UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10
-
Q
(Mark One)
|
|
|
þ
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|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
For the quarterly period ended September 30, 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)
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|
Delaware
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75-2692967
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(State of other jurisdiction
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(I.R.S. Employer
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of incorporation or organization)
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Identification No.)
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6300 Bridge Point Parkway,
Building 2,
Suite 500, Austin, Texas
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78730
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(Address of principal executive offices)
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(Zip Code)
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(512) 427-3300
(Registrants 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.
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Large Accelerated Filer
þ
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Accelerated Filer
o
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Non-Accelerated Filer
o
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Smaller Reporting Company
o
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|
(Do not check if smaller reporting company)
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|
|
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
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Class
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Outstanding
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Common Stock, par value $.01 per share as of November 4, 2011
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117,318,932
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Brigham Exploration Company
Third Quarter 2011 Form 10-Q Report
TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
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|
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ITEM 1.
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|
FINANCIAL STATEMENTS
|
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
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September 30,
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December 31,
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2011
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2010
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ASSETS
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Current assets:
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Cash and cash equivalents
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$
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91,544
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$
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23,743
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Accounts receivable
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131,332
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70,368
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Short-term investments
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114,738
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223,991
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Inventory
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53,238
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34,959
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Other current assets
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26,106
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7,796
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|
|
|
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Total current assets
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416,958
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360,857
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Oil and natural gas properties, using the full cost method including
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Proved, net of accumulated depletion of $495,115 and $423,691
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761,999
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486,423
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Unproved
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433,848
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182,933
|
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1,195,847
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669,356
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Other property and equipment, net
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95,887
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|
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42,837
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|
Deferred loan fees
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17,159
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|
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9,064
|
|
Other noncurrent assets
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|
20,876
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|
|
|
3,287
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|
|
|
|
|
|
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Total assets
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|
$
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1,746,727
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|
|
$
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1,085,401
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|
|
|
|
|
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LIABILITIES AND STOCKHOLDERS EQUITY
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Current liabilities:
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Accounts payable
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$
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89,840
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$
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50,023
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Royalties payable
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82,992
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42,155
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Accrued drilling costs
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155,888
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61,067
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Participant advances received
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5,511
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3,037
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Derivative liabilities
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69
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|
|
|
9,442
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Other current liabilities
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27,315
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|
|
|
10,821
|
|
|
|
|
|
|
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Total current liabilities
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361,615
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176,545
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|
|
|
|
|
|
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Senior Notes
|
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600,000
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300,000
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|
|
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Other noncurrent liabilities
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12,074
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|
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15,586
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|
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Commitments and contingencies (Note 3)
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Stockholders equity:
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Common stock, $.01 par value, 180 million shares authorized,
116,800,125 and 116,564,182 shares issued and 116,498,651 and
116,289,180 shares outstanding at September 30, 2011 and
December 31, 2010, respectively
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1,168
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|
|
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1,166
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Additional paid-in capital
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770,920
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765,326
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Treasury stock, at cost; 301,474 and 275,002 shares at September
30, 2011 and December 31, 2010, respectively
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(3,388
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)
|
|
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(2,657
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)
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Accumulated other comprehensive income (loss)
|
|
|
(8
|
)
|
|
|
(9
|
)
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Retained earnings (deficit)
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4,346
|
|
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|
(170,556
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)
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Total stockholders equity
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773,038
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|
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593,270
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|
|
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Total liabilities and stockholders equity
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|
$
|
1,746,727
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|
|
$
|
1,085,401
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|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
1
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
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Three Months Ended
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Nine Months Ended
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September 30,
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September 30,
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2011
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2010
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2011
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2010
|
|
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Revenues:
|
|
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|
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|
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Oil and natural gas sales
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$
|
113,766
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|
|
$
|
43,663
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$
|
283,455
|
|
|
$
|
113,157
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|
Gain (loss) on derivatives, net
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|
53,094
|
|
|
|
(7,057
|
)
|
|
|
50,557
|
|
|
|
939
|
|
Support infrastructure
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|
|
1,242
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|
|
|
|
|
|
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2,726
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|
|
|
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Other revenue
|
|
|
3
|
|
|
|
4
|
|
|
|
8
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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168,105
|
|
|
|
36,610
|
|
|
|
336,746
|
|
|
|
114,113
|
|
|
|
|
|
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Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
13,595
|
|
|
|
3,964
|
|
|
|
30,039
|
|
|
|
12,684
|
|
Production taxes
|
|
|
11,483
|
|
|
|
4,250
|
|
|
|
28,632
|
|
|
|
10,658
|
|
Support infrastructure
|
|
|
610
|
|
|
|
|
|
|
|
1,329
|
|
|
|
|
|
General and administrative
|
|
|
3,359
|
|
|
|
3,255
|
|
|
|
9,906
|
|
|
|
9,052
|
|
Depletion of oil and natural gas properties
|
|
|
28,953
|
|
|
|
15,312
|
|
|
|
71,424
|
|
|
|
38,770
|
|
Depreciation and amortization
|
|
|
1,722
|
|
|
|
362
|
|
|
|
3,937
|
|
|
|
856
|
|
Accretion of discount on asset retirement obligations
|
|
|
127
|
|
|
|
103
|
|
|
|
350
|
|
|
|
312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59,849
|
|
|
|
27,246
|
|
|
|
145,617
|
|
|
|
72,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
108,256
|
|
|
|
9,364
|
|
|
|
191,129
|
|
|
|
41,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
240
|
|
|
|
1,716
|
|
|
|
949
|
|
|
|
3,056
|
|
Interest expense, net
|
|
|
(7,472
|
)
|
|
|
(2,058
|
)
|
|
|
(16,644
|
)
|
|
|
(7,893
|
)
|
Loss on redemption of Senior Notes
|
|
|
|
|
|
|
(10,948
|
)
|
|
|
|
|
|
|
(10,948
|
)
|
Other income (expense)
|
|
|
(2,333
|
)
|
|
|
1,250
|
|
|
|
4,755
|
|
|
|
3,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,565
|
)
|
|
|
(10,040
|
)
|
|
|
(10,940
|
)
|
|
|
(12,669
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
98,691
|
|
|
|
(676
|
)
|
|
|
180,189
|
|
|
|
29,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
3,822
|
|
|
|
|
|
|
|
(5,287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,822
|
|
|
|
|
|
|
|
(5,287
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
102,513
|
|
|
$
|
(676
|
)
|
|
$
|
174,902
|
|
|
$
|
29,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share available to common
stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.88
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.50
|
|
|
$
|
0.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.86
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.48
|
|
|
$
|
0.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
116,459
|
|
|
|
115,921
|
|
|
|
116,409
|
|
|
|
109,657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
118,557
|
|
|
|
115,921
|
|
|
|
118,552
|
|
|
|
111,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
2
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
|
|
|
|
|
|
|
Stockholders
|
|
|
|
Shares
|
|
|
Amounts
|
|
|
Capital
|
|
|
Stock
|
|
|
Income (Loss)
|
|
|
Retained Earnings
|
|
|
Equity
|
|
Balance, December 31, 2010
|
|
|
116,564
|
|
|
$
|
1,166
|
|
|
$
|
765,326
|
|
|
$
|
(2,657
|
)
|
|
$
|
(9
|
)
|
|
$
|
(170,556
|
)
|
|
$
|
593,270
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,902
|
|
|
|
174,902
|
|
Unrealized gains (losses)
on investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Tax benefit (provisions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,903
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercises of employee stock
options
|
|
|
84
|
|
|
|
1
|
|
|
|
669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
670
|
|
Vesting of restricted stock
|
|
|
144
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation
|
|
|
8
|
|
|
|
|
|
|
|
4,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,926
|
|
Repurchases of common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(731
|
)
|
|
|
|
|
|
|
|
|
|
|
(731
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2011
|
|
|
116,800
|
|
|
$
|
1,168
|
|
|
$
|
770,920
|
|
|
$
|
(3,388
|
)
|
|
$
|
(8
|
)
|
|
$
|
4,346
|
|
|
$
|
773,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2011
|
|
|
2010
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
174,902
|
|
|
$
|
29,112
|
|
Adjustments to reconcile net income (loss) to cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depletion of oil and natural gas properties
|
|
|
71,424
|
|
|
|
38,770
|
|
Depreciation and amortization
|
|
|
3,937
|
|
|
|
856
|
|
Stock based compensation
|
|
|
2,736
|
|
|
|
1,933
|
|
Amortization of deferred loan fees and debt issuance costs
|
|
|
1,798
|
|
|
|
1,475
|
|
Loss on early redemption of Senior Notes
|
|
|
|
|
|
|
10,948
|
|
Market value and other adjustments for derivative instruments
|
|
|
(52,997
|
)
|
|
|
1,262
|
|
Accretion of discount on asset retirement obligations
|
|
|
350
|
|
|
|
312
|
|
Deferred income taxes
|
|
|
5,287
|
|
|
|
|
|
Other noncash items
|
|
|
30
|
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(60,964
|
)
|
|
|
(21,424
|
)
|
Other current assets
|
|
|
(2,545
|
)
|
|
|
(2,218
|
)
|
Accounts payable
|
|
|
39,817
|
|
|
|
20,574
|
|
Royalties payable
|
|
|
40,837
|
|
|
|
19,336
|
|
Participant advances received
|
|
|
2,474
|
|
|
|
(4,187
|
)
|
Other current liabilities
|
|
|
16,542
|
|
|
|
(2,067
|
)
|
Other noncurrent assets and liabilities
|
|
|
(245
|
)
|
|
|
(1,461
|
)
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
243,383
|
|
|
|
93,221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties
|
|
|
(500,271
|
)
|
|
|
(279,406
|
)
|
Changes to inventory
|
|
|
(18,279
|
)
|
|
|
(14,805
|
)
|
Purchases of short term investments
|
|
|
(298,021
|
)
|
|
|
(227,604
|
)
|
Sales of short term investments
|
|
|
407,275
|
|
|
|
116,569
|
|
Additions to other property and equipment
|
|
|
(57,017
|
)
|
|
|
(14,142
|
)
|
Proceeds from the sale of assets
|
|
|
183
|
|
|
|
12,544
|
|
Decrease (increase) in drilling advances paid
|
|
|
550
|
|
|
|
(1,397
|
)
|
|
|
|
|
|
|
|
Net cash provided (used) by investing activities
|
|
|
(465,580
|
)
|
|
|
(408,241
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
|
|
|
|
277,547
|
|
Redemption of Series A mandatorily redeemable preferred stock
|
|
|
|
|
|
|
(10,101
|
)
|
Proceeds from Senior Notes offering
|
|
|
300,000
|
|
|
|
300,000
|
|
Redemption of Senior Notes
|
|
|
|
|
|
|
(162,789
|
)
|
Deferred loan fees paid and equity costs
|
|
|
(9,893
|
)
|
|
|
(6,427
|
)
|
Principal payments on capital lease obligations
|
|
|
(48
|
)
|
|
|
|
|
Proceeds from exercise of employee stock options
|
|
|
670
|
|
|
|
2,484
|
|
Repurchases of common stock
|
|
|
(731
|
)
|
|
|
(471
|
)
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
289,998
|
|
|
|
400,243
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
67,801
|
|
|
|
85,223
|
|
Cash and cash equivalents, beginning of year
|
|
|
23,743
|
|
|
|
40,781
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
91,544
|
|
|
$
|
126,004
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
4
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. Brighams exploration and development of oil and natural
gas properties is currently focused in the Williston Basin, the Onshore 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 Brighams 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. See Part
II, Item 1 Legal Proceedings.
As of September 30, 2011, there are no known environmental or other regulatory matters related
to Brighams 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 Brighams 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
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 and nine months ended September 30, 2011 and 2010 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding basic
|
|
|
116,459
|
|
|
|
115,921
|
|
|
|
116,409
|
|
|
|
109,657
|
|
Plus: Potential common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and restricted stock
|
|
|
2,098
|
|
|
|
|
|
|
|
2,143
|
|
|
|
1,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares
outstanding diluted
|
|
|
118,557
|
|
|
|
115,921
|
|
|
|
118,552
|
|
|
|
111,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options excluded from diluted
EPS due to the anti-dilutive effect
|
|
|
105
|
|
|
|
5,178
|
|
|
|
288
|
|
|
|
1,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5. Income Taxes
Based
on estimates of its 2011 annual effective tax rate, Brigham has a $5.3 million deferred
federal and state income tax expense for the nine months ended September 30, 2011. The annual
effective tax rate takes into consideration the estimated reduction in Brighams valuation
allowance through 2011. There was no federal or state tax expense (benefit) for the nine months
ended September 30, 2010.
Brigham utilizes the asset and liability approach to measure
deferred tax assets and liabilities based on temporary differences at each balance sheet date. By using the estimated 2011 annual
effective rate, the deferred tax assets and liabilities differ from those that would result if Brigham used a year-to-date effective rate.
On a year-to-date basis at September 30, 2011, Brigham has a net deferred tax liability. Using an annual effective tax rate, Brigham has
a net deferred tax asset, primarily due to its net operating loss carryovers. 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.
Based on this criteria, Brigham determined that its valuation allowance should be reduced to zero at September 30, 2011. The valuation
allowance was $62.3 million at December 31, 2010.
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, and 2008. In addition, Brigham is open to examination
for the years 1997 through 2007, 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. Brighams 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, and written call options. 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. 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
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table reflects open commodity derivative contracts at September 30, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10/01/11 12/31/11
|
|
|
90,000
|
|
|
|
|
|
|
$
|
5.75
|
|
|
$
|
7.65
|
|
10/01/11 12/31/11
|
|
|
120,000
|
|
|
|
|
|
|
$
|
5.75
|
|
|
$
|
7.40
|
|
10/01/11 12/31/11
|
|
|
120,000
|
|
|
|
|
|
|
$
|
5.00
|
|
|
$
|
6.55
|
|
Oil Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10/01/11 07/31/12
|
|
|
|
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
97.20
|
|
10/01/11 07/31/12
|
|
|
|
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
98.55
|
|
10/01/11 07/31/12
|
|
|
|
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
100.40
|
|
10/01/11 07/31/12
|
|
|
|
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
21,000
|
|
|
$
|
65.00
|
|
|
$
|
88.25
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
15,000
|
|
|
$
|
60.00
|
|
|
$
|
97.25
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
15,000
|
|
|
$
|
65.00
|
|
|
$
|
108.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
12,000
|
|
|
$
|
70.00
|
|
|
$
|
106.80
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
12,000
|
|
|
$
|
75.00
|
|
|
$
|
102.60
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
9,000
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
9,000
|
|
|
$
|
75.00
|
|
|
$
|
104.30
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
106.50
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
6,000
|
|
|
$
|
75.00
|
|
|
$
|
103.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
6,000
|
|
|
$
|
75.00
|
|
|
$
|
95.15
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
99.00
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
97.40
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
184,000
|
|
|
$
|
90.00
|
|
|
$
|
144.00
|
|
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
|
|
01/01/12 12/31/12
|
|
|
|
|
|
|
366,000
|
|
|
$
|
85.00
|
|
|
$
|
139.50
|
|
02/01/12 12/31/12
|
|
|
|
|
|
|
335,000
|
|
|
$
|
80.00
|
|
|
$
|
134.25
|
|
07/01/12 07/31/12
|
|
|
|
|
|
|
62,000
|
|
|
$
|
65.00
|
|
|
$
|
102.25
|
|
04/01/12 04/30/12
|
|
|
|
|
|
|
15,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
06/01/12 06/30/12
|
|
|
|
|
|
|
25,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
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
|
|
09/01/12 12/31/12
|
|
|
|
|
|
|
110,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
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
|
|
01/01/13 05/31/13
|
|
|
|
|
|
|
302,000
|
|
|
$
|
85.00
|
|
|
$
|
134.00
|
|
03/01/13 03/31/13
|
|
|
|
|
|
|
62,000
|
|
|
$
|
80.00
|
|
|
$
|
120.00
|
|
04/01/13 09/30/13
|
|
|
|
|
|
|
540,000
|
|
|
$
|
75.00
|
|
|
$
|
109.00
|
|
7
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
|
|
|
Purchased
|
|
|
Written
|
|
|
Written
|
|
|
|
Oil
|
|
|
Put
|
|
|
Call
|
|
|
Put
|
|
Settlement Period
|
|
(Barrels)
|
|
|
Nymex
|
|
|
Nymex
|
|
|
Nymex
|
|
Crude Oil Three Way Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/12 06/30/12
|
|
|
136,500
|
|
|
$
|
80.00
|
|
|
$
|
107.50
|
|
|
$
|
65.00
|
|
01/01/12 06/30/12
|
|
|
136,500
|
|
|
$
|
80.00
|
|
|
$
|
107.50
|
|
|
$
|
65.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
Crude
|
|
|
Purchased
|
|
|
Written
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Put
|
|
|
Call
|
|
Settlement Period
|
|
(MMBTU)
|
|
|
(Barrels)
|
|
|
Nymex
|
|
|
Nymex
|
|
Crude Oil Calls
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10/01/11 12/31/11
|
|
|
|
|
|
|
138,000
|
|
|
|
|
|
|
$
|
100.00
|
|
Crude Oil Puts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10/01/11 06/30/12
|
|
|
|
|
|
|
137,000
|
|
|
$
|
65.00
|
|
|
|
|
|
10/01/11 06/30/12
|
|
|
|
|
|
|
137,000
|
|
|
$
|
65.00
|
|
|
|
|
|
10/01/11 06/30/12
|
|
|
|
|
|
|
68,500
|
|
|
$
|
65.00
|
|
|
|
|
|
10/01/11 06/30/12
|
|
|
|
|
|
|
68,500
|
|
|
$
|
65.00
|
|
|
|
|
|
07/01/12 12/31/12
|
|
|
|
|
|
|
276,000
|
|
|
$
|
80.00
|
|
|
|
|
|
Additional Disclosures about Derivative Instruments and Hedging Activities
At September 30, 2011 and December 31, 2010, Brigham had derivative financial instruments
under FASB ASC 815 recorded on the consolidated balance sheet as set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
|
|
|
|
|
|
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
|
|
$
|
18,322
|
|
|
$
|
2,557
|
|
Natural gas and crude oil contracts
|
|
Other non-current assets
|
|
|
19,593
|
|
|
|
309
|
|
|
|
|
|
|
|
|
|
|
Total Derivative Assets
|
|
|
|
$
|
37,915
|
|
|
$
|
2,866
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil contracts
|
|
Derivative liabilities - current
|
|
$
|
(69
|
)
|
|
$
|
(9,442
|
)
|
Natural gas and crude oil contracts
|
|
Other non-current liabilities
|
|
|
|
|
|
|
(8,575
|
)
|
|
|
|
|
|
|
|
|
|
Total Derivative Liabilities
|
|
|
|
$
|
(69
|
)
|
|
$
|
(18,017
|
)
|
8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the three and nine months ended September 30, 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
|
|
|
Three Months
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 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
|
|
$
|
274
|
|
|
$
|
1,689
|
|
Crude oil contracts
|
|
Gain (loss) on derivatives, net
|
|
|
52,820
|
|
|
|
(8,746
|
)
|
|
|
|
|
|
|
|
|
|
Total Derivative Gain (loss)
|
|
|
|
$
|
53,094
|
|
|
$
|
(7,057
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Nine Months
|
|
|
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
|
Sept. 30, 2011
|
|
|
Sept. 30, 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
|
|
$
|
476
|
|
|
$
|
4,349
|
|
Crude oil contracts
|
|
Gain (loss) on derivatives, net
|
|
|
50,081
|
|
|
|
(3,410
|
)
|
|
|
|
|
|
|
|
|
|
Total Derivative Gain (loss)
|
|
|
|
$
|
50,557
|
|
|
$
|
939
|
|
|
|
|
|
|
|
|
|
|
|
The use of derivative transactions involves the risk that the counterparties will be unable to
meet the financial terms of such transactions. Brighams 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 managements best estimate of fair value.
|
As such, the fair values of Brighams derivative financial instruments reflect Brighams
estimate of the default risk of the parties in accordance with FASB ASC 820. The fair value of
Brighams 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.
9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at September 30, 2011 Using
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
|
Active Markets
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
September 30,
|
|
|
for Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
Description
|
|
2011
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
Derivative liabilities
|
|
$
|
(69
|
)
|
|
$
|
|
|
|
$
|
(69
|
)
|
|
$
|
|
|
Other non-current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
|
18,322
|
|
|
|
|
|
|
|
18,322
|
|
|
|
|
|
Other non-current assets
|
|
|
19,593
|
|
|
|
|
|
|
|
19,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
37,846
|
|
|
$
|
|
|
|
$
|
37,846
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brighams 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 Brighams 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 September 30, 2011 Using
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
|
Active Markets
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
September 30,
|
|
|
for Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
Description
|
|
2011
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
Other non-current liabilities
|
|
|
(5,403
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,403
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(5,403
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(5,403
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
10
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 September 30, 2011 Using
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
|
Active Markets
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
September 30,
|
|
|
for Identical Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
Description
|
|
2011
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
Investments
|
|
|
114,738
|
|
|
|
114,738
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
114,738
|
|
|
$
|
114,738
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes, by major security type, the fair value and any unrealized gain
(loss) of Brighams 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)
|
|
Corporate bonds and notes
|
|
$
|
114,738
|
|
|
$
|
(7
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
114,738
|
|
|
$
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
114,738
|
|
|
$
|
(7
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
114,738
|
|
|
$
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The cost basis of Brighams investments in corporate bonds and notes (in thousands) is
$116,198.
Brighams 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 Brighams 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2011
|
|
|
December 31, 2010
|
|
|
|
(in thousands)
|
|
|
(in thousands)
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
8 3/4% Senior Notes
|
|
$
|
300,000
|
|
|
$
|
327,000
|
|
|
$
|
300,000
|
|
|
$
|
325,500
|
|
6 7/8% Senior Notes
|
|
$
|
300,000
|
|
|
$
|
297,000
|
|
|
$
|
|
|
|
$
|
|
|
The fair value of Brighams 8 3/4% and 6 7/8% Senior Notes (as hereinafter defined) is based upon
current market quotes and is the estimated amount required to purchase the 8 3/4% and 6 7/8% Senior
Notes on the open market.
11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 September 30, 2011 ($4.16 per MMBtu
for Henry Hub natural gas and $94.50 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of Brighams 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 September 30, 2011.
During the second quarter 2010, Brigham sold a portion of its proved developed producing West
Texas assets for $14 million with an effective date of January 1, 2010. The proceeds for the sale
were applied to reduce the capitalized costs of oil and gas properties.
9. Support Infrastructure
Brigham recognizes revenue and expenses from its support infrastructure operations, which
provide the usage of its oil, natural gas, produced water and fresh water gathering lines for
transportation for certain operated wells. 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
8 3/4% Senior Notes
On September 27, 2010, Brigham issued $300 million of unregistered 8 3/4% Senior Notes due
October 2018 (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.
On September 27, 2010, 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. Brigham recorded a $10.9 million loss upon the purchase of the 9 5/8% Senior
Notes. On October 8, 2010, Brigham redeemed the remaining $5.6 million of the 9 5/8% Senior Notes.
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 Brighams flexibility
to manage and fund its business. At September 30, 2011, Brigham was in compliance with all
covenants under the indenture.
12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
6 7/8% Senior Notes
On May 16, 2011, Brigham issued $300 million of unregistered 6 7/8% Senior Notes due 2019 (the
6 7/8% 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.
The indenture governing the 6 7/8% Senior Notes contains customary events of default. Upon the
occurrence of certain events of default, the trustee or the holders of the 6 7/8% Senior Notes may
declare all outstanding 6 7/8% Senior Notes to be due and payable immediately. The indenture also
contains customary restrictions and covenants which could potentially limit Brighams flexibility
to manage and fund its business. At September 30, 2011, Brigham was in compliance with all
covenants under the indenture.
11. Senior Credit Facility
In February 2011, Brigham amended and restated its Senior Credit Facility to provide for
revolving credit borrowings up to $600 million, with an initial borrowing base of $325 million.
Borrowings under the 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
September 30, 2011 and December 31, 2010.
Borrowings under the Senior Credit Facility bear interest, at Brighams 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 September 30, 2011).
Borrowings under the Senior Credit Facility are collateralized by substantially all of Brighams
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 September 30, 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.
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.
13
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table summarizes Brighams asset retirement obligation transactions recorded in
accordance with the provisions of FASB ASC 410 during the nine months ended September 30, 2011 and
2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
|
2011
|
|
|
2010
|
|
Beginning asset retirement obligations
|
|
$
|
5,923
|
|
|
$
|
6,323
|
|
Liabilities incurred for new wells placed on production
|
|
|
816
|
|
|
|
548
|
|
Liabilities settled
|
|
|
(1,686
|
)
|
|
|
(141
|
)
|
Accretion of discount on asset retirement obligations
|
|
|
350
|
|
|
|
312
|
|
Revisions to estimates due to sale of oil and gas properties
|
|
|
|
|
|
|
(1,208
|
)
|
|
|
|
|
|
|
|
|
|
$
|
5,403
|
|
|
$
|
5,834
|
|
|
|
|
|
|
|
|
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 nine months ended September 30,
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 nine months ended September 30, 2011 and 2010:
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
Risk-free interest rate
|
|
|
1.17
|
%
|
|
|
2.47
|
%
|
Expected life (in years)
|
|
|
5.0
|
|
|
|
5.0
|
|
Expected volatility
|
|
|
82
|
%
|
|
|
81
|
%
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
Weighted average fair value per share of stock compensation
|
|
$
|
18.20
|
|
|
$
|
12.39
|
|
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 Brighams 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 nine months ended
September 30, 2011 and 2010.
The following table summarizes the components of stock based compensation included in general
and administrative expense (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
Pre-tax stock based compensation expense
|
|
$
|
1,668
|
|
|
$
|
1,698
|
|
|
$
|
4,926
|
|
|
$
|
3,594
|
|
Capitalized stock based compensation
|
|
|
(776
|
)
|
|
|
(804
|
)
|
|
|
(2,191
|
)
|
|
|
(1,662
|
)
|
Tax benefit
|
|
|
(312
|
)
|
|
|
(313
|
)
|
|
|
(957
|
)
|
|
|
(676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation expense, net
|
|
$
|
580
|
|
|
$
|
581
|
|
|
$
|
1,778
|
|
|
$
|
1,256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 Brighams policy to use unissued shares of stock when
stock options are exercised. As of September 30, 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 September 30, 2011, approximately 1,429,347 shares remain available for grant
under the 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 Brighams 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 nine months
ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
54,500
|
|
|
$
|
27.98
|
|
|
|
969,500
|
|
|
$
|
18.88
|
|
Forfeited or cancelled
|
|
|
(9,300
|
)
|
|
$
|
12.96
|
|
|
|
(16,800
|
)
|
|
$
|
3.92
|
|
Exercised
|
|
|
(84,020
|
)
|
|
$
|
7.98
|
|
|
|
(487,107
|
)
|
|
$
|
5.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at the end of the quarter
|
|
|
4,397,580
|
|
|
$
|
8.65
|
|
|
|
4,635,730
|
|
|
$
|
8.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at the end of the quarter
|
|
|
1,432,795
|
|
|
$
|
7.04
|
|
|
|
805,650
|
|
|
$
|
5.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant-date fair value per share of stock options granted during the nine
months ended September 30, 2011 and 2010 was $18.20 and $12.39, respectively. The total intrinsic
value of options exercised during the nine months ended September 30, 2011 and 2010 was $1.2
million and $1.2 million, respectively.
The following table summarizes information about stock options outstanding and exercisable at
September 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
Number
|
|
|
Weighted-
|
|
|
|
|
|
|
Number
|
|
|
Weighted-
|
|
|
|
|
|
|
Outstanding at
|
|
|
Average
|
|
|
Weighted-
|
|
|
Exercisable at
|
|
|
Average
|
|
|
Weighted-
|
|
|
|
September 30,
|
|
|
Remaining
|
|
|
Average
|
|
|
September 30,
|
|
|
Remaining
|
|
|
Average
|
|
Exercise Price
|
|
2011
|
|
|
Contractual Life
|
|
|
Exercise Price
|
|
|
2011
|
|
|
Contractual Life
|
|
|
Exercise Price
|
|
$2.20 to $3.11
|
|
|
1,064,000
|
|
|
7.5 years
|
|
$
|
2.24
|
|
|
|
350,000
|
|
|
7.4 years
|
|
$
|
2.25
|
|
3.66 to 5.08
|
|
|
357,600
|
|
|
4.0 years
|
|
$
|
5.08
|
|
|
|
89,400
|
|
|
4.0 years
|
|
$
|
5.08
|
|
5.96 to 6.23
|
|
|
1,586,480
|
|
|
7.3 years
|
|
$
|
5.98
|
|
|
|
652,995
|
|
|
6.5 years
|
|
$
|
6.00
|
|
7.22 to 8.77
|
|
|
110,000
|
|
|
3.1 years
|
|
$
|
7.51
|
|
|
|
68,000
|
|
|
2.8 years
|
|
$
|
7.44
|
|
8.93 to 13.86
|
|
|
214,500
|
|
|
5.1 years
|
|
$
|
11.80
|
|
|
|
92,500
|
|
|
2.3 years
|
|
$
|
11.05
|
|
14.43 to 16.85
|
|
|
62,000
|
|
|
8.7 years
|
|
$
|
15.24
|
|
|
|
12,400
|
|
|
8.7 years
|
|
$
|
15.24
|
|
18.36 to 27.15
|
|
|
969,000
|
|
|
8.5 years
|
|
$
|
19.67
|
|
|
|
167,500
|
|
|
8.6 years
|
|
$
|
19.12
|
|
28.00 to 30.20
|
|
|
34,000
|
|
|
9.8 years
|
|
$
|
29.31
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$2.20 to $30.20
|
|
|
4,397,580
|
|
|
7.2 years
|
|
$
|
8.65
|
|
|
|
1,432,795
|
|
|
6.4 years
|
|
$
|
7.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The aggregate intrinsic value of options outstanding and exercisable at September 30, 2011 was
$93.5 million and $32.8 million, respectively. The aggregate intrinsic value represents the total
pre-tax value (the difference between Brighams 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 September 30,
2011. The amount of aggregate intrinsic value will change based on the fair market value of
Brighams stock.
As of September 30, 2011, there was approximately $14.2 million of total unrecognized
compensation expense related to unvested stock based compensation plans. This compensation expense
is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining
vesting period of approximately 5 years.
Restricted Stock
During the nine months ended September 30, 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 September 30, 2011, there was approximately $8.8 million of total unrecognized
compensation expense related to unvested restricted stock. This compensation expense is expected
to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.5 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 nine months ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
(1,863
|
)
|
|
$
|
23.84
|
|
|
|
(600
|
)
|
|
$
|
5.26
|
|
Lapse of restrictions
|
|
|
(144,423
|
)
|
|
$
|
10.21
|
|
|
|
(119,760
|
)
|
|
$
|
7.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding at the end of the quarter
|
|
|
657,928
|
|
|
$
|
17.25
|
|
|
|
541,993
|
|
|
$
|
8.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the nine months ended September 30, 2011, Brigham also issued 7,500 shares of certain
non-plan stock to non-employee directors. The shares of non-plan stock vested immediately and
Brigham recognized approximately $199,000 of compensation expense.
15. Comprehensive Income
For the periods indicated, comprehensive income (loss) consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
2011
|
|
|
2010
|
|
|
20101
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
102,513
|
|
|
$
|
(676
|
)
|
|
$
|
174,902
|
|
|
$
|
29,112
|
|
Unrealized gains (losses) on investments
|
|
|
52
|
|
|
|
220
|
|
|
|
1
|
|
|
|
(1,861
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net
|
|
$
|
102,565
|
|
|
$
|
(456
|
)
|
|
$
|
174,903
|
|
|
$
|
27,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
16. Subsequent Events
On October 17, 2011, Brigham entered into a definitive merger
agreement with Statoil ASA
(Parent) and Fargo Acquisition Inc.
(Purchaser) to purchase all the issued and outstanding
shares of common stock of Brigham Exploration Company for
$36.50 per share by means of an all cash tender offer net to the
stockholder without interest, less any applicable with holding taxes. The tender offer commenced on
October 28, 2011 and is scheduled to expire, unless extended, at 12:00 midnight, New York City time
at the end of Wednesday, November 30, 2011.
The agreement contains certain termination rights that provide that,
upon termination of the agreement by Brigham under specified
circumstances, Brigham would be required to pay a termination fee of
$137 million.
17. Related Party Transactions
During the nine months ended September 30, 2011 and 2010, Brigham incurred costs of
approximately $7.7 million and $7.2 million, respectively, in fees for land acquisition services
performed by Brigham Land Management, owned by a brother of Brighams Chairman, President and Chief
Executive Officer and its Executive Vice President Land and Administration. Other participants in
Brighams 3-D seismic projects reimbursed Brigham for a portion of these amounts. At September 30,
2011 and December 31, 2010, Brigham had a liability recorded in accounts payable of approximately
$499,000 and $1,000, respectively, related to services performed by this company.
During the nine months ended September 30, 2011 and 2010, Brigham incurred costs of
approximately $1.4 million and $1.4 million, respectively, in fees for services performed by a
service company in which Mr. Hobart Smith, one of Brighams current directors, owns stock and
serves as a consultant. At September 30, 2011 and December 31, 2010, Brigham had a liability
recorded in accounts payable of approximately $349,000 and $219,000, respectively, related to
services performed by this company.
17
|
|
|
ITEM 2.
|
|
MANAGEMENTS 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 and nine month periods ended September 30, 2011 and September 30, 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 were 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 and Three Forks objectives. We have
approximately 376,000 net leasehold acres in the Williston Basin. Through the third quarter 2011,
we have invested in excess of $1.2 billion on drilling, land and support infrastructure in this
region.
In total, we have drilled 98 consecutive long lateral high frac stage
Bakken and three forks wells in North Dakota at an average early
24-hour peak rate of approximately 2,819 barrels of oil equivalent.
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 Third Quarter 2011
Third quarter 2011 crude oil prices, excluding realized and unrealized derivative hedging
results, increased 26% from that in the third quarter 2010. In the third quarter 2011, the average
sales price that we received for crude oil, excluding realized and unrealized derivative hedging
results, was $84.60 per barrel, which represents a $17.53 per barrel increase from that in the
third quarter 2010. Third quarter 2011 natural gas prices inclusive of natural gas liquids, but
excluding realized and unrealized derivative hedging results, increased 29% from that in the third
quarter 2010. In the third 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 $6.41 per Mcf, which represents a $1.43 per Mcf increase from that in the third quarter 2010.
Our third quarter 2011 production volumes were 16,380 barrels of equivalent per day, which
represents a 93% increase from last years third quarter production volumes. Crude oil represented
86% of our production volumes in the third quarter 2011 as compared to 75% of our production
volumes in the third 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 objectives. Our third quarter 2011 production volumes included approximately 13,863 barrels
of crude oil added to inventory during the quarter. Adjusting our third quarter 2011 production
volumes for our increased level of inventory resulted in sales volumes of 16,226 barrels of
equivalent per day in the third quarter 2011 versus sales volumes of 8,427 barrels of equivalent
per day in the third quarter 2010.
Our third quarter 2011 crude oil revenue, including cash hedge settlements but excluding
unrealized hedging gains and losses, increased $67.3 million, or 178%, compared to that in the
third quarter 2010. Crude oil revenue increased $45.9 million due to higher sales volumes and
$21.9 million due to higher sales prices. These increases were partially offset by a $0.5 million
decrease in crude oil cash hedge settlements.
18
Third quarter 2011 natural gas revenue, including cash hedge settlements but excluding
unrealized hedging gains and losses, increased $2.0 million from that in the third quarter 2010.
Natural gas revenue increased $1.8 million due to higher sales prices and $0.5 million due to
higher sales volumes. These increases were partially offset by a $0.3 million decrease in natural
gas cash hedge settlements.
Third quarter 2011 operating income was $108.3 million versus $9.4 million in the third
quarter last year. The improvement in revenue associated with higher sales volumes, higher
commodity prices and higher unrealized mark-to-market hedging gains was partially offset by lower
cash hedge settlements. Higher revenue was also partially offset by increased depletion, lease
operating and production tax expenses.
As of September 30, 2011, we had $206.3 million in cash, cash equivalents and short term
investments and $1.7 billion in total assets. Short term investments totaling $114.7 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 September 30, 2011 also includes
approximately $15.0 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.
Subsequent Events
On October 17, 2011, Brigham entered into a definitive merger
agreement with Statoil ASA
(Parent) and Fargo Acquisition Inc.
(Purchaser) to purchase all the issued and outstanding
shares of common stock of Brigham Exploration Company for
$36.50 per share by means of an all cash tender offer net to the
stockholder without interest, less any applicable with holding taxes. The tender offer commenced on
October 28, 2011 and is scheduled to expire, unless extended, at 12:00 midnight, New York City time
at the end of Wednesday, November 30, 2011.
The agreement contains certain termination rights that provide that,
upon termination of the agreement by Brigham under specified
circumstances, Brigham would be required to pay a termination fee of
$137 million.
19
Results for the Three and Nine Months Ended September 30, 2011
Comparison of the three month and nine month periods ended September 30, 2011 and 2010.
Production volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MBbls)(1)
|
|
|
1,262
|
|
|
|
121
|
%
|
|
|
572
|
|
|
|
3,010
|
|
|
|
116
|
%
|
|
|
1,394
|
|
Natural gas (MMcf)
|
|
|
1,271
|
|
|
|
9
|
%
|
|
|
1,163
|
|
|
|
3,486
|
|
|
|
4
|
%
|
|
|
3,344
|
|
Total (MBoe)(2)
|
|
|
1,474
|
|
|
|
93
|
%
|
|
|
766
|
|
|
|
3,591
|
|
|
|
84
|
%
|
|
|
1,952
|
|
Average daily production (Boe/d)(3)
|
|
|
16,380
|
|
|
|
93
|
%
|
|
|
8,509
|
|
|
|
13,300
|
|
|
|
84
|
%
|
|
|
7,228
|
|
|
|
|
(1)
|
|
Includes approximately 13,863 and 7,395 barrels of crude oil produced in the Williston
Basin and added to inventory during the third quarters 2011 and 2010, respectively.
Includes approximately 32,751 and 17,496 barrels of crude oil produced in the Williston
Basin and added to inventory during the first nine months 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.
|
Sales Volumes (Production volumes less the Incremental Change in Inventory)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MBbls)(1)
|
|
|
1,248
|
|
|
|
121
|
%
|
|
|
565
|
|
|
|
2,977
|
|
|
|
116
|
%
|
|
|
1,377
|
|
Natural gas (MMcf)
|
|
|
1,271
|
|
|
|
9
|
%
|
|
|
1,163
|
|
|
|
3,486
|
|
|
|
4
|
%
|
|
|
3,344
|
|
Total (MBoe)(2)
|
|
|
1,460
|
|
|
|
93
|
%
|
|
|
758
|
|
|
|
3,558
|
|
|
|
84
|
%
|
|
|
1,934
|
|
Average daily production (Boe/d)(3)
|
|
|
16,226
|
|
|
|
93
|
%
|
|
|
8,427
|
|
|
|
13,179
|
|
|
|
84
|
%
|
|
|
7,163
|
|
|
|
|
(1)
|
|
Excludes approximately 13,863 and 7,395 barrels of crude oil produced in the Williston
Basin and added to inventory during the third quarters 2011 and 2010, respectively.
Excludes approximately 32,751 and 17,496 barrels of crude oil produced in the Williston
Basin and added to inventory during the first nine months 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 86% of our third quarter 2011 production volumes and 84% of our first
nine months 2011 production volumes, compared to 75% in the third quarter 2010 and 71% in the first
nine months 2010.
20
Revenues, Commodity Prices and Hedging
The following table sets forth our production volumes, 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 September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue
|
|
$
|
105,617
|
|
|
|
179
|
%
|
|
$
|
37,868
|
|
|
$
|
262,574
|
|
|
|
176
|
%
|
|
$
|
95,161
|
|
Crude oil derivative settlement
gains (losses)
|
|
|
(448
|
)
|
|
NM
|
|
|
|
|
|
|
|
(4,331
|
)
|
|
|
1,800
|
%
|
|
|
(228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue including
derivative settlements
|
|
$
|
105,169
|
|
|
|
178
|
%
|
|
$
|
37,868
|
|
|
$
|
258,243
|
|
|
|
172
|
%
|
|
$
|
94,933
|
|
Crude oil derivative unrealized
gains (losses)
|
|
|
53,268
|
|
|
NM
|
|
|
|
(8,746
|
)
|
|
|
54,412
|
|
|
NM
|
|
|
|
(3,183
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue including
derivative settlements and
unrealized gains (losses)
|
|
$
|
158,437
|
|
|
|
444
|
%
|
|
$
|
29,122
|
|
|
$
|
312,655
|
|
|
|
241
|
%
|
|
$
|
91,750
|
|
Natural gas revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue
|
|
$
|
8,149
|
|
|
|
41
|
%
|
|
$
|
5,795
|
|
|
$
|
20,881
|
|
|
|
16
|
%
|
|
$
|
17,996
|
|
Natural gas derivative settlement
gains (losses)
|
|
|
426
|
|
|
|
(44
|
%)
|
|
|
757
|
|
|
|
1,891
|
|
|
|
(22
|
%)
|
|
|
2,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue including
derivative settlements
|
|
$
|
8,575
|
|
|
|
31
|
%
|
|
$
|
6,552
|
|
|
$
|
22,772
|
|
|
|
11
|
%
|
|
$
|
20,424
|
|
Natural gas derivative unrealized
gains (losses)
|
|
|
(152
|
)
|
|
NM
|
|
|
|
932
|
|
|
|
(1,415
|
)
|
|
NM
|
|
|
|
1,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue including
derivative settlements and
unrealized gains (losses)
|
|
$
|
8,423
|
|
|
|
13
|
%
|
|
$
|
7,484
|
|
|
$
|
21,357
|
|
|
|
(4
|
%)
|
|
$
|
22,346
|
|
Crude oil and natural gas revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas revenue
|
|
$
|
113,766
|
|
|
|
161
|
%
|
|
$
|
43,663
|
|
|
$
|
283,455
|
|
|
|
150
|
%
|
|
$
|
113,157
|
|
Crude oil and natural gas
derivative settlement gains
(losses)
|
|
|
(22
|
)
|
|
NM
|
|
|
|
757
|
|
|
|
(2,440
|
)
|
|
NM
|
|
|
|
2,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas revenue
including derivative settlements
|
|
|
113,744
|
|
|
|
156
|
%
|
|
|
44,420
|
|
|
|
281,015
|
|
|
|
144
|
%
|
|
|
115,357
|
|
Crude oil and natural gas
derivative unrealized gains
(losses)
|
|
|
53,116
|
|
|
NM
|
|
|
|
(7,814
|
)
|
|
|
52,997
|
|
|
NM
|
|
|
|
(1,261
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas revenue
including derivative settlements
and unrealized gains (losses)
|
|
|
166,860
|
|
|
|
356
|
%
|
|
|
36,606
|
|
|
|
334,012
|
|
|
|
193
|
%
|
|
|
114,096
|
|
Support infrastructure
|
|
|
1,242
|
|
|
NM
|
|
|
|
|
|
|
|
2,726
|
|
|
NM
|
|
|
|
|
|
Other revenue
|
|
|
3
|
|
|
|
(25
|
%)
|
|
|
4
|
|
|
|
8
|
|
|
|
(53
|
%)
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
168,105
|
|
|
|
359
|
%
|
|
$
|
36,610
|
|
|
$
|
336,746
|
|
|
|
195
|
%
|
|
$
|
114,113
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average crude oil prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil price (per Bbl)
|
|
$
|
84.60
|
|
|
|
26
|
%
|
|
$
|
67.07
|
|
|
$
|
88.19
|
|
|
|
28
|
%
|
|
$
|
69.12
|
|
Crude oil price including
derivative settlement gains
(losses) (per Bbl)
|
|
|
84.24
|
|
|
|
26
|
%
|
|
|
67.07
|
|
|
|
86.74
|
|
|
|
26
|
%
|
|
|
68.97
|
|
Crude oil price including
derivative settlements and
unrealized gains (losses) (per Bbl)
|
|
$
|
126.91
|
|
|
|
146
|
%
|
|
$
|
51.58
|
|
|
$
|
105.01
|
|
|
|
58
|
%
|
|
$
|
66.64
|
|
Average natural gas prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price (per Mcf)
|
|
$
|
6.41
|
|
|
|
29
|
%
|
|
$
|
4.98
|
|
|
$
|
5.99
|
|
|
|
11
|
%
|
|
$
|
5.38
|
|
Natural gas price including
derivative settlement gains
(losses) (per Mcf)
|
|
|
6.74
|
|
|
|
20
|
%
|
|
|
5.63
|
|
|
|
6.53
|
|
|
|
7
|
%
|
|
|
6.11
|
|
Natural gas price including
derivative settlements and
unrealized gains (losses) (per Mcf)
|
|
$
|
6.63
|
|
|
|
3
|
%
|
|
$
|
6.44
|
|
|
$
|
6.13
|
|
|
|
(8
|
%)
|
|
$
|
6.68
|
|
Average crude oil equivalent prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil equivalent price (per Boe)
|
|
$
|
77.90
|
|
|
|
35
|
%
|
|
$
|
57.57
|
|
|
$
|
79.66
|
|
|
|
36
|
%
|
|
$
|
58.51
|
|
Crude oil equivalent price
including derivative settlement
gains (losses) (per Boe)
|
|
|
77.89
|
|
|
|
33
|
%
|
|
|
58.57
|
|
|
|
78.98
|
|
|
|
32
|
%
|
|
|
59.64
|
|
Crude oil equivalent price
including derivative settlements
and unrealized gains (losses) (per
Boe)
|
|
$
|
114.26
|
|
|
|
137
|
%
|
|
$
|
48.27
|
|
|
$
|
93.87
|
|
|
|
59
|
%
|
|
$
|
58.99
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three
|
|
|
For the nine
|
|
|
|
month periods
|
|
|
month periods
|
|
|
|
ended September 30,
|
|
|
ended September 30,
|
|
|
|
2011 and 2010
|
|
|
2011 and 2010
|
|
|
|
|
|
|
|
|
|
|
Change in revenue from the sale of crude oil
|
|
|
|
|
|
|
|
|
Volume variance impact
|
|
$
|
45,865
|
|
|
$
|
110,628
|
|
Price variance impact
|
|
|
21,884
|
|
|
|
56,785
|
|
Cash settlement of hedging contracts
|
|
|
(448
|
)
|
|
|
(4,103
|
)
|
Unrealized hedge gain or loss
|
|
|
62,014
|
|
|
|
57,595
|
|
|
|
|
|
|
|
|
Total change
|
|
$
|
129,315
|
|
|
$
|
220,905
|
|
|
|
|
|
|
|
|
Change in revenue from the sale of natural gas
|
|
|
|
|
|
|
|
|
Volume variance impact
|
|
$
|
536
|
|
|
$
|
758
|
|
Price variance impact
|
|
|
1,818
|
|
|
|
2,127
|
|
Cash settlement of hedging contracts
|
|
|
(331
|
)
|
|
|
(537
|
)
|
Unrealized hedge gain or loss
|
|
|
(1,084
|
)
|
|
|
(3,337
|
)
|
|
|
|
|
|
|
|
Total change
|
|
$
|
939
|
|
|
$
|
(989
|
)
|
|
|
|
|
|
|
|
Change in revenue from the sale of crude oil and natural gas
|
|
|
|
|
|
|
|
|
Volume variance impact
|
|
$
|
46,401
|
|
|
$
|
111,386
|
|
Price variance impact
|
|
|
23,702
|
|
|
|
58,912
|
|
Cash settlement of hedging contracts
|
|
|
(779
|
)
|
|
|
(4,640
|
)
|
Unrealized hedge gain or loss
|
|
|
60,930
|
|
|
|
54,258
|
|
|
|
|
|
|
|
|
Total change
|
|
$
|
130,254
|
|
|
$
|
219,916
|
|
|
|
|
|
|
|
|
22
Third quarter 2011 crude oil and natural gas revenues including derivative cash settlements
and unrealized gains (losses) increased $130.3 million when compared to the third quarter 2010.
The change in revenues was attributable to the following:
|
|
|
a $53.2 million unrealized derivative gain in third quarter 2011 versus a $7.8 million
unrealized derivative loss in third quarter 2010 increased revenues by $61.0 million;
|
|
|
|
an increase in crude oil and natural gas sales volumes of 121% and 9%, respectively,
resulted in a $46.4 million increase in revenues;
|
|
|
|
an increase in pre-hedge crude oil and natural gas prices of 26% and 29%, respectively,
increased revenues by $23.7 million; and
|
|
|
|
a minimal cash loss from the settlement of derivative contracts in the third quarter
2011 versus a $0.8 million cash gain from the settlement of derivative contracts in the
third quarter 2010 decreased revenues by $0.8 million.
|
First nine months 2011 crude oil and natural gas revenues including derivative cash
settlements and unrealized gains (losses) increased $219.9 million when compared to that in the
first nine months 2010. The change in revenues was attributable to the following:
|
|
|
an increase in crude oil and natural gas sales volumes of 116% and 4%, respectively,
drove a $111.4 million increase in revenues;
|
|
|
|
an increase in pre-hedge crude oil and natural gas prices of 28% and 11%, respectively,
increased revenues by $58.9 million;
|
|
|
|
a $53.0 million unrealized derivative gain in first nine months 2011 versus a $1.3
million unrealized derivative loss in first nine months 2010 increased revenues by $54.3
million; and
|
|
|
|
a $2.5 million cash loss from the settlement of derivative contracts in the first nine
months 2011 versus a $2.2 million cash gain from the settlement of derivative contracts in
first nine months 2010 decreased revenues by $4.7 million.
|
Hedging.
We utilize collars, three way costless collars and puts to (i) reduce the effect of
price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and
(iii) provide a base level of cash flow in order to assure we can execute at least a portion of our
capital spending plans.
The following table details derivative contracts that settled during the third quarter and
first nine months 2011 and 2010 and includes the type of derivative contract, the volume, the
weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon
settlement.
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls)
|
|
|
698,000
|
|
|
|
117
|
%
|
|
|
322,000
|
|
|
|
1,772,000
|
|
|
|
161
|
%
|
|
|
678,000
|
|
Average floor price ($ per Bo)
|
|
$
|
67.69
|
|
|
|
6
|
%
|
|
$
|
63.92
|
|
|
$
|
66.61
|
|
|
|
8
|
%
|
|
$
|
61.88
|
|
Average ceiling price ($ per Bo)
|
|
$
|
103.57
|
|
|
|
9
|
%
|
|
$
|
94.60
|
|
|
$
|
100.55
|
|
|
|
10
|
%
|
|
$
|
91.64
|
|
Gain (loss) upon settlement ($ in
thousands)
|
|
$
|
(448
|
)
|
|
NM
|
|
|
$
|
|
|
|
$
|
(4,331
|
)
|
|
|
1,800
|
%
|
|
$
|
(228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) upon settlement ($ in
thousands)
|
|
$
|
(448
|
)
|
|
NM
|
|
|
$
|
|
|
|
$
|
(4,331
|
)
|
|
|
1,800
|
%
|
|
$
|
(228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
330,000
|
|
|
|
(52
|
%)
|
|
|
690,000
|
|
|
|
1,200,000
|
|
|
|
(33
|
%)
|
|
|
1,800,000
|
|
Average floor price ($ per MMbtu)
|
|
$
|
5.48
|
|
|
|
(1
|
%)
|
|
$
|
5.51
|
|
|
$
|
5.79
|
|
|
|
5
|
%
|
|
$
|
5.50
|
|
Average ceiling price ($ per MMbtu)
|
|
$
|
7.16
|
|
|
|
2
|
%
|
|
$
|
7.02
|
|
|
$
|
7.44
|
|
|
|
6
|
%
|
|
$
|
7.02
|
|
Gain (loss) upon settlement ($ in
thousands)
|
|
$
|
426
|
|
|
|
(44
|
%)
|
|
$
|
757
|
|
|
$
|
1,891
|
|
|
|
2
|
%
|
|
$
|
1,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
$
|
426
|
|
|
|
(44
|
%)
|
|
$
|
757
|
|
|
$
|
1,891
|
|
|
|
(22
|
%)
|
|
$
|
2,428
|
|
Support infrastructure.
Revenue from support infrastructure comes from fees related to
our support infrastructure assets in the Williston Basin, including fees from crude oil, natural
gas, produced water and fresh water gathering lines as well as produced water disposal wells. Two
of 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. A second
produced water disposal well in Rough Rider became operational at the end of the second quarter
2011. Our crude oil, produced water and fresh water gathering lines are expected to be operational
in the fourth quarter 2011 and first quarter 2012.
Other revenue
. Other revenue relates to fees that we charge other parties who use our gas
gathering systems that we own outside the Williston Basin to move their production from the
wellhead to first party gas pipeline systems.
Operating costs and expenses
Production costs.
We believe that per unit of production measures are the best ways 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 September 30,
|
|
|
Three months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance
|
|
$
|
6.89
|
|
|
|
50
|
%
|
|
$
|
4.58
|
|
|
$
|
10,063
|
|
|
|
190
|
%
|
|
$
|
3,470
|
|
Expensed workovers
|
|
|
2.03
|
|
|
|
534
|
%
|
|
|
0.32
|
|
|
|
2,957
|
|
|
|
1,112
|
%
|
|
|
244
|
|
Ad valorem taxes
|
|
|
0.39
|
|
|
|
18
|
%
|
|
|
0.33
|
|
|
|
575
|
|
|
|
130
|
%
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
9.31
|
|
|
|
78
|
%
|
|
$
|
5.23
|
|
|
$
|
13,595
|
|
|
|
243
|
%
|
|
$
|
3,964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
7.87
|
|
|
|
40
|
%
|
|
|
5.61
|
|
|
|
11,483
|
|
|
|
170
|
%
|
|
|
4,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
17.18
|
|
|
|
58
|
%
|
|
$
|
10.84
|
|
|
$
|
25,078
|
|
|
|
205
|
%
|
|
$
|
8,214
|
|
24
Third quarter 2011 per unit of production costs increased $6.34 per Boe, or 58%, when
compared to that in the third quarter last year, primarily due to the following:
|
|
|
operating and maintenance expenses increased $2.31 per Boe, or 50%, due to increased
costs associated with surface location and road repairs following the record winter
snowfall melt and heavy rains and higher produced water disposal
costs;
|
|
|
|
production taxes increased $2.26 per Boe, or 40%, 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
|
|
|
|
expensed workovers increased $1.71 per Boe, or 534%, due to an increase in major,
non-recurring repairs following the record winter snowfall melt and heavy rains.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-of-Production
|
|
|
Amount
|
|
|
|
(Per Boe)
|
|
|
(In thousands)
|
|
|
|
Nine months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance
|
|
$
|
6.19
|
|
|
|
34
|
%
|
|
$
|
4.61
|
|
|
$
|
22,014
|
|
|
|
147
|
%
|
|
$
|
8,915
|
|
Expensed workovers
|
|
|
1.77
|
|
|
|
13
|
%
|
|
|
1.56
|
|
|
|
6,300
|
|
|
|
109
|
%
|
|
|
3,019
|
|
Ad valorem taxes
|
|
|
0.48
|
|
|
|
23
|
%
|
|
|
0.39
|
|
|
|
1,725
|
|
|
|
130
|
%
|
|
|
750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
8.44
|
|
|
|
29
|
%
|
|
$
|
6.56
|
|
|
$
|
30,039
|
|
|
|
137
|
%
|
|
$
|
12,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
8.05
|
|
|
|
46
|
%
|
|
|
5.51
|
|
|
|
28,632
|
|
|
|
169
|
%
|
|
|
10,658
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
16.49
|
|
|
|
37
|
%
|
|
$
|
12.07
|
|
|
$
|
58,671
|
|
|
|
151
|
%
|
|
$
|
23,342
|
|
First nine months 2011 per unit of production costs increased $4.42 per Boe, or 37%, when
compared to the first nine months last year mainly due to the following:
|
|
|
production taxes increased $2.54 per Boe, or 46%, due to higher commodity sales prices
and higher crude oil sales volumes in North Dakota, which are subject to a 11.5% tax rate;
|
|
|
|
operating and maintenance expenses increased $1.58 per Boe, or 34%, due to increased
costs associated with surface location and road repairs following the record winter
snowfall melt and heavy rains and higher produced water disposal
costs; and
|
|
|
|
expensed workovers increased $0.21 per Boe, or 13%, due to an increase in major,
non-recurring repairs following the record winter snowfall melt and heavy rains.
|
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 September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
(In thousands, except per unit measurements)
|
|
General and administrative costs
|
|
$
|
6,698
|
|
|
|
7
|
%
|
|
$
|
6,255
|
|
|
$
|
19,598
|
|
|
|
12
|
%
|
|
$
|
17,503
|
|
Capitalized general and administrative costs
|
|
|
(3,339
|
)
|
|
|
11
|
%
|
|
|
(3,000
|
)
|
|
|
(9,692
|
)
|
|
|
15
|
%
|
|
|
(8,451
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
3,359
|
|
|
|
3
|
%
|
|
$
|
3,255
|
|
|
$
|
9,906
|
%
|
|
|
9
|
%
|
|
$
|
9,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense ($ per Boe)
|
|
$
|
2.30
|
|
|
|
(46
|
%)
|
|
$
|
4.29
|
|
|
$
|
2.78
|
|
|
|
(41
|
%)
|
|
$
|
4.68
|
|
Our general and administrative costs prior to capitalization for the third quarter 2011
increased primarily because of higher financial reporting, travel and professional costs. Our
general and administrative costs prior to capitalization for the nine months ended September 2011
increased primarily because of higher compensations costs attributable to higher stock compensation
costs and 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. Our per unit costs in both the three and nine months periods ended September 2011
decreased due to our higher sales volumes.
25
Depletion of 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 September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
(In thousands, except per unit measurements)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of oil and natural gas properties
|
|
$
|
28,953
|
|
|
|
89
|
%
|
|
$
|
15,312
|
|
|
$
|
71,424
|
|
|
|
84
|
%
|
|
$
|
38,770
|
|
Depletion of oil and natural gas
properties ($ per Boe)
|
|
$
|
19.83
|
|
|
|
(2
|
%)
|
|
$
|
20.20
|
|
|
$
|
20.07
|
|
|
|
0
|
%
|
|
$
|
20.05
|
|
Our depletion expense for the third quarter 2011 was $13.6 million higher than that in
the third quarter 2010. Higher sales volumes increased depletion expense by $14.2 million, while a
lower depletion rate decreased depletion expense by $0.6 million.
Our depletion expense for the first nine months 2011 was $32.7 million higher than that in the
first nine months 2010. Higher sales volumes and a higher depletion rate increased depletion
expense by $32.6 million and $0.1 million, respectively.
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 substantial downward revisions in our estimated proved
reserves.
During the three and nine month periods ended September 30, 2011 and 2010, no ceiling test
impairment was recorded.
26
Net interest expense.
Interest on our 8 3/4% and 6 7/8% 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 September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on Senior Notes
|
|
$
|
11,719
|
|
|
|
195
|
%
|
|
$
|
3,977
|
|
|
$
|
27,250
|
|
|
|
133
|
%
|
|
$
|
11,677
|
|
Interest on Senior Credit Facility
|
|
|
11
|
|
|
NM
|
|
|
|
|
|
|
|
139
|
|
|
NM
|
|
|
|
|
|
Commitment fees
|
|
|
429
|
|
|
|
166
|
%
|
|
|
161
|
|
|
|
1,090
|
|
|
|
124
|
%
|
|
|
487
|
|
Dividend on mandatorily
redeemable preferred stock
|
|
|
|
|
|
|
0
|
%
|
|
|
|
|
|
|
|
|
|
NM
|
|
|
|
269
|
|
Amortization of deferred loan and
debt issuance cost
|
|
|
643
|
|
|
|
48
|
%
|
|
|
435
|
|
|
|
1,751
|
|
|
|
25
|
%
|
|
|
1,398
|
|
Other general interest expense
|
|
|
11
|
|
|
NM
|
|
|
|
|
|
|
|
110
|
|
|
|
9
|
%
|
|
|
101
|
|
Capitalized interest expense
|
|
|
(5,341
|
)
|
|
|
112
|
%
|
|
|
(2,515
|
)
|
|
|
(13,696
|
)
|
|
|
127
|
%
|
|
|
(6,039
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense
|
|
$
|
7,472
|
|
|
|
263
|
%
|
|
$
|
2,058
|
|
|
$
|
16,644
|
|
|
|
111
|
%
|
|
$
|
7,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average debt outstanding
|
|
$
|
600,437
|
|
|
|
261
|
%
|
|
$
|
166,331
|
|
|
$
|
455,743
|
|
|
|
171
|
%
|
|
$
|
168,091
|
|
Average interest rate on
outstanding indebtedness (a)
|
|
|
8.0
|
%
|
|
|
|
|
|
|
9.9
|
%
|
|
|
8.4
|
%
|
|
|
|
|
|
|
10.0
|
%
|
|
|
|
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.
|
Third quarter 2011 interest expense was $5.4 million higher than that in 2010 primarily due to
a $7.7 million increase in interest expense associated with our 8 3/4% and 6 7/8% Senior Notes that
were issued in September 2010 and May 2011, respectively. This increase was partially offset by a
$2.8 million increase in capitalized interest expense associated with our higher level of activity
in the Williston Basin.
First nine months 2011 interest expense was $8.8 million higher than that in 2010 primarily
due to a $15.6 million increase in interest expense associated with our 8 3/4% and 6 7/8% Senior
Notes that were issued in September 2010 and May 2011, respectively. This increase was partially
offset by a $7.7 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 September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
2011
|
|
|
%
Change
|
|
|
2010
|
|
|
|
(In thousands)
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
|
|
$
|
(2,333
|
)
|
|
NM
|
|
|
$
|
1,250
|
|
|
$
|
4,755
|
|
|
|
53
|
%
|
|
$
|
3,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
income decreased in third quarter 2011 as a result of costs to refurbish drilling
pipe.
Brigham utilizes the asset and
liability approach to measure deferred tax assets and liabilities based on temporary differences at each
balance sheet date. By using the estimated 2011 annual effective rate, the deferred tax assets and liabilities
differ from those that would result if Brigham used a year-to-date effective rate. On a year-to-date basis at
September 30, 2011, Brigham has a net deferred tax liability. Using an annual effective tax rate, Brigham has
a net deferred tax asset, primarily due to its net operating loss carryovers. 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. Based on this criteria, Brigham determined that its
valuation allowance should be reduced to zero at September 30, 2011. The valuation allowance was $62.3 million
at December 31, 2010.
27
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we operate the
majority of our wells. We have long-term capital commitment expenditures with a drilling
contractor for four walking drilling rigs for a three year period beginning on their delivery dates, two of which are expected to be delivered in early
2012 and two of which are expected to be delivered mid-year 2012. Other than these
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
prospects risked reserve size and risked initial producing rate. Other factors that are also
monitored throughout the year that influence the amount and timing of our planned expenditures
include the level of production from our existing crude oil and natural gas properties, the
availability of drilling and completion services, and the success and resulting production of our
newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our
exploration and development drilling schedule to ensure that we are optimizing our capital
expenditure plan.
The final determination with respect to our 2011 budgeted expenditures will depend on a number
of factors, including:
|
|
|
production from our existing producing wells;
|
|
|
|
the results of our current exploration and development drilling efforts;
|
|
|
|
economic conditions at the time of drilling;
|
|
|
|
industry conditions at the time of drilling, including the availability of drilling and
completion equipment;
|
|
|
|
our liquidity and the availability of external sources of financing; and
|
|
|
|
the availability of more economically attractive prospects.
|
There can be no assurance that the budgeted wells will, if drilled, encounter commercial
quantities of crude oil or natural gas.
Factors that could cause us to further increase our level of activity and capital budget in
2011 include an improvement in commodity prices or well performance that exceeds our risked
forecasts, the divestiture of non-strategic conventional assets, a reduction in service and
material costs, or the formation of joint ventures with other exploration and production companies
outside of our core de-risked acreage positions in the Williston Basin, all of which would
positively impact our operating cash flow.
Factors that would cause us to reduce our capital budget in 2011 include, but are not limited
to, reductions in commodity prices or underperformance of wells relative to our risked forecasts or
increases in service and materials costs, all of which would negatively impact our operating cash
flow.
The table below summarizes the amount spent on oil and gas capital expenditures
through September 30, 2011.
|
|
|
|
|
|
|
Amount
|
|
|
|
Spent Through
|
|
|
|
September 30, 2011
|
|
|
|
(In millions)
|
Drilling
|
|
$
|
514.4
|
|
Support infrastructure
|
|
|
49.6
|
|
Land
|
|
|
69.2
|
|
|
|
|
|
Oil and gas capital expenditures
|
|
$
|
633.2
|
|
|
|
|
|
28
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 September 30, 2011,
cash flows from operations, the potential sale of interests in projects and properties,
availability under our Senior Credit Facility or alternative financing sources.
8 3/4% Senior Notes
As of September 30, 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 paid 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 September 30,
2011.
6 7/8% Senior Notes
As of September 30, 2011, we had outstanding $300 million of 6 7/8% Senior Notes due 2019,
which were issued in May 2011.
Our 6 7/8% Senior Notes are fully and unconditionally guaranteed by us, and our wholly-owned
subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. Beginning December 2011, we will pay 6 7/8%
interest on the $300 million outstanding. Future interest payments are due semi-annually in arrears
in December and June of each year.
The 6 7/8% 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 6 7/8% Senior Notes contains customary events of default. Upon the
occurrence of certain events of default, the trustee or the holders of the 6 7/8% Senior Notes may
declare all outstanding 6 7/8% Senior Notes to be due and payable immediately.
29
Additionally, the Indenture governing the 6 7/8% 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 6 7/8% Senior Notes as of September 30,
2011.
Senior Credit Facility
Our Senior Credit Facility provides for revolving credit borrowings up to $600 million, a
current borrowing base of $325 million and a five year maturity. As of September 30, 2011, we had
no amounts outstanding under our Senior Credit Facility.
The borrowing base under our Senior Credit Facility will be redetermined at least
semi-annually and the amount of borrowing capacity available to us under the Senior Credit Facility
could fluctuate. In early November 2011, banks in our Senior Credit Facility waived conducting the
regularly scheduled fall redetermination in light of our acquisition by Statoil ASA announced on
October 17, 2011 and as discussed further in Subsequent Events. Depending on the results and
timing of Statoil ASAs tender offer, we may elect to schedule a redetermination in December. In
the event that we schedule a redetermination in December and 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 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 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 Americas 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 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. As of September 30, 2011, we were in
compliance with the covenants under our Senior Credit Facility.
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.
30
Analysis of Changes in Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
% Change
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
174,902
|
|
|
|
501
|
%
|
|
$
|
29,112
|
|
Non-cash items
|
|
|
32,565
|
|
|
|
(41
|
%)
|
|
|
55,556
|
|
Changes in working capital and other items
|
|
|
35,916
|
|
|
|
320
|
%
|
|
|
8,553
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating activities
|
|
$
|
243,383
|
|
|
|
161
|
%
|
|
$
|
93,221
|
|
Cash flows (used) by investing activities
|
|
|
(465,580
|
)
|
|
|
14
|
%
|
|
|
(408,241
|
)
|
Cash flows provided by financing activities
|
|
|
289,998
|
|
|
|
(28
|
%)
|
|
|
400,243
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
$
|
67,801
|
|
|
|
(20
|
%)
|
|
$
|
85,223
|
|
|
|
|
|
|
|
|
|
|
|
|
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 nine months 2011 was $150.2 million
higher than the first nine months 2010. The following are the primary reasons for the increase:
|
|
|
higher crude oil and natural gas sales volumes increased
operating cash flow by $111.3
million;
|
|
|
|
higher crude oil and natural gas sales prices increased operating
cash flow by $58.9 million;
|
|
|
|
higher production taxes decreased operating cash flow by $18.0 million; and
|
|
|
|
higher lease operating costs decreased operating cash flow by $17.4 million.
|
31
Analysis of changes in cash flows used in investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
|
2011
|
|
|
% Change
|
|
|
2010
|
|
|
|
(In thousands)
|
|
Capital expenditures for oil and natural gas activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
$
|
514,421
|
|
|
|
160
|
%
|
|
$
|
197,970
|
|
Support infrastructure
|
|
|
49,593
|
|
|
|
205
|
%
|
|
|
16,259
|
|
Land
|
|
|
69,199
|
|
|
|
(33
|
%)
|
|
|
103,172
|
|
Capitalized cost
|
|
|
21,806
|
|
|
|
51
|
%
|
|
|
14,489
|
|
Capitalized asset retirement obligation
|
|
|
816
|
|
|
|
49
|
%
|
|
|
547
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
655,835
|
|
|
|
97
|
%
|
|
$
|
332,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciling Items:
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset sale proceeds including ARO liability reduction
|
|
$
|
|
|
|
|
(100
|
%)
|
|
$
|
(13,706
|
)
|
Change in accrued drilling costs
|
|
|
(94,821
|
)
|
|
|
128
|
%
|
|
|
(41,605
|
)
|
Change in drilling advances paid
|
|
|
(550
|
)
|
|
NM
|
|
|
|
1,397
|
|
Change in short term investments
|
|
|
(109,254
|
)
|
|
NM
|
|
|
|
111,035
|
|
Change in other property and equipment
|
|
|
7,447
|
|
|
NM
|
|
|
|
4,500
|
|
Change in inventory
|
|
|
18,279
|
|
|
|
23
|
%
|
|
|
14,805
|
|
Other
|
|
|
(11,356
|
)
|
|
|
1,726
|
%
|
|
|
(622
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total Reconciling Items
|
|
|
(190,255
|
)
|
|
NM
|
|
|
|
75,804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
$
|
465,580
|
|
|
|
14
|
%
|
|
$
|
408,241
|
|
Net cash used by investing activities was impacted by the following items during in the
first nine months 2011:
|
|
|
drilling expenditures increased by $316.5 million;
|
|
|
|
support infrastructure expenditures increased by $33.3 million;
|
|
|
|
land expenditures decreased by $34.0 million;
|
|
|
|
capitalized costs increased by $7.3 million;
|
|
|
|
the change in accrued drilling costs decreased cash used in investing activities by $53.2
million;
|
|
|
|
the change in short term investments decreased cash used in investing activities by
$220.3 million; and
|
|
|
|
the change in inventory increased cash used in investing activities by $3.5 million.
|
Analysis of changes in cash flows from financing activities
Net cash provided by financing activities in the first nine months of 2011 was 28% less than
the first nine months of 2010. During the first nine months 2011, we received net proceeds of
$294.4 million associated with our May 2011
6
7
/
8
%
Senior Notes offering. During the first nine months
2010, we received net proceeds of $277.5 million from our April 2010 common stock offering and
$146.5 million from our September 2010 8 3/4% Senior Notes offering.
Common Stock Transactions
The following is a list of common stock transactions that occurred in the nine months ended
September 30, 2011 and 2010.
|
|
|
|
|
|
|
|
|
|
|
Shares Issued
|
|
|
Net Proceeds
|
|
|
|
(In thousands, except share data)
|
|
2011 common stock transactions:
|
|
|
|
|
|
|
|
|
Exercise of employee stock options
|
|
|
84,020
|
|
|
$
|
670
|
|
|
|
|
|
|
|
|
|
|
2010 common stock transactions:
|
|
|
|
|
|
|
|
|
Common stock offering (April)
|
|
|
16,100,000
|
|
|
$
|
277,547
|
|
Exercise of employee stock options
|
|
|
487,107
|
|
|
$
|
2,484
|
|
32
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.
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.
33
|
|
|
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 September 30, 2011, we were party to crude oil costless collars, crude
oil puts, natural gas costless collars and natural gas three-way costless collars.
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.
34
The following tables reflect our open crude oil and natural gas contracts as of September 30,
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
|
|
|
|
|
|
|
|
|
|
|
|
|
10/01/11 12/31/11
|
|
|
21,000
|
|
|
$
|
65.00
|
|
|
$
|
88.25
|
|
10/01/11 12/31/11
|
|
|
15,000
|
|
|
$
|
60.00
|
|
|
$
|
97.25
|
|
10/01/11 12/31/11
|
|
|
15,000
|
|
|
$
|
65.00
|
|
|
$
|
108.00
|
|
10/01/11 12/31/11
|
|
|
12,000
|
|
|
$
|
70.00
|
|
|
$
|
106.80
|
|
10/01/11 12/31/11
|
|
|
12,000
|
|
|
$
|
75.00
|
|
|
$
|
102.60
|
|
10/01/11 12/31/11
|
|
|
6,000
|
|
|
$
|
75.00
|
|
|
$
|
103.00
|
|
10/01/11 12/31/11
|
|
|
6,000
|
|
|
$
|
70.00
|
|
|
$
|
96.35
|
|
10/01/11 12/31/11
|
|
|
6,000
|
|
|
$
|
75.00
|
|
|
$
|
95.15
|
|
10/01/11 12/31/11
|
|
|
9,000
|
|
|
$
|
75.00
|
|
|
$
|
104.30
|
|
01/01/12 06/30/12
|
|
|
60,000
|
|
|
$
|
75.00
|
|
|
$
|
106.90
|
|
10/01/11 12/31/11
|
|
|
9,000
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
10/01/11 07/31/12
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
97.20
|
|
10/01/11 07/31/12
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
98.55
|
|
10/01/11 07/31/12
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
10/01/11 07/31/12
|
|
|
152,500
|
|
|
$
|
65.00
|
|
|
$
|
100.40
|
|
10/01/11 12/31/11
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
97.40
|
|
01/01/12 06/30/12
|
|
|
182,000
|
|
|
$
|
65.00
|
|
|
$
|
99.25
|
|
10/01/11 12/31/11
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
99.00
|
|
01/01/12 06/30/12
|
|
|
91,000
|
|
|
$
|
65.00
|
|
|
$
|
101.00
|
|
01/01/12 06/30/12
|
|
|
182,000
|
|
|
$
|
65.00
|
|
|
$
|
100.75
|
|
01/01/12 06/30/12
|
|
|
91,000
|
|
|
$
|
65.00
|
|
|
$
|
102.75
|
|
07/01/12 07/31/12
|
|
|
62,000
|
|
|
$
|
65.00
|
|
|
$
|
102.25
|
|
10/01/11 12/31/11
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
100.00
|
|
07/01/12 07/31/12
|
|
|
31,000
|
|
|
$
|
65.00
|
|
|
$
|
105.25
|
|
10/01/11 12/31/11
|
|
|
46,000
|
|
|
$
|
65.00
|
|
|
$
|
106.50
|
|
10/01/11 12/31/11
|
|
|
46,000
|
|
|
$
|
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
|
|
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
|
|
10/01/11 12/31/11*
|
|
|
138,000
|
|
|
$
|
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
|
|
10/01/11 12/31/11
|
|
|
184,000
|
|
|
$
|
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
|
|
01/01/12
06/30/12**
|
|
|
136,500
|
|
|
$
|
80.00
|
|
|
$
|
107.50
|
|
01/01/12
06/30/12**
|
|
|
136,500
|
|
|
$
|
80.00
|
|
|
$
|
107.50
|
|
04/01/12 04/30/12
|
|
|
15,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
06/01/12 06/30/12
|
|
|
25,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
09/01/12 09/30/12
|
|
|
20,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
10/01/12 12/31/12
|
|
|
90,000
|
|
|
$
|
80.00
|
|
|
$
|
102.50
|
|
04/01/13 09/30/13
|
|
|
540,000
|
|
|
$
|
75.00
|
|
|
$
|
109.00
|
|
|
|
|
*
|
|
Crude oil collar was completed in two phases. First, the put option (floor) was purchased.
Subsequently, the call option (ceiling) was sold thereby converting the position into a
collar.
|
|
**
|
|
Crude oil collar was completed in two phases. First, the put
option(floor) was purchased. Subsequently, a three-way costless collar was
purchased to convert the position into a collar with a higher floor
price.
|
35
|
|
|
|
|
|
|
|
|
|
|
Crude
|
|
|
Purchased
|
|
|
|
Oil
|
|
|
Put
|
|
Settlement Period
|
|
(Bbls)
|
|
|
(Nymex)
|
|
Crude Oil Puts
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
10/01/11 12/31/11
|
|
|
90,000
|
|
|
$
|
5.75
|
|
|
$
|
7.65
|
|
10/01/11 12/31/11
|
|
|
120,000
|
|
|
$
|
5.75
|
|
|
$
|
7.40
|
|
10/01/11 12/31/11
|
|
|
120,000
|
|
|
$
|
5.00
|
|
|
$
|
6.55
|
|
36
|
|
|
ITEM 4.
|
|
CONTROLS AND PROCEDURES
|
Evaluation of Disclosure Controls and Procedures
As of September 30, 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 third
quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
37
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.
On Monday, October 17, 2011, the Company entered into an Agreement and Plan of Merger (the Merger
Agreement) with Statoil ASA (Statoil) and its indirect, wholly-owned subsidiary Fargo
Acquisition, Inc. (Purchaser), pursuant to which Purchaser would commence an all-cash tender
offer to purchase all outstanding shares of the Companys common stock. Subject to certain
conditions, after completion of the tender offer, Purchaser would merge with the Company, with the
Company surviving as a wholly-owned subsidiary of Statoil. The tender offer was commenced by
Purchaser on October 28, 2011, and on that date the Company filed a Solicitation/Recommendation
Statement on Schedule 14D-9 (the Schedule 14D-9) with the Securities and Exchange Commission
(SEC) under the Securities Exchange Act of 1934, in which the Companys Board of Directors
unanimously recommended to the Companys stockholders that they accept the tender offer and, if
necessary under applicable law, vote their shares to approve the proposed merger. Under the terms
of the tender offer, each stockholder is entitled to receive $36.50 per share, net to the
stockholder in cash, without interest. The tender offer is scheduled to expire on November 30,
2011, unless extended by Purchaser. Following the announcement of the tender offer, several
separate Plaintiffs filed putative class action lawsuits in Texas and Delaware against the Company
and its Board of Directors. These lawsuits also include certain claims against Statoil and, in
some cases, Purchaser. Each lawsuit purports to represent the same class of individuals, that is,
the Companys stockholders. Six suits were filed in Travis County, Texas and six suits were filed
in the Chancery Court of the State of Delaware. Following these initial filings, the plaintiffs in
the Delaware suits amended their claims and consolidated their pleadings into one lawsuit filed in
the Court of Chancery in the State of Delaware,
The Edward J. Goodman Life Income Trust et al. v.
Brigham Exploration Company, et al.
The Company filed a motion with the Travis County Court
requesting that the Court consolidate the six suits pending in that court and then stay the
consolidated case in favor of the litigation pending in the Delaware Court of Chancery. A hearing
on this motion to consolidate and stay the Texas litigation is scheduled for Wednesday, November 9,
2011. The Delaware and Texas suits seek certification of a class of the Companys stockholders and
generally allege, among other things, that (i) members of the Board of Directors breached their
fiduciary duties in connection with the Merger Agreement by failing to maximize stockholder value,
agreeing to preclusive deal protection provisions, engaging in self-dealing, failing to protect
against conflicts of interest and by filing a materially false and misleading Schedule 14D-9 with
the SEC; and (ii) the Company aided and abetted the Board of Directors purported breaches of
fiduciary duties. The Delaware and Texas suits seek, among other relief, an injunction prohibiting
the tender offer and requiring the Company to implement new procedures and processes to obtain a
new merger agreement, the imposition of a constructive trust in favor of the plaintiffs and the
members of the proposed class upon any benefits improperly received by defendants as a result of
their alleged wrongful conduct, rescission for any portions of the tender offer already
implemented, damages, costs and attorneys and experts fees. We believe the Delaware and Texas
actions are without merit and intend to defend ourselves vigorously. The six lawsuits filed in the Chancery Court of the State of Delaware as described above are:
Weisberg v. Brigham
Exploration Company et al.
, Case No. 6957 (filed on October 20, 2011),
Fioravanti v. Brigham Exploration Company et
al.
, Case No. 6962 (filed on October 21, 2011),
Teamsters Allied Benefit Funds v. Brigham Exploration Company et al.
,
Case No. 6975 (filed on October 25, 2011),
The Edward J. Goodman Life Income Trust and the Edward J. Goodman Generation
Skipping Trust v. Brigham Exploration Company et al.
, Case No. 6969 (filed on October 25, 2011),
Oklahoma Law
Enforcement Retirement System v. Brigham Exploration Company et al.
, Case No. 6980 (filed on October 26, 2011), and
Oklahoma Police Pension & Retirement System v. Brigham Exploration Company et al.
, Case No. 6982 (filed on October 26,
2011). The six lawsuits filed in the District Court in Travis County, Texas as described above are:
Boytim v. Brigham
Exploration Company et al.
, Case No. D-1-GN-11-003205 (filed on October 17, 2011),
Duncan v. Brigham Exploration
Company et al.
, Case No. D-1-GN-11-003215 (filed on October 18, 2011),
Giske v. Brigham Exploration Company et al.
,
Case No. D-1-GN-11-003227 (filed on October 19, 2011),
Fioravanti v. Brigham Exploration Company et al.
, Case No.
D-1-GN-11-003258 (filed on October 24, 2011),
Schwimmer v. Brigham Exploration Company et al.
, Case No. D-1-GN-11-00317
(filed on October 28, 2011), and
Ohler v. Brigham Exploration Company et al.
, Case No. D-1-GN-11-003418 (filed on
November 7, 2011).
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 except as stated
below.
Failure to complete or delays in completing our pending acquisition by affiliates of Statoil ASA
could negatively affect our stock price and our future business, operations and financial results.
On October 17, 2011, we entered into an Agreement and Plan of Merger with Statoil ASA
(Parent) and Fargo Acquisition Inc., a wholly owned subsidiary of Parent (Purchaser), pursuant
to which Purchaser will commence an offer (the Offer) to acquire all of the outstanding shares of
our common stock, par value $0.01 per share, for $36.50 per share, net to the stockholder in cash,
without interest. The Offer commenced on October 28, 2011 and will remain open until November 30,
2011, subject to extension under certain circumstances. The Agreement and Plan of Merger also
provides that following consummation of the Offer and satisfaction or waiver of certain customary
conditions, Purchaser will be merged with and into the Company, with the Company surviving as a
wholly owned subsidiary of Parent. There is no assurance that Purchaser will consummate the Offer
or the merger. If the transactions contemplated by the Agreement and Plan of Merger are not
completed for any reason, we may be subject to a number of risks, including the following:
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the current market price of our common stock may reflect a market assumption that the
Offer will be consummated and the merger will occur and a failure to consummate the Offer
and the merger could result in a negative perception of us by the stock market and cause a
decline in the market price of our common stock;
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certain costs relating to the Agreement and Plan of Merger, including certain
investment banking, financing, legal and accounting fees and expenses, must be paid even
if the merger is not completed, and we may be required to pay a fee of $137 million to
Parent if the Agreement and Plan of Merger is terminated under specified circumstances;
and
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we would continue to face the risks that we currently face as an independent company.
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The pending transactions with Parent may cause disruption in our business and management and
present difficulties attracting, motivating and retaining executives and other key employees.
Parties with which we do business may experience uncertainty associated with the transactions
contemplated in the Agreement and Plan of Merger, including with respect to current or future
business relationships, and our management and employees may be distracted from day-to-day
operations because matters related to the merger may require substantial commitments of time and
resources. In addition, the Agreement and Plan of Merger restricts us from making certain
acquisitions and taking other specified actions without Parents approval. These restrictions could
prevent us from pursuing attractive business opportunities that may arise prior to the completion
of the merger. These disruptions could have an adverse effect on our business, financial condition,
results of operations or prospects. The adverse effect of such disruptions could be exacerbated by
a delay in the consummation of the Offer and the completion of the merger or the termination of the
Agreement and Plan of Merger. In addition, uncertainty about the
effect of the merger on our employees may have an adverse effect on us. This uncertainty may impair
our ability to attract, retain and motivate key personnel until the merger is completed. Employee
retention may be particularly challenging during the pendency of the merger, as employees may
experience uncertainty about their future roles with Parent.
The Agreement and Plan of Merger restricts our ability to pursue alternatives to the merger.
The Agreement and Plan of Merger contains no shop provisions that, subject to limited
fiduciary exceptions, restrict our ability to initiate, solicit, encourage or facilitate, discuss,
negotiate or accept a competing third party proposal to acquire all or a significant part of us.
Further, there are only a limited number of exceptions that would allow our board of directors to
withdraw or change its recommendation to holders of our common stock that they tender their shares
of common stock in the Offer and that stockholder vote in favor of the adoption of the Agreement
and Plan of Merger. If our board of directors were to take such actions as permitted by the
Agreement and Plan of Merger, doing so in specified situations could entitle Parent to terminate
the Agreement and Plan of Merger and to be paid a termination fee of 137.0 million. These
restrictions could deter a potential acquirer from proposing an alternative transaction.
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ITEM 2.
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UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
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Issuer Purchases of Equity Securities
In the third quarter 2011, we elected to allow employees to deliver shares of vested
restricted stock with a fair market value equal to their federal, state and local tax withholding
amounts on the date of issue in lieu of cash payment.
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Maximum
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Number (or
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Approximate
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Dollar Value) of
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Total Number of
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Shares that May
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Shares Purchased
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Yet Be
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as Part of Publicly
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Purchased Under
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Total Number of
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Average Price
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Announced Plans
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the Plans or
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Period
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Shares Purchased
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Paid per Share
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or Programs
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Programs
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July 2011
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$
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August 2011
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September 2011
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7,915
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28.45
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Total
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7,915
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$
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28.45
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ITEM 3.
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DEFAULTS UPON SENIOR SECURITIES
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None.
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ITEM 4.
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(REMOVED AND RESERVED)
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ITEM 5.
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OTHER INFORMATION
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None.
38
ITEM 6. EXHIBITS
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2.1
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Agreement and Plan of Merger dated October 17, 2011 by and among Statoil ASA, Fargo
Acquisition Inc. and Brigham Exploration Company (filed as Exhibit 2.1to Brighams Current
Report on Form 8-K (filed October 21, 2011) and incorporated herein by reference)
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2.2
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Tender and Voting Agreement dated as of October 17, 2011 by and among Statoil ASA, Fargo
Acquisition Inc. and the directors and executive officers of Brigham Exploration Company
(filed as Exhibit 2.2 to Brighams Current Report on Form 8-K (filed October 21, 2011) and
incorporated herein by reference)
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3.1
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Certificate of Incorporation (filed as Exhibit 3.1 to Brighams Registration Statement on
Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
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3.2
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Certificates of Amendment of Certificate of Incorporation of Brigham Exploration Company
dated May 6, 1999 and May 22, 2000 (filed as Exhibit 3.1.1 to Brighams Registration Statement
on Form S-3 (Registration No. 333-37558) and incorporated herein by reference)
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3.3
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Bylaws, as amended through May 28, 2009 (filed as Exhibit 3.5 to Brighams Current Report on
Form 8-K (filed May 28, 2009) and incorporated herein by reference)
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3.4
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Certificate of Amendment of Certificate of Incorporation of Brigham Exploration Company dated
June 14, 2006, (filed as Exhibit 3.4 to Brighams Annual Report on Form 10-K for the year
ended December 31, 2008 and incorporated herein by reference)
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3.5
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Certificate of Amendment of Certificate of Incorporation of Brigham Exploration Company dated
October 7, 2009 (filed as Exhibit 3.5 to Brighams Current Report on Form 8-K (filed October
13, 2009) and incorporated herein by reference)
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4.1
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Form of Common Stock Certificate (filed as Exhibit 4.1 to Brighams Registration Statement on
Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
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4.2
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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 Brighams Current Report
on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference)
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4.3
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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 Brighams Annual Report on Form 10-K for the year ended December 31, 2000 and
incorporated herein by reference)
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4.4
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Certificate of Elimination of Certificate of Designations of Series A Preferred Stock (Par
Value $.01 Per Share) of Brigham Exploration Company dated August 9, 2010 (filed as Exhibit
3.7 to Brighams Current Report on Form 8-K (filed August 10, 2010) and incorporated herein by
reference)
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4.5
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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 Brighams Annual Report
on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference)
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4.6
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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 Brighams Current
Report on Form 8-K (filed July 20, 2004) and incorporated herein by reference)
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4.7
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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 Brighams
Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
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4.8
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Certificate of Elimination of Certificate of Designations of Series C Junior Participating
Preferred Stock of Brigham Exploration Company dated March 9, 2010 (filed as Exhibit 3.6 to
Brighams Current Report on
Form 8-K
(filed March 15, 2010) and incorporated herein by
reference)
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4.9
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Indenture, dated September 27, 2010, among Brigham Exploration Company, Brigham, Inc.,
Brigham Oil & Gas, L.P. and Wells Fargo Bank, National Association, as Trustee (filed as
Exhibit 4.17 to Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated
herein by reference)
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4.10
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Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.18 to
Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by
reference)
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4.11
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Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.19 to
Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by
reference)
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4.12
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*
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Indenture, dated May 19, 2011, among Brigham Exploration Company, Brigham, Inc., Brigham Oil & Gas, L.P. and Wells
Fargo Bank, National Association, as
Trustee
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4.13
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*
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Rule 144A 6 7/8% Senior Note due 2019 and Notation of Guarantee
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4.14
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*
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Regulation S 6 7/8% Senior Note due 2019 and Notation of Guarantee
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4.15
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*
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Registration Rights Agreement dated May 19, 2011, among Brigham Exploration Company,
Brigham, Inc., Brigham Oil & Gas, L.P., Merrill Lynch, Pierce, Fenner & Smith Incorporated and
Credit Suisse Securities (USA) LLC, as representatives for the several initial purchasers
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31.1
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*
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Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934
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31.2
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*
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Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934
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32.1
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*
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Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350
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32.2
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*
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Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
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101.INS
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**
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XBRL Instance Document
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101.SCH
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**
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XBRL Schema Document
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101.CAL
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**
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XBRL Calculation Linkbase Document
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101.LAB
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**
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XBRL Label Linkbase Document
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101.PRE
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**
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XBRL Presentation Linkbase Document
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101.DEF
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**
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XBRL Definition Linkbase Document
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*
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Filed herewith.
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**
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Furnished herewith.
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39
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3.4
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|
Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated
June 14, 2006 (filed as Exhibit 3.4 to Brighams Annual Report on Form 10-K for the year ended
December 31, 2008 and incorporated herein by reference)
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3.5
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Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated
October 7, 2009 (filed as Exhibit 3.5 to Brighams Current Report on Form 8-K (dated October
13, 2009) and incorporated herein by reference)
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4.1
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Form of Common Stock Certificate (filed as Exhibit 4.1 to Brighams Registration Statement on
Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
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4.2
|
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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 Brighams Current Report
on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference)
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4.3
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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 Brighams Annual Report on Form 10-K for the year ended December 31, 2000 (filed
March 23, 2001) and incorporated herein by reference)
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4.4
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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 Brighams Current Report on Form 8-K (filed August 10, 2010) and incorporated herein by
reference
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4.5
|
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|
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 Brighams Annual Report
on Form 10-K for the year ended December 31, 2002 (filed March 31, 2003) and incorporated
herein by reference)
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4.6
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|
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 Brighams Current
Report on Form 8-K (filed July 20, 2004) and incorporated herein by reference)
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4.7
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Indenture, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named
therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to Brighams Current
Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference)
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4.8
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Notations of Guarantees, dated April 20, 2006, among Brigham Exploration Company, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (filed as Exhibit 4.2 to
Brighams Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by
reference)
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4.9
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Rule 144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.3 to
Brighams Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by
reference)
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4.10
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Reg S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.4 to Brighams
Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference)
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4.11
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Notations of Guarantees dated as of April 9, 2007, among Brigham Exploration Company, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.2 to
Brighams Current Report on Form 8-K (filed April 13, 2007) and incorporated in by reference)
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4.12
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Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brighams Current Report on
Form 8-K (filed April 13, 2007) and incorporated in by reference)
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4.13
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|
|
Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 to Brighams Current Report on Form
8-K (filed April 13, 2007) and incorporated herein by reference)
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40
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4.14
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Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and
American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to
Brighams Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by
reference)
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4.15
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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 Brighams
Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
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4.16
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Certificate of Elimination of Certificate of Designations of Series C Junior Preferred Stock
of Brigham Exploration Company effective March 9, 2010 (filed as Exhibit 3.6 to Brighams
Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)
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4.17
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First Supplemental Indenture, dated September 27, 2010, among the Company, the Guarantors and
Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.16 to Brighams Current
Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
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4.18
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Indenture, dated September 27, 2010, among the Company, the Guarantors and Wells Fargo Bank,
National Association, as Trustee (filed as Exhibit 4.17 to Brighams Current Report on Form
8-K (filed October 1, 2010) and incorporated herein by reference)
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4.19
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Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.18 to
Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by
reference)
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4.20
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Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.19 to
Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by
reference)
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4.21
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Registration Rights Agreement, dated September 27, 2010, among the Company, the Guarantors
and the Initial Purchasers (filed as Exhibit 4.20 to Brighams Current Report on Form 8-K
(filed October 1, 2010) and incorporated herein by reference)
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10.48
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Seventh Amendment and Consent to the Fourth Amended and Restated Credit Agreement dated as
of June 29, 2005 between the Company and the banks named therein (filed as Exhibit 10.48 to
Brighams Current Report on Form 8-K (filed September 13, 2010) and incorporated herein by
reference)
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10.49
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Purchase Agreement dated September 16, 2010 among the Company, the Guarantors and the
Initial Purchasers. (filed as Exhibit 10.49 to Brighams Current Report on Form 8-K (filed
September 20, 2010) and incorporated herein by reference)
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31.1
|
|
|
Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934
|
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31.2
|
|
|
Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934
|
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32.1
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|
Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350
|
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32.2
|
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Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
|
41
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 on
November 7, 2011.
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BRIGHAM EXPLORATION COMPANY
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By:
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/s/ BEN M. BRIGHAM
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Ben M. Brigham
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Chief Executive Officer,
President
and Chairman of the Board
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By:
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/s/ EUGENE B. SHEPHERD, JR.
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Eugene B. Shepherd, Jr.
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Executive Vice President and
Chief Financial Officer
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42
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