8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 8, 2011

BRIGHAM EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	001-34224	75-2692967
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

6300 Bridgepoint Parkway Building Two, Suite 500 Austin, Texas	78730
(Address of principal executive offices)	(Zip Code)

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

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operation and Financial Condition.

We are furnishing our press release dated August 8, 2011, which announced our financial results for the second quarter ended June 30, 2011 and provided third quarter and full year forecasts. The text of that press release is attached to this Report as Exhibit 99.1 and is incorporated by reference herein.

We are also furnishing our press release dated August 8, 2011, which announced operational results. The text of that press release is attached to this Report as Exhibit 99.2 and is incorporated by reference herein.

Item 7.01 Regulation FD Disclosure.

In addition to the filing of this report on Form 8-K and the issuance of the attached press releases, we are also updating our corporate presentation, which can be found on our website at www.bexp3d.com. We caution you that the information provided in our corporate presentation is given as of August 9, 2011 based on currently available information, and that we are not undertaking any obligation to update it as conditions change or other information becomes available.

Item 9.01 Financial Statements and Exhibits.

(d)	Exhibit 99.1 Press Release dated August 8, 2011.
	Exhibit 99.2 Press Release dated August 8, 2011.

2

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BRIGHAM EXPLORATION COMPANY
Date: August 9, 2011
	By:	/s/ Eugene B. Shepherd, Jr.
		Eugene B. Shepherd, Jr.
		Executive Vice President & Chief Financial Officer

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INDEX TO EXHIBITS

Item Number	Exhibit
99.1	Press Release dated August 8, 2011.
99.2	Press Release dated August 8, 2011.

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EX-99.1

Exhibit 99.1

NEWS RELEASE
FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION REPORTS RECORD QUARTERLY PRODUCTION VOLUMES, RECORD EARNINGS EXCLUDING CERTAIN ITEMS, SECOND QUARTER 2011 RESULTS AND UPDATES 2011 FORECASTS

Austin, TX — August 8, 2011 — Brigham Exploration Company (NASDAQ:BEXP) today announced record quarterly production volumes, record earnings excluding certain items and its financial results for the second quarter and six months ended June 30, 2011.

SECOND QUARTER 2011 RESULTS

Our average daily production volumes for the second quarter 2011 were a quarterly record 12,206 barrels of crude oil equivalent (Boe) per day, up 57% from the second quarter 2010 and up 8% from the first quarter 2011. Our previous record quarterly production volumes of 11,384 Boe per day were achieved in the fourth quarter 2010.

Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our crude oil production volumes for the second quarter 2011 averaged 10,208 barrels per day, which represents an 83% increase from that in the second quarter 2010 and an 11% sequential increase from that in the first quarter 2011. Our crude oil production volumes represented 84% of our total production volumes in the second quarter 2011 as compared to 72% in the second quarter 2010 and 81% in the first quarter 2011.

Our production volumes in the Williston Basin for the second quarter 2011 were 10,401 Boe per day, which represents an 88% increase from that in the second quarter 2010 and an 11% sequential increase from that in the first quarter 2011.

Our second quarter production volumes included approximately 18,156 barrels of crude oil produced during the quarter and added to inventory. Adjusting our production volumes for amounts included in inventory resulted in second quarter 2011 daily sales volumes of 12,004 Boe per day.

Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the second quarter 2011, were up 120% to $91.3 million as compared to that in the second quarter 2010. Higher crude oil sales volumes and crude oil prices increased revenues by $27.9 million and $25.0 million, respectively. Higher natural gas prices also increased revenues by $0.7 million. Lower cash hedge settlements and natural gas sales volumes decreased revenues by $3.3 million and $0.5 million, respectively.

During the second quarter 2011, our average realized price for crude oil was $93.86 per barrel, which included a $3.15 per barrel cash loss due to the settlement of our crude oil derivative contracts. This compares to an average realized price in the second quarter 2010 of $68.93 per barrel, which included a $0.26 per barrel cash loss due to the settlement of our crude oil derivative contracts. Our average realized price for natural gas inclusive of natural gas liquids in the second quarter 2011 was $6.24 per Mcf, which included a $0.34 per Mcf cash gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the second quarter 2010 of $6.08 per Mcf, which included a $0.84 per Mcf cash gain due to the settlement of our natural gas derivative contracts.

Our second quarter 2011 production costs, which include costs for operating and maintaining (O&M expense) our producing wells, expensed workovers, ad valorem taxes and production taxes, increased $4.90 per Boe when compared to those in the second quarter 2010. The increase was largely attributable to a $3.12 per Boe increase in production taxes, which was driven by higher commodity prices and higher levels of production in North Dakota, which are subject to an 11.5% tax rate. The increase was also partially attributable to a $1.88 per Boe increase in O&M expense, partially attributable to increased costs associated with surface location and road repairs following the record winter snowfall melt and subsequent heavy rains and higher produced water disposal costs for volumes injected at third party disposal wells.

Our general and administrative (G&A) expenses for the second quarter 2011 decreased by $0.98 per Boe to $2.93 per Boe due to our higher sales volumes. The per unit decrease associated with our higher sales volumes was partially offset by an increase in employee compensation costs due to higher levels of non-cash stock compensation expense.

Our depletion expense for the second quarter 2011 was $23.5 million ($21.79 per Boe) compared to $14.2 million ($20.56 per Boe) in the second quarter 2010. Our higher sales volumes increased depletion expense by $8.0 million and our higher depletion rate increased depletion expense by $1.3 million.

Our net interest expense for the second quarter 2011 was $2.9 million higher than that in the second quarter 2010. Interest expense increased due to the September 2010 issuance of our $300 million Senior Notes due 2018 and the May 2011 issuance of our $300 million Senior Notes due 2019. These increases were partially offset by an increase in our capitalized interest associated with our higher level of drilling activity in the Williston Basin.

We recorded deferred income tax expense of $8.9 million in the second quarter 2011, which consists of $6.2 million in deferred federal income tax expense and $2.7 million in deferred North Dakota state income tax expense.

Our reported net income for the second quarter 2011 was $70.8 million ($0.60 per diluted share) versus net income of $18.5 million ($0.16 per diluted share) for the same period last year. Our after-tax earnings in the second quarter 2011 excluding unrealized mark-to-market hedging gains were $38.7 million ($0.33 per diluted share) as compared to our after-tax earnings in the second quarter 2010 excluding unrealized mark-to-market hedging gains were $15.0 million ($0.13 per diluted share). After-tax earnings excluding the above items is a non-GAAP measure and a reconciliation of GAAP net income to after-tax earnings excluding the above items is included in our accompanying financial tables found later in this release.

In the second quarter, 2011, we spent $244.1 million in oil and gas capital expenditures. Capital expenditures for the second quarter 2011 and 2010 were:

	Three months ended June 30,
	2011		2010
	(in thousands)
Drilling	$	166,014	$	71,324
Support infrastructure		27,572		—
Land		50,503		21,062
Oil and gas capital expenditures	$	244,089	$	92,386
Capitalized costs		6,918		4,405
Capitalized FAS 143 ARO		374		205
Total capital expenditures	$	251,381	$	96,996

FIRST SIX MONTHS 2011 RESULTS

Our average daily production volumes for the first six months of 2011 were 11,760 barrels of crude oil equivalent (Boe) per day, up 79% from that in the first six months of 2010. Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our crude oil production volumes for the first six months of 2011 averaged 9,710 barrels per day, which represents a 113% increase from that in the first six months of 2010. Our crude oil production volumes represented 83% of our total production volumes in the first six months of 2011 as compared to 69% in the first six months of 2010.

Our production volumes in the Williston Basin for the first six months of 2011 were 9,890 Boe per day, which represents a 126% increase from that in the first six months of 2010.

Our first six months of 2011 production volumes included approximately 18,888 barrels of crude oil produced and added to inventory during the period. Adjusting our production volumes for amounts included in inventory results in average first six months of 2011 daily sales volumes of 11,655 Boe per day.

Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the first six months of 2011, were up 136% to $167.3 million as compared to that in the first six months of 2010. Higher crude oil sales volumes and crude oil prices increased revenues by $64.7 million and $35.0 million, respectively. Higher natural gas sales volumes and natural gas prices also increased revenues by $0.2 million and $0.4 million, respectively. Lower cash hedge settlements decreased revenues by $3.9 million.

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During the first six months of 2011, our average realized price for crude oil was $88.54 per barrel, which included a $2.25 per barrel cash loss due to the settlement of our crude oil derivative contracts. This compares to an average realized price in the first six months of 2010 of $70.27 per barrel, which included a $0.28 per barrel cash loss due to the settlement of our crude oil derivative contracts. Our average realized price for natural gas inclusive of natural gas liquids in the first six months of 2011 was $6.41 per Mcf, which included a $0.66 per Mcf cash gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the first six months of 2010 of $6.36 per Mcf, which included a $0.77 per Mcf cash gain due to the settlement of our natural gas derivative contracts.

Our production costs for the first six months of 2011 increased $3.14 per Boe when compared to those in the corresponding period last year. The increase was largely attributable to a $2.72 per Boe increase in production taxes, which was driven by higher commodity prices and higher levels of production in North Dakota, which are subject to an 11.5% tax rate, and a $1.07 per Boe increase in O&M expense, partially due to increased costs associated with surface location and road repairs following the record winter snowfall melt and subsequent heavy rains and higher produced water disposal costs for volumes injected at third party disposal wells. These increases were partially offset by a $0.77 per Boe decrease in expensed workovers due to our higher sales volumes.

Our G&A expenses for the first six months of 2011 decreased by $1.81 per Boe as compared to the first six months of 2010 due to our higher sales volumes. The per unit decrease associated with our higher sales volumes was partially offset by an increase in employee compensation costs due to higher levels of non-cash stock compensation expense.

Our depletion expense for the first six months of 2011 was $42.5 million ($20.24 per Boe) versus $23.5 million ($19.95 per Boe) in the first six months of 2010. Our higher sales volumes increased depletion expense by $18.4 million and our higher depletion rate increased depletion expense by $0.6 million.

Our net interest expense for the first six months of 2011 was $3.3 million higher than that in the corresponding period last year. Interest expense increased due to the September 2010 issuance of our $300 million Senior Notes due 2018 and the May 2011 issuance of our $300 million Senior Notes due 2019. These increases were partially offset by an increase in our capitalized interest associated with our higher level of drilling activity in the Williston Basin.

We recorded deferred income tax expense of $9.1 million in the first six months of 2011, which consists of $6.3 million in deferred federal income tax expense and $2.8 million in deferred North Dakota state income tax expense.

Our reported net income for the first six months of 2011 was $72.4 million ($0.61 per diluted share) versus net income of $29.8 million ($0.27 per diluted share) for the same period last year. Our after-tax earnings in the first six months of 2011 excluding unrealized mark-to-market hedging losses were $72.5 million ($0.61 per diluted share) as compared to our after-tax earnings in the first six months of 2010 excluding unrealized mark-to-market hedging gains were $23.2 million ($0.21 per diluted share). After-tax earnings excluding the above items is a non-GAAP measure and a reconciliation of GAAP net income to after-tax earnings excluding the above items is included in our accompanying financial tables found later in this release.

Through June 30, 2011, we spent $366.9 million in oil and gas capital expenditures. Capital expenditures for the first six months of 2011 and 2010 were:

	Six months ended June 30,
	2011		2010
	(in thousands)
Drilling	$	276,792	$	114,930
Support infrastructure		32,836		—
Land		57,273		29,539
Oil and gas capital expenditures	$	366,901	$	144,469
Capitalized costs		13,559		8,974
Capitalized FAS 143 ARO		552		257
Total capital expenditures	$	381,012	$	153,700

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THIRD QUARTER AND FULL YEAR 2011 FORECASTS

The following forecasts and estimates for the third quarter and fourth quarter 2011 are forward-looking statements subject to the risks and uncertainties identified in the “Forward-Looking Statements Disclosure” at the end of this release.

We are forecasting that our third quarter 2011 production volumes will average between 15,000 Boe per day and 16,200 Boe per day and that our crude oil volumes will comprise approximately 84% of our third quarter production volumes. We are confirming that our previously issued full year 2011 production volumes will average between 14,000 Boe per day and 16,000 Boe per day and that our crude oil volumes will comprise approximately 84% of our full year production volumes.

For the third quarter 2011, lease operating expenses are projected to be $7.92 per Boe based on the mid-point of our production guidance, production taxes are projected to be approximately 10.0 to 10.5% of pre-hedge crude oil and natural gas revenues, and general and administrative expenses are projected to be $3.1 million ($2.21 per Boe).

MANAGEMENT COMMENTS

Gene Shepherd, Brigham’s Chief Financial Officer, commented, “Continued strong performance of our horizontal Bakken and Three Forks drilling program led to another record quarter for production volumes, revenues and operating income. Furthermore, based on our 2011 production guidance, we expect to see significant growth in our production volumes in the second half of the year.”

Gene Shepherd continued, “Based on the growth in our production volumes and the strong commodity price realizations during the quarter, our per unit operating margins, which represent revenues including realized hedging gains and losses less lease operation expense, production taxes and cash G&A, reached a record $65.14 per barrel, an improvement of 21% from the record $54.06 per barrel operating margins that we achieved in the first quarter. Given that we have drilled a total of 79 horizontal Bakken and Three Forks wells using our current formula and given the consistency of our results, we have excellent visibility as to our future financial performance and future liquidity needs.”

CONFERENCE CALL INFORMATION

Our management will host a conference call to discuss operational and financial results for the second quarter 2011 with investors, analysts and other interested parties on Tuesday, August 9, at 11:00 a.m. Eastern Time. To participate in the call, participants within the U.S./Canada please dial 877-398-9480 and participants outside the U.S./Canada please dial 708-290-1157. The conference ID number for the call is 86489005. A telephone recording of the conference call will be available approximately two hours after the call is completed through 11:59 p.m. Eastern Time on Tuesday, August 16, 2011. For toll-free access to the recording, dial 855-859-2056. The conference ID number for the call is 86489005. In addition, a live and archived web cast of the conference call will be available over the Internet at www.bexp3d.com.

We will be updating our corporate presentation prior to our conference call and will reference information contained therein. We encourage you to access the presentation in advance of the conference call. To access the presentation, go to www.bexp3d.com and click on Corporate Presentation along the left side of our home page. In addition, a copy of this press release and other financial and statistical information about the periods covered by this press release and by the conference call that will take place on Tuesday, August 9, 2011, will be available on our website. To access the press release, go to www.bexp3d.com, click on Investor Relations and then click on Press Releases. The file with a copy of the press release is named Brigham Exploration Reports Second Quarter 2011 Results and is dated Monday, August 8, 2011. To access the other financial and statistical information that will be covered by the conference call that will take place on Tuesday, August 9, 2011, go to www.bexp3d.com, click on Investor Relations and then click on Events & Presentations. The file with the other financial and statistical information is named Financial and Statistical Information for the Second Quarter 2011 Conference Call and is dated Tuesday, August 9, 2011.

ABOUT BRIGHAM EXPLORATION

Brigham Exploration Company is an independent exploration, development and production company that utilizes advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. For more information about Brigham Exploration, please visit our website at www.bexp3d.com or contact Investor Relations at 512-427-3444.

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FORWARD-LOOKING STATEMENTS DISCLOSURE

Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements within the meaning of the federal securities laws. Important factors that could cause our actual results to differ materially from those contained in the forward-looking statements include early initial production rates which decline steeply over the early life of wells, particularly our Williston basin horizontal wells for which we estimate the average monthly production rates may decline by approximately 70% in the first twelve months of production, our growth strategies, our ability to successfully and economically explore for and develop oil and natural gas resources, anticipated trends in our business, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry, our ability to make and integrate acquisitions, the impact of governmental regulation and other risks more fully described in the company’s filings with the Securities and Exchange Commission. Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. All forward-looking statements contained in this release, including any forecasts and estimates, are based on management’s outlook only as of the date of this release, and we undertake no obligation to update or revise these forward-looking statements, whether as a result of subsequent developments or otherwise.

Contact:	Rob Roosa, Director of Finance & Investor Relations
	(512) 427-3300

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BRIGHAM EXPLORATION COMPANY
SUMMARY 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:
Crude oil sales	$	87,361		$	34,423		$	156,957		$	57,293
Natural gas sales		6,365			6,141			12,732			12,201
Hedging settlements		(2,468	)		861			(2,418	)		1,443
		91,258			41,425			167,271			70,937
Unrealized hedging gains (losses)		35,889			3,501			(119	)		6,553
		127,147			44,926			167,152			77,490
Support infrastructure		890			—			1,484			—
Other revenue		3			4			5			13
Total revenue		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 crude 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 expense, net		(5,794	)		(2,931	)		(9,172	)		(5,835	)
Interest income		342			887			709			1,340
Other income (expense)		3,934			1,181			7,088			1,866
		(1,518	)		(863	)		(1,375	)		(2,629	)
Income 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 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

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BRIGHAM EXPLORATION COMPANY
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
(unaudited)

	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Average net daily production volumes:
Crude oil (Bbls)		10,208			5,584			9,710			4,568
Natural gas (MMcf)		12.0			13.0			12.3			12.1
Equivalent crude oil (Boe) (6:1)		12,206			7,756			11,760			6,588
Total net production volumes:
Crude oil (MBbls)		919			503			1,748			822
Natural gas (MMcf)		1,079			1,173			2,215			2,182
Equivalent crude oil (MBoe) (6:1)		1,099			698			2,117			1,186
% Crude oil		84	%		72	%		83	%		69	%
Increase in inventory:
Crude oil (Bbls)		18,156			5,089			18,888			10,101
Natural gas (MMcf)		—			—			—			—
Equivalent crude oil (Boe) (6:1)		18,156			5,089			18,888			10,101
Average net daily sales volumes (Average net production volumes less average net daily increase in inventory):
Crude oil (Bbls)		10,007			5,528			9,605			4,512
Natural gas (MMcf)		12.0			13.0			12.3			12.1
Equivalent crude oil (Boe) (6:1)		12,004			7,700			11,655			6,532
Total net sales volumes (Total net production volumes less increase in inventory):
Crude oil (MBbls)		901			497			1,729			812
Natural gas (MMcf)		1,079			1,173			2,215			2,182
Equivalent crude oil (MBoe) (6:1)		1,080			693			2,098			1,176
% Crude oil		83	%		72	%		82	%		69	%
Sales price:
Crude oil ($/Bbl)	$	97.01		$	69.19		$	90.79		$	70.55
Natural gas ($/Mcf)		5.90			5.24			5.75			5.59
Equivalent crude oil ($/Boe) (6:1)		86.75			58.53			80.88			59.09
Sales price including derivative settlement gains (losses):
Crude oil ($/Bbl)	$	93.86		$	68.93		$	88.54		$	70.27
Natural gas ($/Mcf)		6.24			6.08			6.41			6.36
Equivalent crude oil ($/Boe) (6:1)		84.47			59.78			79.73			60.32
Sales price including derivative settlement gains (losses) and unrealized gains (losses):
Crude oil ($/Bbl)	$	134.01		$	79.16		$	89.20		$	77.12
Natural gas ($/Mcf)		5.98			4.73			5.84			6.81
Equivalent crude oil ($/Boe) (6:1)		117.69			64.83			79.67			65.89

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SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)

	June 30, 2011		December 31, 2010
	(unaudited)
Assets:
Current assets	$	528,503	$	360,857
Oil and natural gas properties, net (full cost method)		973,983		669,356
Other property and equipment, net		75,075		42,837
Other non-current assets		22,922		12,351
Total assets	$	1,600,483	$	1,085,401
Liabilities and stockholders’ equity:
Current liabilities	$	307,807	$	176,545
Senior notes		600,000		300,000
Other non-current liabilities		23,734		15,586
Total liabilities	$	931,541	$	492,131
Stockholders’ equity		668,942		593,270
Total liabilities and stockholders’ equity	$	1,600,483	$	1,085,401

BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) (unaudited)

	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Cash flows from operating activities:
Net income	$	70,835		$	18,473		$	72,389		$	29,788
Depletion, depreciation and amortization		24,775			14,508			44,686			23,952
Accretion of discount on ARO		113			104			223			209
Amortization of deferred loan fees and debt issuance costs		615			508			1,141			1,014
Non-cash stock compensation		1,097			611			1,844			1,038
Market value adjustments for derivatives instruments		(35,889	)		(6,208	)		119			(9,260	)
Deferred income tax expense		8,930			—			9,109			—
Provision for doubtful accounts		—			—			(2	)		—
Other noncash items		—			—			—			(1	)
Changes in operating assets and liabilities		23,754			12,951			30,932			20,180
Cash flows provided by operating activities	$	94,230		$	40,947		$	160,441		$	66,920
Cash flows (used) by investing activities		(227,344	)		(250,882	)		(292,869	)		(293,792	)
Cash flows provided by financing activities		294,217			268,281			290,374			268,913
Net increase (decrease) in cash and cash equivalents	$	161,103		$	58,346		$	157,946		$	42,041

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SUMMARY PER BOE DATA
(unaudited)

	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Revenues:
Crude oil and natural gas sales	$	86.75		$	58.53		$	80.88		$	59.09
Hedge settlements		(2.28	)		1.24			(1.15	)		1.23
Unrealized hedge gains (losses)		33.22			5.05			(0.06	)		5.57
Support infrastructure		0.82			—			0.71			—
Other revenue		0.00			0.01			0.00			0.01
	$	118.51		$	64.83		$	80.38		$	65.90
Costs and expenses:
Lease operating		8.08			6.30			7.84			7.42
Production taxes		8.75			5.63			8.17			5.45
Support infrastructure		0.49			—			0.34			—
General and administrative		2.93			3.91			3.12			4.93
Depletion of crude oil and natural gas properties		21.79			20.56			20.24			19.95
Depreciation and amortization		1.15			0.38			1.06			0.42
Accretion of discount on ARO		0.10			0.15			0.11			0.18
	$	43.29		$	36.93		$	40.88		$	38.35
Operating income (loss)	$	75.22		$	27.90		$	39.50		$	27.55
Interest expense, net of interest income (a)		(5.05	)		(2.94	)		(4.04	)		(3.82	)
Other income (expense)		3.64			1.70			3.38			1.59
Adjusted income	$	73.81		$	26.66		$	38.84		$	25.32

(a) Calculated as interest expense minus interest income divided by production for period.

BRIGHAM EXPLORATION COMPANY
RECONCILIATION OF GAAP NET INCOME TO EARNINGS WITHOUT THE EFFECT OF CERTAIN ITEMS
(in thousands)

	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Net income (loss) as reported	$	70,835		$	18,473		$	72,389		$	29,788
Unrealized derivative (gains) losses		(35,889	)		(3,501	)		119			(6,553	)
Tax impact		3,707			—			(13	)		—
Earnings without the effect of certain items	$	38,653		$	14,972		$	72,495		$	23,235

Earnings without the effect of certain items represent net income excluding both unrealized gains and losses on derivative contracts and our non-cash impairment change in our oil and gas properties. Management believes that exclusion of both of these items will help enhance comparability of operating results between periods.

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SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF AUGUST 8, 2011
(unaudited)

	2011				2012								2013
	Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2
Crude Oil Costless Collars:
Daily volumes Bbls/d		7,587		9,207		8,239		8,580		10,168		10,000		9,000		1,341
Floor $/Bbl	$	67.69	$	70.84	$	69.03	$	69.46	$	71.71	$	73.99	$	80.38	$	85.00
Cap $/Bbl	$	103.57	$	109.45	$	109.07	$	110.07	$	114.56	$	116.11	$	125.25	$	134.00
Crude Oil Floors:
Daily volumes Bbls/d		—		—		1,500		1,500		1,500		1,500		—		—
Floor $/Bbl	$	—	$	—	$	65.00	$	65.00	$	80.00	$	80.00	$	—	$	—
Natural Gas Costless Collars:
Daily volumes MMBtu/d		3,587		3,587		—		—		—		—		—		—
Floor $/MMBtu	$	5.48	$	5.48	$	—	$	—	$	—	$	—	$	—	$	—
Cap $/MMBtu	$	7.16	$	7.16	$	—	$	—	$	—	$	—	$	—	$	—

Hedged volumes and prices reflected in this table represent average contract amounts for the quarterly periods presented; natural gas hedge prices and crude oil hedge contract prices are based on NYMEX pricing.

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EX-99.2

Exhibit 99.2

NEWS RELEASE
FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION ANNOUNCES ADDITIONAL MONTANA BAKKEN COMPLETIONS, UPDATES CORE ACREAGE FOR DRILLING SUCCESSES, AND PROVIDES SMART PAD EFFICIENCY AND WILLISTON BASIN OPERATIONS UPDATE

Austin, TX — August 8, 2011 — Brigham Exploration Company (NASDAQ: BEXP) announced additional Montana Bakken drilling successes with the completion of the Storvik 7-6 #1H and the Charley 10-15 #1H at early 24-hour peak rates of approximately 2,066 and 1,069 barrels of oil equivalent, respectively. Due to its recently announced positive well results in Eastern Montana, Brigham believes it has increased its de-risked acreage for the Bakken in Eastern Montana to approximately 33,500 net acres from its previously disclosed 24,400 net acres. As a result of the successes and incremental acreage acquisitions, Brigham has grown its de-risked acreage in the Williston Basin by approximately 10,800 net acres to a total of approximately 235,200 net acres, which represents an inventory of at least 794 net remaining drilling locations. Furthermore, to date Brigham has drilled 79 consecutive long lateral high frac stage wells in North Dakota with an average early 24-hour peak rate of approximately 2,803 barrels of oil equivalent. Brigham also provided an update on its Smart Pad efficiency initiatives and an update on its drilling and completion activities in the Williston Basin.

Montana Drilling / Completion / Acreage Update

Brigham announced the successful completion of the Storvik 7-6 #1H, which is located in Richland County, at an early 24-hour peak rate of approximately 2,066 barrels of oil equivalent (1,857 barrels of oil and 1.26 MMcf of natural gas). The Storvik 7-6 #1H was completed with 34 frac stages and is located approximately three miles to the north of the Johnson 30-19 #1H. Brigham also completed the Charley 10-15 #1H, which is located in Roosevelt County, at an early 24-hour peak rate of approximately 1,069 barrels of oil equivalent (917 barrels of oil and 0.91 MMcf of natural gas). The Charley 10-15 #1H was completed with 30 frac stages and is located approximately two miles to the east of the Gobbs 17-8 #1H, which was completed with 36 frac stages.

Based on results of the above wells and previously announced completions, Brigham now believes that it has de-risked approximately 33,500 net acres for the Bakken in Eastern Montana, which represents an approximate 37% increase in its Eastern Montana de-risked acreage. In total, Brigham now believes that it has de-risked approximately 235,200 net acres and has at least 794 net remaining drilling locations in its inventory in the Williston Basin.

Brigham is currently completing the Beck 15-10 #1H in Roosevelt County and is drilling the Glenn 28-33 #1H, which is located in Richland County. The Glenn 28-33 #1H is approximately eight miles to the west-southwest of the Voss 21-11H and will represent Brigham’s westernmost

completion in Richland County. Brigham is currently using a riglet to redrill the horizontal portion of the State Hardy 31-16H, which is also located in Richland County, and is a wellbore acquired in one of Brigham’s recent acreage acquisitions. Brigham anticipates spudding approximately four additional wells in Montana during the remainder of 2011.

Smart Pad / Other Efficiency Initiatives

Brigham is early in the implementation of its Smart Pad drilling initiative, which along with other improvements, are anticipated to reduce drilling and completion costs by 10 to 20%. Smart Pad drilling consists of drilling multiple wells from a single pad utilizing walking rigs, simultaneously fracture stimulating wells (i.e., zipper fracs) and consolidating equipment and services into centralized facilities.

To date, Brigham has completed drilling eight Smart Pad locations and anticipates that seven of its operated rigs will be drilling smart pads in August. For the remainder of 2011, approximately 70% of Brigham’s wells will be drilled on Smart Pads. Efficiencies are currently being achieved by limiting the number of rig moves and the amount of rig up and rig down time for a Smart Pad location relative to an independent well. Additional efficiencies will be achieved beginning later this year as three conventional rigs will be converted to walking rigs. Further, Brigham anticipates receiving two specially built walking rigs into its operated rig fleet in the first quarter of 2012 and two additional specially built walking rigs by July 2012. Brigham has the option to drop an equal number of less efficient conventional rigs upon receipt of the walking rigs. With walking rigs, Brigham will batch drill multiple wells and will achieve additional efficiencies by minimizing the changeover of drill pipe and mud systems.

Further efficiencies are being achieved via zipper fracs, which minimize the amount of frac crew moves and the amount of rig up and rig down time. Additionally, pressure pumping equipment is more efficiently utilized as perf and plug down time is minimized during a zipper frac. To date, Brigham has currently completed six zipper fracs and expects to continue to develop efficiency enhancements. During Brigham’s recent two well zipper frac, comprised of the Larsen 3-10 #2H and the Lucy Hanson 15-22 #1H, approximately 6.4 stages were completed per day including move time for a total time to complete of 10.5 days, or 5.3 days per well. Additionally, Brigham recently completed its first three well zipper frac comprised of the Holm 9-4 #1H, the Holm 9-4 #2H and the Alger State 16-21 #1H. During the three well zipper frac, approximately 8.4 stages were completed per day including move time for a total time to complete of 11.6 days, or less than 4 days per well. For comparison, at a recent single well frac, approximately 3.6 stages were completed per day including move time for a total frac time of 9.0 days. It’s estimated that Brigham was 75 to 130% more efficient in completing a two or three well zipper frac relative to an independent frac. Brigham anticipates that approximately 62% of its wells will be completed with zipper fracs during the remainder of 2011.

Brigham has completed mechanical field tests of new frac sleeve technologies provided by both Halliburton and Baker Hughes. For independently completed wells, the new technologies have the potential to eliminate wireline work associated with perf and plug for the initial stages, while initiating the development of fractures along the length of the wellbore. By fully utilizing pressure pumping equipment during independent fracs, the systems would allow Brigham to

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complete more wells per month. Brigham is currently completing wells that have approximately 15 stages, or half of the well, with new frac sleeves installed. The remaining half of the wellbores will be completed with perf and plug and production from these wells will be compared to direct offset wells that were completed entirely with perf and plug.

Lastly, Brigham is progressing the build out of its support infrastructure system consisting of crude oil, produced water and fresh water gathering lines and produced water disposal wells. The crude oil, produced water and fresh water systems serving Williams and McKenzie counties, North Dakota are expected to be operational near year-end 2011. In total, Brigham spent $33.2 million in 2010 and has budgeted to spend $87.1 million in 2011 on support infrastructure. In addition to reducing operating and maintenance expense as well as drilling well cap-ex, Brigham expects that these systems will provide greater control over the transportation of its fluid volumes, which were constrained during the second quarter due to the adverse weather conditions which limited truck access to Brigham’s drilling and producing well locations. The systems will also significantly improve Brigham’s access to the different oil markets.

Operated Drilling and Completion Update

Brigham’s accelerated development of its acreage in North Dakota and Montana is proceeding with seven operated rigs drilling in Rough Rider, two operated rigs drilling in Ross and one operated rig drilling in Eastern Montana. Brigham plans to add two walking rigs in the first quarter of 2012.

In its Rough Rider project area, Brigham currently has a Three Forks well waiting on completion in each of McKenzie and Williams Counties. Brigham plans to spud an additional Three Forks well in McKenzie County in September.

Brigham currently has four wells flowing back, four wells fracing, and 10 wells waiting on completion. In the second quarter, Brigham brought on line to production a record 21 gross wells. To date, Brigham has completed 79 consecutive long lateral high frac stage wells in North Dakota at an average early 24-hour peak rate of approximately 2,803 barrels of oil equivalent.

Brigham is currently running two fully dedicated frac crews focused on completing Brigham operated horizontal wells in the Williston Basin. Brigham estimates that it will be capable of fracture stimulating and bringing on line to production a minimum of eight wells per month, with the goal of achieving 10 fracs per month due to the efficiencies gained by zipper fracs.

Management Comments

Bud Brigham, the Chairman, President and CEO, commented, “Despite the adverse weather experienced in North Dakota, our employees delivered sequential production growth of 8% in the second quarter that resulted in record quarterly production volumes of 12,206 barrels of oil equivalent per day. Once weather conditions improved and we were able to fully realize the benefits of our ramp up in operated rigs and frac crews, our production in the Williston Basin surged to record levels, greater than 12,000 barrels of oil equivalent per day in June and in

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excess of 13,000 barrels of oil equivalent per day in July. We believe the continued ramp up in our production volumes during the second half of 2011 will allow us to achieve our previously forecasted full year 2011 guidance range of 14,000 to 16,000 barrels of total equivalent oil production per day.”

Bud Brigham continued, “Our Smart Pad efficiency initiatives, and midstream build out that is currently underway and expected to come on line near year-end, should allow us to mitigate most of the weather issues experienced in the past in the upcoming winters and thaw periods. By drilling multiple wells from a Smart Pad, we will keep our operated rigs and frac crews more efficiently utilized, due in part to reduced transportation and rig up and rig down times, as well as reduced dependence on trucks. Our midstream gathering system will provide very significant competitive advantages. For example, this gathering system will allow us to move oil and produced water volumes off the majority of our locations to ensure we can keep most of our producing wells on line regardless of the weather. Further, the transport of fresh water out to our frac jobs will enable us to continue to frac most of our completing wells in order to continue to bring production on line consistently throughout the year, at times when other operators without such systems will be challenged.”

Bud Brigham continued, “I’m particularly pleased with the entrepreneurial spirit our operations group has demonstrated on our zipper frac designs and operations. Our zipper fracs helped us to achieve sequential production growth in the second quarter 2011 during a period of difficult operating conditions in the Williston Basin. They demonstrated the benefits of a two well zipper by completing 6.4 frac stages per day relative to 3.6 when fracing a single well. Our engineers continue to work with service providers to evolve and improve the zipper frac process in order to achieve further efficiencies. For example, over the weekend we completed our first three well zipper frac at our Holm 9-4 #1H, the Holm 9-4 #2H and the Alger State 16-21 #1H Smart Pad and completed approximately 8.4 frac stages per day and completed the entire frac of all three wells in under 12 days including move time. We estimate that we were 130% more efficient in completing the three well zipper frac procedure relative to a single well frac.”

Bud Brigham concluded, “The second half of 2011 is filled with catalysts for future growth and in my view will be one of the most exciting periods of potential net asset value growth for our stockholders. First, we will bring on line three additional Three Forks wells in Rough Rider that, if successful, would further delineate the economics on up to 500 incremental net drilling locations, which would represent an incremental seven years of drilling inventory at our 2011 operated drilling pace. Second, we will spud five well density pattern tests in both Rough Rider and Ross to test the potential to increase the number of Bakken and Three Forks wells in our spacing units. Our micro seismic analysis of our frac jobs, combined with the production performance will help us to determine whether we have the ability to increase our inventory by up to 25%. Third, we will drill an incremental four wells in Eastern Montana. Fourth, we anticipate fracing two wells using new technology frac sleeves that have the potential to revolutionize the frac process by replicating the benefits of perf and plug while achieving the time efficiencies of standard frac sleeves. Fifth, near year-end we will bring on line our midstream gathering system that will generate substantial economic benefit and make many facets of our drilling and completion operations more efficient. Overall, the next five months will be filled with new data and potential for our stockholders.”

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About Brigham Exploration

Brigham Exploration Company is an independent exploration, development and production company that utilizes advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. For more information about Brigham Exploration, please visit our website at www.bexp3d.com or contact Investor Relations at 512-427-3444.

Forward-Looking Statement Disclosure

Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements within the meaning of the federal securities laws. Important factors that could cause our actual results to differ materially from those contained in the forward-looking statements include early initial production rates which decline steeply over the early life of wells, particularly our Williston Basin horizontal wells for which we estimate the average monthly production rates may decline by approximately 70% in the first twelve months of production, our growth strategies, our ability to successfully and economically explore for and develop oil and gas resources, anticipated trends in our business, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry, our ability to make and integrate acquisitions, the impact of governmental regulation and other risks more fully described in the company’s filings with the Securities and Exchange Commission. Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. All forward-looking statements contained in this release, including any forecasts and estimates, are based on management’s outlook only as of the date of this release, and we undertake no obligation to update or revise these forward-looking statements, whether as a result of subsequent developments or otherwise.

Contact: Rob Roosa, Director of Finance & Investor Relations
(512) 427-3300

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