Brigham Exploration (BEXP) 10-Q 2011 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 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)

Delaware (State of other jurisdiction of incorporation or organization)	75-2692967 (I.R.S. Employer Identification No.)
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas (Address of principal executive offices)	78730 (Zip Code)

(512) 427-3300
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232 405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filerþ	Accelerated Filero	Non-Accelerated Filero	Smaller Reporting Companyo
		(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

Class	Outstanding
Common Stock, par value $.01 per share as of August 5, 2011	117,319,127

Brigham Exploration Company

Second Quarter 2011 Form 10-Q Report

TABLE OF CONTENTS

	Page
PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets — June 30, 2011 and December 31, 2010		1
Consolidated Statements of Operations — Three and six months ended June 30, 2011 and 2010		2
Consolidated Statement of Stockholders’ Equity — Six months ended June 30, 2011		3
Consolidated Statements of Cash Flows — Six months ended June 30, 2011 and 2010		4
Notes to the Consolidated Financial Statements		5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		18
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		34
ITEM 4. CONTROLS AND PROCEDURES		37
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		38
ITEM 1A. RISK FACTORS		38
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		38
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		39
ITEM 4. (REMOVED AND RESERVED)		39
ITEM 5. OTHER INFORMATION		39
ITEM 6. EXHIBITS		39
SIGNATURES		41
Exhibit 4.12
Exhibit 4.13
Exhibit 4.14
Exhibit 4.15
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	June 30,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	181,689		$	23,743
Accounts receivable		108,271			70,368
Short-term investments		180,585			223,991
Inventory		47,488			34,959
Other current assets		10,470			7,796
Total current assets		528,503			360,857
Oil and natural gas properties, using the full cost method including Proved, net of accumulated depletion of $466,162 and $423,691		708,981			486,423
Unproved		265,002			182,933
		973,983			669,356
Other property and equipment, net		75,075			42,837
Deferred loan fees		17,512			9,064
Other noncurrent assets		5,410			3,287
Total assets	$	1,600,483		$	1,085,401
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	84,403		$	50,023
Royalties payable		67,436			42,155
Accrued drilling costs		116,616			61,067
Participant advances received		10,739			3,037
Derivative liabilities		14,400			9,442
Other current liabilities		14,213			10,821
Total current liabilities		307,807			176,545
Senior Notes		600,000			300,000
Other noncurrent liabilities		23,734			15,586
Commitments and contingencies (Note 3)
Stockholders’ equity:
Common stock, $.01 par value, 180 million shares authorized, 116,736,145 and 116,564,182 shares issued and 116,442,586 and 116,289,180 shares outstanding at June 30, 2011 and December 31, 2010, respectively		1,168			1,166
Additional paid-in capital		769,164			765,326
Treasury stock, at cost; 293,559 and 275,002 shares at June 30, 2011 and December 31, 2010, respectively		(3,163	)		(2,657	)
Accumulated other comprehensive income (loss)		(60	)		(9	)
Retained earnings (deficit)		(98,167	)		(170,556	)
Total stockholders’ equity		668,942			593,270
Total liabilities and stockholders’ equity	$	1,600,483		$	1,085,401

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)

		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2011			2010			2011			2010
Revenues:
Oil and natural gas sales		$	93,726		$	40,564		$	169,689		$	69,494
Gain (loss) on derivatives, net			33,421			4,362			(2,537	)		7,996
Support infrastructure			890			—			1,484			—
Other revenue			3			4			5			13
			128,040			44,930			168,641			77,503
Costs and expenses:
Lease operating			8,724			4,371			16,444			8,720
Production taxes			9,451			3,900			17,149			6,408
Support infrastructure			529			—			719			—
General and administrative	��		3,165			2,711			6,547			5,797
Depletion of oil and natural gas properties			23,531			14,247			42,471			23,458
Depreciation and amortization			1,244			261			2,215			494
Accretion of discount on asset retirement obligations			113			104			223			209
			46,757			25,594			85,768			45,086
Operating income (loss)			81,283			19,336			82,873			32,417
Other income (expense):
Interest income			342			887			709			1,340
Interest expense, net			(5,794	)		(2,931	)		(9,172	)		(5,835	)
Other income (expense)			3,934			1,181			7,088			1,866
			(1,518	)		(863	)		(1,375	)		(2,629	)
Income (loss) before income taxes			79,765			18,473			81,498			29,788
Income tax expense:
Current						—						—
Deferred			(8,930	)		—			(9,109	)		—
			(8,930	)		—			(9,109	)		—
Net income (loss)			70,835			18,473		$	72,389		$	29,788
Net income (loss) per share available to common stockholders:
Basic		$	0.61		$	0.16		$	0.62		$	0.28
Diluted		$	0.60		$	0.16		$	0.61		$	0.27
Weighted average shares outstanding:
Basic			116,408			113,426			116,384			106,473
Diluted			118,524			115,383			118,533			108,491

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			Retained			Stockholders’
	Shares		Amounts		Capital			Stock			Income (Loss)			Earnings			Equity
Balance, December 31, 2010		116,564	$	1,166	$	765,326		$	(2,657	)	$	(9	)	$	(170,556	)	$	593,270
Comprehensive income:
Net income (loss)		—		—		—			—			—			72,389			72,389
Unrealized gains (losses) on investments		—		—		—			—			(51	)		—			(51	)
Tax benefit (provisions)		—		—		—			—			—			—			—
Comprehensive income																		72,338
Issuance of common stock		—		—		—			—			—			—			—
Exercises of employee stock options		69		1		581			—			—			—			582
Vesting of restricted stock		95		1		(1	)		—			—			—			—
Stock based compensation		8		—		3,258			—			—			—			3,258
Repurchases of common stock		—		—		—			(506	)		—			—			(506	)
Balance, June 30, 2011		116,736	$	1,168	$	769,164		$	(3,163	)	$	(60	)	$	(98,167	)	$	668,942

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)

	Six Months Ended
	June 30,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	72,389		$	29,788
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion of oil and natural gas properties		42,471			23,458
Depreciation and amortization		2,215			494
Stock based compensation		1,844			1,038
Amortization of deferred loan fees and debt issuance costs		1,141			1,014
Market value and other adjustments for derivative instruments		119			(9,260	)
Accretion of discount on asset retirement obligations		223			209
Deferred income taxes		9,109			—
Other noncash items		—			(1	)
Changes in operating assets and liabilities:
Accounts receivable		(37,903	)		(16,477	)
Other current assets		(2,213	)		(2,210	)
Accounts payable		34,380			25,574
Royalties payable		25,281			15,914
Participant advances received		7,702			(2,534	)
Other current liabilities		3,413			(56	)
Other noncurrent assets and liabilities		270			(31	)
Net cash provided by operating activities		160,441			66,920
Cash flows from investing activities:
Additions to oil and natural gas properties		(289,766	)		(122,782	)
Changes to inventory		(12,529	)		(3,806	)
Purchases of short term investments		(189,414	)		(214,001	)
Sales of short term investments		232,769			41,659
Additions to other property and equipment		(34,453	)		(5,752	)
Proceeds from the sale of assets		183			12,544
Decrease (increase) in drilling advances paid		341			(1,654	)
Net cash provided (used) by investing activities		(292,869	)		(293,792	)
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			—
Deferred loan fees paid and equity costs		(9,681	)		(115	)
Principal payments on capital lease obligations		(21	)		—
Proceeds from exercise of employee stock options		582			1,854
Repurchases of common stock		(506	)		(272	)
Net cash provided (used) by financing activities		290,374			268,913
Net increase (decrease) in cash and cash equivalents		157,946			42,041
Cash and cash equivalents, beginning of year		23,743			40,781
Cash and cash equivalents, end of period	$	181,689		$	82,822

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. Brigham’s 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 Brigham’s 2010 Annual Report on Form 10-K filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

3. Commitments and Contingencies

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

As of June 30, 2011, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.

4. Net Income Available Per Common Share

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

5

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 six months ended June 30, 2011 and 2010 are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Weighted average common shares outstanding — basic		116,408		113,426		116,384		106,473
Plus: Potential common shares Stock options and restricted stock		2,116		1,957		2,149		2,018
Weighted average common shares outstanding — diluted		118,524		115,383		118,533		108,491
Stock options excluded from diluted EPS due to the anti-dilutive effect		195		1,087		195		1,078

5. Income Taxes

Based on estimates of its 2011 annual effective tax rate, Brigham has a $9.1 million deferred federal and state income tax expense for the six months ended June 30, 2011. The annual effective tax rate takes into consideration the estimated reduction in Brigham’s valuation allowance through 2011. There was no federal or state tax expense (benefit) for the six months ended June 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-year date basis, at June 30, 2011, Brigham has a net deferred tax asset, due to its net operating loss carryovers and ceiling test writedowns in the fourth quarter of 2008 and the first quarter of 2009. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Based on this criteria, Brigham determined that it has a valuation allowance of $34.6 million on its net deferred tax asset at June 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, 2008, and 2007. In addition, Brigham is open to examination for the years 1997 through 2006, resulting from net operating losses generated and available for carryforward.

6. Derivative Instruments and Hedging Activities

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

Natural Gas and Crude Oil Derivative Contracts

Brigham enters into contracts to hedge against the variability in cash flows associated with the forecasted sale of future oil and gas production. Brigham’s hedges consist of costless collars (purchased put options and written call options), three-way collars (a standard collar plus a sold put below the floor price of the collar), purchased put options, 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 June 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
07/01/11 - 12/31/11		180,000			$	5.75	$	7.65
07/01/11 - 12/31/11		240,000			$	5.75	$	7.40
07/01/11 - 12/31/11		240,000			$	5.00	$	6.55
Oil Costless Collars
07/01/11 - 07/31/12				198,500	$	65.00	$	97.20
07/01/11 - 07/31/12				198,500	$	65.00	$	98.55
07/01/11 - 07/31/12				198,500	$	65.00	$	100.40
07/01/11 - 07/31/12				198,500	$	65.00	$	100.00
07/01/11 - 07/31/11				3,000	$	70.00	$	94.80
07/01/11 - 12/31/11				42,000	$	65.00	$	88.25
07/01/11 - 12/31/11				30,000	$	60.00	$	97.25
07/01/11 - 12/31/11				30,000	$	65.00	$	108.00
07/01/11 - 12/31/11				24,000	$	70.00	$	106.80
07/01/11 - 12/31/11				24,000	$	75.00	$	102.60
07/01/11 - 12/31/11				18,000	$	65.00	$	100.00
07/01/11 - 12/31/11				18,000	$	75.00	$	104.30
07/01/11 - 12/31/11				92,000	$	65.00	$	100.00
07/01/11 - 08/31/11				15,500	$	65.00	$	96.75
07/01/11 - 08/31/11				15,500	$	65.00	$	94.80
07/01/11 - 12/31/11				92,000	$	65.00	$	100.00
07/01/11 - 12/31/11				92,000	$	65.00	$	106.50
07/01/11 - 09/30/11				9,000	$	70.00	$	95.00
07/01/11 - 12/31/11				12,000	$	75.00	$	103.00
07/01/11 - 12/31/11				12,000	$	75.00	$	95.15
09/01/11 - 12/31/11				61,000	$	65.00	$	99.00
09/01/11 - 12/31/11				61,000	$	65.00	$	97.40
09/01/11 - 12/31/11				244,000	$	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
07/01/12 - 07/31/12				31,000	$	65.00	$	105.25
07/01/12 - 07/31/12				62,000	$	75.00	$	114.00
07/01/12 - 09/30/12				92,000	$	65.00	$	109.40
08/01/12 - 09/30/12				61,000	$	65.00	$	110.25
08/01/12 - 09/30/12				61,000	$	65.00	$	112.00
08/01/12 - 10/31/12				92,000	$	70.00	$	110.90
08/01/12 - 10/31/12				92,000	$	70.00	$	106.50
08/01/12 - 10/31/12				276,000	$	75.00	$	112.50
10/01/12 - 10/31/12				62,000	$	65.00	$	112.65
10/01/12 - 10/31/12				31,000	$	70.00	$	110.90
11/01/12 - 12/31/12				122,000	$	70.00	$	107.70

7

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

	Natural	Crude		Purchased		Written
	Gas	Oil		Put		Call
Settlement Period	(MMBTU)	(Barrels)		Nymex		Nymex
Oil Costless Collars cont.
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

	Natural	Crude		Purchased		Written
	Gas	Oil		Put		Call
Settlement Period	(MMBTU)	(Barrels)		Nymex		Nymex
Crude Oil Calls
07/01/11 - 12/31/11			276,000			$	100.00
Crude Oil Puts
07/01/11 - 06/30/12			183,000	$	65.00
07/01/11 - 06/30/12			183,000	$	65.00
07/01/11 - 06/30/12			91,500	$	65.00
07/01/11 - 06/30/12			91,500	$	65.00
07/01/12 - 12/31/12			276,000	$	80.00

Additional Disclosures about Derivative Instruments and Hedging Activities

At June 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:

		June 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	$	2,933		$	2,557
Natural gas and crude oil contracts	Other non-current assets		3,911			309
Total Derivative Assets		$	6,844		$	2,866
Derivative Liabilities:
Natural gas and crude oil contracts	Derivative liabilities - current	$	(14,400	)	$	(9,442	)
Natural gas and crude oil contracts	Other non-current liabilities		(7,714	)		(8,575	)
Total Derivative Liabilities		$	(22,114	)	$	(18,017	)

8

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

For the three and six months ended June 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
		June 30, 2011		June 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	$	91	$	(594	)
Crude oil contracts	Gain (loss) on derivatives, net		33,330		4,956
Total Derivative Gain (loss)		$	33,421	$	4,362

		Six Months			Six Months
		Ended			Ended
		June 30, 2011			June 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	$	202		$	2,661
Crude oil contracts	Gain (loss) on derivatives, net		(2,739	)		5,335
Total Derivative Gain (loss)		$	(2,537	)	$	7,996

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

7. Fair Values

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

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

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

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

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

9

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

				Fair Value Measurements at June 30, 2011 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	June 30,			for Identical Assets		Inputs			Inputs
Description	2011			(Level 1)		(Level 2)			(Level 3)
Derivative liabilities	$	(14,400	)	$	—	$	(14,400	)	$	—
Other non-current liabilities		(7,714	)		—		(7,714	)		—
Other current assets		2,933			—		2,933			—
Other non-current assets		3,911			—		3,911			—
	$	(15,270	)	$	—	$	(15,270	)	$	—
				Fair Value Measurements at December 31, 2010 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2010			(Level 1)		(Level 2)			(Level 3)
Derivative liabilities	$	(9,442	)	$	—	$	(9,442	)	$	—
Other non-current liabilities		(8,575	)		—		(8,575	)		—
Other current assets		2,557			—		2,557			—
Other non-current assets		309			—		309			—
	$	(15,151	)	$	—	$	(15,151	)	$	—

Brigham’s assessment of the significance of a particular input to the fair value measurement requires judgment and may effect the valuation on the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of Brigham’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. These inputs include salvage value, estimated life, working interest, a factor for inflation, and a discount factor. The fair value of the asset retirement obligations is reflected on the balance sheet as detailed below (in thousands).

				Fair Value Measurements at June 30, 2011 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	June 30,			for Identical Assets		Inputs		Inputs
Description	2011			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(5,491	)		—		—		(5,491	)
	$	(5,491	)	$	—	$	—	$	(5,491	)
				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 June 30, 2011 Using
			Quoted Prices in		Significant Other		Significant
			Active Markets		Observable		Unobservable
	June 30,		for Identical Assets		Inputs		Inputs
Description	2011		(Level 1)		(Level 2)		(Level 3)
Investments		180,585		180,585		—		—
	$	180,585	$	180,585	$	—	$	—
			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 Brigham’s investments (in thousands). The unrealized gain (loss) is recorded on the consolidated balance sheet as other comprehensive income (loss), a component of stockholders’ equity.

	Less Than 12 Months					12 Months or Greater				Total
			Unrealized					Unrealized				Unrealized
	Fair		Gains			Fair		Gains		Fair		Gains
Description of Securities	Value		(Losses)			Value		(Losses)		Value		(Losses)
Corporate bonds and notes	$	180,585	$	(42	)	$	—	$	—	$	180,585	$	(42	)
Total	$	180,585	$	(42	)	$	—	$	—	$	180,585	$	(42	)

The cost basis of Brigham’s investments in corporate bonds and notes (in thousands) is $183,963.

Brigham’s other financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The carrying value of Brigham’s Senior Credit Facility approximates its fair market value since it bears interest at floating market interest rates. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

	June 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	$	297,375	$	—	$	—

The fair value of Brigham’s 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 June 30, 2011 ($4.21 per MMBtu for Henry Hub natural gas and $90.09 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties did not exceed the ceiling limit. Therefore, Brigham was not required to writedown the net capitalized costs of its oil and gas properties at June 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 Brigham’s flexibility to manage and fund its business. At June 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 Brigham’s flexibility to manage and fund its business. At June 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 June 30, 2011 and December 31, 2010.

Borrowings under the Senior Credit Facility bear interest, at Brigham’s election, at a base rate (as the term is defined in the Senior Credit Facility) or Eurodollar rate, plus in each case an applicable margin that is reset quarterly. The applicable interest rate margin varies from 1.0% to 1.75% in the case of borrowings based on the base rate (as the term is defined in the Senior Credit Facility) and from 2.0% to 2.75% in the case of borrowings based on the Eurodollar rate, depending on percentage of the available borrowing base utilized. In addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base (0.50% at June 30, 2011). Borrowings under the Senior Credit Facility are collateralized by substantially all of Brigham’s oil and natural gas properties under first liens.

The Senior Credit Facility contains various covenants, including among other restrictions on liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on investments, and restrictions on hedging activity of a speculative nature or with counterparties having credit ratings below specified levels. The Senior Credit Facility required Brigham to maintain a current ratio (as defined) of at least 1 to 1 and a net leverage ratio that must be no greater than 4 to 1. At June 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 Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410 during the six months ended June 30, 2011 and 2010 (in thousands):

	Six Months Ended
	June 30,
	2011			2010
Beginning asset retirement obligations	$	5,923		$	6,323
Liabilities incurred for new wells placed on production		552			257
Liabilities settled		(1,207	)		(65	)
Accretion of discount on asset retirement obligations		223			209
Revisions to estimates due to sale of oil and gas properties		—			(1,208	)
	$	5,491		$	5,516

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 six months ended June 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 six months ended June 30, 2011 and 2010:

	2011			2010
Risk-free interest rate		1.96	%		2.49	%
Expected life (in years)		5.0			5.0
Expected volatility		82	%		81	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	18.99		$	12.49

The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free rate of interest for periods within the contractual life of the option is based on a zero-coupon U.S. government instrument over the contractual term of the equity instrument. Expected volatility is based on the historical volatility of Brigham’s stock for an equal period of the expected term.

Prior to the adoption of FASB ASC 718, Brigham presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. FASB ASC 718 requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Brigham did not record any excess tax benefits during the six months ended June 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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Pre-tax stock based compensation expense	$	1,879		$	1,133		$	3,258		$	1,896
Capitalized stock based compensation		(782	)		(522	)		(1,414	)		(858	)
Tax benefit		(384	)		(214	)		(645	)		(363	)
Stock based compensation expense, net	$	713		$	397		$	1,199		$	675

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 Brigham’s policy to use unissued shares of stock when stock options are exercised. As of June 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 June 30, 2011, approximately 1,466,084 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 Brigham’s common stock on the date of grant. Options vest over five years and have a maximum contractual life of either seven or ten years.

Brigham also maintains a director stock option plan under which stock options are awarded to non-employee directors. Options granted under this plan have an exercise price equal to the fair market value of Brigham common stock on the date of grant and vest over five years. Stockholders have authorized the issuance of 1,000,000 shares to non-employee directors and approximately 516,800 shares remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for the six months ended June 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		12,000		$	28.99		931,500		$	19.04
Forfeited or cancelled		(4,800	)	$	8.60		—		$	—
Exercised		(69,300	)	$	8.40		(379,412	)	$	4.80
Options outstanding at the end of the quarter		4,374,300		$	8.47		4,722,225		$	7.91
Options exercisable at the end of the quarter		1,076,620		$	7.32		548,550		$	5.46

The weighted-average grant-date fair value per share of stock options granted during the six months ended June 30, 2011 and 2010 was $18.99 and $12.49, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2011 and 2010 was $904,000 and $3.5 million, respectively.

The following table summarizes information about stock options outstanding and exercisable at June 30, 2011:

	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average	Weighted-
	June 30,		Remaining	Average		June 30,		Remaining	Average
Exercise Price	2011		Contractual Life	Exercise Price		2011		Contractual Life	Exercise Price
$2.20 to $3.11		1,070,000	7.7 years	$	2.24		356,000	7.6 years	$	2.25
3.66 to 5.08		359,600	4.3 years	$	5.08		91,400	4.3 years	$	5.08
5.96 to 6.23		1,589,200	7.6 years	$	5.98		295,920	6.2 years	$	6.02
7.22 to 8.77		110,000	3.3 years	$	7.51		64,000	3.1 years	$	7.46
8.93 to 13.86		218,000	5.4 years	$	11.78		96,000	2.6 years	$	11.02
14.43 to 16.85		62,000	8.9 years	$	15.24		4,800	8.7 years	$	15.47
18.36 to 27.15		953,500	8.7 years	$	19.53		168,500	8.8 years	$	19.11
28.00 to 29.61		12,000	9.8 years	$	28.99		—	—	$	—
$2.20 to $29.61		4,374,300	7.4 years	$	8.47		1,076,620	6.4 years	$	7.32

15

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The aggregate intrinsic value of options outstanding and exercisable at June 30, 2011 was $93.9 million and $24.3 million, respectively. The aggregate intrinsic value represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the quarter and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on June 30, 2011. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of June 30, 2011, there was approximately $14.6 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.8 years.

Restricted Stock

During the six months ended June 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 June 30, 2011, there was approximately $9.5 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 4.8 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 six months ended June 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		(600	)	$	5.26		—		$	—
Lapse of restrictions		(95,163	)	$	12.77		(69,800	)	$	8.78
Shares outstanding at the end of the quarter		708,451		$	16.44		592,553		$	8.16

During the six months ended June 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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Net income (loss)	$	70,835		$	18,473		$	72,839		$	29,788
Unrealized gains (losses) on investments		(155	)		(1,817	)		(51	)		(2,081	)
Other comprehensive income (loss), net	$	70,680		$	16,656		$	72,338		$	27,707

16

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

17. Related Party Transactions

During the six months ended June 30, 2011 and 2010, Brigham incurred costs of approximately $4.6 million and $4.9 million, respectively, in fees for land acquisition services performed by Brigham Land Management, owned by a brother of Brigham’s Chairman, President and Chief Executive Officer and its Executive Vice President — Land and Administration. Other participants in Brigham’s 3-D seismic projects reimbursed Brigham for a portion of these amounts. At June 30, 2011 and December 31, 2010, Brigham had a liability recorded in accounts payable of approximately $420,000 and $1,000, respectively, related to services performed by this company.

During the six months ended June 30, 2011 and 2010, Brigham incurred costs of approximately $803,000 and $904,000, respectively, in fees for services performed by a service company in which Mr. Hobart Smith, one of Brigham’s current directors, owns stock and serves as a consultant. At June 30, 2011 and December 31, 2010, Brigham had a liability recorded in accounts payable of approximately $155,000 and $219,000, respectively, related to services performed by this company.

17

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following updates information as to our financial condition provided in our 2010 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2011 and June 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 have been focused in our Onshore Gulf Coast, the Anadarko Basin and West Texas and Other provinces. However, in late 2007, the majority of our drilling capital expenditures shifted from our historically active areas to the Williston Basin, where we are currently targeting the Bakken and Three Forks objectives. We currently have approximately 375,800 net leasehold acres in the Williston Basin. Through the second quarter 2011, we have invested in excess of $975 million on drilling, land and support infrastructure in this region.

Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we can use technology to generate high rates of return on our invested capital.

Overview of Second Quarter 2011

Second quarter 2011 crude oil prices, excluding realized and unrealized derivative hedging results, increased 40% from that in the second quarter 2010. In the second quarter 2011, the average sales price that we received for crude oil, excluding realized and unrealized derivative hedging results, was $97.01 per barrel, which represents a $27.82 per barrel increase from that in the second quarter 2010. Second quarter 2011 natural gas prices inclusive of natural gas liquids, but excluding realized and unrealized derivative hedging results, increased 13% from that in the second quarter 2010. In the second quarter 2011, the average sales price that we received for natural gas inclusive of natural gas liquids, excluding realized and unrealized derivative hedging results, was $5.90 per Mcf, which represents a $0.66 per Mcf increase from that in the second quarter 2010.

Our second quarter 2011 production volumes were 12,206 barrels of equivalent per day, which represents a 57% increase from last year’s second quarter production volumes. Crude oil represented 84% of our production volumes in the second quarter 2011 as compared to 72% of our production volumes in the second 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 second quarter 2011 production volumes included approximately 18,156 barrels of crude oil added to inventory during the quarter. Adjusting our second quarter 2011 production volumes for our increased level of inventory resulted in sales volumes of 12,004 barrels of equivalent per day in the second quarter 2011 versus sales volumes of 7,700 barrels of equivalent per day in the second quarter 2010.

Our second quarter 2011 crude oil revenue, including cash hedge settlements but excluding unrealized hedging gains and losses, increased $50.2 million, or 146%, compared to that in the second quarter 2010. Crude oil revenue increased $27.9 million due to higher sales volumes and $25.0 million due to higher sales prices. These increases were partially offset by a $2.7 million decrease in crude oil cash hedge settlements.

18

Second quarter 2011 natural gas revenue, including cash hedge settlements but excluding unrealized hedging gains and losses, decreased $0.4 million from that in the second quarter 2010. Natural gas revenue decreased $0.5 million due to lower sales volumes and $0.6 million due to lower cash hedge settlements. These decreases were partially offset by the higher natural gas prices during the second quarter 2011 compared to those in the prior year’s quarter, which increased natural gas revenue by $0.7 million.

Second quarter 2011 operating income was $81.3 million versus $19.3 million in the second quarter last year. The improvement in revenue associated with higher crude oil production, higher commodity prices as well as higher unrealized mark-to-market hedging gains was partially offset by lower cash hedge settlements and lower natural gas production. Higher revenue was also partially offset by increased depletion, lease operating and production tax expenses.

As of June 30, 2011, we had $362.3 million in cash, cash equivalents and short term investments and $1.6 billion in total assets. Short term investments totaling $180.6 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 June 30, 2011 also includes approximately $120.6 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.

During the second quarter, we announced an acceleration of our drilling activities in the Williston Basin and reached 10 operated rigs in July 2011, which represents an acceleration of approximately six months relative to our previously announced schedule. In connection with the acceleration, we increased our capital budget for 2011 by approximately 21% and issued $300 million in senior notes to pre-fund our drilling activities. Furthermore, we also announced that two additional operated rigs would be added during the first quarter 2012.

Results for the Three and Six Months Ended June 30, 2011

Comparison of the three month and six month periods ended June 30, 2011 and 2010.

Production volumes

	Three months ended June 30,							Six months ended June 30,
	2011		%Change			2010		2011		%Change			2010
Crude oil (MBbls)(1)		919		83	%		503		1,748		113	%		822
Natural gas (MMcf)		1,079		(8	%)		1,173		2,215		2	%		2,182
Total (MBoe)(2)		1,099		57	%		698		2,117		79	%		1,186
Average daily production (Boe/d)(3)		12,206		57	%		7,756		11,760		79	%		6,588

(1)	Includes approximately 18,156 and 5,089 barrels of crude oil produced in the Williston Basin and added to inventory during the second quarters 2011 and 2010, respectively. Includes approximately 18,888 and 10,101 barrels of crude oil produced in the Williston Basin and added to inventory during the first half of 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.

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Sales Volumes (Production volumes less the Incremental Change in Inventory)

	Three months ended June 30,							Six months ended June 30,
	2011		%Change			2010		2011		%Change			2010
Crude oil (MBbls)(1)		901		81	%		497		1,729		113	%		812
Natural gas (MMcf)		1,079		(8	%)		1,173		2,215		2	%		2,182
Total (MBoe)(2)		1,080		56	%		693		2,098		78	%		1,176
Average daily production (Boe/d)(3)		12,004		56	%		7,700		11,655		78	%		6,532

(1)	Excludes approximately 18,156 and 5,089 barrels of crude oil produced in the Williston Basin and added to inventory during the second quarters 2011 and 2010, respectively. Excludes approximately 18,888 and 10,101 barrels of crude oil produced in the Williston Basin and added to inventory during the first half of 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 84% of our second quarter 2011 production volumes and 83% of our first six months 2011 production volumes, compared to 72% in the second quarter 2010 and 69% in the first six months 2010.

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Revenue, Commodity Prices and Hedging

The following table sets forth our revenue, our derivative settlement gains (losses), our unrealized derivative gains (losses), the average prices we received before hedging, the average prices we received including derivative settlement gains (losses) and the average prices including derivative settlements and unrealized gains (losses).

	Three months ended June 30,									Six months ended June 30,
	2011			%Change			2010			2011			%Change			2010
Crude oil revenue:
Crude oil revenue	$	87,361			154	%	$	34,423		$	156,957			174	%	$	57,293
Crude oil derivative settlement gains (losses)		(2,837	)		2,049	%		(132	)		(3,883	)		1,603	%		(228	)
Crude oil revenue including derivative settlements	$	84,524			146	%	$	34,291		$	153,074			168	%	$	57,065
Crude oil unrealized derivative gains (losses)		36,167			611	%		5,088			1,144			(79	%)		5,563
Crude oil revenue including derivative settlements and unrealized gains (losses)	$	120,691			206	%	$	39,379		$	154,218			146	%	$	62,628
Natural gas revenue:
Natural gas revenue	$	6,365			4	%	$	6,141		$	12,732			4	%	$	12,201
Natural gas derivative settlement gains (losses)		369			(63	%)		993			1,465			(12	%)		1,671
Natural gas revenue including derivative settlements	$	6,734			(6	%)	$	7,134		$	14,197			2	%	$	13,872
Natural gas unrealized derivative gains (losses)		(278	)		(82	%)		(1,587	)		(1,263	)	NM				990
Natural gas revenue including derivative settlements and unrealized gains (losses)	$	6,456			16	%	$	5,547		$	12,934			(13	%)	$	14,862
Crude oil and natural gas revenue:
Crude oil and natural gas revenue	$	93,726			131	%	$	40,564		$	169,689			144	%	$	69,494
Crude oil and natural gas derivative settlement gains (losses)		(2,468	)	NM				861			(2,418	)	NM				1,443
Crude oil and natural gas revenue including derivative settlement gains (losses)		91,258			120	%		41,425			167,271			136	%		70,937
Crude oil and natural gas unrealized derivative gains (losses)		35,889			925	%		3,501			(119	)	NM				6,553
Crude oil and natural gas revenue including derivative settlements and unrealized gains (losses)		127,147			183	%		44,926			167,152			116	%		77,490
Support infrastructure revenue		890		NM				—			1,484		NM				—
Other revenue		3			(25	%)		4			5			(62	%)		13
Total revenue	$	128,040			185	%	$	44,930		$	168,641			118	%	$	77,503

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	Three months ended June 30,							Six months ended June 30,
	2011		%Change			2010		2011		%Change			2010
Average crude oil prices:
Crude oil price (per Bbl)	$	97.01		40	%	$	69.19	$	90.79		29	%	$	70.55
Crude oil price including derivative settlement gains (losses) (per Bbl)		93.86		36	%		68.93		88.54		26	%		70.27
Crude oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	134.01		69	%	$	79.16	$	89.20		16	%	$	77.12
Average natural gas prices:
Natural gas price (per Mcf)	$	5.90		13	%	$	5.24	$	5.75		3	%	$	5.59
Natural gas price including derivative settlement gains (losses) (per Mcf)		6.24		3	%		6.08		6.41		1	%		6.36
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	5.98		26	%	$	4.73	$	5.84		(14	%)	$	6.81
Average equivalent prices:
Crude oil equivalent price (per Boe)	$	86.75		48	%	$	58.53	$	80.88		37	%	$	59.09
Crude oil equivalent price including derivative settlement gains (losses) (per Boe)		84.47		41	%		59.78		79.73		32	%		60.32
Crude oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)	$	117.69		82	%	$	64.83	$	79.67		21	%	$	65.89

	For the three			For the six
	month periods			month periods
	ended June 30,			ended June 30,
	2011 and 2010			2011 and 2010
Change in revenue from the sale of crude oil
Volume variance impact	$	27,889		$	64,676
Price variance impact		25,049			34,988
Cash settlement of hedging contracts		(2,705	)		(3,655	)
Unrealized hedge gain or loss		31,079			(4,419	)
Total change	$	81,312		$	91,590
Change in revenue from the sale of natural gas
Volume variance impact	$	(488	)	$	179
Price variance impact		712			352
Cash settlement of hedging contracts		(624	)		(206	)
Unrealized hedge gain or loss		1,309			(2,253	)
Total change	$	909		$	(1,928	)
Change in revenue from the sale of crude oil and natural gas
Volume variance impact	$	27,401		$	64,855
Price variance impact		25,761			35,340
Cash settlement of hedging contracts		(3,329	)		(3,861	)
Unrealized hedge gain or loss		32,388			(6,672	)
Total change	$	82,221		$	89,662

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Second quarter 2011 crude oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) increased $82.2 million when compared to the second quarter 2010. The change in revenues was attributable to the following:

• a $35.9 million unrealized derivative gain in second quarter 2011 versus a $3.5 million unrealized derivative gain in second quarter 2010 increased revenues by $32.4 million;

• an 81% increase in crude oil sales volumes, which was partially offset by an 8% decrease in natural gas sales volumes, resulted in a $27.4 million increase in revenues;

• an increase in pre-hedge crude oil and natural gas prices of 40% and 13%, respectively, increased revenues by $25.8 million; and

• a $2.5 million cash loss from the settlement of derivative contracts in the second quarter 2011 versus a $0.8 million cash gain from the settlement of derivative contracts in the second quarter 2010 decreased revenues by $3.3 million.

First six months 2011 crude oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) increased $89.7 million when compared to that in the first six months 2010. The change in revenues was attributable to the following:

• an increase in crude oil and natural gas sales volumes of 113% and 2%, respectively, drove a $64.9 million increase in revenues;

• an increase in pre-hedge crude oil and natural gas prices of 29% and 3%, respectively, increased revenues by $35.3 million;

• a $0.1 million unrealized derivative loss in first six months 2011 versus a $6.6 million unrealized derivative gain in first six months 2010 decreased revenues by $6.7 million; and

• a $2.4 million cash loss from the settlement of derivative contracts in the first six months 2011 versus a $1.5 million cash gain from the settlement of derivative contracts in first six months 2010 decreased revenues by $3.9 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 second quarter and first six 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.

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	Three months ended June 30,									Six months ended June 30,
	2011			%Change			2010			2011			%Change			2010
Crude oil collars
Volumes (Bbls)		556,000			164	%		211,000			1,074,000			202	%		356,000
Average floor price (per Bbl)	$	65.68			7	%	$	61.55		$	65.91			10	%	$	60.03
Average ceiling price (per Bbl)	$	98.83			10	%	$	90.16		$	98.59			11	%	$	88.95
Gain (loss) upon settlement (in thousands)	$	(2,837	)		2,049	%	$	(132	)	$	(3,883	)		1,603	%	$	(228	)
Total crude oil
Gain (loss) upon settlement (in thousands)	$	(2,837	)		2,049	%	$	(132	)	$	(3,883	)		1,603	%	$	(228	)
Natural gas collars
Volumes (MMbtu)		330,000			(52	%)		690,000			870,000			(22	%)		1,110,000
Average floor price (per MMbtu)	$	5.48			(1	%)	$	5.51		$	5.91			8	%	$	5.49
Average ceiling price (per MMbtu)	$	7.16			2	%	$	7.02		$	7.55			8	%	$	7.02
Gain (loss) upon settlement (in thousands)	$	369			(63	%)	$	993		$	1,465			33	%	$	1,098
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)	$	369			(63	%)	$	993		$	1,465			(12	%)	$	1,671

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 fully operational in the fourth quarter 2011.

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 June 30,							Three months ended June 30,
	2011		% Change			2010		2011		% Change			2010
Production costs:
Operating & maintenance	$	5.94		46	%	$	4.06	$	6,408		127	%	$	2,821
Expensed workovers		1.61		(14	%)		1.88		1,741		34	%		1,300
Ad valorem taxes		0.53		47	%		0.36		575		130	%		250
Lease operating expenses	$	8.08		28	%	$	6.30	$	8,724		100	%	$	4,371
Production taxes		8.75		55	%		5.63		9,451		142	%		3,900
Production costs	$	16.83		41	%	$	11.93	$	18,175		120	%	$	8,271

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Second quarter 2011 per unit of production costs increased $4.90 per Boe, or 41%, compared to that in the second quarter last year primarily due to the following:

• production taxes increased $3.12 per Boe, or 55%, 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

• operating and maintenance expenses increased $1.88 per Boe, or 46%, primarily due to increased costs associated with surface location and road repairs following the record winter snowfall melt and the heavy rains and higher produced water disposal costs for volumes injected at third party disposal wells.

	Unit-of-Production							Amount
	(Per Boe)							(In thousands)
	Six months ended June 30,							Six months ended June 30,
	2011		% Change			2010		2011		% Change			2010
Production costs:
Operating & maintenance	$	5.70		23	%	$	4.63	$	11,951		119	%	$	5,445
Expensed workovers		1.59		(33	%)		2.36		3,343		20	%		2,775
Ad valorem taxes		0.55		28	%		0.43		1,150		130	%		500
Lease operating expenses	$	7.84		6	%	$	7.42	$	16,444		89	%	$	8,720
Production taxes		8.17		50	%		5.45		17,149		168	%		6,408
Production costs	$	16.01		24	%	$	12.87	$	33,593		122	%	$	15,128

First six months 2011 per unit of production costs increased $3.14 per Boe, or 24%, when compared to the first six months last year mainly due to the following:

• production taxes increased $2.72 per Boe, or 50%, due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to an 11.5% tax rate;

• operating and maintenance expenses increased $1.07 per Boe, or 23%, due to increased costs associated with surface location and road repairs following the record winter snowfall melt and the heavy rains and higher produced water disposal costs for volumes injected at third party disposal wells; and

• expensed workovers decreased $0.77 per Boe, or 33%, largely due to our higher sales volumes.

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 June 30,									Six months ended June 30,
	2011			% Change			2010			2011			% Change			2010
	(In thousands, except per unit measurements)
General and administrative costs	$	6,262			17	%	$	5,332		$	12,900			15	%	$	11,247
Capitalized general and administrative costs		(3,097	)		18	%		(2,621	)		(6,353	)		17	%		(5,450	)
General and administrative expenses	$	3,165			17	%	$	2,711		$	6,547			13	%	$	5,797
General and administrative expense ($  per Boe)	$	2.93			(25	%)	$	3.91		$	3.12			(37	%)	$	4.93

Our general and administrative costs prior to capitalization for the first three months and six months of 2011 increased primarily because of higher employee compensation costs due to higher levels of non-cash stock compensation expense. Our per unit costs decreased due to our higher sales volumes.

Depletion of crude oil and natural gas properties. Our depletion expense is driven by many factors including certain costs spent in the exploration for and development of producing reserves, production levels, and estimates of proved reserve quantities and future developmental costs at the end of the year.

25

	Three months ended June 30,							Six months ended June 30,
	2011		% Change			2010		2011		% Change			2010
	(In thousands, except per unit measurements)
Depletion of crude oil and natural gas properties	$	23,531		65	%	$	14,247	$	42,471		81	%	$	23,458
Depletion of crude oil and natural gas properties ($  per Boe)	$	21.79		6	%	$	20.56	$	20.24		1	%	$	19.95

Our depletion expense for the second quarter 2011 was $9.3 million higher than that in the second quarter 2010. Higher sales volumes and a higher depletion rate increased depletion expense by $8.0 million and $1.3 million, respectively.

Our depletion expense for the first six months 2011 was $19.0 million higher than that in the first six months 2010. Higher sales volumes and a higher depletion rate increased depletion expense by $18.4 million and $0.6 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 six month periods ended June 30, 2011 and 2010, no ceiling test impairment was recorded.

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.

26

	Three months ended June 30,									Six months ended June 30,
	2011			% Change			2010			2011			% Change			2010
	(In thousands)
Interest on Senior Notes	$	8,969			133	%	$	3,850		$	15,531			102	%	$	7,700
Interest on Senior Credit Facility		125		NM				—			128		NM				—
Commitment fees		407			150	%		163			661			103	%		326
Dividend on mandatorily redeemable preferred stock		—			(100	%)		120			—			(100	%)		269
Amortization of deferred loan and debt issuance cost		591			23	%		481			1,108			15	%		963
Other general interest expense		63			(38	%)		101			99			(2	%)		101
Capitalized interest expense		(4,361	)		144	%		(1,784	)		(8,355	)		137	%		(3,524	)
Net interest expense	$	5,794			98	%	$	2,931		$	9,172			57	%	$	5,835
Weighted average debt outstanding	$	463,492			176	%	$	167,881		$	382,197			126	%	$	168,985
Average interest rate on outstanding indebtedness (a)		8.3	%					10.1	%		8.7	%					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.

Second quarter 2011 interest expense was $2.9 million higher than that in 2010 primarily due to a $5.1 million increase in interest expense associate 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 $2.6 million increase in capitalized interest expense associated with our higher level of activity in the Williston Basin.

First six months 2011 interest expense was $3.3 million higher than that in 2010 primarily due to a $7.8 million increase in interest expense associate 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 $4.8 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 June 30,							Six months ended June 30,
	2011		% Change			2010		2011		% Change			2010
	(In thousands)
Other income (expense):
Total other income (expense)	$	3,934		233	%	$	1,181	$	7,088		280	%	$	1,866

Other income increased in 2011 as a result of higher levels of field general equipment income in the Williston Basin.

Income taxes.Based on estimates of our annual effective tax rate of 11.2%, we recorded $8.9 million and $9.1 million in deferred federal and state income tax expense in the second quarter and the first six months of 2011, respectively, compared to no current or deferred federal or state income tax expense in the second quarter and the first six months of 2010. The differences in our effective tax rate of 11.2% and the statutory rate of 35% are primarily due to decreases in our valuation allowances on federal and state net operating losses and our inability to deduct certain portions of our non-cash stock compensation expense for federal income tax purposes.

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Capital Expenditures

The timing of most of our capital expenditures is discretionary because we operate the majority of our wells. 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 prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of our planned expenditures include the level of production from our existing crude oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our exploration and development drilling schedule to ensure that we are optimizing our capital expenditure plan.

The final determination with respect to our 2011 budgeted expenditures will depend on a number of factors, including:

• commodity prices;

• production from our existing producing wells;

• the results of our current exploration and development drilling efforts;

• economic conditions at the time of drilling;

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

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

• the availability of more economically attractive prospects.

There can be no assurance that the budgeted wells will, if drilled, encounter commercial quantities of crude oil or natural gas.

Factors that could cause us to further increase our level of activity and capital budget in 2011 include an improvement in commodity prices or well performance that exceeds our risked forecasts, the divestiture of non-strategic conventional assets, a reduction in service and material costs, or the formation of joint ventures with other exploration and production companies outside of our core de-risked acreage positions in the Williston Basin, all of which would positively impact our operating cash flow.

Factors that would cause us to reduce our capital budget in 2011 include, but are not limited to, reductions in commodity prices or underperformance of wells relative to our risked forecasts or increases in service and materials costs, all of which would negatively impact our operating cash flow.

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The table below summarizes our 2011 oil and gas capital expenditure budget, the amount spent through June 30, 2011 and the amount of our 2011 oil and gas capital expenditure budget that remains to be spent.

			Amount
	2011		Spent Through		Amount
	Budget		June 30, 2011		Remaining (a)
	(In millions)
Drilling	$	669.2	$	276.8	$	392.4
Support infrastructure		87.1		32.8		54.3
Land		79.2		57.3		21.9
Oil and gas capital expenditures	$	835.5	$	366.9	$	468.6

(a) Calculated based on the revised 2011 oil and gas capital expenditure budget announced in May 2011 less amounts spent through June 30, 2011.

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2011, we intend to fund our capital expenditure program and contractual commitments with cash, cash equivalents, short term investments on hand as of June 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 June 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 June 30, 2011.

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6 7/8% Senior Notes

As of June 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.

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 June 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 June 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 the event that the borrowing base is adjusted below the amount that we have borrowed, our access to further borrowings will be reduced, and we may not have the resources necessary to pay off the borrowing base deficiency and carry out our planned spending for exploration and development activities.

Borrowings under our 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 America’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change.

Our 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.

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Mandatorily Redeemable Preferred Stock

In June 2010, we exercised our option to redeem all of our Series A mandatorily redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC.

Off Balance Sheet Arrangements

We currently have operating leases, which are considered off balance sheet arrangements. We do not currently have any other off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the debt of any other party. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Analysis of Changes in Cash and Cash Equivalents

The table below summarizes our sources and uses of cash during the periods indicated.

	Six months ended June 30,
	2011			%Change			2010
	(In thousands)
Net income (loss)	$	72,389			143	%	$	29,788
Non-cash items		57,122			237	%		16,952
Changes in working capital and other items		30,930			53	%		20,180
Cash flows provided by operating activities	$	160,441			140	%	$	66,920
Cash flows (used) by investing activities		(292,869	)		0	%		(293,792	)
Cash flows provided by financing activities		290,374			8	%		268,913
Net increase in cash and cash equivalents	$	157,946			276	%	$	42,041

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 six months of 2011 was $93.5 million higher than the first six months of 2010. The following are the primary reasons for the increase:

• higher crude oil and natural gas sales volumes increased operating cash flow by $64.9 million;

• higher oil equivalent sales prices increased operating cash flow by $35.3 million;

• higher production taxes decreased operating cash flow by $10.7 million; and

• higher lease operating costs decreased operating cash flow by $7.7 million.

Analysis of changes in cash flows used in investing activities

	Six months ended June 30,
	2011		%Change			2010
	(In thousands)
Capital expenditures for crude oil and natural gas activities:
Drilling	$	276,792		141	%	$	114,930
Support infrastructure		32,836	NM				—
Land		57,273		94	%		29,539
Capitalized cost		13,559		51	%		8,974
Capitalized asset retirement obligation		552		115	%		257
Total	$	381,012		148	%	$	153,700

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	Six months ended June 30,
	2011			%Change			2010
	(In thousands)
Reconciling Items:
Asset sale proceeds including ARO liability reduction	$	—			(100	%)	$	(13,706	)
Change in accrued drilling costs		(55,549	)		86	%		(29,849	)
Change in short term investments		(43,355	)	NM				172,342
Change in other property and equipment		1,640			(69	%)		5,375
Change in inventory		12,529			229	%		3,806
Other		(3,408	)	NM				2,124
Total Reconciling Items		(88,143	)	NM				140,092
Net cash used in investing activities	$	292,869			0	%	$	293,792

Net cash used by investing activities was impacted by the following items during in the first six months 2011:

• drilling expenditures increased by $161.9 million;

• land expenditures increased by $27.7 million;

• capitalized costs increased by $4.6 million;

• the change in accrued drilling costs decreased cash used in investing activities by $25.7 million;

• the change in short term investments decreased cash used in investing activities by $215.7 million; and

• the change in inventory increased cash used in investing activities by $8.7 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first six months of 2011 was 8% greater than the first six months of 2010. During the first six months 2011, we received net proceeds of $294.4 million associated with our May 2011 Senior Notes offering. During the first six months 2010, we received net proceeds of $277.5 million from our April 2010 common stock offering.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the six months ended June 30, 2011 and 2010.

	Shares Issued		Net Proceeds
			(In thousands)
2011 common stock transactions:
Exercise of employee stock options		69,300	$	582
2010 common stock transactions:
Common stock offering (April)		16,100,000	$	277,547
Exercise of employee stock options		379,412	$	1,854

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.

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Effects of Inflation and Changes in Prices

Our results of operations and cash flows are affected by changing crude oil and natural gas prices. If the price of crude oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues as well as the operating costs that we are required to bear for operations.

Environmental and Other Regulatory Matters

Our business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and marketing of crude oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although we believe that we are in substantial compliance with all applicable laws and regulations, the requirements imposed by laws and regulations are frequently changed and subject to interpretation, and we cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect our financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to us, compliance has not had a material adverse effect on our earnings or competitive position. Future regulations may add to the cost of, or significantly limit, drilling activity.

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.

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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 June 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.

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The following tables reflect our open crude oil and natural gas contracts as of June 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
07/01/11 – 12/31/11		42,000	$	65.00	$	88.25
07/01/11 – 12/31/11		30,000	$	60.00	$	97.25
07/01/11 – 12/31/11		30,000	$	65.00	$	108.00
07/01/11 – 12/31/11		24,000	$	70.00	$	106.80
07/01/11 – 12/31/11		24,000	$	75.00	$	102.60
07/01/11 – 12/31/11		12,000	$	75.00	$	103.00
07/01/11 – 09/30/11		9,000	$	70.00	$	95.00
10/01/11 – 12/31/11		6,000	$	70.00	$	96.35
07/01/11 – 07/31/11		3,000	$	70.00	$	94.80
07/01/11 – 12/31/11		12,000	$	75.00	$	95.15
07/01/11 – 12/31/11		18,000	$	75.00	$	104.30
01/01/12 – 06/30/12		60,000	$	75.00	$	106.90
07/01/11 – 12/31/11		18,000	$	65.00	$	100.00
07/01/11 – 07/31/12		198,500	$	65.00	$	97.20
07/01/11 – 07/31/12		198,500	$	65.00	$	98.55
07/01/11 – 07/31/12		198,500	$	65.00	$	100.00
07/01/11 – 07/31/12		198,500	$	65.00	$	100.40
07/01/11 – 08/31/11		15,500	$	65.00	$	94.80
09/01/11 – 12/31/11		61,000	$	65.00	$	97.40
01/01/12 – 06/30/12		182,000	$	65.00	$	99.25
09/01/11 – 12/31/11		61,000	$	65.00	$	99.00
07/01/11 – 08/31/11		15,500	$	65.00	$	96.75
01/01/12 – 06/30/12		91,000	$	65.00	$	101.00
01/01/12 – 06/30/12		182,000	$	65.00	$	100.75
01/01/12 – 06/30/12		91,000	$	65.00	$	102.75
07/01/12 – 07/31/12		62,000	$	65.00	$	102.25
07/01/11 – 12/31/11		92,000	$	65.00	$	100.00
07/01/12 – 07/31/12		31,000	$	65.00	$	105.25
07/01/11 – 12/31/11		92,000	$	65.00	$	106.50
07/01/11 – 12/31/11		92,000	$	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
07/01/11 – 12/31/11*		276,000	$	65.00	$	100.00
08/01/12 – 10/31/12		276,000	$	75.00	$	112.50
11/01/12 – 12/31/12		244,000	$	75.00	$	112.50
07/01/12 – 07/31/12		62,000	$	75.00	$	114.00
01/01/13 – 02/28/13		118,000	$	75.00	$	113.05
01/01/13 – 03/31/13		180,000	$	80.00	$	120.00
03/01/13 – 03/31/13		62,000	$	80.00	$	120.00
02/01/12 – 12/31/12		335,000	$	80.00	$	134.25
01/01/13 – 03/31/13		270,000	$	80.00	$	129.45
09/01/11 – 12/31/11		244,000	$	90.00	$	144.00
01/01/12 – 12/31/12		366,000	$	85.00	$	139.50
01/01/13 – 05/31/13		302,000	$	85.00	$	134.00

* Crude oil collar was completed in two phases. First, the put option (floor) was purchased. Subsequently, the call option (ceiling) was sold thereby converting the position into a collar.

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	Crude		Purchased
	Oil		Put
Settlement Period	(Bbls)		(Nymex)
Crude Oil Puts
01/01/12 – 06/30/12		91,000	$	65.00
01/01/12 – 06/30/12		91,000	$	65.00
01/01/12 – 06/30/12		45,500	$	65.00
01/01/12 – 06/30/12		45,500	$	65.00
07/01/12 – 12/31/12		276,000	$	80.00

	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
Natural Gas Costless Collars
07/01/11 – 12/31/11		180,000	$	5.75	$	7.65
07/01/11 – 12/31/11		240,000	$	5.75	$	7.40
07/01/11 – 12/31/11		240,000	$	5.00	$	6.55

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 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 second quarter of 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

As discussed in Note 3 of Notes to the Consolidated Financial Statements included in Part I. Financial Statements, Brigham is party to various legal actions arising in the ordinary course of business and does not expect these matters to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors disclosed in Item 1A. of our report on Form 10-K for the year ended December 31, 2010.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

In the second 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.

							Maximum
							Number (or
							Approximate
							Dollar Value) of
					Total Number of		Shares that May
					Shares Purchased		Yet Be
					as Part of Publicly		Purchased Under
	Total Number of		Average Price		Announced Plans		the Plans or
Period	Shares Purchased		Paid per Share		or Programs		Programs
April 2011		—	$	—		—		—
May 2011		1,326		28.752		—		—
June 2011		—		—		—		—
Total		1,326	$	28.752		—		—

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (REMOVED AND RESERVED)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

3.1	Certificate of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
3.2	Certificates of Amendment of Certificate of Incorporation of Brigham Exploration Company dated May 6, 1999 and May 22, 2000 (filed as Exhibit 3.1.1 to Brigham’s Registration Statement on Form S-3 (Registration No. 333-37558) and incorporated herein by reference)
3.3	Bylaws, as amended through May 28, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (filed May 28, 2009) and incorporated herein by reference)
3.4	Certificate of Amendment of Certificate of Incorporation of Brigham Exploration Company dated June 14, 2006, (filed as Exhibit 3.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference)
3.5	Certificate of Amendment of Certificate of Incorporation of Brigham Exploration Company dated October 7, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (filed October 13, 2009) and incorporated herein by reference)
4.1	Form of Common Stock Certificate (filed as Exhibit 4.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491) and incorporated herein by reference)
4.2	Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference)
4.3	Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed March 2, 2001 (filed as Exhibit 4.2.1 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2000 and incorporated herein by reference)
4.4	Certificate of Elimination of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company dated August 9, 2010 (filed as Exhibit 3.7 to Brigham’s Current Report on Form 8-K (filed August 10, 2010) and incorporated herein by reference)
4.5	Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference)
4.6	Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of Brigham Exploration Company, dated June 4, 2004 (filed as Exhibit 99.2 to Brigham’s Current Report on Form 8-K (filed July 20, 2004) and incorporated herein by reference)
4.7	Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
4.8	Certificate of Elimination of Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham Exploration Company dated March 9, 2010 (filed as Exhibit 3.6 to Brigham’s Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)

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4.9		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 Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
4.10		Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.18 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
4.11		Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.19 to Brigham’s Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference)
4.12	*	Indenture, dated May 19, 2011, among Brigham Exploration Company, Brigham, Inc., Brigham Oil & Gas, L.P. and Wells Fargo Bank, National Association, as Trustee
4.13	*	Rule 144A 6 7/8% Senior Note due 2019 and Notation of Guarantee
4.14	*	Regulation S 6 7/8% Senior Note due 2019 and Notation of Guarantee
4.15	*	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
10.33		First Amendment to the Fifth Amended and Restated Credit Agreement dated February 23, 2011 among Brigham Oil & Gas, L.P., Brigham Exploration Company and Brigham, Inc. and Bank of America, N.A. (filed as Exhibit 10.33 to Brigham’s Current Report on Form 8-K (filed May 16, 2011) and incorporated herein by reference)
10.34		Purchase Agreement dated May 16, 2011 among the Company, the Guarantors and the Purchasers (filed as Exhibit 10.34 to Brigham’s Current Report on Form 8-K (filed May 19, 2011) and incorporated herein by reference)
10.35		Amendment to 1997 Director Stock Option Plan (filed as Exhibit 10.35 to Brigham’s Current Report on Form 8-K (filed June 24, 2011) and incorporated herein by reference)
31.1	*	Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
31.2	*	Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
32.1	*	Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350
32.2	*	Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
101.INS	**	XBRL Instance Document
101.SCH	**	XBRL Schema Document
101.CAL	**	XBRL Calculation Linkbase Document
101.LAB	**	XBRL Label Linkbase Document
101.PRE	**	XBRL Presentation Linkbase Document
101.DEF	**	XBRL Definition Linkbase Document

*	Filed herewith.
**	Furnished herewith.

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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 August 8, 2011.

BRIGHAM EXPLORATION COMPANY
By:	/s/ BEN M. BRIGHAMBen M. Brigham
	Chief Executive Officer, President and
	Chairman of the Board
By:	/s/ EUGENE B. SHEPHERD, JR.Eugene B. Shepherd, Jr.
	Executive Vice President and
	Chief Financial Officer

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