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): March 3, 2008

Brigham Exploration Company

(Exact name of registrant as specified in its charter)

Delaware	000-22433	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, including zip code, of principal executive offices)

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:

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

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

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

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

Item 2.02 Results of Operation and Financial Condition.

Registrant is furnishing its press release dated March 3, 2008, which announced its financial results for the fourth quarter and twelve months ended December 31, 2007 and provided first quarter 2008 forecast. The text of that press release is attached to this Report as Exhibit 99.1 and is incorporated by reference herein.

With the filing of this report on Form 8-K and the issuance of the attached press release, 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 March 3, 2008 based on currently available information, and that we are not undertaking any obligation to update our estimates as conditions change or other information becomes available.

Registrant is also furnishing its press release dated March 3, 2008, which provides operational update. The text of the press release is furnished as attached hereto as Exhibit 99.2.

Item 7.01Regulation FD Disclosure.

Registrant is furnishing its press release dated March 3, 2008, which provides operational update. The text of the press release is furnished as attached hereto as Exhibit 99.2.

Item 9.01Financial Statements and Exhibits.

(d)Exhibit 99.1Press Release dated March 3, 2008.

(d)Exhibit 99.2Press Release dated March 3, 2008.

Page 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:March 4, 2008
	By:	/s/ Eugene B. Shepherd, Jr.
		Eugene B. Shepherd, Jr. Executive Vice President &
		Chief Financial Officer

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INDEX TO EXHIBITS

Item NumberExhibit

99.1* Press Release dated March 3, 2008.

99.2* Press Release dated March 3, 2008.

EX-99.1

   NEWS RELEASE FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION REPORTS YEAR-END AND FOURTH QUARTER 2007 RESULTS

Austin, TX - March 3, 2008 -- Brigham Exploration Company (NASDAQ:BEXP) today announced financial results for the year-ended and quarter ended December 31, 2007.

YEAR-END 2007 RESULTS

Average daily production volumes for 2007 were 41.6 MMcfe per day, up 13% when compared to those for 2006. Revenues from the sale of oil and natural gas including hedge settlements for 2007 were $124.7 million, which represents a 20% increase when compared to last year. Higher production volumes increased revenue by $10.4 million, higher prices also increased revenue by $10.4 million and higher hedge settlements increased revenue by $0.4 million.

Our average realized price for natural gas in 2007 was $7.66 per Mcf, which included a $0.36 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in 2006 of $7.09 per Mcf, which included a $0.35 per Mcf gain due to the settlement of our natural gas derivative contracts. Our average realized price for oil for 2007 was $71.51 per barrel, which included a $0.79 per Bbl loss due to the settlement of our oil derivative contracts. This compares to an average realized price in 2006 of $64.39, which included a $0.35 per barrel gain due to the settlement of oil derivative contracts last year.

Our production costs, which include costs for operating and maintaining (O&M expense) our producing wells, expensed workovers, ad valorem taxes and production taxes, decreased 21%, or by $0.23 per Mcfe, when compared to those for 2006. Production taxes decreased 43%, or by $0.13 per Mcfe, due to an increase in tax credits associated with high cost gas production tax abatements. The increase in tax credits is partially attributable to the fact that we are recording credits immediately upon commencing production from our Vicksburg and Mills Ranch wells given our 100% success rate in applying for credits. We now book credits immediately rather than deferring recognition until receiving approval from the relevant government authority. O&M expenses decreased 14%, or by $0.09 per Mcfe, due primarily to decreases in salt water disposal, chemical treating, and equipment rental. The divestiture of our Anadarko Basin Granite Wash assets in September 2007 reduced salt water disposal and chemical treating costs. In addition, we purchased production equipment in South Texas thereby reducing our equipment rental costs. Ad valorem taxes decreased 17%, or by $0.02 per Mcfe, due to a decrease in property valuations for our oil and natural gas properties because of lower commodity prices at year-end 2006, which were the basis for determining property tax rates for 2007.

Per unit general and administrative (G&A) expense for 2007 increased 3% from 2006 to $0.62 per Mcfe, as higher employee compensation costs offset the impact of our increased production volumes. Roughly 52% of the increase in our compensation costs was attributable to an increase in non-cash share-based compensation expense under FAS 123(R).

Our depletion expense for 2007 was $59.1 million ($3.94 per Mcfe) compared to $46.4 million ($3.50 per Mcfe) in 2006. Our increased depletion rate accounted for 52% of the increase in depletion expense while our increased production volumes accounted for 48% of the increased depletion expense. The increase in our depletion rate was a result of an increase in the cost of reserve additions.

Our net interest expense for 2007 was 51% higher than last year. The primary drivers behind the increase in our interest expense were a 54% increase in our weighted average debt outstanding and an increase in our weighted average interest rate due to our Senior Notes issuances in April 2006 and 2007. Our weighted average debt outstanding for 2007 was $189.1 million versus $123.0 million in 2006.

We recorded deferred income tax expense of $6.7 million in 2007 compared to deferred income tax expense of $12.7 million in 2006. The decrease in our deferred income tax expense was primarily due to lower 2007 income before income taxes.

Our reported net income for 2007 was $10.2 million ($0.22 per diluted share) versus net income of $19.8 million ($0.43 per diluted share) for the same period last year. Our after-tax earnings in 2007 excluding both the effect of our unrealized derivative losses and ceiling test impairment charge were $17.9 million ($0.39 per diluted share) and our after-tax earnings in 2006 excluding both unrealized derivative gains and non-cash gains associated with the ineffective portion of our cash flow hedges were $16.3 million ($0.36 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.

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As of December 31, 2007, we had $13.9 million in cash, $10.0 million of debt outstanding under our senior credit facility and a debt to book capitalization ratio of 39%.

In 2007, we spent $126.3 million on oil and gas capital expenditures, which represents a 32% decrease from 2006. Oil and gas capital expenditures for 2007 and 2006 were:

	Twelve Months Ended December 31,
	2007		2006
	(in thousands)
Drilling	$	96,833	$	142,338
Net land and seismic		17,527		31,683
Capitalized costs		11,631		9,954
Capitalized SFAS 143 ARO		325		609
Total oil and gas capital expenditures	$	126,316	$	184,584

FOURTH QUARTER 2007 RESULTS

Our average net daily production volumes for the fourth quarter 2007 were 35.5 MMcfe per day, down 9% when compared to those for the fourth quarter 2006. Revenues from the sale of oil and natural gas including hedge settlements for the fourth quarter 2007 were up 12% to $29.1 million when compared to those for the fourth quarter 2006. Higher realized prices increased revenues by $5.7 million, while lower production volumes and lower hedge settlement gains decreased revenues by $2.2 million and $0.4 million, respectively.

Our average realized price for natural gas for the fourth quarter 2007 was $8.02 per Mcf, which included a $0.45 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the fourth quarter 2006 of $7.00, which included a $0.36 per Mcf gain due to the settlement of our natural gas derivative contracts. During the fourth quarter 2007, our average realized price for oil was $84.98 per barrel, which included a $4.29 per barrel loss due to the settlement of our oil derivative contracts. This compares to an average realized price in the fourth quarter 2006 of $56.09, which included a $1.38 per barrel gain due to the settlement of our oil derivative contracts.

Our fourth quarter 2007 per unit production costs were up 6% when compared to those for the fourth quarter 2006. A $0.14 per Mcfe increase in production taxes and a $0.04 per Mcfe increase in workover expense were partially offset by a $0.11 per Mcfe decrease in our O&M expense. The increase in production taxes is attributable to approximately $0.8 million in additional severance tax refunds approved by states in the fourth quarter 2006 as compared to the fourth quarter 2007.

Per unit G&A expense for the fourth quarter 2007 increased 29% to $0.72 per Mcfe from the fourth quarter 2006 because of lower production volumes and higher compensation costs. Roughly 26% of the increase in our compensation costs was attributable to an increase in non-cash share-based compensation expense under FAS 123(R).

Our depletion expense for the fourth quarter 2007 was $13.7 million ($4.30 per Mcfe) compared to $13.1 million ($3.76 per Mcfe) in the fourth quarter 2006. Our increased depletion rate increased depletion expense by $1.7 million while our decreased production volumes reduced depletion expense by $1.1 million. The increase in our depletion rate was a result of an increase in the cost of reserve additions.

Our net interest expense for the fourth quarter 2007 increased $0.8 million, or by 27%, from the fourth quarter 2006. This increase was primarily due to our higher weighted average debt outstanding and our higher weighted average interest cost associated with our Senior Notes add-on issuance in April 2007. Our weighted average debt outstanding for the fourth quarter 2007 was $176.6 million as compared to $149.6 million for the comparable period last year.

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We recorded deferred income tax expense of $1.5 million in the fourth quarter of this year compared to deferred income tax expense of $2.8 million in the fourth quarter last year. The decrease in our deferred income tax expense was primarily due to lower fourth quarter 2007 income before income taxes.

Our reported net income for the fourth quarter 2007 was $1.8 million ($0.04 per diluted share) versus net income of $5.0 million ($0.11 per diluted share) for the same period last year. Our after-tax earnings in the fourth quarter 2007 excluding the effect of our unrealized derivative losses were $3.4 million ($0.07 per diluted share) and our after-tax earnings in the fourth quarter 2006 excluding unrealized derivative gains were $3.2 million ($0.07 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.

2007 PROVED RESERVES

Our estimated net proved reserve volumes at December 31, 2007 totaled 140.2 Bcfe of which approximately 76% was natural gas. During 2007, we added approximately 32.6 Bcfe in net proved reserves and replaced 217% of our 15.0 Bcfe of production. Our net proved reserves decreased by 23.8 Bcfe due to the divestiture of our Anadarko Basin Granite Wash assets. As of December 31, 2007, our estimated proved reserves were comprised of 69.3 Bcfe of net proved developed reserves and 70.9 Bcfe of net proved undeveloped reserves.

	Equivalent Reserves (MMcfe)
2007 Beginning Proved Reserves		146,452
Extensions, discoveries & other additions		23,622
Revisions of prior estimates		8,960
Sale of minerals-in-place		(23,854	)
Production		(14,978	)
2007 Ending Proved Reserves		140,202

At year-end 2007, the standardized measure and the pre-tax present value (“Pre-tax PV10% Value”) of our estimated proved reserves were $394.5 million and $491.6 million, respectively. For 2007, these measures were calculated using a West Texas Intermediate Sweet oil price of $96.01 per barrel and a Henry Hub natural gas price of $7.10 per MMBtu.

	At December 31,2007
	(in millions)
Standardized measure of discounted future net cash flows	$	394.5
Add present value of future income tax discounted at 10%		97.1
Pre-tax PV10% Value	$	491.6

Pre-tax PV10% Value is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes, discounted using a 10% discount rate. Pre-tax PV10% Value is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that Pre-tax PV10% Value is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that Pre-tax PV10% Value is widely used by security analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and natural gas industry calculate Pre-tax PV10% Value on the same basis. Pre-tax PV10% Value is computed on the same basis as the standardized measure of discounted future net cash flows, but without deducting income taxes.

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FIRST QUARTER 2008 FORECASTS

The following forecasts and estimates of our first quarter 2008 production volumes are forward looking statements subject to the risks and uncertainties identified in the "Forward Looking Statements Disclosure" at the end of this release. We currently expect our first quarter 2008 production volumes to average between 30.0 MMcfe per day and 32.0 MMcfe per day. Given that it is early in the evaluation of our Bakken acreage and the fact that we could experience a wide range of outcomes on our initial wells, we are electing not to provide a full year production forecast, but will revisit this decision as we move through the year. However, beyond the first quarter 2008, we expect to generate sequential quarterly growth in our production volumes.

For the first quarter 2008, lease operating expenses are projected to be $0.84 per Mcfe based on the mid-point of our production guidance, production taxes are projected to be approximately 3.25% to 3.5% of pre-hedge oil and natural gas revenues, and general and administrative expenses are projected to be $2.6 million ($0.95 to $0.89 per Mcfe).

MANAGEMENT COMMENTS

Bud Brigham, Brigham’s CEO and President, commented, “During 2007, we achieved record production volumes, revenue and cash flow. Our total proved finding cost for the relatively low operating cost high value reserves we added during the year was approximately $3.88 per Mcfe. The Vicksburg has driven our growth in recent years. Despite the fact that we’ve been aggressively drilling proved undeveloped locations in our Vicksburg fields, our three year total proved finding costs for our high present value Vicksburg reserves was approximately $2.77 per Mcfe, illustrating the growth we continue to achieve in our Vicksburg fields.”

Bud Brigham continued, “Looking forward, we see the compelling repeatable economics of the Bakken play, and we therefore believe that 2007 was portending a new era of growth. In terms of reserves, we expect the very substantial inventory of drilling projects we’ve accumulated, particularly in the Bakken, provides us with the opportunity to add meaningful proved reserves for years to come. Given our drilling results to date in the Bakken, we expect to add and develop these reserves with low finding costs and attractive margins, providing us with the multi-year period of more consistent and predictable growth. As we build out and drill up this inventory, our oil reserves should grow meaningfully. While we are currently 76% natural gas, within a few years more than 50% of our reserves could be oil.”

Bud Brigham continued, “In terms of production, it’s also a new beginning. To some degree we’re rotating from investing the largest portion of our drilling expenditures in the short reserve life plays of the Gulf Coast, to now investing the largest portion in 30 to 40 year reserve life Bakken oil projects. This rotation, combined with the pause we’ve taken in our Vicksburg drilling, which has now resumed, the natural decline of last year’s high rate Southern Louisiana production, and the loss in production associated with our late year 2007 divestiture, has resulted in lower net production volumes as we commence 2008. We expect the resumption of our Vicksburg drilling, combined with our Southern Louisiana drilling and the acceleration in our Bakken drilling, to provide sequential quarterly production growth as we move through 2008. Regarding our guidance, the largest percentage of our capital expenditures is allocated to the Bakken, which has experienced a very high degree of variability in production rates. Therefore, as we gain additional data over time as to the production profiles in the different areas that we are drilling we may subsequently issue full year production guidance.”

Bud Brigham concluded, “Given the longer reserve lives associated with the Bakken production, we’ll benefit from stronger production volumes in subsequent years, smoothing out our production growth profile. Over time, our growing resource play drilling should provide more consistent and predictable production growth. In addition, our Bakken oil volumes also provide substantially greater cash flow per equivalent unit (Mcfe) of production, relative to natural gas, given the relatively high current pricing for oil today. We welcome and relish this new era of growth, and look forward to reporting on what should be a very exciting year for our shareholders.”

CONFERENCE CALL INFORMATION

Our management will host a conference call to discuss operational and financial results for the year-end and fourth quarter 2007 with investors, analysts and other interested parties on Tuesday March 4, at 10:00 a.m. Eastern Time. To participate in the call, participants within the U.S. please dial 888-680-0869 and participants outside the U.S. please dial 617-213-4854. The participant passcode for the call is 11452972. Participants may pre-register for the call at https://www.theconferencingservice.com/prereg/key.process?key=PJLNDJU6N. Pre-registrants will be issued a pin number to use when dialing into the live call which will provide quick access to the conference by bypassing the operator upon connection. A telephone recording of the conference call will be available to interested parties approximately two hours after the call is completed through 12:00 p.m. Eastern Time on Friday, April 4, 2008. To access the recording, domestic callers dial 888-286-8010 and international callers dial 617-801-6888. The passcode for the conference call playback is 43891332. In addition, a live and archived web cast of the conference call will be available over the Internet at either www.bexp3d.com or www.streetevents.com.

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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, March 4, 2008, will be available on our website. To access the press release: go to www.bexp3d.com and click on News Releases. The file with a copy of the press release is named Brigham Exploration Reports Year-End and Fourth Quarter 2007 Results and is dated Monday, March 3, 2008. To access the other financial and statistical information that will be covered by the conference call that will take place on Tuesday, March 4, 2008, go to www.bexp3d.com and click on Event Calendar. The file with the other financial and statistical information is named Financial and Statistical Information for the Fourth Quarter 2007 Conference Call and is dated Tuesday, March 4, 2008.

ABOUT BRIGHAM EXPLORATION

Brigham Exploration Company is an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore and develop onshore domestic natural gas and oil provinces. 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 include 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, Finance Manager (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						Twelve months Ended
	December 31,						December 31,
	2007			2006			2007			2006
Revenues:
Oil and natural gas sales	$	28,307		$	24,817		$	120,557		$	99,794
Hedging settlements		762			1,175			4,167			3,796
		29,069			25,992			124,724			103,590
Unrealized hedging gains(losses)		(2,846	)		2,868			(5,831	)		2,580
		26,223			28,860			118,893			106,170
Other revenue		15			40			88			127
Total Revenue		26,238			28,900			118,981			106,297
Costs and expenses:
Lease operating		2,246			2,763			10,704			10,701
Production taxes		968			566			2,541			4,021
General and administrative		2,303			1,951			9,276			7,887
Depletion of oil and natural gas properties		13,732			13,114			59,079			46,386
Impairment of oil and natural gas properties		—			—			6,505			—
Depreciation and amortization		145			161			613			537
Accretion of discount on asset retirement obligations		81			88			379			317
		19,475			18,643			89,097			69,849
Operating income		6,763			10,257			29,884			36,448
Other income (expense):
Interest expense, netInterest income		(3,551	)		(2,789	)		(14,622	)		(9,688	)
Interest income		118			135			654			1,207
Other income (expense)		15			171			1,022			4,565
		(3,418	)		(2,483	)		(12,946	)		(3,916	)
Income before income taxes		3,345			7,774			16,938			32,532
Income tax expense:
Current		—			—			—			—
Deferred		(1,501	)		(2,773	)		(6,728	)		(12,744	)
		(1,501	)		(2,773	)		(6,728	)		(12,744	)
Net income	$	1,844		$	5,001		$	10,210		$	19,788
Net income per share available to common stockholders:
Basic	$	0.04		$	0.11		$	0.23		$	0.44
Diluted	$	0.04		$	0.11		$	0.22		$	0.43
Weighted average shares outstanding:
Basic		45,184			45,054			45,110			45,017
Diluted		45,708			45,515			45,531			45,597

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BRIGHAM EXPLORATION COMPANY

PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA

(unaudited)

	Three Months Ended December 31,						Twelve months Ended December 31,
	2007			2006			2007			2006
Average net daily production:
Natural gas (MMcf)		29.2			31.3			35.1			29.5
Oil (Bbls)		1,045			1,247			1,089			1,227
Equivalent natural gas (MMcfe) (6:1)		35.5			38.8			41.6			36.8
Total net production:
Natural gas (MMcf)		2,629			2,814			12,626			10,603
Oil (MBbls)		94			112			392			442
Equivalent natural gas (MMcfe) (6:1)		3,194			3,488			14,978			13,254
% Natural gas		82	%		81	%		84	%		80	%
Sales price:
Natural gas ($/Mcf)	$	7.57		$	6.64		$	7.30		$	6.74
Oil ($/Bbl)		89.27			54.71			72.30			64.04
Equivalent natural gas ($/Mcfe) (6:1)		8.86			7.11			8.05			7.53
Sales price including derivative settlement gains (losses):
Natural gas ($/Mcf)	$	8.02		$	7.00		$	7.66		$	7.09
Oil ($/Bbl)		84.98			56.09			71.51			64.39
Equivalent natural gas ($/Mcfe) (6:1)		9.10			7.45			8.33			7.82
Sales price including derivative settlement gains (losses) and unrealized gains (losses):
Natural gas ($/Mcf)	$	7.52		$	7.96		$	7.38		$	7.31
Oil ($/Bbl)		68.66			57.43			65.57			64.79
Equivalent natural gas ($/Mcfe) (6:1)		8.21			8.27			7.94			8.01

SUMMARY CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2007		December 31, 2006
Assets:
Current assets	$	32,505	$	31,218
Oil and natural gas properties, net (full cost method)		510,207		485,525
Other property and equipment, net		1,034		936
Other non-current assets		4,682		4,908
Total assets	$	548,428	$	522,587
Liabilities and stockholders' equity:
Current liabilities	$	41,718	$	57,453
Senior notes		158,492		123,434
Senior credit facility		10,000		25,900
Mandatorily redeemable preferred stock, Series A		10,101		10,101
Deferred income tax liability		41,625		34,609
Other non-current liabilities		7,465		5,075
Total liabilities	$	269,401	$	256,572
Stockholders' equity		279,027		266,015
Total liabilities and stockholders' equity	$	548,428	$	522,587

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BRIGHAM EXPLORATION COMPANY

SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands) (unaudited)

	Three Months Ended December 31,						Twelve months Ended December 31,
	2007			2006			2007			2006
Cash flows from operating activities:
Net income	$	1,844		$	5,001		$	10,210		$	19,788
Depletion, depreciation and amortization		13,877			13,275			59,692			46,923
Impairment of oil and gas properties		—			—			6,505			—
Accretion of discount on ARO		81			88			379			317
Interest paid through issuance of additional redeemable preferred stock		—			—			—			—
Amortization of deferred loan fees and debt issuance costs		255			209			968			1,682
Non-cash stock compensation		450			437			1,905			1,571
Market value adjustments for derivatives instruments		2,846			(2,868	)		5,831			(5,794	)
Deferred income tax expense		1,501			2,773			6,728			12,744
Provision for doubtful accounts		—			48			—			48
Other noncash items		—			—			(4	)		64
Changes in operating assets and liabilities		(3,757	)		(4,571	)		(1,765	)		11,344
Cash flows provided by operating activities	$	17,097		$	14,392		$	90,449		$	88,687
Cash flows used by investing activities		(23,930	)		(45,608	)		(99,093	)		(171,747	)
Cash flows (used) provided by financing activities		10,200			25,902			18,207			83,385
Net increase (decrease) in cash and cash equivalents	$	3,367		$	(5,314	)	$	9,563		$	325

SUMMARY PER MCFE DATA

(unaudited)

	Three Months Ended December 31,						Twelve months Ended December 31,
	2007			2006			2007			2006
Revenues:
Oil and natural gas sales	$	8.21		$	8.27		$	7.94		$	8.01
Other revenue		—			0.01			—			0.01
	$	8.21		$	8.28		$	7.94		$	8.02
Costs and expenses:
Lease operating		0.70			0.79			0.71			0.81
Production taxes		0.30			0.16			0.17			0.30
General and administrative		0.72			0.56			0.62			0.60
Depletion of natural gas and oil properties		4.30			3.76			3.94			3.50
Impairment of natural gas and oil properties		—			—			0.43			—
Depreciation and amortization		0.05			0.05			0.04			0.04
Accretion of discount on ARO		0.03			0.03			0.03			0.02
	$	6.10		$	5.35		$	5.94		$	5.27
Operating income	$	2.11		$	2.93		$	2.00		$	2.75
Interest expense, net of interest income (a)		(1.07	)		(0.76	)		(0.93	)		(0.64	)
Other income (expense) (b)		—			0.05			0.07			0.10
Adjusted income	$	1.04		$	2.22		$	1.14		$	2.21

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

(b) Excludes non-cash gains/(losses) arising from hedge accounting for certain of our oil and natural gas hedges.

Page 9 

BRIGHAM EXPLORATION COMPANY

RECONCILIATION OF GAAP NET INCOME TO AFTER-TAX EARNINGS

EXCLUDING THE EFFECT OF CERTAIN ITEMS

(in thousands)

	Three months ended December 31,						Twelve months ended December 31,
	2007			2006			2007			2006
Net income (loss) as reported	$	1,844		$	5,001		$	10,210		$	19,788
Unrealized derivative (gains) losses		2,846			(2,868	)		5,831			(2,580	)
Unrealized derivative (gains) losses on ineffective hedges		—						—			(3,213	)
Impairment of oil and natural gas properties		—			—			6,505			—
Tax impact		(1,277	)		1,023			(4,678	)		2,269
Earnings excluding the effect of certain items	$	3,413		$	3,156		$	17,868		$	16,264

Earnings without the effect of certain items represents net income excluding the following: unrealized gains and losses on derivative contracts; unrealized gains and losses related to ineffectiveness on our derivatives that were previously classified as cash flow hedges; and our non-cash impairment charge on our oil and gas properties. Management believes that exclusion of these items enhances comparability of operating results between periods.

BRIGHAM EXPLORATION COMPANY

SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF MARCH 3, 2008

(unaudited)

		2008								2009
		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Natural Gas Costless Collars:
Daily volumes	MMBtu/d		16,703		15,055		10,543		4,783		4,333		2,308		2,283
Floor	$/MMBtu	$	7.873	$	7.109	$	7.023	$	7.830	$	7.904	$	7.071	$	7.071
Cap	$/MMBtu	$	12.441	$	9.536	$	9.697	$	10.434	$	10.438	$	9.750	$	9.750
Natural Gas Three Way Costless Collars:
Daily volumes	MMBtu/d		—		—		—		1,630		1,667		—		—
Floor	$/MMBtu	$	—	$	—	$	—	$	8.00	$	8.00	$	—	$	—
Written Put	$/MMBtu	$	—	$	—	$	—	$	5.50	$	5.50	$	—	$	—
Cap	$/MMBtu	$	—	$	—	$	—	$	10.35	$	10.35	$	—	$	—
Oil Costless Collars:
Daily volumes	Bbls/d		500		451		337		293		100		99		—
Floor	$/Bbl	$	61.68	$	64.98	$	66.17	$	65.52	$	62.00	$	62.00	$	—
Cap	$/Bbl	$	85.59	$	86.65	$	88.50	$	87.83	$	81.75	$	81.75	$	—

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.

EX-99.2

   NEWS RELEASE FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION ANNOUNCES FOURTH BAKKEN DISCOVERY AND SIGNIFICANT ACREAGE GROWTH IN MOUNTRAIL COUNTY, NORTH DAKOTA AND EXTENSIONAL AREAS, AND PROVIDES AN OPERATIONAL UPDATE

Austin, TX - March 3, 2008 -- Brigham Exploration Company (NASDAQ: BEXP) announced its fourth Mountrail County horizontal Bakken discovery and the commencement of its fifth well. Brigham also announced growth in its acreage in the Williston Basin to over 240,000 net acres. Most of the recent growth has occurred in Mountrail County and extensional areas where Brigham now controls over 88,000 net acres.

SIGNIFICANT WELLS RECENTLY COMPLETED, COMPLETING, DRILLING OR PREPARING TO DRILL

Resource Plays	Objective	WI%	NRI	Status / Comments
Hallingstad 27 #1H	Bakken	48 %	36 %	Completing Mountrail Co. well flowing after frac @ early rate of ~ 450 Boepd up 4.5" casing
Bakke 23 #1H	Bakken	93 %	76 %	Producing ~ 310 Boepd on rod pump
Hynek 2 #1H	Bakken	97 %	78 %	Producing ~ 142 Boepd on rod pump
Bergstrom Family Trust 26 #1H	Bakken	56 %	43 %	Producing ~ 119 Boepd on rod pump
Manitou State 36 #1H	Bakken	100 %	81 %	Drilling Mountrail Co. Bakken well ~1 mile northeast of Hynek 2 #1H in vertical @ depth of ~9,000'
Headington Nesson State 41 X 36H	Bakken	14 %	12 %	Completing Mountrail Co. Consortium Bakken well
Headington Nesson State 42 X 36H	Bakken	14 %	12 %	Drilling Mountrail Co. Consortium Bakken monitoring well in lateral @ ~12,365'
Headington Nesson State 44 X 36H	Bakken	14 %	12 %	Planned April spud of Mountrail Co. third Consortium Bakken well
Johnson 33 #1H	Bakken	38 %	30 %	Planned April spud of North Stanley extensional area horizontal Bakken well
Bakke Offset	Bakken	67 %	55 %	Planned May spud of western offset to Bakke 23 #1H
Mrachek 15-22 1H	Bakken	100 %	79 %	Horizontal sidetrack of McKenzie Co., ND well being remediated after apparent casing leak
Krejci Fed. #1-32H	Mowry	50 %	40 %	Successfully drilled and swell packers installed, fracing Mid-March, results early April

Conventional Wells	Objective	WI%	NRI	Status / Comments
Richardson 25 #1	Red River	90 %	68 %	Discovery currently producing 279 Boepd
Red River Test	Red River	75 %	60 %	Planned April Red River exploration well, est. total depth of 11,200', results expected in June
Cary Sr. Estate #1	Oligocene	40 %	29 %	Completing after encountering approx. 26' of pay @~12,300' true vertical depth, results in late March
SL 18826 #1	Miocene	50 %	38 %	Planned April spud of 1st of 5 planned 2008 JV wells to test amplitude related prospects, total depth ~7,900'
BLM 013045 #1	Miocene	50 %	38 %	Planned May spud of 2nd of 5 planned JV wells to test amplitude related prospects ~10,500'
Cotten Land #5	Miocene	39 %	27 %	Planned July spud of acceleration well developing behind pipe pay in Cotten Land #3 producer
Sullivan C-38	Vicksburg	100 %	76 %	Drilling development well in prolific Floyd Field @ depth of 10,610', est. total depth of 14,000', results in April
Sullivan C-39	Vicksburg	100 %	76 %	Planned late March spud of Triple Crown Field development well, results expected in June
Sullivan F-35	Vicksburg	100 %	76 %	Planned May spud of Dawson Sand development well in Triple Crown Field, results expected in July

Page 2

Williston Basin

Acreage Growth to over 240,000 Net Acres with over 88,000 Net Acres in Mountrail County & Extensional Areas - Brigham has grown its acreage position in the Williston Basin to over 240,000 net acres. Most of the recent growth has occurred east of the Nesson Anticline in Mountrail County and extensional areas where Brigham now controls over 88,000 net acres, approximately 40,300 net acres of which are located in Mountrail County. Approximately 7,000 net acres are generally proximal to the Parshall Field and EOG's Austin discoveries, while roughly 26,000 net acres are located in the Ross area, generally between the Parshall Field area and the Nesson Anticline. An additional 7,300 net acres are located in Mountrail County in the North Stanley area, which is approximately 15 miles northwest of the EOG Austin wells, and approximately 12 miles north of the Brigham operated Bakke 23 #1H. Approximately 48,000 net acres are located in undisclosed extensional areas to the east of the Nesson Anticline.

To the west of the Nesson Anticline in McKenzie and Williams Counties, North Dakota, Brigham controls Bakken rights on approximately 51,000 net acres. In eastern Montana, where Brigham drilled its recent Red River discovery, Brigham controls all rights on roughly 100,000 net acres in Sheridan and Roosevelt Counties.

Mountrail County Bakken Drilling and Completion Activity - Brigham successfully drilled and completed its fourth operated Mountrail County horizontal Bakken well, the Hallingstad 27 #1H. Subsequent to fracture stimulation the Hallingstad 27 #1H produced at an early rate of approximately 450 Boe per day up 4.5" casing. Northern Oil and Gas Inc. (OTC: NOGS) participated in the Hallingstad 27 #1H with a 8.4% working interest, which increases to a 20% working interest after payout. The Hallingstad 27 #1H is located approximately one mile west of the Bergstrom Family Trust 26 #1H well and approximately four miles northeast of the Parshall Field.

Subsequent to drilling the Hallingstad 27 #1H, Brigham commenced the Manitou State 36 #1H, which is currently drilling at a depth of approximately 9,000 feet. The Manitou State 36 #1H is located approximately one mile northeast of the Brigham operated Hynek 2 #1H and approximately five miles northwest of the Brigham operated Bakke 23 #1H. Following the Manitou State 36 #1H, Brigham plans to commence the Johnson 33 #1H in the North Stanley area, where Brigham controls approximately 7,300 net acres. Brigham currently plans to keep this operated rig running continuously to drill horizontal Bakken wells in North Dakota.

Brigham has installed 2 7/8" production tubing and pumping units on its first three Mountrail County horizontal Bakken completions. The Bakke 23 #1H is currently producing approximately 310 Boe per day, the Hynek 2 #1H is producing approximately 142 Boe per day, and the Bergstrom Family Trust 26 #1H is producing approximately 119 Boe per day.

Bud Brigham, the Chairman, President and CEO stated, "We're encouraged by the early results of the Hallingstad 27 #1H, which appears to be a strong producer. Approximately five miles to the west of the Hallingstad 27 #1H, EOG has completed the Austin 26 #1H in section 2 of 154N-90W, which they reported to have produced at an early rate of approximately 3,060 barrels per day. We have a meaningful acreage position within a few miles of the Austin 26 #1H, including interests in two sections directly offsetting the discovery. Our larger working interest directly offsets the Austin 26 #1 to the South where we own a 25% interest and is reportedly planned to be drilled this year. As shown on our Mountrail area map in our corporate presentation, we control approximately 7,000 net acres in the Parshall Field area, including acreage offsetting EOG's three previously announced high rate Austin discoveries in sections 2, 4 and 9 of T154N-R90W. Provided the area is developed on 640 acre spacing roughly 11 net wells would be drilled, double that if 320 acre spacing is validated, which we believe to be likely. Given the accelerating drilling pace announced by several of the operators, we expect drilling in this area to meaningfully impact our production and reserves in 2008 and subsequent years."

Bud Brigham continued, "Subsequent to drilling the Manitou State 36 #1H, we'll commence the Johnson 33 #1H in our North Stanley area. We believe this area has many attributes in common with the Parshall/Austin area, and it is about 17 miles northwest and generally on trend with those producers. In total, the 88,000 net acres we've accumulated in the play east of the Nesson Anticline, including approximately 40,300 of which is in Mountrail County, provides us with the potential to drill 137 to 275 net wells, depending on spacing. Given our size, we believe we've accumulated the most impactful acreage position in the Bakken play. This year, we expect to drill or participate in the drilling of at least seventeen gross, or six net wells in the play in at least four different areas."

About Brigham Exploration

Brigham Exploration Company is a leading independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore and develop onshore domestic natural gas and oil provinces. For more information about Brigham Exploration, please visit our website at http://www.bexp3d.com or contact Investor Relations at 512-427-3444.

Page 3

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 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, Finance Manager

(512) 427-3300