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 5, 2009

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 5, 2009, which announced our financial results for the second quarter ended June 30, 2009 and provided third quarter 2009 forecasts. The text of that press release is attached to this Report as Exhibit 99.1 and is incorporated by reference herein.

In addition to 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 August 5, 2009 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 5, 2009.

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 5, 2009
	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 5, 2009.

EX-99.1

Exhibit 99.1

NEWS RELEASE
FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION REPORTS SECOND QUARTER 2009 RESULTS AND PROVIDES THIRD QUARTER 2009 FORECASTS

Austin, TX – August 5, 2009 — Brigham Exploration Company (NASDAQ:BEXP) today announced its financial results for the second quarter and six months ended June 30, 2009.

SECOND QUARTER 2009 RESULTS

Revenues from the sale of oil and natural gas including hedge settlements, but excluding unrealized mark-to-market hedging gains and losses, for the second quarter 2009 were $14.5 million, which represented a 59% decrease when compared to that in the second quarter 2008. The primary driver behind the decrease was a 62% decrease in our average natural gas equivalent sales price, which reduced revenues by $24.3 million. Lower natural gas volumes also decreased revenues by $5.8 million while higher oil volumes and higher hedge settlements increased revenues by $4.4 million and $4.6 million, respectively.

Importantly, for the first time in our company’s history, pre-hedged oil revenues exceeded natural gas revenues as our oil production volumes increased 28% in the second quarter 2009 versus that in the second quarter 2008. The increase in our oil production is attributable to our increased capital spending in the Williston Basin and our improved drilling results as we have increased the number of fracture stimulation stages on our horizontal well completions. In addition, our oil revenues continue to benefit from oil’s relative price advantage compared to natural gas, as our pre-hedged oil was priced at a 14 to 1 equivalent ratio versus the Btu equivalency convention of 6 to 1.

Our production volumes for the second quarter 2009 were 27.2 MMcfe per day, or 4,526 barrels of equivalent per day, which was within our previously established guidance range. As previously mentioned, our oil volumes for the second quarter 2009 increased by 28% to 1,823 barrels of oil per day from that in the second quarter 2008. Our oil production for the second quarter 2009 represented 40% of our total volumes versus 28% in the second quarter 2008. Our natural gas volumes were negatively impacted by approximately 2.7 MMcfe per day due to higher than forecasted decline rates associated with our Bayou Postillion wells in Southern Louisiana. Benefitting from our Williston Basin focused capital expenditure program, our Williston Basin production volumes increased by 143% from that in the second quarter 2008 to 1,273 barrels of oil equivalent per day.

During the second quarter 2009, our average realized price for oil was $48.06 per barrel, which includes a $1.35 per barrel loss due to the settlement of our oil derivative contracts. This compares to an average realized price in the second quarter 2008 of $109.71, which includes a $12.51 per barrel loss due to the settlement of our oil derivative contracts. Our average realized price for natural gas in the second quarter 2009 was $4.53 per Mcf, which includes a $1.03 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the second quarter 2008 of $11.03 per Mcf, which includes a $0.90 per Mcf loss associated with the settlement of our natural gas derivative contracts.

Our second quarter 2009 production costs, which include operating and maintenance (O&M) expenses, expensed workovers, ad valorem taxes and production taxes, were $1.80 per Mcfe, or $10.80 per Boe. This compares to $1.47 per Mcfe, or $8.82 per Boe, in the second quarter 2008. This increase was primarily attributable to higher compressor rental, surface equipment and saltwater disposal expenses. Offsetting these increases, production taxes decreased due to lower commodity prices.

Our second quarter 2009 general and administrative (G&A) expense was 13% lower than that in the second quarter of last year. G&A costs decreased primarily because of lower employee compensation expense associated with our cost cutting measures implemented earlier in the year.

Our depletion expense for the second quarter 2009 was $6.2 million, compared to $12.4 million in the second quarter 2008. Our lower production volumes decreased depletion expense by $1.2 million, while our lower depletion rate decreased depletion expense by $5.0 million. On a per unit basis, depletion expense in the second quarter 2009 was $2.55 per Mcfe, or $15.30 per Boe, compared to $4.57 per Mcfe, or $27.42 per Boe, in the second quarter 2008.

Our net interest expense for the second quarter 2009 was $0.8 million higher than in the second quarter 2008. This increase was primarily due to higher levels of outstanding debt under our Senior Credit Agreement and a lower amount of capitalized interest. Our weighted average debt outstanding for the second quarter 2009 was $301.6 million, compared to $205.5 million for the comparable period last year.

We recorded no deferred income taxes in the second quarter 2009, compared to $0.9 million in the second quarter of last year.

Our reported net income (loss) for the second quarter 2009 was ($7.0) million (($0.12) per diluted share), versus $1.5 million ($0.03 per diluted share) for the same period last year. Our after-tax earnings (loss) in the second quarter 2009 excluding the effect of our unrealized mark-to-market hedging losses and non-cash write-down of the carrying value of our inventory were ($2.8) million (($0.05) per diluted share), while our after-tax earnings in the second quarter 2008 excluding unrealized mark-to-market hedging losses were $8.1 million ($0.17 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.

For the second quarter 2009, we spent $7.4 million on oil and gas capital expenditures, which represents a decrease of 83% from that in the second quarter 2008. Oil and gas capital expenditures for the second quarter 2009 and 2008 were:

	Three months ended June 30,
	2009		2008
	(in thousands)
Drilling	$	3,552	$	31,489
Net land and G&G		784		8,196
Capitalized costs		2,923		3,389
Capitalized FAS 143 ARO		103		71
Total oil and gas capital expenditures	$	7,362	$	43,145

FIRST SIX MONTHS 2009 RESULTS

Revenues from the sale of oil and natural gas including hedge settlements, but excluding unrealized mark-to-market hedging gains and losses, for the first six months of 2009 were down 46% to $35.8 million when compared to that in the corresponding period last year. Revenues decreased $43.9 million due to a 59% decrease in our average natural gas equivalent price compared to that in the first six months of 2008. Lower natural gas volumes also decreased revenues by $8.6 million while higher oil volumes and higher hedge settlements increased revenues by $10.2 million and $12.2 million, respectively.

Our average realized price for oil for the first half of 2009 was $44.18 per barrel, which includes a $2.55 per barrel gain due to the settlement of our oil derivative contracts. This compares to an average realized price in the first six months of 2008 of $100.53, which includes an $8.93 per barrel loss due to the settlement of our oil derivative contracts. Our average realized price for natural gas during the first six months of 2009 was $6.33 per Mcf, which includes a $2.40 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the first six months of 2008 of $9.99 per Mcf, which includes a $0.30 per Mcf loss due to the settlement of our natural gas derivative contracts.

Our per unit production costs for the first six months of 2009 increased 14% to $1.69 per Mcfe, or $10.14 per Boe, when compared to that in the same period last year. O&M expense increased due to higher compressor rental, saltwater disposal, and fuel and electricity expenses versus that in the first six months of 2008. Production taxes were lower in the first six months 2009 due to lower commodity prices.

Our G&A expense for the first six months of 2009 was 15% lower than that in the first six months of last year. G&A costs decreased primarily because of lower employee compensation expense associated with cost cutting measures implemented earlier in the year.

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Our depletion expense for the first six months of 2009 was $16.1 million compared to $24.8 million in the first six months of last year. Lower production volumes decreased depletion expense by $1.2 million, while our lower depletion rate decreased depletion expense by $7.5 million. On a per unit basis, depletion expense in the first half of 2009 was $3.02 per Mcfe, or $18.12 per Boe, compared to $4.43 per Mcfe, or $26.58 per Boe, in the second quarter 2008.

Our net interest expense for the first six months of 2009 increased by $1.5 million, or 21%, from that in the comparable period last year. This increase was primarily due to higher levels of outstanding debt under our Senior Credit Agreement. Our weighted average debt outstanding for the first six months of 2009 was $308.3 million versus $194.2 million for the comparable period last year.

We recorded no deferred income taxes in the first six months 2009, compared to $1.9 million in the first six months of last year.

Our reported net income (loss) for the first six months of 2009 was ($126.0) million (($2.39) per diluted share) versus net income of $3.0 million ($0.07 per diluted share) for the same period last year. Our after-tax earnings (loss) in the first six months 2009 excluding the effect of our first quarter 2009 ceiling test write-down, unrealized mark-to-market hedging losses, and $2.2 million non-cash write-down of the carrying value of our inventory were ($2.2) million (($0.04) per diluted share) and our after-tax earnings for the first six months of 2008 excluding unrealized mark-to-market hedging losses were $12.9 million ($0.28 per diluted share). A reconciliation of the first six months 2009 GAAP net income to earnings without the effect of the above items is included in our accompanying financial tables found later in this release.

Through June 30, 2009, we spent $26.5 million on drilling capital expenditures and $26.7 million in total oil and gas capital expenditures. Oil and gas capital expenditures for the first six months of 2009 and 2008 were:

	Six months ended June 30,
	2009			2008
	(in thousands)
Drilling	$	26,492		$	62,689
Net land and G&G		(5,687	)		19,029
Capitalized costs		5,663			6,799
Capitalized FAS 143 ARO		275			132
Total oil and gas capital expenditures	$	26,743		$	88,649

THIRD QUARTER 2009 FORECASTS

The following forecasts and estimates for the third quarter 2009 are forward-looking statements subject to the risks and uncertainties identified in the “Forward-Looking Statements Disclosure” at the end of this release.

Based on the historic 6 to 1 industry equivalent convention, we currently expect our oil volumes to comprise approximately 50% of our total production volumes for the third quarter 2009, up from approximately 40% in the second quarter 2009.  We currently anticipate our third quarter 2009 production volumes to average between 4,667 barrels of oil equivalent per day to 5,167 barrels of oil equivalent per day.  Furthermore, we currently anticipate that our oil production will grow to approximately 2,458 barrels of oil per day in the third quarter 2009 based on the mid point of our production guidance.  This would represent an approximate 35% sequential increase in our oil volumes from the second quarter 2009, and an approximate 73% increase relative to that in the third quarter of 2008. 

For the third quarter 2009, lease operating expenses are projected to be $8.52 per Boe based on the mid-point of our production guidance, production taxes are projected to be approximately 7.5 to 8.0% of pre-hedge oil and natural gas revenues, and general and administrative expenses are projected to be $2.1 million ($4.75 per Boe).

MANAGEMENT COMMENTS

Gene Shepherd, Brigham’s Chief Financial Officer, commented, “During the second quarter, we completed several liquidity-enhancing initiatives that have positioned the company to benefit from our very significant resource potential in the Williston Basin. These initiatives have come on the heels of, and have been positively impacted by, a dramatic improvement in our Williston Basin drilling economics, which include a significant improvement in our initial production rates and EURs, the rebound in oil prices, the dramatic decline in service costs, and the decline in oil differentials. We are excited to have our Williston Basin drilling program underway in such a dramatically improved drilling environment.”

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Bud Brigham, the Chairman, President and Chief Executive Officer commented, “Our Williston Basin drilling program kicked off in July with significant operational momentum thanks to the highly successful completion of our Strobeck 27-34 #1H, which commenced production at an early 24 hour rate of 2,021 barrels of oil equivalent per day. The well continues to perform strongly and it averaged 989 barrels of oil equivalent over the first 30 days of production. We’re also excited about our Anderson 28-33 #1H and the Figaro 29-32 #1H, both of which are currently undergoing fracture stimulation operations, and we expect to have initial results on the wells in the next several weeks. All three of these wells should positively impact our oil production for the third quarter.”

Bud Brigham continued, “The Brad Olson 9-16 #1H is currently drilling ahead at 13,171’ in the horizontal section of the wellbore. We expect the well will be at total depth in the next week. After the Brad Olson, we expect to begin drilling the BCD Farms 16-21 #1H, which is also located in Williams County, North Dakota.”

Bud Brigham continued, “Our company is involved in a very exciting and beneficial transformation. For the first time as a public company, our oil revenues exceeded that of our gas revenues during the second quarter 2009. Furthermore, the third quarter 2009 is expected to be the first quarter in which our 6:1 equivalent oil production is anticipated to approach a record 50% of our total production. We’re extremely excited to see a potential 35% sequential increase in our oil production volumes in the third quarter 2009, especially given the current 14 to 1 pricing relationship between oil and gas, which generates incremental cash flow to our shareholders from every barrel of oil that we extract from the Williston Basin.”

Bud Brigham concluded, “Our shareholders are just beginning to see the benefits of our large top tier acreage position and our early drilling in the premier oil resource play in the United States. The benefits of this transformation include our growing, long reserve life and high value Williston Basin oil volumes. Given the improved environment today, including the lower service costs, moderated differentials, our ongoing operational enhancements, and the price advantage offered by oil, we believe we are providing our shareholders with a substantial net asset value creation opportunity.”

CONFERENCE CALL INFORMATION

Our management will host a conference call to discuss operational and financial results for the second quarter 2009 with investors, analysts and other interested parties on Thursday, August 6, at 11:00 a.m. Eastern Time. To participate in the call, participants within the U.S. please dial 888-713-4211 and participants outside the U.S. please dial 617-213-4864. The participant passcode for the call is 40018944. Participants may pre-register for the call at https://www.theconferencingservice.com/prereg/key.process?key=PR6FY9A7W. Pre-registrants will be issued a pin number to use when dialing into the live call which will provide quick access to the conference. 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 Thursday, August 13, 2009. 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 64434578. 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.

A copy of this press release and other financial and statistical information about the periods covered by this press release and conference call 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 Second Quarter 2009 Results and is dated Wednesday, August 5, 2009. To access the other financial and statistical information that will be covered by this conference call, 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 Second Quarter 2009 Conference Call and is dated Wednesday, August 5, 2009.

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 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 natural 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						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues:
Oil sales	$	8,105		$	15,640		$	14,055		$	26,797
Natural gas sales		5,104			23,231			12,963			42,584
Hedging settlements		1,286			(3,357	)		8,807			(3,419	)
		14,495			35,514			35,825			65,962
Unrealized hedging gains/ losses		(4,013	)		(10,550	)		(6,891	)		(15,944	)
		10,482			24,964			28,934			50,018
Other revenue		32			62			66			79
Total revenue		10,514			25,026			29,000			50,097
Costs and expenses:
Lease operating		3,573			2,548			7,372			5,534
Production taxes		831			1,441			1,645			2,724
General and administrative		2,264			2,596			4,386			5,189
Depletion of oil and natural gas properties		6,233			12,405			16,066			24,848
Impairment of oil and gas properties		—			—			114,781			—
Depreciation and amortization		167			158			316			305
Loss on inventory valuation		128			—			2,167			—
Accretion of discount on asset retirement obligations		105			89			206			180
		13,301			19,237			146,939			38,780
Operating income (loss)		(2,787	)		5,789			(117,939	)		11,317
Other income (expense):
Interest expense, net		(4,251	)		(3,482	)		(8,378	)		(6,901	)
Interest income		111			39			204			114
Other income (expense)		(33	)		96			82			403
		(4,173	)		(3,347	)		(8,092	)		(6,384	)
Income before income taxes		(6,960	)		2,442			(126,031	)		4,933
Income tax expense:
Current		—			—			—			—
Deferred		—			(925	)		—			(1,889	)
		—			(925	)		—			(1,889	)
Net income (loss)	$	(6,960	)	$	1,517		$	(126,031	)	$	3,044
Net income per share available to common stockholders:
Basic	$	(0.12	)	$	0.03		$	(2.39	)	$	0.07
Diluted	$	(0.12	)	$	0.03		$	(2.39	)	$	0.07
Weighted average shares outstanding:
Basic		59,687			45,332			52,745			45,296
Diluted		59,687			46,444			52,745			46,171

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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,
	2009			2008			2009			2008
Average net daily production:
Natural gas (MMcf)		16.2			21.6			18.3			23.0
Oil (Bbls)		1,823			1,422			1,875			1,360
Equivalent natural gas (MMcfe) (6:1)		27.2			30.2			29.6			31.2
Equivalent oil (Boe) (6:1)		4,526			5,027			4,933			5,193
Total net production:
Natural gas (MMcf)		1,460			1,947			3,302			4,139
Oil (MBbls)		164			128			338			245
Equivalent natural gas (MMcfe) (6:1)		2,444			2,715			5,328			5,609
Equivalent oil (MBoe) (6:1)		407			453			888			935
% Natural gas		60	%		72	%		62	%		74	%
Sales price:
Natural gas ($/Mcf)	$	3.50		$	11.93		$	3.93		$	10.29
Oil ($/Bbl)		49.41			122.22			41.63			109.46
Equivalent natural gas ($/Mcfe) (6:1)		5.40			14.32			5.07			12.37
Sales price including derivative settlement gains (losses):
Natural gas ($/Mcf)	$	4.53		$	11.03		$	6.33		$	9.99
Oil ($/Bbl)		48.06			109.71			44.18			100.53
Equivalent natural gas ($/Mcfe) (6:1)		5.93			13.08			6.72			11.76
Sales price including derivative settlement gains (losses) and unrealized gains (losses):
Natural gas ($/Mcf)	$	3.86		$	7.61		$	5.56		$	7.14
Oil ($/Bbl)		29.56			79.25			31.32			83.64
Equivalent natural gas ($/Mcfe) (6:1)		4.29			9.19			5.43			8.92

SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)

	June 30, 2009		December 31, 2008
	(unaudited)
Assets:
Current assets	$	96,738	$	78,520
Oil and natural gas properties, net (full cost method)		300,733		404,839
Other property and equipment, net		2,359		1,873
Other non-current assets		4,578		3,824
Total assets	$	404,408	$	489,056
Liabilities and stockholders’ equity:
Current liabilities	$	28,389	$	48,215
Senior notes		158,849		158,730
Senior credit facility		110,000		145,000
Mandatorily redeemable preferred stock, Series A		10,101		10,101
Deferred income tax liability		149		149
Other non-current liabilities		6,783		5,592
Total liabilities	$	314,271	$	367,787
Stockholders’ equity		90,137		121,269
Total liabilities and stockholders’ equity	$	404,408	$	489,056

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

	Three months ended June 30,						Six months ended June 30,
	2009			2008			2009			2008
Cash flows from operating activities:
Net income	$	(6,960	)	$	1,517		$	(126,031	)	$	3,044
Depletion, depreciation and amortization		6,400			12,563			16,382			25,153
Impairment of oil and gas properties		—			—			114,781			—
Accretion of discount on ARO		105			89			206			180
Amortization of deferred loan fees and debt issuance costs		330			273			626			528
Non-cash stock compensation		444			404			797			818
Market value adjustments for derivatives instruments		4,013			10,550			6,891			15,944
Deferred income tax expense		—			925			—			1,889
Other noncash items		(1	)		32			35			4
Changes in operating assets and liabilities		(1,819	)		(11,648	)		2,260			(4,520	)
Cash flows provided by operating activities	$	2,512		$	14,705		$	15,947		$	43,040
Cash flows used by investing activities		(19,109	)		(39,678	)		(45,498	)		(84,712	)
Cash flows (used) provided by financing activities		57,652			29,820			57,594			38,822
Net increase (decrease) in cash and cash equivalents	$	41,055		$	4,847		$	28,043		$	(2,850	)

SUMMARY PER MCFE DATA
(unaudited)

	Three months ended June 30,						Six months ended June 30,
	2009			2008			2009			2008
Revenues:
Oil and natural gas sales	$	5.40		$	14.32		$	5.07		$	12.37
Hedge settlements		0.53			(1.24	)		1.65			(0.61	)
Unrealized hedge gains (losses)		(1.64	)		(3.88	)		(1.29	)		(2.84	)
Other revenue		0.01			0.02			0.01			0.01
	$	4.30		$	9.22		$	5.44		$	8.93
Costs and expenses:
Lease operating		1.46			0.94			1.38			0.99
Production taxes		0.34			0.53			0.31			0.49
General and administrative		0.93			0.96			0.82			0.93
Depletion of natural gas and oil properties		2.55			4.57			3.02			4.43
Impairment of oil and gas properties		—			—			21.54			—
Depreciation and amortization		0.07			0.06			0.06			0.05
Loss on inventory valuation		0.05			—			0.41			—
Accretion of discount on ARO		0.04			0.03			0.04			0.03
	$	5.44		$	7.09		$	27.58		$	6.92
Operating income (loss)	$	(1.14	)	$	2.13		$	(22.14	)	$	2.01
Interest expense, net of interest income (a)		(1.69	)		(1.27	)		(1.53	)		(1.21	)
Other income (expense)		(0.01	)		0.04			0.02			0.07
Adjusted income	$	(2.84	)	$	0.90		$	(23.65	)	$	0.87

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

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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,
	2009			2008			2009			2008
Net income (loss) as reported	$	(6,960	)	$	1,517		$	(126,031	)	$	3,044
Unrealized derivative (gains) losses		4,013			10,550			6,891			15,944
Impairment of oil and natural gas properties		—			—			114,781			—
Loss on inventory valuation		128			—			2,167			—
Tax impact		—			(3,996	)		—			(6,105	)
Earnings without the effect of certain items	$	(2,819	)	$	8,071		$	(2,192	)	$	12,883

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.

SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF AUGUST 5, 2009
(unaudited)

		2009				2010
		Q3		Q4		Q1		Q2		Q3		Q4		2011(a)
Natural Gas Costless Collars:
Daily volumes	MMBtu/d		—		3,804		4,667		5,934		5,870		3,587		329
Floor	$/MMBtu	$	—	$	5.510	$	5.450	$	5.517	$	5.517	$	5.641	$	6.500
Cap	$/MMBtu	$	—	$	7.030	$	7.025	$	7.117	$	7.117	$	7.455	$	8.250
Natural Gas Three Way Costless Collars:
Daily volumes	MMBtu/d		—		4,239		4,333		—		—		—		—
Floor	$/MMBtu	$	—	$	6.962	$	6.962	$	—	$	—	$	—	$	—
Written Put	$/MMBtu	$	—	$	4.577	$	4.577	$	—	$	—	$	—	$	—
Cap	$/MMBtu	$	—	$	8.615	$	8.615	$	—	$	—	$	—	$	—
Natural Gas Swaps:
Daily volumes	MMBtu/d		12,239		3,283		—		—		—		—		—
Swap	$/MMBtu	$	4.14	$	4.44	$	—	$	—	$	—	$	—	$	—
Oil Costless Collars:
Daily volumes	Bbls/d		967		772		933		835		750		717		230
Floor	$/Bbl	$	56.26	$	54.68	$	55.43	$	54.62	$	55.09	$	54.41	$	65.00
Cap	$/Bbl	$	74.21	$	73.56	$	80.48	$	80.70	$	82.23	$	82.05	$	88.25
Oil Swaps:
Daily volumes	Bbls/d		326		326		—		—		—		—		—
Floor	$/Bbl	$	50.75	$	50.75	$	—	$	—	$	—	$	—	$	—

(a) Hedged 40,000 MMBtu/month for Q1 2011 and 7,000 Bbls/month for all of 2011

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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