Exhibit 99.1

		NEWS RELEASE FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION REPORTS RECORD PRODUCTION VOLUMES, REVENUES AND OPERATING INCOME IN THE FOURTH QUARTER 2010, ANNOUNCES ENTRY INTO A NEW SENIOR CREDIT FACILITY AND PROVIDES 2011 CAPITAL EXPENDITURE BUDGET AND FORECASTS

Austin, TX — February 24, 2011 — Brigham Exploration Company (NASDAQ:BEXP) today announced record quarterly production volumes, revenues and operating income, excluding the impact of unrealized hedging losses. Brigham also announced the entry into a new Senior Credit Facility and provided 2011 capital expenditure budget and forecasts.

FOURTH QUARTER 2010 RESULTS

Our average daily production volumes for the fourth quarter 2010 were a quarterly record 11,384 barrels of crude oil equivalent (Boe) per day, up 125% from the fourth quarter 2009 and up 34% from the third quarter 2010. Our previous record quarterly production volumes of 8,509 Boe per day were achieved in the third quarter 2010.

Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our high value crude oil production volumes for the fourth quarter 2010 averaged 9,129 barrels of crude oil per day, which represents a 218% increase from that in the fourth quarter 2009 and a 44% sequential increase from that in the third quarter 2010. Our high value crude oil production volumes represented 80% of our total production volumes in the fourth quarter 2010, as compared to 57% in the fourth quarter 2009 and 75% in the third quarter 2010.

Our production volumes in the Williston Basin for the fourth quarter 2010 were 9,359 Boe per day, which represents a 272% increase from that in the fourth quarter 2009 and a 45% sequential increase from that in the third quarter 2010.

Our fourth quarter production volumes included approximately 12,158 barrels of crude oil produced during the fourth quarter 2010 and added to inventory. Adjusting our production volumes for amounts included in inventory resulted in fourth quarter 2010 daily sales volumes of 11,249 Boe per day.

Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the fourth quarter 2010, were up 195% to $67.0 million as compared to that in the fourth quarter 2009. Higher crude oil sales volumes and crude oil prices increased revenues by $38.8 million and $4.9 million, respectively. Also, higher cash hedge settlements and natural gas production increased revenue by $0.6 million and $0.1 million, respectively. Lower natural gas prices decreased revenues by $0.2 million.

During the fourth quarter 2010, our average realized price for crude oil was $74.12 per barrel, which included a $0.30 loss from the cash settlement of our crude oil derivative contracts. This compares to an average realized price in the fourth quarter 2009 of $64.32 per barrel, which included a $4.04 per barrel cash loss due to the settlement of our crude oil derivative contracts. Our average realized price for natural gas in the fourth quarter 2010 was $5.77 per Mcf, which included a $0.94 per Mcf cash gain due to the settlement of our natural gas derivative contracts. This compares to an average realized price in the fourth quarter 2009 of $6.05 per Mcf, which included a $1.08 per Mcf cash gain due to the settlement of our natural gas derivative contracts.

Our fourth quarter 2010 production costs, which include costs for operating and maintaining (O&M expense) our producing wells, expensed workovers, ad valorem taxes and production taxes, were down $0.93 per Boe when compared to the fourth quarter 2009. The decrease was driven by a $2.06 per Boe decrease in expensed workovers due to fewer workovers associated with our conventional onshore Gulf Coast and Anadarko Basin natural gas wells and a $0.97 per Boe decrease in O&M expense primarily due to our higher production volumes. These decreases were partially offset by a $2.26 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.

Our general and administrative (G&A) expenses for the fourth quarter 2010 decreased by $2.47 per Boe as compared to the prior year’s quarter due to our higher production volumes. The gains associated with our higher production volumes were partially offset by an increase in employee compensation costs due to the reinstatement of full salaries in late 2009, the reinstatement of our bonus plan in 2010, higher levels of employee salaries in 2010 to ensure competitive compensation levels with other oil and gas companies, and a higher number of employees due to our increased activity in the Williston Basin.

Our depletion expense for the fourth quarter 2010 was $19.4 million ($19.19 per Boe) compared to $8.2 million ($18.53 per Boe) in the fourth quarter 2009. Our higher sales volumes increased depletion expense by $10.6 million and our higher depletion rate increased depletion expense by $0.7 million.

Our net interest expense for the fourth quarter 2010 was flat with that in the fourth quarter 2009. Net interest expense decreased $2.7 million primarily due to both the repayment of our Senior Credit Facility as a result of our October 2009 equity offering and an increase in our capitalized interest associated with our higher level of drilling activity in the Williston Basin. This was offset by a $2.7 million increase in interest expense associate with the September 2010 issuance of our $300 million Senior Notes due 2018.

We recorded a deferred tax expense of $1.1 million in the fourth quarter 2010, which was mainly due to the state of North Dakota’s tax expense.

Our reported net income for the fourth quarter 2010 was $13.8 million ($0.12 per diluted share) versus net income of $2.5 million ($0.03 per diluted share) for the same period last year. Our after-tax earnings in the fourth quarter 2010 excluding the loss on the early redemption of our Senior Notes due 2014 and unrealized mark-to-market hedging losses were $25.4 million ($0.21 per diluted share) as compared to our after-tax earnings in the fourth quarter 2009 excluding our unrealized mark-to-market hedging losses were $3.8 million ($0.04 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 fourth quarter 2010, we spent $108.1 million in oil and gas capital expenditures. Capital expenditures for the fourth quarter 2010 and 2009 were:

		Three months ended December 31,
		2010				2009
		(in thousands)
Drilling		$	82,110			$	20,599
Support infrastructure			16,967				—
Land			8,981				4,973
Oil and gas capital expenditures		$	108,058			$	25,572
Capitalized costs			6,981				3,889
Capitalized FAS 143 ARO			267				25
Total capital expenditures		$	115,306			$	29,486

YEAR END 2010 RESULTS

Our average daily production volumes for 2010 were 8,267 Boe per day, up 64% from that in 2009. Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our high value crude oil production volumes for 2010 averaged 6,155 barrels per day, which represents a 167% increase from that in 2009. Our high value crude oil production volumes represented 74% of our total production volumes in 2010 as compared to 46% in 2009.

Our production volumes in the Williston Basin for 2010 were 6,146 Boe per day, which represents a 240% increase from that in 2009.

Our 2010 production volumes included approximately 29,654 barrels of crude oil produced and added to inventory during the period. Adjusting our production volumes for amounts included in inventory results in average 2010 daily sales volumes of 8,185 Boe per day.

Revenues from the sale of crude oil and natural gas, including cash hedge settlements for 2010, were up 135% to $182.4 million as compared to that in 2009. Higher crude oil sales volumes and crude oil commodity prices increased revenues by $75.2 million and $35.6 million, respectively. Higher natural gas prices also increased revenues by $5.6 million. Lower natural gas sales volumes and cash hedge settlements decreased revenues by $5.3 million and $6.3 million, respectively.

During 2010, our average realized price for crude oil was $70.87 per barrel, which included a $0.21 per barrel cash loss due to the cash settlement of our crude oil derivative contracts. This compares to an average realized price in 2009 of $53.99 per barrel, which included a $0.80 per barrel cash loss due to the settlement of our crude oil derivative contracts. Our average realized price for natural gas in 2010 was $6.02 per Mcf, which included a $0.79 per Mcf cash gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in 2009 of $5.71 per Mcf, which included a $1.70 per Mcf cash gain due to the settlement of our natural gas derivative contracts.

Our production costs for 2010 were up $1.21 per Boe when compared to those in last year. The increase was driven by a $3.04 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 in production taxes was partially offset by a $1.37 per Boe decrease in O&M expense due primarily to our higher production volumes and a $0.26 per Boe decrease in Ad valorem taxes.

Our G&A expenses for 2010 decreased by $0.76 per Boe as compared to the prior year due to our higher production volumes. The gains associated with our higher production volumes were partially offset by an increase in employee compensation costs due to the reinstatement of full salaries in late 2009, the reinstatement of our bonus plan in 2010, higher levels of employee salaries in 2010 to ensure competitive compensation levels with other oil and gas companies, and a higher number of employees due to our increased activity in the Williston Basin.

Our depletion expense for 2010 was $58.2 million ($19.75 per Boe) versus $32.1 million ($17.85 per Boe) in 2009. Our higher sales volumes increased depletion expense by $20.5 million and our higher depletion rate increased depletion expense by $5.6 million.

Our net interest expense for 2010 was $5.0 million lower than that in 2009 primarily due to a $5.1 million increase in capitalized interest expense associated with our higher level of activity in the Williston Basin. Interest expense also decreased $3.3 million due to lower levels of debt outstanding on our Senior Credit Facility subsequent to its repayment in October 2009 in conjunction with our common stock offering. These decreases were partially offset by a $2.8 million increase in interest expense associate with the September 2010 issuance of our $300 million Senior Notes due 2018.

We recorded a deferred tax expense of $1.1 million in 2010, which was mainly due to the state of North Dakota’s tax expense.

Our reported net income for 2010 was $42.9 million ($0.38 per diluted share) versus net income (loss) of ($123.0) million (($1.74) per diluted share) for last year. Our after-tax earnings in 2010 excluding the loss on early redemption of Senior Notes due 2014 and unrealized mark-to-market hedging losses were $66.7 million ($0.59 per diluted share) as compared to our after-tax earnings in 2009 excluding the effect of our first quarter 2009 ceiling test write-down, unrealized mark-to-market hedging losses, and non-cash write-down of the carrying value of our inventory were $1.3 million ($0.02 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 2010, we spent $425.5 million in oil and gas capital expenditures. Capital expenditures for 2010 and 2009 were:

		Year ended December 31,
		2010				2009
		(in thousands)
Drilling		$	280,080			$	58,209
Support infrastructure			33,226				—
Land			112,153				1,761
Oil and gas capital expenditures		$	425,459			$	59,970
Capitalized costs			21,470				12,432
Capitalized FAS 143 ARO			814				327
Total capital expenditures		$	447,743			$	72,729

NEW SENIOR CREDIT FACILITY

On February 23, 2011, we entered into a new five year $600 million Senior Credit Facility with an initial borrowing base of $325 million. In conjunction with entry into the Senior Credit Facility, we added a total of eight banks to the bank group, which is now comprised of 14 banks and represents $545 million of total commitments. As a result of our enhanced operational and financial results, the pricing grid and covenants under the Senior Credit Facility were modified. The next redetermination of the facility will occur in October 2011. As of the date of this press release, we had no amounts outstanding under our Senior Credit Facility.

2011 OIL AND GAS CAPITAL EXPENDITURE BUDGET

Our 2011 oil and gas capital expenditure budget totals $692.7 million, which represents a 63% increase from 2010. The 2011 budget will fund approximately 65.7 net Williston Basin wells and 2.4 net wells primarily in the West Texas Wolfberry oil resource play.

Our budgeted oil and gas capital expenditures for 2011 are as follows:

		(in millions)
Drilling		$	582.1
Support infrastructure			83.2
Land			27.4
Total oil and gas capital expenditures		$	692.7

FIRST QUARTER AND FULL YEAR 2011 FORECASTS

The following forecasts and estimates for the first quarter and full year 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 first quarter 2011 total production volumes to average between 11,300 Boe per day and 12,000 Boe per day and that our crude oil volumes will comprise approximately 80% of our total first quarter production volumes. We are forecasting that our full year 2011 total production volumes to average between 14,000 Boe per day and 16,000 Boe per day and that our crude oil volumes will comprise approximately 82% of our total production volumes.

For the first quarter 2011, lease operating expenses are projected to be $6.96 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 $4.1 million ($3.91 per Boe).

MANAGEMENT COMMENTS

Gene Shepherd, Brigham’s Chief Financial Officer, commented, “During the fourth quarter, the continued strong performance of our horizontal Bakken and Three Forks drilling program led to record production volumes and, excluding unrealized hedge settlements, record revenues and operating income. Furthermore, with much of the proceeds of our September senior notes offering still on the balance sheet, we ended the fourth quarter with $248 million of cash, cash equivalents and investments and currently have an undrawn credit facility with a $325 million borrowing base. When combined with our growing cash flow and expanded hedging program, this level of liquidity ensures the company’s ability to fully fund our drilling program for 2011 and beyond.”

Gene Shepherd continued, “As we continue to accelerate our drilling activity to take advantage of our deep and growing inventory of horizontal Bakken and Three Forks drilling locations, we believe 2011 represents another year of record production and reserve growth which should take our company’s net asset value to new heights.”

CONFERENCE CALL INFORMATION

Our management will host a conference call to discuss operational and financial results for the fourth quarter 2010 with investors, analysts and other interested parties on Friday, February 25, 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 43080127. A telephone recording of the conference call will be available approximately two hours after the call is completed through 12:00 p.m. Eastern Time on Friday, March 4, 2011. To access the recording, U.S./Canada callers dial 800-642-1687 and international callers dial 706-645-9291. The conference ID number for the call is 43080127. 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 Friday, February 25, 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 Fourth Quarter 2010 Results and is dated Thursday, February 24, 2011. To access the other financial and statistical information that will be covered by the conference call that will take place on Friday, February 25, 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 Fourth Quarter 2010 Conference Call and is dated Thursday, February 24, 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.

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 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

BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) (unaudited)

		Three months ended								Year ended
		December 31,								December 31,
		2010				2009				2010				2009
Revenues:
Crude oil sales		$	60,242			$	16,515			$	155,403			$	44,580
Natural gas sales			5,880				5,912				23,876				23,612
Hedging settlements			908				310				3,109				9,377
			67,030				22,737				182,388				77,569
Unrealized hedging gains/ losses			(11,913	)			(1,276	)			(13,175	)			(7,313	)
			55,117				21,461				169,213				70,256
Support infrastructure revenue			489				—				489				—
Other revenue			3				16				20				88
Total revenue			55,609				21,477				169,722				70,344
Costs and expenses:
Lease operating			5,967				4,004				18,651				14,655
Production taxes			6,655				1,902				17,313				5,098
Support infrastructure expenses			50				—				50				—
General and administrative			3,891				2,775				12,943				9,243
Depletion of crude oil and natural gas properties			19,425				8,153				58,195				32,054
Impairment of crude oil and gas properties			—				—				—				114,781
Depreciation and amortization			848				262				1,704				812
Loss on inventory valuation			—				—				—				2,196
Accretion of discount on asset retirement obligations			110				108				422				421
			36,946				17,204				109,278				179,260
Operating income (loss)			18,663				4,273				60,444				(108,916	)
Other income (expense):
Interest expense, net			(3,555	)			(3,532	)			(11,448	)			(16,431	)
Interest income			(1,858	)			217				1,198				578
Loss on early redemption of Senior Notes			(360	)			—				(11,308	)			—
Other income (expense)			1,978				1,062				5,094				1,544
			(3,795	)			(2,253	)			(16,464	)			(14,309	)
Income before income taxes			14,868				2,020				43,980				(123,225	)
Income tax benefit (expense):
Current			—				—				—				—
Deferred			(1,084	)			528				(1,084	)			233
			(1,084	)			528				(1,084	)			233
Net income (loss)		$	13,784			$	2,548			$	42,896			$	(122,992	)
Net income per share available to common stockholders:
Basic		$	0.12			$	0.03			$	0.39			$	(1.74	)
Diluted		$	0.12			$	0.03			$	0.38			$	(1.74	)
Weighted average shares outstanding:
Basic			116,207				94,119				111,355				70,569
Diluted			118,232				95,677				113,308				70,569

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

		Three months ended December 31,								Year ended December 31,
		2010				2009				2010				2009
Average net daily production volumes:
Crude oil (Bbls)			9,129				2,867				6,155				2,306
Natural gas (MMcf)			13.5				13.2				12.7				16.4
Equivalent crude oil (Boe) (6:1)			11,384				5,069				8,267				5,034
Total net production volumes:
Crude oil (MBbls)			822				258				2,216				830
Natural gas (MMcf)			1,218				1,189				4,562				5,892
Equivalent crude oil (MBoe) (6:1)			1,025				456				2,976				1,812
% Crude oil			80	%			57	%			74	%			46	%
Increase in inventory:
Crude oil (Bbls)			12,158				16,475				29,654				16,475
Natural gas (MMcf)			—				—				—				—
Equivalent crude oil (Boe) (6:1)			12,158				16,475				29,654				16,475
Average net daily sales volumes (Average net production volumes less average net daily increase in inventory):
Crude oil (Bbls)			8,994				2,684				6,073				2,260
Natural gas (MMcf)			13.5				13.2				12.7				16.4
Equivalent crude oil (Boe) (6:1)			11,249				4,886				8,185				4,988
Total net sales volumes (Total net production volumes less increase in inventory):
Crude oil (MBbls)			809				242				2,186				814
Natural gas (MMcf)			1,218				1,189				4,562				5,892
Equivalent crude oil (MBoe) (6:1)			1,012				440				2,947				1,796
% Crude oil			80	%			55	%			74	%			45	%
Sales price:
Crude oil ($/Bbl)		$	74.42			$	68.36			$	71.08			$	54.79
Natural gas ($/Mcf)			4.83				4.97				5.23				4.01
Equivalent crude oil ($/Boe) (6:1)			65.31				50.97				60.84				37.97
Sales price including derivative settlement gains (losses):
Crude oil ($/Bbl)		$	74.12			$	64.32			$	70.87			$	53.99
Natural gas ($/Mcf)			5.77				6.05				6.02				5.71
Equivalent crude oil ($/Boe) (6:1)			66.21				51.68				61.90				43.19
Sales price including derivative settlement gains (losses) and unrealized gains (losses):
Crude oil ($/Bbl)		$	61.00			$	59.02			$	64.55			$	48.65
Natural gas ($/Mcf)			4.71				6.06				6.16				5.21
Equivalent crude oil ($/Boe) (6:1)			54.44				48.78				57.43				39.12

SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)

		December 31, 2010				December 31, 2009
		(unaudited)
Assets:
Current assets		$	360,857			$	158,439
Oil and natural gas properties, net (full cost method)			669,356				330,733
Other property and equipment, net			42,051				3,025
Other non-current assets			13,137				6,059
Total assets		$	1,085,401			$	498,256
Liabilities and stockholders’ equity:
Current liabilities		$	176,545			$	67,773
Senior notes			300,000				158,968
Other non-current liabilities			15,586				7,232
Total liabilities		$	492,131			$	233,973
Stockholders’ equity			593,270				264,283
Total liabilities and stockholders’ equity		$	1,085,401			$	498,256

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

		Three months ended December 31,								Year ended December 31,
		2010				2009				2010				2009
Cash flows from operating activities:
Net income		$	13,784			$	2,548			$	42,896			$	(122,992	)
Depletion, depreciation and amortization			20,273				8,415				59,899				32,866
Impairment of oil and gas properties			—				—				—				114,781
Accretion of discount on ARO			110				108				422				421
Amortization of deferred loan fees and debt issuance costs			550				508				2,025				1,635
Loss on early redemption of Senior Notes			360				—				11,308				—
Non-cash stock compensation			743				918				2,676				2,278
Market value adjustments for derivatives instruments			11,913				1,276				13,175				7,313
Deferred income tax expense (benefit)			1,084				(530	)			1,084				(233	)
Provision for doubtful accounts			146				(19	)			146				(19	)
Other noncash items			—				55				—				90
Changes in operating assets and liabilities			2,336				5,284				10,889				15,610
Cash flows provided by operating activities		$	51,299			$	18,563			$	144,520			$	51,750
Cash flows used by investing activities			(147,970	)			(92,052	)			(556,211	)			(164,620	)
Cash flows (used) provided by financing activities			(5,590	)			58,392				394,653				113,608
Net increase (decrease) in cash and cash equivalents		$	(102,261	)		$	(15,097	)		$	(17,038	)		$	738

SUMMARY PER BOE DATA
(unaudited)

		Three months ended December 31,								Year ended December 31,
		2010				2009				2010				2009
Revenues:
Crude oil and natural gas sales		$	65.31			$	50.97			$	60.84			$	37.97
Hedge settlements			0.90				0.71				1.06				5.22
Unrealized hedge gains (losses)			(11.77	)			(2.90	)			(4.47	)			(4.07	)
Support infrastructure revenues			0.48				—				0.17				—
Other revenue			—				0.04				0.01				0.05
		$	54.92			$	48.82			$	57.61			$	39.17
Costs and expenses:
Lease operating			5.90				9.10				6.33				8.16
Production taxes			6.58				4.32				5.88				2.84
Support infrastructure expenses			0.05				—				0.02				—
General and administrative			3.84				6.31				4.39				5.15
Depletion of crude oil and natural gas properties			19.19				18.53				19.75				17.85
Impairment of crude oil and natural gas properties			—				—				—				63.91
Depreciation and amortization			0.84				0.60				0.58				0.45
Loss on inventory valuation			—				—				—				1.22
Accretion of discount on ARO			0.11				0.25				0.14				0.23
		$	36.51			$	39.11			$	37.09			$	99.81
Operating income (loss)		$	18.41			$	9.71			$	20.52			$	(60.64	)
Interest expense, net of interest income (a)			(5.35	)			(7.53	)			(3.48	)			(8.83	)
Loss on early redemption of Senior Notes			(0.36	)			—				(3.84	)			—
Other income (expense)			1.95				2.41				1.73				0.86
Adjusted income		$	14.65			$	4.59			$	14.93			$	(68.61	)

BRIGHAM EXPLORATION COMPANY
RECONCILIATION OF GAAP NET INCOME TO EARNINGS EXCLUDING THE EFFECT OF CERTAIN ITEMS
(in thousands)

		Three months ended December 31,								Year ended December 31,
		2010				2009				2010				2009
Net income (loss) as reported		$	13,784			$	2,548			$	42,896			$	(122,992	)
Unrealized derivative (gains) losses			11,913				1,276				13,175				7,313
Impairment of crude oil and natural gas properties			—				—				—				114,781
Loss on inventory valuation			—				—				—				2,196
Loss on early redemption of Senior Notes			360				—				11,308				—
Tax impact			(681	)			—				(681	)			—
Earnings without the effect of certain items		$	25,376			$	3,824			$	66,698			$	1,298

Earnings without the effect of certain items represent net income excluding our unrealized gains and losses on derivative contracts, our non-cash impairment charge of our oil and gas properties, our non-cash loss on inventory valuation and our loss on the early redemption of our Senior Notes due 2014. Management believes that exclusion of all of these items will help enhance comparability of operating results between periods.

SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF FEBRUARY 24, 2011
(unaudited)

						2011																2012																2013
						Q1				Q2				Q3				Q4				Q1				Q2				Q3				Q4				Q1
Crude Oil Costless Collars:
Daily volumes		Bbls/d					5,756				6,110				6,935				7,207				6,580				6,580				8,168				8,000				4,000
Floor		$/Bbl				$	66.16			$	65.68			$	65.59			$	65.52			$	65.50			$	65.50			$	69.07			$	71.87			$	78.36
Cap		$/Bbl				$	98.33			$	98.83			$	99.76			$	99.86			$	101.92			$	101.92			$	109.10			$	110.92			$	117.72
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					6,000				3,626				3,587				3,587				—				—				—				—				—
Floor		$/MMBtu				$	6.17			$	5.48			$	5.48			$	5.48			$	—			$	—			$	—			$	—			$	—
Cap		$/MMBtu				$	7.79			$	7.16			$	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.