to 16.85
    62,000     9.2 years     $ 15.24       3,800     8.9 years     $ 15.10  
18.36 to 19.12
    917,500     9.1 years     $ 19.11                 $  
27.15 to 28.00
    54,000     9.8 years     $ 27.21                 $  
 
                                           
$2.20 to $28.00
    4,429,180     7.7 years     $ 8.43       709,200     5.7 years     $ 6.08  
 
                                           
The aggregate intrinsic value of options outstanding and exercisable at March 31, 2011 was $127.3 million and $22.4 million, respectively. The aggregate intrinsic value represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the quarter 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 March 31, 2011. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.
As of March 31, 2011, there was approximately $15.4 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.8 years.
Restricted Stock
During the three months ended March 31, 2011 and 2010, Brigham issued 273,331 and 105,363, respectively, restricted shares of common stock as compensation to officers and employees of Brigham. The restricted shares generally vest over five years or cliff-vest at the end of five years. As of March 31, 2011, there was approximately $10.1 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 5 years. Brigham has assumed a 3% weighted average forfeiture rate for restricted stock. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods.
The following table reflects the outstanding restricted stock awards and activity related thereto for the three months ended March 31:
                                 
    2011     2010  
            Weighted-             Weighted-  
            Average             Average  
    Shares     Price     Shares     Price  
 
                               
Restricted shares outstanding at the beginning of the year
    530,883     $ 8.35       556,990     $ 7.04  
Shares granted
    273,331     $ 30.85       105,363     $ 14.45  
Shares forfeited
        $           $  
Lapse of restrictions
    (85,363 )   $ 12.97       (55,000 )   $ 8.59  
 
                           
Shares outstanding at the end of the quarter
    718,851     $ 16.36       607,353     $ 8.19  
 
                           

 

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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)
15. Comprehensive Income
For the periods indicated, comprehensive income (loss) consisted of the following (in thousands):
                 
    Three Months Ended  
    March 31,  
    2011     2010  
       
Net income (loss)
  $ 1,554     $ 11,315  
Unrealized gains (losses) on investments
    104       (264 )
Tax benefits (provisions)
           
 
           
Other comprehensive income (loss), net
  $ 1,658     $ 11,051  
 
           
16. Subsequent Events
Subsequent to March 31, 2011, Brigham added approximately 5,600 net acres in the Williston Basin through two property transactions.
17. Related Party Transactions
During the three months ended March 31, 2011 and 2010, Brigham incurred costs of approximately $1.9 million and $1.8 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 March 31, 2011 and December 31, 2010, Brigham had a liability recorded in accounts payable of approximately $293,000 and $1,000, respectively, related to services performed by this company.
During the three months ended March 31, 2011 and 2010, Brigham incurred costs of approximately $0.4 million and
$0.4 million, respectively, in fees for services performed by a service company in which Mr. Hobart Smith, one of Brigham’s current directors, owns stock and serves as a consultant. At March 31, 2011 and December 31, 2010, Brigham had a liability recorded in accounts payable of approximately $196,000 and $219,000, respectively, related to services performed by this company.

 

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ITEM 2.  
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to our financial condition provided in our 2010 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month periods ended March 31, 2011 and March 31, 2010. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the “Glossary of Oil and Gas Terms” provided in our 2010 Annual Report on Form 10-K. 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.
General Overview
We are an independent exploration, development and production company that utilizes advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore crude oil and natural gas reserves. We focus our activities in provinces where we believe these technologies, including horizontal drilling, multi-stage isolated fracture stimulations and 3-D seismic imaging, can be used to effectively maximize our return on invested capital.
Historically, our exploration and development activities have been focused in our Onshore Gulf Coast, the Anadarko Basin and West Texas and Other provinces. However, in late 2007, the majority of our drilling capital expenditures shifted from our historically active areas to the Williston Basin, where we are currently targeting the Bakken, Three Forks and Red River objectives. We currently have approximately 371,200 net leasehold acres in the Williston Basin. Through the first quarter 2011, we have invested in excess of $745 million on drilling, land and support infrastructure in this region.
Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we can use technology to generate high rates of return on our invested capital.
Overview of First Quarter 2011 Financial Results
First quarter 2011 crude oil prices, excluding realized and unrealized derivative hedging results, increased 16% from that in the first quarter 2010. In the first quarter 2011, the average sales price that we received for crude oil, excluding realized and unrealized derivative hedging results, was $84.03 per barrel, which represents an $11.34 per barrel increase from the first quarter 2010. First quarter 2011 natural gas prices, excluding realized and unrealized derivative hedging results, decreased 7% from that in the first quarter 2010. In the first quarter 2011, the average sales price that we received for natural gas inclusive of natural gas liquids, but excluding realized and unrealized derivative hedging results, was $5.61 per Mcf, which represents a $0.40 per Mcf decrease from that in the first quarter 2010.
Our first quarter 2011 production volumes were 11,314 barrels of equivalent per day, which represents a 109% increase from last year’s first quarter production volumes of 5,420 barrels of equivalent per day. Crude oil represented 81% of our production volumes in the first quarter 2011 as compared to 66% of our production volumes in the first quarter 2010. Both the increase in our production volumes and the increase in crude oil as a percent of total production volumes were as a result of our increased level of activity and successful drilling program in the Williston Basin targeting the Bakken and Three Forks. Our first quarter 2011 production volumes include approximately 732 Boe in crude oil added to inventory during the quarter. Adjusting our first quarter 2011 production volumes for our increased level of inventory resulted in sales volumes of 11,306 barrels of equivalent per day in the first quarter 2011 versus sales volumes of 5,364 barrels of equivalent per day in the first quarter 2010.
Our first quarter 2011 crude oil revenue, including hedge settlements but excluding unrealized hedging gains and losses, were up $45.8 million, or 201%, compared to that in the first quarter 2010. Crude oil revenue increased $37.3 million due to higher sales volumes and $9.4 million due to higher sales prices. These increases were partially offset by a $1.0 million decrease in crude oil hedge settlements.

 

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First quarter 2011 natural gas revenue, including hedge settlements but excluding unrealized hedging gains and losses, increased $0.7 million from the first quarter 2010. Natural gas revenue increased $0.8 million due to higher sales volumes and $0.4 million due to higher hedge settlements. These increases were partially offset by the lower natural gas prices during the first quarter 2011 compared to those in the prior year’s quarter, which decreased natural gas revenue by $0.5 million.
First quarter 2011 operating income was $1.6 million versus $13.1 million in the first quarter last year. The improvement in revenues associated with higher crude oil and natural gas production and higher crude oil prices was partially offset by $39.1 million in higher unrealized mark-to-market hedging losses recorded in the first quarter 2011. Operating income also decreased due to higher depletion, lease operating and production tax expenses.
As of March 31, 2011, we had $192.7 million in cash, cash equivalents and short term investments and $1.2 billion in total assets. Short term investments totaling $172.2 million consist of government sponsored entity and investment grade corporate bonds, notes and commercial paper. Maturity dates are staggered to meet anticipated funding needs, and we expect to hold these investments to maturity. All of our investments are subject to market risks if sold prior to maturity and the credit risks of the issuers. Our portfolio at March 31, 2011 also includes approximately $2.0 million in cash equivalents. Our cash is held in commercial bank accounts. See Note 7 for a discussion of the fair value of these investments and instruments.
Overview of Williston Basin Operational Results
During the first quarter 2011, we had seven operated rigs running in the Williston Basin. Four of the rigs were primarily drilling wells in our Rough Rider project area in Williams and McKenzie Counties, North Dakota; two of the rigs were drilling wells in our Ross project area in Mountrail County, North Dakota; and one rig was drilling in our Eastern Montana project area in Richland and Roosevelt Counties, Montana. The following table summarizes our completions in the Williston Basin since year-end 2010.
                                         
                    Frac     IP     30 Day  
Well Name   County     Objective     Stages     (Boe/d)     Average (Boe/d)*  
 
                                       
Erickson 8-17 #3H
  Williams   Bakken     32       3,091     NA  
Brad Olson 9-16 #3H
  Williams   Bakken     32       2,375     NA  
Esther Hynek 10-11 #1H
  Mountrail   Bakken     31       1,904     NA  
Sorenson 29-32 #2H
  Mountrail   Bakken     38       5,330       1,815  
Cvancara 20-17 #1H
  Mountrail   Bakken     36       4,402       1,577  
Brown 30-19 #1H
  Mountrail   Bakken     37       3,309     NA  
Hospital 31-36 #1H
  Mountrail   Bakken     33       1,449     NA  
Afseth 34-3 #1H
  Mountrail   Bakken     38       1,267     NA  
Johnson 30-19 #1H
  Richland   Bakken     36       2,962       803  
Knoshaug 14-11 #1H
  Williams   Bakken     36       4,443       1,390  
Gibbins 1-12 #1H
  McKenzie   Bakken     33       2,582       1,101  
Swindle 16-9 #1H
  Roosevelt   Bakken     19       1,065       400  
Lloyd 34-3 #1H
  McKenzie   Bakken     31       4,030       1,456  
Bratcher 10-3 #1H
  McKenzie   Bakken     30       3,667       1,129  
M. Macklin 15-22 #1H
  Williams   Bakken     38       2,534       1,062  
M. Olson 20-29 #1H
  Williams   Bakken     38       2,080       1,007  
 
                                   
 
          Averages             2,906       1,174  
     
*  
Excludes any days well was down for remediation.

 

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Subsequent Events
Subsequent to the first quarter 2011, we added approximately 5,600 net acres to our total Williston Basin acreage position through two transactions.
First Quarter 2011 Results
Comparison of the three-month periods ended March 31, 2011 and 2010.
                         
    Three Months Ended March 31,  
Production Volumes   2011     % Change     2010  
Crude oil (MBbls)(1)
    829       159 %     320  
Natural gas (MMcf)
    1,136       13 %     1,009  
Total (MBoe)(2)
    1,018       109 %     488  
Average daily production (Boe/d) (3)
    11,314       109 %     5,420  
 
     
(1)  
Includes approximately 732 and 5,012 barrels of crude oil produced in the Williston Basin and added to inventory during the first quarters 2011 and 2010, respectively.
 
(2)  
Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
 
(3)  
Average daily production is calculated using 30 days per calendar month.
                         
    Three Months Ended March 31,  
Sales Volumes (Production volumes less the Incremental Change in Inventory)   2011     % Change     2010  
Crude oil (MBbls)(1)
    828       163 %     315  
Natural gas (MMcf)
    1,136       13 %     1,009  
Total (MBoe)(2)
    1,018       111 %     483  
Average daily production (Boe/d) (3)
    11,306       111 %     5,364  
 
     
(1)  
Excludes approximately 732 and 5,012 barrels of crude oil produced in the Williston Basin and added to inventory during the first quarters 2011 and 2010, respectively.`
 
(2)  
Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
 
(3)  
Average daily production is calculated using 30 days per calendar month.
Crude oil represented 81% of our first quarter 2011 production volumes, compared to 66% in the first quarter of last year.

 

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Revenues, Commodity Prices and Hedging
The following table sets forth our revenues, our derivative settlement gains (losses), our unrealized derivative gains (losses), the average prices we received before hedging, the average prices we received including derivative settlement gains (losses) and the average prices including derivative settlements and unrealized gains (losses).
                         
    Three Months Ended March 31,  
    2011     % Change     2010  
    (In thousands)  
Crude Oil revenue:
                       
Crude oil revenue
  $ 69,596       204 %   $ 22,870  
Crude oil derivative settlement gains (losses)
    (1,046 )     990 %     (96 )
 
                   
Crude oil revenue including derivative settlements
  $ 68,550       201 %   $ 22,774  
Crude oil derivative unrealized gains (losses)
    (35,023 )   NM       475  
 
                   
Crude oil revenue including derivative settlements and unrealized gains (losses)
  $ 33,527       44 %   $ 23,249  
Natural gas revenue:
                       
Natural gas revenue
  $ 6,367       5 %   $ 6,060  
Natural gas derivative settlement gains (losses)
    1,096       62 %     678  
 
                   
Natural gas revenue including derivative settlements
  $ 7,463       11 %   $ 6,738  
Natural gas derivative unrealized gains (losses)
    (985 )   NM       2,577  
 
                   
Natural gas revenue including derivative settlements and unrealized gains (losses)
  $ 6,478       (30 %)   $ 9,315  
Crude oil and natural gas revenue:
                       
Crude oil and natural gas revenue
  $ 75,963       163 %   $ 28,930  
Crude oil and natural gas derivative settlement gains (losses)
    50       (91 %)     582  
 
                   
Crude oil and natural gas revenue including derivative settlements
    76,013       158 %     29,512  
Crude oil and natural gas derivative unrealized gains (losses)
    (36,008 )   NM       3,052  
 
                   
Crude oil and natural gas revenue including derivative settlements and unrealized gains (losses)
    40,005       23 %     32,564  
Support infrastructure revenue
    594     NM        
Other revenue
    2       (78 %)     9  
 
                   
Total revenue
  $ 40,601       25 %   $ 32,573  
 
                       
Average crude oil prices (based on sales volumes):
                       
Crude oil price (per Bbl)
  $ 84.03       16 %   $ 72.69  
Crude oil price including derivative settlement gains (losses) (per Bbl)
    82.76       14 %     72.39  
Crude oil price including derivative settlements and unrealized gains (losses) (per Bbl)
    40.48       (45 %)     73.90  
Average natural gas prices:
                       
Natural gas price (per Mcf)
  $ 5.61       (7 %)   $ 6.01  
Natural gas price including derivative settlement gains (losses) (per Mcf)
    6.57       (2 %)     6.68  
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)
  $ 5.70       (38 %)   $ 9.23  
Average equivalent prices (based on sales volumes):
                       
Crude oil equivalent price (per Bbl)
  $ 74.65       25 %   $ 59.93  
Crude oil equivalent price including derivative settlement gains (losses) (per Bbl)
    74.70       22 %     61.13  
Crude oil equivalent price including derivative settlements and unrealized gains (losses) (per Bbl)
  $ 39.31       (42 %)   $ 67.45  

 

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    For the three  
    month periods  
    ended March 31,  
    2011 and 2010  
    (In thousands)  
 
       
Change in revenue from the sale of crude oil:
       
Price variance impact
  $ 9,391  
Volume variance impact
    37,335  
Cash settlement of derivative hedging contracts
    (950 )
Unrealized gains (losses) due to derivative hedging contracts
    (35,498 )
 
     
Total change
  $ 10,278  
 
     
 
       
Change in revenue from the sale of natural gas:
       
Price variance impact
  $ (459 )
Volume variance impact
    766  
Cash settlement of derivative hedging contracts
    418  
Unrealized gains (losses) due to derivative hedging contracts
    (3,562 )
 
     
Total change
  $ (2,837 )
 
     
 
       
Change in revenue from the sale of crude oil and natural gas:
       
Price variance impact
  $ 8,932  
Volume variance impact
    38,101  
Cash settlement of derivative hedging contracts
    (532 )
Unrealized gains (losses) due to derivative hedging contracts
    (39,060 )
 
     
Total change
  $ 7,441  
 
     
First quarter 2011 crude oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) increased $7.4 million when compared to the first quarter 2010. The change in revenues was attributable to the following:
   
an increase in crude oil and natural gas sales volumes of 163% and 13%, respectively, increased revenue $38.1 million;
   
a 16% increase in pre-hedge crude oil prices, which was partially offset by a 7% decrease in pre-hedge natural gas prices, resulted in a $8.9 million increase in crude oil and natural gas revenue;
   
a $0.1 million gain from the settlement of derivative contracts in the first quarter 2011 versus a $0.6 million gain from the settlement of derivative contracts in the first quarter 2010 decreased revenues by $0.5 million; and
   
a $36.0 million unrealized derivative loss in first quarter 2011 versus a $3.1 million unrealized derivative gain in first quarter 2010 decreased revenues by $39.1 million.
Hedging. We utilize collars, three way costless collars and puts to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans.
The following table details derivative contracts that settled during first quarter 2011 and 2010 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon settlement.

 

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    Three months ended March 31,  
    2011     % Change     2010  
Crude oil collars
                       
Volumes (Bbls)
    518,000       257 %     145,000  
Average floor price (per Bbl)
  $ 66.16       14 %   $ 57.83  
Average ceiling price (per Bbl)
  $ 98.33       13 %   $ 87.19  
Gain (loss) upon settlement (in thousands)
  $ (1,046 )     992 %   $ (96 )
 
                       
Total Crude Oil Gain (loss) upon settlement (in thousands)
  $ (1,046 )     992 %   $ (96 )
 
                       
Natural gas collars
                       
Volumes (MMbtu)
    540,000       29 %     420,000  
Average floor price (per MMbtu)
  $ 6.17       13 %   $ 5.45  
Average ceiling price (per MMbtu)
  $ 7.79       11 %   $ 7.03  
Gain (loss) upon settlement (in thousands)
  $ 1,096       944 %   $ 105  
 
                       
Natural gas three ways
                       
Volumes (MMbtu)
          (100 %)     390,000  
Average floor price (per MMbtu)
  $       (100 %)   $ 6.96  
Average ceiling price (per MMbtu)
  $       (100 %)   $ 8.62  
Average price – written puts ($  per MMbtu)
  $       (100 %)   $ 4.58  
Gain (loss) upon settlement (in thousands)
  $       (100 %)   $ 573  
 
                       
Total Natural Gas Gain (loss) upon settlement (in thousands)
  $ 1,096       62 %   $ 678  
Support infrastructure. Revenue from support infrastructure comes from fees related to our support infrastructure assets in North Dakota, including fees from oil, natural gas, produced water and fresh water gathering lines. Our produced water disposal wells in our Ross and Rough Rider project areas became operational early in the fourth quarter 2010 and late in the fourth quarter 2010, respectively. Our crude oil, produced water and fresh water gathering lines are expected to be operational in the fourth quarter 2011.
Other revenue. Other revenue relates to fees that we charge third parties who use our gas gathering systems to move their production from the wellhead to third party gas pipeline systems.
Operating costs and expenses
Production costs. We believe that per unit of production measures are the best way to evaluate our production costs. We use this information to internally evaluate our performance, as well as to evaluate our performance relative to our peers.
                                                 
    Unit–of-Production     Amount  
    (Per Boe)     (In thousands)  
    Three months ended March 31,     Three months ended March 31,  
    2011     % Change     2010     2011     % Change     2010  
 
                                               
Production costs:
                                               
Operating & maintenance
  $ 5.45       0 %   $ 5.43     $ 5,543       111 %   $ 2,624  
Expensed workovers
    1.57       (49 %)     3.05       1,602       9 %     1,475  
Ad valorem taxes
    0.56       8 %     0.52       575       130 %     250  
 
                                       
Lease operating expenses
  $ 7.58       (16 %)   $ 9.00     $ 7,720       78 %   $ 4,349  
 
                                               
Production taxes
    7.56       46 %     5.19       7,698       207 %     2,508  
 
                                       
Production costs
  $ 15.14       7 %   $ 14.19     $ 15,418       125 %   $ 6,857  

 

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First quarter 2011 per unit of production costs increased $0.95 per Boe, or 7%, compared to that in the first quarter last year mainly due to the following:
   
production taxes increased $2.37 per Boe, or 46%, due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to an 11.5% tax rate; and
   
higher production taxes were partially offset by a $1.48 per Boe, or 49%, decrease in expensed workovers due to fewer workovers associated with our conventional onshore Gulf Coast and Anadarko Basin natural gas wells.
General and administrative expenses. We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on capital projects and a portion of our associated technical organization costs such as supervision, telephone and postage.
                         
    Three months ended March 31,  
    2011     % Change     2010  
    (In thousands, except per unit measurements)  
 
                       
General and administrative costs
  $ 6,638       12 %   $ 5,916  
Capitalized general and administrative costs
    (3,256 )     15 %     (2,830 )
 
                   
General and administrative expenses
  $ 3,382       10 %   $ 3,086  
 
                   
 
                       
General and administrative expense ($  per Boe)
  $ 3.32       (48 %)   $ 6.39  
Our general and administrative costs prior to capitalization increased primarily because of a $0.8 million increase in employee compensation costs due to higher levels of employee salaries in 2011 to ensure competitive compensation levels with other oil and gas companies, and a higher number of employees due to our increased activity in the Williston Basin.
Depletion of crude oil and natural gas properties. Our depletion expense is driven by many factors including certain costs spent in the exploration for and development of producing reserves, production levels, and estimates of proved reserve quantities and future developmental costs at the end of the year.
                         
    Three months ended March 31,  
    2011     % Change     2010  
    (In thousands, except per unit measurements)  
 
                       
Depletion of crude oil and natural gas properties
  $ 18,940       106 %   $ 9,211  
Depletion of crude oil and natural gas properties ($  per Boe)
  $ 18.61       (2 %)   $ 19.07  
Our depletion expense for the first quarter 2011 was $9.7 million higher than the first quarter 2010. Higher production volumes increased depletion expense by $10.2 million, while a lower depletion rate due largely to increased levels of year-end 2010 proved reserves decreased depletion expense by $0.5 million.
Impairment of crude oil and natural gas properties. We use the full cost method of accounting for crude oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain payroll, asset retirement costs, other internal costs, and interest incurred for the purpose of finding crude oil and natural gas reserves, are capitalized. Internal costs and interest capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.
Capitalized costs of crude oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved crude oil and natural gas reserves, based on the average of crude oil and natural gas prices in effect at the beginning of each month in the twelve month period prior to the end of the reporting period; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of crude oil and gas properties exceed this ceiling amount, we are subject to a ceiling test writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings and reduces stockholders’ equity in the period of occurrence. The risk that we will experience a ceiling test writedown increases when crude oil and gas prices are depressed or if we have a substantial downward revisions in our estimated proved reserves.

 

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Net interest expense. Interest on our Senior Notes and our Senior Credit Facility represents the largest portion of our interest expense. Other costs include commitment fees that we pay on the unused portion of the borrowing base for our Senior Credit Facility. In addition, we typically pay loan and debt issuance costs when we enter into new lending agreements or amend existing agreements. When incurred, these costs are recorded as non-current assets and are then amortized over the life of the loan. We capitalize interest costs on borrowings associated with our major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.
                         
    Three months ended March 31,  
    2011     % Change     2010  
    (In thousands)  
Interest on Senior Notes
  $ 6,562       70 %   $ 3,850  
Interest on Senior Credit Facility
    3     NM        
Commitment fees
    254       56 %     163  
Dividend on mandatorily redeemable preferred stock
          (100 %)     149  
Amortization of deferred loan and debt issuance cost
    517       7 %     482  
Other general interest expense
    36     NM        
Capitalized interest expense
    (3,994 )     130 %     (1,740 )
 
                   
Net interest expense
  $ 3,378       16 %   $ 2,904  
 
                   
 
                       
Weighted average debt outstanding
  $ 300,000       76 %   $ 170,101  
Average interest rate on outstanding indebtedness (a)
    9.3 %             9.9 %
 
     
a)  
Calculated as the sum of the interest expense on our outstanding indebtedness, commitment fees that we pay on our unused borrowing capacity and the dividend on our mandatorily redeemable preferred stock divided by our weighted average debt and preferred stock outstanding for the period.
First quarter 2011 interest expense was $0.5 million higher than that in 2010 primarily due to a $2.7 million increase in interest expense associate with the September 2010 issuance of our $300 million Senior Notes due 2018. This increase was partially offset by a $2.3 million increase in capitalized interest expense associated with our higher level of activity in the Williston Basin.
Other income (expense).
Other income (expense) included:
                         
    Three months ended March 31,  
    2011     % Change     2010  
    (In thousands)  
Other income (expense):
                       
Non-cash gain (loss)
  $     NM     $  
Income (expense)
    3,154       360 %     685  
 
                   
Total other income (expense)
  $ 3,154       360 %   $ 685  
 
                   
Other income increased in 2011 as a result of higher levels of field general equipment income in the Williston Basin, which was driven by accelerated development in the basin.
Income taxes. We recorded $0.2 million in deferred federal and state income tax expense in the first quarter of this year, compared to no current or deferred federal or state income tax expense in the first quarter last year. For the first three months of 2011, our effective tax rate on book net income was 10.3%, which was lower than the statutory rate of 35% primarily due to decreases in our valuation allowances on federal and state net operating losses and our inability to deduct certain portions of our non-cash stock compensation expense for federal tax purposes.

 

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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;
   
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:
   
commodity prices;
   
production from our existing producing wells;
   
the results of our current exploration and development drilling efforts;
   
economic conditions at the time of drilling;
   
industry conditions at the time of drilling, including the availability of drilling and completion equipment;
   
our liquidity and the availability of external sources of financing; and
   
the availability of more economically attractive prospects.
There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of crude oil or natural gas.
Factors that could cause us to further increase our level of activity and capital budget in 2011 include an improvement in commodity prices or well performance that exceeds our risked forecasts, the divestiture of non-strategic conventional assets, a reduction in service and material costs, or the formation of joint ventures with other exploration and production companies outside of our core de-risked acreage positions in the Williston Basin, all of which would positively impact our operating cash flow.
Factors that would cause us to reduce our capital budget in 2011 include, but are not limited to, reductions in commodity prices or underperformance of wells relative to our risked forecasts or increases in service and materials costs, all of which would negatively impact our operating cash flow.

 

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The table below summarizes our 2011 oil and gas capital expenditure budget, the amount spent through March 31, 2011 and the amount of our 2011 oil and gas capital expenditure budget that remains to be spent.
                         
            Amount        
    2011     Spent Through     Amount  
    Budget     March 31, 2011     Remaining (a)  
    (In millions)  
Drilling
  $ 582.1     $ 110.8     $ 471.3  
Support infrastructure
    83.2       5.3       77.9  
Land
    27.4       6.7       20.7  
 
                 
Oil and gas capital expenditures
  $ 692.7     $ 122.8     $ 569.9  
 
                 
 
     
(a)  
Calculated based on the 2011 oil and gas capital expenditure budget less amounts spent through March 31, 2011.
Liquidity and Capital Resources
Sources of Capital
For the remainder of 2011, we intend to fund our capital expenditure program and contractual commitments with cash, cash equivalents, short term investments on hand as of March 31, 2011, cash flows from operations, reimbursements of prior land and seismic costs by third parties who participate in our projects, the potential sale of interests in projects and properties, availability under our Senior Credit Facility or alternative financing sources.
Senior Notes
As of March 31, 2011, we had outstanding $300 million of 8 3/4% Senior Notes due 2018, which were issued in September 2010. In connection with the issuance of the 8 3/4% Senior Notes, we tendered for and purchased or redeemed $160 million of our 9 5/8% Senior Notes due 2014 in September and October 2010.
Our 8 3/4% Senior Notes are fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. Beginning April 2011, we will pay 8 3/4% interest on the $300 million outstanding. Future interest payments are due semi-annually in arrears in October and April of each year.
The 8 3/4% Senior Notes are our unsecured senior obligations, and:
   
rank equally in right of payment with all our existing and future senior indebtedness;
   
rank senior to all of our future subordinated indebtedness; and
   
are effectively junior in right of payment to all of our and our guarantors’ existing and future secured indebtedness, including debt of our Senior Credit Facility.
The Indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon the occurrence of certain events of default, the trustee or the holders of the 8 3/4% Senior Notes may declare all outstanding 8 3/4% Senior Notes to be due and payable immediately.
Additionally, the Indenture governing the 8 3/4% Senior Notes contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the 8 3/4% Senior Notes as of March 31, 2011.
Senior Credit Facility
In February 2011, we entered into our Fifth Amended and Restated Credit Facility, which provides for revolving credit borrowings up to $600 million, a current borrowing base of $325 million and a five year maturity. As of March 31, 2011, we had no amounts outstanding under our Senior Credit Facility.

 

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The borrowing base under the new Senior Credit Facility will be redetermined at least semi-annually and the amount of borrowing capacity available to us under the new Senior Credit Facility could fluctuate. In the event that the borrowing base is adjusted below the amount that we have borrowed, our access to further borrowings will be reduced, and we may not have the resources necessary to pay off the borrowing base deficiency and carry out our planned spending for exploration and development activities.
Borrowings under our new Senior Credit Facility bear interest at a base rate or a Eurodollar rate, at our election, plus in each case an applicable margin. These margins are reset quarterly and are subject to increase if the total amount borrowed under our new Senior Credit Facility reaches certain percentages of the available borrowing base, as shown below:
                                 
Percent of         Eurodollar              
Borrowing Base         Rate     Base Rate     Commitment  
Utilized         Advances     Advances(1)     Fee  
< 50%      
 
    2.00 %     1.00 %     0.50 %
> 50%      
 
    2.25 %     1.25 %     0.50 %
> 75%      
 
    2.50 %     1.50 %     0.50 %
> 90%      
 
    2.75 %     1.75 %     0.50 %
 
     
(1)  
Base Rate means for any day a fluctuating rate per annum equal to the highest of the following: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of one month determined as of approximately 11:00 a.m. (London time) on such day plus 1.00% and (c) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate.” The “prime rate” is a rate set by Bank of America based upon various factors including Bank of America’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change.
Our new Senior Credit Facility also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our Senior Credit Facility, our current ratio must be at least 1.0 to 1 and net leverage ratio must not be greater than 4.00 to 1.
Mandatorily Redeemable Preferred Stock
In June 2010, we exercised our option to redeem all of our Series A mandatorily redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC.
Off Balance Sheet Arrangements
We currently have operating leases, which are considered off balance sheet arrangements. We do not currently have any other off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the debt of any other party. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.
Analysis of Changes in Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during the periods indicated.
                         
    Three months ended March 31,  
    2011     % Change     2010  
    (In thousands)  
       
Net income (loss)
  $ 1,554       (86 %)   $ 11,315  
Non-cash items
    57,479       674 %     7,429  
Changes in working capital and other items.
    7,178       (1 %)     7,229  
 
                   
Cash flows provided by operating activities
  $ 66,211       155 %   $ 25,973  
Cash flows used by investing activities
    (65,525 )     53 %     (42,910 )
Cash flows provided by financing activities
    (3,843 )   NM       632  
 
                   
Net increase in cash and cash equivalents
  $ (3,157 )     (81 %)   $ (16,305 )
 
                   

 

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Analysis of net cash provided by operating activities
Net cash provided by operating activities is a function of the amount of crude oil and natural gas that we produce, the prices that we receive from the sale of crude oil and natural gas, which are inherently volatile and unpredictable, gains or losses related to the settlement of our derivative contracts, operating costs and our cost of capital. Our asset base, as with other extractive industries, is a depleting one in which each barrel of crude oil or Mcf of natural gas produced must be replaced or our ability to generate cash flow, and thus sustain our exploration and development activities, will diminish.
Net cash provided by operating activities for the first quarter 2011 was $40.2 million higher than the first quarter 2010. The following are the primary reasons for the decrease:
   
higher crude oil and natural gas volumes increased operating cash flow by $38.1 million;
   
higher oil equivalent sales prices increased operating cash flow by $8.9 million;
   
higher production taxes decreased operating cash flow by $5.2 million; and
   
higher lease operating costs decreased operating cash flow by $3.4 million.
Analysis of changes in cash flows used in investing activities
                         
    Three months ended March 31,  
    2011     % Change     2010  
    (In thousands)  
Capital expenditures for oil and natural gas activities:
                       
Drilling
  $ 110,778       154 %   $ 43,606  
Support infrastructure
    5,264     NM        
Land
    6,770       (20 %)     8,477  
Capitalized cost
    6,641       45 %     4,569  
Capitalized asset retirement obligation
    178       242 %     52  
 
                   
Total
  $ 129,631       129 %   $ 56,704  
 
                   
 
                       
Reconciling Items:
                       
Change in accrued drilling costs
  $ (11,604 )     (32 %)   $ (16,957 )
Change in short term investments
    (51,936 )   NM       2,912  
Change in other property and equipment
    854     NM        
Change in inventory
    (276 )   NM        
Other
    (1,144 )   NM       251  
 
                   
Total Reconciling Items
    (64,106 )     365 %     (13,794 )
 
                       
Net cash used in investing activities
  $ 65,525       53 %   $ 42,910  
Net cash used by investing activities in the first quarter 2011 increased by $22.6 million, or 53%, over the same period in 2010. The following were the main reasons for the change:
   
drilling expenditures increased by $67.2 million due to higher levels of drilling activity in the Williston Basin;
   
the change in accrued drilling costs increased cash used in investing activities by $5.4 million.
   
support infrastructure expenditures increased by $5.3 million due to the building of additional infrastructure in the Williston Basin;
   
capitalized costs increased by $2.1 million due to higher levels of drilling activity;
   
the change in short term investments decreased cash used in investing activities by $54.8 million; and
Analysis of changes in cash flows from financing activities
Net cash used by financing activities in the first quarter 2011 increased $4.5 million from that in the first quarter 2010. The increase was largely due to the payment of $3.4 million in deferred loan fees in connection with our Senior Credit Facility and a $0.7 million decrease in cash flow from the exercise of employee stock options. In the first quarter 2010, we had $0.6 million net cash provided by financing activities which was mainly due to the exercise of employee stock options.

 

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Common Stock Transactions
The following is a list of common stock transactions that occurred in the three months ended March 31, 2011 and 2010.
                 
    Shares Issued     Net Proceeds  
    (In thousands, except share data)  
2011 common stock transactions:
               
Exercise of employee stock options
    10,220     $ 77  
 
               
2010 common stock transactions:
               
Exercise of employee stock options
    129,962     $ 844  
Other Matters
Derivative Instruments
Our results of operations and operating cash flow are impacted by changes in market prices for crude oil and natural gas. We believe the use of derivative instruments, although not free of risk, allows us to reduce our exposure to crude oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our derivative contracts generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivative contracts will vary from time to time.
Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing crude oil and natural gas prices. If the price of crude oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that we are required to bear for operations.
Environmental and Other Regulatory Matters
Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of crude oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe that we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity.

 

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Forward-looking Information
We or our representatives may make forward-looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from crude oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in crude oil and natural gas production, the number of wells we anticipate drilling during 2011 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward-looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in crude oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in our Form 10-K report for the year ended December 31, 2010, including, but not limited to, the Risk Factors identified in Item 1A. of such report. All subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.
ITEM 3.  
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Management Opinion Concerning Derivative Instruments
We use derivative instruments to manage exposure to commodity prices and interest rate risks. Our objectives for holding derivatives are to achieve a 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. See Notes 6 and 7 for more details.
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 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 and through March 31 2011, we were party to crude oil costless collars, crude oil puts, natural gas costless collars and natural gas three-way costless collars.

 

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We use costless collars to establish floor (purchased put option) and ceiling prices (written call option) on our anticipated future crude oil and natural gas production. We do not pay or receive net premiums when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is above the ceiling price (written call option), we pay our counterparty. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us.
A three-way costless collar consists of a costless collar (purchased put option and written call option) plus a put (written put) sold by us with a price below the floor price (purchased put option) of the costless collar. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. The written put requires us to make a payment to our counterparty if the settlement price for a period is below the written put price. Combining the costless collar (purchased put option and written call option) with the written put results in us being entitled to a net payment equal to the difference between the floor price (purchased put option) of the costless collar and the written put price if the settlement price is equal to or less than the written put price. If the settlement price is greater than the written put price, the result is the same as it would have been with a costless collar. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while offsetting the associated cost with the sale of the written put.
We also use put options to establish floor prices (purchased put option) on our anticipated future crude oil production. We pay an initial premium when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us.
Natural gas derivative transactions are generally settled based upon the average reported settlement prices on the NYMEX for the last three trading days of a particular contract month. Crude oil derivative transactions are generally settled based on the average reported settlement prices on the NYMEX for each trading day of a particular calendar month.
The following tables reflect our open crude oil and natural gas contracts as of March 31, 2011, the associated volumes and the corresponding weighted average NYMEX floor and cap price.
                         
    Crude     Purchased     Written  
    Oil     Put     Call  
Settlement Period   (Bbls)     (Nymex)     (Nymex)  
Crude Oil Costless Collars
                       
04/01/11 – 12/31/11
    63,000     $ 65.00     $ 88.25  
04/01/11 – 12/31/11
    45,000     $ 60.00     $ 97.25  
04/01/11 – 12/31/11
    45,000     $ 65.00     $ 108.00  
04/01/11 – 06/30/11
    9,000     $ 65.00     $ 97.50  
04/01/11 – 12/31/11
    36,000     $ 70.00     $ 106.80  
04/01/11 – 12/31/11
    36,000     $ 75.00     $ 102.60  
07/01/11 – 12/31/11
    12,000     $ 75.00     $ 103.00  
04/01/11 – 06/30/11
    12,000     $ 70.00     $ 92.50  
07/01/11 – 09/30/11
    9,000     $ 70.00     $ 95.00  
10/01/11 – 12/31/11
    6,000     $ 70.00     $ 96.35  
04/01/11 – 07/31/11
    12,000     $ 70.00     $ 94.80  
07/01/11 – 12/31/11
    12,000     $ 75.00     $ 95.15  
04/01/11 – 12/31/11
    27,000     $ 75.00     $ 104.30  
01/01/12 – 06/30/12
    60,000     $ 75.00     $ 106.90  
04/01/11 – 04/30/11
    8,000     $ 75.00     $ 104.50  
04/01/11 – 12/31/11
    27,000     $ 65.00     $ 100.00  
04/01/11 – 07/31/12
    244,000     $ 65.00     $ 97.20  
04/01/11 – 07/31/12
    244,000     $ 65.00     $ 98.55  
04/01/11 – 07/31/12
    244,000     $ 65.00     $ 100.00  
04/01/11 – 07/31/12
    244,000     $ 65.00     $ 100.40  
04/01/11 – 08/31/11
    38,250     $ 65.00     $ 94.80  
09/01/11 – 12/31/11
    61,000     $ 65.00     $ 97.40  
01/01/12 – 06/30/12
    182,000     $ 65.00     $ 99.25  
09/01/11 – 12/31/11
    61,000     $ 65.00     $ 99.00  
04/01/11 – 08/31/11
    38,250     $ 65.00     $ 96.75  
01/01/12 – 06/30/12
    91,000     $ 65.00     $ 101.00  
01/01/12 – 06/30/12
    182,000     $ 65.00     $ 100.75  

 

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Table of Contents

                         
    Crude     Purchased     Written  
    Oil     Put     Call  
Settlement Period   (Bbls)     (Nymex)     (Nymex)  
01/01/12 – 06/30/12
    91,000     $ 65.00     $ 102.75  
07/01/12 – 07/31/12
    62,000     $ 65.00     $ 102.25  
05/01/11 – 12/31/11
    122,500     $ 65.00     $ 100.00  
07/01/12 – 07/31/12
    31,000     $ 65.00     $ 105.25  
05/01/11 – 12/31/11
    122,500     $ 65.00     $ 106.50  
04/01/11 – 12/31/11
    137,500     $ 65.00     $ 100.00  
01/01/12 – 06/30/12
    136,500     $ 65.00     $ 107.25  
07/01/12 – 09/30/12
    92,000     $ 65.00     $ 109.40  
08/01/12 – 09/30/12
    61,000     $ 65.00     $ 110.25  
08/01/12 – 09/30/12
    61,000     $ 65.00     $ 112.00  
10/01/12 – 10/31/12
    62,000     $ 65.00     $ 112.65  
01/01/12 – 07/31/12
    106,500     $ 65.00     $ 110.00  
04/01/11 – 06/30/11*
    45,500     $ 65.00     $ 95.00  
04/01/11 – 06/30/11*
    45,500     $ 65.00     $ 97.50  
08/01/12 – 10/31/12
    92,000     $ 70.00     $ 110.90  
10/01/12 – 10/31/12
    31,000     $ 70.00     $ 110.90  
08/01/12 – 10/31/12
    92,000     $ 70.00     $ 106.50  
11/01/12 – 12/31/12
    122,000     $ 70.00     $ 107.70  
11/01/12 – 12/31/12
    122,000     $ 70.00     $ 110.00  
07/01/11 – 12/31/11*
    276,000     $ 65.00     $ 100.00  
08/01/12 – 10/31/12
    276,000     $ 75.00     $ 112.50  
11/01/12 – 12/31/12
    244,000     $ 75.00     $ 112.50  
07/01/12 – 07/31/12
    62,000     $ 75.00     $ 114.00  
01/01/13 – 02/28/13
    118,000     $ 75.00     $ 113.05  
01/01/13 – 03/31/13
    180,000     $ 80.00     $ 120.00  
03/01/13 – 03/31/13
    62,000     $ 80.00     $ 120.00  
02/01/12 – 12/31/12
    335,000     $ 80.00     $ 134.25  
01/01/13 – 03/31/13
    270,000     $ 80.00     $ 129.45  
     
*  
Crude oil collar was completed in two phases. First, the put option (floor) was purchased. Subsequently, the call option (ceiling) was sold thereby converting the position into a collar.
                 
    Crude     Purchased  
    Oil     Put  
Settlement Period   (Bbls)     (Nymex)  
Crude Oil Puts
               
01/01/12 – 06/30/12
    91,000     $ 65.00  
01/01/12 – 06/30/12
    91,000     $ 65.00  
01/01/12 – 06/30/12
    45,500     $ 65.00  
01/01/12 – 06/30/12
    45,500     $ 65.00  
07/01/12 – 12/31/12
    276,000     $ 80.00  
                         
    Natural     Purchased     Written  
    Gas     Put     Call  
Settlement Period   (MMbtu)     (Nymex)     (Nymex)  
Natural Gas Costless Collars
                       
04/01/11 – 12/31/11
    270,000     $ 5.75     $ 7.65  
04/01/11 – 12/31/11
    360,000     $ 5.75     $ 7.40  
04/01/11 – 12/31/11
    360,000     $ 5.00     $ 6.55  
The following table reflects commodity derivative contracts entered into subsequent to March 31, 2011, the associated volumes and the corresponding weighted average NYMEX reference price.
                         
    Crude     Purchased     Written  
    Oil     Put     Call  
Settlement Period   (Bbls)     (Nymex)     (Nymex)  
Crude oil Costless Collars
                       
09/01/11 – 12/31/11
    244,000     $ 90.00     $ 144.00  
01/01/12 – 12/31/12
    366,000     $ 85.00     $ 139.50  
01/01/13 – 05/31/13
    302,000     $ 85.00     $ 134.00  

 

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Table of Contents

ITEM 4.  
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of March 31, 2011, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness 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 our disclosure controls and procedures were effective at a reasonable assurance level.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the first quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

PART II – OTHER INFORMATION
ITEM 1.  
LEGAL PROCEEDINGS
As discussed in Note 3 of Notes to the Consolidated Financial Statements included in Part I. Financial Statements, Brigham is party to various legal actions arising in the ordinary course of business and does not expect these matters to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.
ITEM 1A.  
RISK FACTORS
There have been no material changes to the risk factors disclosed in Item 1A. of our report on Form 10-K for the year ended December 31, 2010.
ITEM 2.  
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
The following table provides information relating to our purchase of shares of our common stock during the three months ended March 31, 2011. The repurchases reflect shares of our employees withheld upon vesting of restricted stock to satisfy statutory minimum tax withholding obligations.
                                 
    (a)     (b)     (c)     (d)  
                    Total Number of     Maximum Number (or Approximate  
                    Shares Purchased as Part     Dollar Value) of Shares that May Yet  
    Total Number of     Average Price     of Publicly Announced     Be Purchased Under the  
Period   Shares Purchased     Paid per Share     Plans or Programs     Plans or Programs  
Month # 1
January 1, 2011 – January 31, 2011
    17,231     $ 27.15              
Month # 2
February 1, 2011 – February 28, 2011
                       
Month # 3
March 1, 2011 – March 31, 2011
                       
ITEM 3.  
DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4.  
(REMOVED AND RESERVED)
None.
ITEM 5.  
OTHER INFORMATION
None.
ITEM 6.  
EXHIBITS
         
       
 
  3.1    
Certificate of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
       
 
  3.2    
Certificates of Amendment of Certificate of Incorporation (filed as Exhibit 3.1.1 to Brigham’s Registration Statement on Form S-3 (Registration No. 333-37558) and incorporated herein by reference)
       
 
  3.3    
Bylaws, as amended through May 28, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (filed May 28, 2009) and incorporated herein by reference)
       
 
  3.4    
Certificate of Amendment of Certificate of Incorporation of Brigham Exploration Company dated June 14, 2006, (filed as Exhibit 3.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference)
       
 
  3.5    
Certificate of Amendment of Certificate of Incorporation of Brigham Exploration Company dated October 7, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (filed October 13, 2009) and incorporated herein by reference)
       
 
  4.1    
Form of Common Stock Certificate (filed as Exhibit 4.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491) and incorporated herein by reference)

 

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Table of Contents

         
       
 
  4.2    
Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference)
       
 
  4.3    
Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2000 and incorporated herein by reference)
       
 
  4.4    
Certificate of Elimination of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed August 9, 2010 (filed as Exhibit 3.7 to Brigham’s Current Report on Form 8-K (filed August 10, 2010) and incorporated herein by reference)
       
 
  4.5    
Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference)
       
 
  4.6    
Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit 99.2 to Brigham’s Current Report on Form 8-K (filed July 20, 2004) and incorporated herein by reference)
       
 
  4.7    
Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
       
 
  4.8    
Certificate of Elimination of Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham Exploration Company effective March 9, 2010 (filed as Exhibit 3.6 to Brigham’s Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)
       
 
  4.9    
Indenture, dated September 27, 2010, among the Company, the Guarantors and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.17 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
       
 
  4.10    
Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.18 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
       
 
  4.11    
Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.19 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
       
 
  10.32 *  
Fifth Amended and Restated Credit Agreement dated February 23, 2011 among Brigham Oil & Gas, L.P., Brigham Exploration Company and Brigham, Inc. and Bank of America, N.A.
       
 
  31.1 *  
Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
       
 
  31.2 *  
Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
       
 
  32.1 *  
Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350
       
 
  32.2 *  
Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
 
   
  101.INS**    
XBRL Instance Document
 
   
  101.SCH**    
XBRL Schema Document
 
   
  101.CAL**    
XBRL Calculation Linkbase Document
 
   
  101.LAB**    
XBRL Label Linkbase Document
 
   
  101.PRE**    
XBRL Presentation Linkbase Document
 
   
  101.DEF**    
XBRL Definition Linkbase Document
 
     
*  
Filed herewith
 
   
**  
Furnished herewith

 

35


Table of Contents

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  BRIGHAM EXPLORATION COMPANY
 
 
May 4, 2011  By:   /s/ BEN M. BRIGHAM    
    Ben M. Brigham   
    Chief Executive Officer, President
and Chairman of the Board 
 
     
May 4, 2011  By:   /s/ EUGENE B. SHEPHERD, JR.    
    Eugene B. Shepherd, Jr.   
    Executive Vice President
and Chief Financial Officer 
 

 

36