Filed by Bowne Pure Compliance

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2008


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

For the transition period from to

Commission File Number: 000-22433

Brigham Exploration Company

(Exact name of registrant as specified in its charter)


Delaware	1311	75-2692967
(State of other jurisdiction	(Primary Standard Industrial	(I.R.S. Employer
of incorporation or organization)	Classification Code Number)	Identification Number)

6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices)

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

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

Yes þ No o

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


Large Accelerated Filer o	Accelerated Filer þ	Non-Accelerated Filer o	Small Reporting Company o
		(Do not check if a smaller reporting company)

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

Yes o No þ


Class		Outstanding
Common Stock, par value $.01 per share as of May 1, 2008		46,201,276

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)


	March 31,			December 31,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	6,166		$	13,863
Accounts receivable		20,412			14,609
Derivative assets		—			1,416
Other current assets		2,984			2,617

Total current assets		29,562			32,505

Oil and natural gas properties, using the full cost method including
Proved, net		460,725			448,663
Unproved		82,542			61,544

		543,267			510,207

Other property and equipment, net		1,072			1,034
Deferred loan fees		3,502			3,687
Other noncurrent assets		1,536			995

Total assets	$	578,939		$	548,428


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	19,992		$	12,301
Royalties payable		9,731			5,978
Accrued drilling costs		15,450			14,841
Participant advances received		129			2,095
Derivative liabilities		5,740			1,812
Other current liabilities		8,615			4,691

Total current liabilities		59,657			41,718


Senior Notes		158,551			158,492
Senior credit facility		19,000			10,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at March 31, 2008 and December 31, 2007		10,101			10,101
Deferred income taxes		42,609			41,625
Other taxes payable		2,162			2,162
Other noncurrent liabilities		5,644			5,303

Commitments and contingencies (Note 3)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,387,639 and 45,304,139 shares issued and 45,264,473 and 45,197,303 shares outstanding at March 31, 2008 and December 31, 2007, respectively		454			453
Additional paid-in capital		208,422			207,526
Treasury stock, at cost; 123,166 and 106,836 shares at March 31, 2008 and December 31, 2007, respectively		(975	)		(854	)
Accumulated other comprehensive income (loss)		—			115
Retained earnings		73,314			71,787

Total stockholders’ equity		281,215			279,027

Total liabilities and stockholders’ equity	$	578,939		$	548,428

The accompanying notes are an integral part of these consolidated financial statements.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended
	March 31,
	2008			2007

Revenues:
Oil and natural gas sales	$	30,510		$	28,486
Gain (loss) on derivatives, net		(5,456	)		(3,492	)
Other revenue		17			27

		25,071			25,021


Costs and expenses:
Lease operating		2,986			2,569
Production taxes		1,283			71
General and administrative		2,593			2,178
Depletion of oil and natural gas properties		12,443			13,959
Depreciation and amortization		147			163
Accretion of discount on asset retirement obligations		91			117

		19,543			19,057

Operating income		5,528			5,964

Other income (expense):
Interest income		75			131
Interest expense, net		(3,419	)		(3,417	)
Other income (expense)		307			190

		(3,037	)		(3,096	)

Income before income taxes		2,491			2,868

Income tax expense:
Current		—			—
Deferred		(964	)		(995	)

		(964	)		(995	)


Net income	$	1,527		$	1,873


Net income per share available to common stockholders:
Basic	$	0.03		$	0.04

Diluted	$	0.03		$	0.04


Weighted average shares outstanding:
Basic		45,261			45,051

Diluted		45,770			45,430

The accompanying notes are an integral part of these consolidated financial statements.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)


											Accumulated
					Additional						Other					Total
	Common Stock				Paid In			Treasury			Comprehensive			Retained		Stockholders’
	Shares		Amounts		Capital			Stock			Income (Loss)			Earnings		Equity
Balance, December 31, 2007		45,304	$	453	$	207,526		$	(854	)	$	115		$	71,787	$	279,027
Comprehensive income:
Net income		—		—		—			—			—			1,527		1,527
Net (gains) losses included in net income		—		—		—			—			(177	)		—		(177	)
Tax benefit (provision) related to hedges		—		—		—			—			62			—		62

Comprehensive income																	1,412
Exercises of employee stock options		34		—		134			—			—			—		134
Vesting of restricted stock		50		1		(1	)		—			—			—		—
Stock based compensation		—		—		763			—			—			—		763
Repurchases of common stock		—		—		—			(121	)		—			—		(121	)


Balance, March 31, 2008		45,388	$	454	$	208,422		$	(975	)	$	—		$	73,314	$	281,215

The accompanying notes are an integral part of these consolidated financial statements.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended
	March 31,
	2008			2007

Cash flows from operating activities:
Net income	$	1,527		$	1,873
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		12,443			13,959
Depreciation and amortization		147			163
Stock based compensation		414			421
Amortization of deferred loan fees and debt issuance costs		255			214
Market value adjustment for derivative instruments		5,394			4,916
Accretion of discount on asset retirement obligations		91			117
Deferred income taxes		964			995
Other noncash items		(28	)		—
Changes in operating assets and liabilities:
Accounts receivable		(5,803	)		(215	)
Other current assets		(285	)		426
Accounts payable		7,691			(8,079	)
Royalties payable		3,753			176
Participant advances received		(1,966	)		(2,387	)
Other current liabilities		3,924			2,999
Other noncurrent assets and liabilities		(186	)		6

Net cash provided by operating activities		28,335			15,584


Cash flows from investing activities:
Additions to oil and natural gas properties		(44,484	)		(47,605	)
Additions to other property and equipment		(157	)		(411	)
Decrease (increase) in drilling advances paid		(393	)		(206	)

Net cash used by investing activities		(45,034	)		(48,222	)


Cash flows from financing activities:
Increase in senior credit facility		9,000			35,600
Repayment of senior credit facility		—			—
Repayment of senior subordinated notes		—			—
Deferred loan fees paid and equity costs		(11	)		—
Proceeds from issuance of stock, net of issuance costs		—			—
Proceeds from exercise of employee stock options		134			23
Repurchases of common stock		(121	)		(134	)

Net cash provided by financing activities		9,002			35,489

Net increase (decrease) in cash and cash equivalents		(7,697	)		2,851
Cash and cash equivalents, beginning of year		13,863			4,300

Cash and cash equivalents, end of period	$	6,166		$	7,151

The accompanying notes are an integral part of these consolidated financial statements.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Organization and Nature of Operations

Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the “Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as “Brigham.” Brigham is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Brigham’s exploration and development of oil and natural gas properties is currently focused in the onshore Gulf Coast, the Anadarko Basin, the Rocky Mountains and West Texas.

2. Basis of Presentation

The accompanying unaudited consolidated financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated.

The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham’s 2007 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

See Note 7 for a discussion of the accounting policy pertaining to the adoption of Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements” (SFAS 157) effective January 1, 2008.

3. Commitments and Contingencies

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

As of March 31, 2008, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.

4. Net Income Available Per Common Share

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2008 and 2007 are as follows (in thousands):


	Three Months Ended
	March 31,
	2008		2007

Weighted average common shares outstanding – basic		45,261		45,051
Plus: Potential common shares
Stock options and restricted stock		509		379


Weighted average common shares outstanding – diluted		45,770		45,430


Stock options excluded from diluted EPS due to the anti-dilutive effect		2,347		2,550

5. Income Taxes

The income tax expense (benefit) for the three months ended March 31, 2008 and 2007 consists of the following (in thousands):


	March 31,		March 31,
	2008		2007
Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		872		1,179
State		92		(184	)

	$	964	$	995

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement 109” (FIN 48), which provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” of being sustained if the position were to be challenged by a taxing authority. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is greater than 50% likely of being recognized upon ultimate settlement with the taxing authority is recorded. Brigham adopted the provisions of FIN 48 on January 1, 2007. Brigham has examined the tax positions taken in its tax returns or expected to be taken in its future tax returns and has determined that the full values of the uncertain tax positions have been recorded as part of the deferred tax liabilities. Therefore, no additional liabilities should be created and no incremental current or deferred income tax expenses should be recognized. However, consistent with the view of the FASB, Brigham has reclassified the liability for unrecognized tax benefits related to these uncertain tax positions from deferred tax liabilities to other tax liabilities on the consolidated balance sheet.

The following table sets forth the reconciliation of unrecognized tax benefits:


	(In thousands)

Increases (decreases) resulting from adoption of FIN 48	$	2,162
Increases (decreases) resulting from tax positions taken in the current period		—
Decreases relating to settlements with taxing authorities		—
Reductions resulting from the lapse of applicable statutes of limitations		—

Unrecognized tax benefits at March 31, 2008	$	2,162

None of the above unrecognized benefits would affect Brigham’s effective tax rate. Brigham classifies interest on uncertain tax positions as interest expense. Penalties are included in general administrative expense on the consolidated statement of operations. There are no interest and penalties recognized in the consolidated statement of operations or in the consolidated balance sheet because of the existence of Brigham’s net operating loss carryovers.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 2007, 2006, 2005 and 2004.

6. Derivative Instruments and Hedging Activities

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

Natural Gas and Crude Oil Derivative Contracts

Cash flow hedges

All derivative positions are carried at their fair value on the consolidated balance sheet and are marked-to-market at the end of each period. Any realized and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the consolidated statement of operations rather than as a component of other comprehensive income or as other income (expense).

Brigham does not offset asset and liability fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. Brigham’s agreements do not require cash collateral deposits.

Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham’s oil and natural gas prices including and excluding the realized and unrealized hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three months ended March 31, 2008 and 2007:


	Three Months Ended
	March 31,
	2008			2007
*Natural Gas*
Average price per Mcf realized excluding gas hedging results	$	8.83		$	7.32
Average price per Mcf including gas hedging settlement results	$	9.07		$	7.76
Increase (decrease) in revenue, in thousands	$	524		$	1,311
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	6.71		$	6.23
Increase (decrease) in revenue, in thousands	$	(4,632	)	$	(3,251	)
*Oil*
Average price per Bbl realized excluding oil hedging results	$	95.50		$	54.75
Average price per Bbl including oil hedging settlement results	$	90.48		$	55.68
Increase (decrease) in revenue, in thousands	$	(586	)	$	113
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	88.45		$	52.78
Increase (decrease) in revenue, in thousands	$	(824	)	$	(240	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at March 31, 2008, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
04/01/08 - 07/31/08		120,000			$	7.00	$	9.25
04/01/08 – 06/30/08		120,000			$	7.00	$	9.00
04/01/08 - 09/30/08		420,000			$	6.75	$	9.75
04/01/08 - 09/30/08		260,000			$	7.00	$	8.35
04/01/08 - 09/30/08		540,000			$	7.00	$	9.68
04/01/08 - 10/31/08		350,000			$	7.25	$	10.40
04/01/08 - 05/31/08		60,000			$	7.00	$	8.70
04/01/08 - 04/30/08		60,000			$	7.25	$	9.00
04/01/08 - 07/31/08		200,000			$	7.50	$	10.20
05/01/08 - 07/31/08		90,000			$	8.50	$	10.40
06/01/08 - 09/30/08		80,000			$	7.25	$	9.53
07/01/08 - 09/30/08		90,000			$	6.75	$	9.62
08/01/08 - 12/31/08		400,000			$	9.75	$	11.50
04/01/09 - 09/30/09		120,000			$	7.25	$	9.80
10/01/08 - 03/31/09		180,000			$	8.00	$	10.20
10/01/08 - 03/31/09		300,000			$	8.00	$	11.20
10/01/08 - 03/31/09		300,000			$	7.75	$	9.82
01/01/09 - 03/31/09		220,000			$	10.25	$	12.25
04/01/09 - 09/30/09		420,000			$	8.00	$	10.70
04/01/09 - 09/30/09		300,000			$	7.00	$	9.73
*Oil Costless Collars*
04/01/08 - 04/30/08				2,000	$	60.00	$	74.75
04/01/08 - 06/30/08				3,000	$	65.00	$	82.60
04/01/08 - 06/30/08				9,000	$	62.00	$	81.60
04/01/08 - 10/31/08				21,000	$	65.70	$	90.00
04/01/08 - 12/31/08				18,000	$	57.50	$	75.50
04/01/08 - 12/31/08				18,000	$	85.00	$	117.00
04/01/08 - 12/31/08				18,000	$	57.50	$	76.00
06/01/08 - 10/31/08				30,000	$	90.00	$	120.00
07/01/08 - 08/31/08				4,000	$	65.00	$	80.60
11/01/08 - 12/31/08				8,000	$	87.75	$	120.00
11/01/08 - 06/30/09				24,000	$	62.00	$	81.75
01/01/09 - 03/31/09				21,000	$	86.50	$	120.00

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMBTU)

Nymex

Natural Gas Three Way Costless Collars

10/01/08 - 03/31/09

300,000

8.00

10.35

5.50

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

7. Fair Values

Effective January 1, 2008, the fair values of Brigham’s derivative financial instruments also reflect Brigham’s estimate of the default risk of the parties in accordance with Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157). The fair value of Brigham’s derivative financial instruments is determined based on counterparties’ valuation models that utilize market-corroborated inputs. The fair value of all derivative contracts is reflected on the balance sheet as detailed in the following schedule. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.


				Fair Value Measurements at March 31, 2008 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2007			(Level 1)		(Level 2)			(Level 3)
Current derivative liabilities	$	(1,812	)	$	—	$	(5,740	)	$	—
Other non-current liabilities		(256	)		—		(463	)		—
Current derivative assets		1,416			—		—			—
Other non-current assets		25			—		6			—

	$	(627	)	$	—	$	(6,197	)	$	—

8. Senior Notes

In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the “Senior Notes”). The Senior Notes were priced at 98.629% of their face value to yield 9 7/8% and are fully and unconditionally guaranteed by Brigham Exploration and its wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P. The guarantees are joint and several. Brigham Exploration does not have any independent assets or operations and the aggregate assets and revenues of the subsidiaries not guaranteeing are less than 3% of the Company’s consolidated assets and revenues.

In April 2007, Brigham issued $35 million of 9 5/8% Senior Notes due 2014. The notes were issued as an add-on to the existing $125 million of 9 5/8% Senior Notes due 2014 under the indenture dated April 20, 2006. The add-on notes were priced at 99.50% of face value to yield 9.721%. Brigham used the proceeds from the add-on offering to repay amounts outstanding under the existing senior credit agreement and for general corporate purposes. Upon completion of the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes due 2014 (collectively the “Senior Notes”).

The indenture contains various covenants, including among others restrictions on incurring other indebtedness, restrictions on liens, restrictions on the sale of assets, and restrictions on certain payments. The indenture requires Brigham to maintain a fixed charge coverage ratio (as defined) for the most recent four full fiscal quarters of at least 2.5 to 1. At March 31, 2008, Brigham was in compliance with all covenants under the indenture.

9. Asset Retirement Obligations

Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Prior to the adoption of SFAS 143 “Accounting for Asset Retirement Obligations”, Brigham assumed salvage value approximated plugging and abandonment costs. As such, estimated salvage value was not excluded from depletion and plugging and abandonment costs were not accrued for over the life of the oil and gas properties. Under the provisions of SFAS 143, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the three months ended March 31, 2008 and 2007 (in thousands):


	Three Months Ended
	March 31,
	2008			2007

Beginning asset retirement obligations	$	5,047		$	5,002
Liabilities incurred for new wells placed on production		61			208
Liabilities settled		(19	)		10
Accretion of discount on asset retirement obligations		91			117

	$	5,180		$	5,337

10. Stock Based Compensation

Brigham adopted SFAS 123R using the modified prospective method. Under this transition method, compensation cost recognized includes the cost for all stock based compensation granted prior to, but not yet vested, as of January 1, 2006. This cost was based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. The cost for all stock based awards granted subsequent to January 1, 2006, was based on the grant date fair value that was estimated in accordance with the provisions of SFAS 123R. The maximum contractual life of stock based awards is seven years. Additionally, during 2007, stock compensation expense related to unvested stock based awards was adjusted to recognize actual forfeitures during the year. Brigham has assumed a 4% weighted average forfeiture rate for stock based awards to be used prospectively at September 30, 2007. At adoption of SFAS 123R, Brigham elected to amortize newly issued and existing granted awards on a straight-line basis over the requisite service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods. Unearned stock compensation recorded under APB 25 of $2.3 million was eliminated and additional paid-in capital was reduced by a like amount on the consolidated balance sheet and consolidated statements of stockholders’ equity, in accordance with SFAS 123R. Results for prior periods have not been restated.

The estimated fair value of the options granted during the three months ended March 31, 2008 was calculated using a Black-Scholes Merton option pricing model (Black-Scholes). There were no options granted during the first quarter of 2007. The following table summarizes the weighted average assumptions used in the Black-Scholes model for options granted during the three months ended March 31, 2008:


	2008
Risk-free interest rate		2.7	%
Expected life (in years)		5.0
Expected volatility		44	%
Expected dividend yield		—

Weighted average fair value per share of stock compensation	$	3.26

The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free rate of interest for periods within the contractual life of the option is based on a zero-coupon U.S. government instrument over the contractual term of the equity instrument. Expected volatility is based on the historical volatility of Brigham’s stock for an equal period of the expected term. The expected life is determined using the contractual life and vesting term in accordance with the guidance in Staff Accounting Bulletin No. 107 for using the “simplified” method for “plain vanilla” options.

In November 2005, the FASB issued FASB Staff Position No. FAS 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” Brigham elected to adopt the alternative transition method provided in the FASB Staff Position for calculating the tax effects of stock based compensation pursuant to SFAS 123R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (APIC pool) related to the tax effects of employee stock based compensation, and to determine the subsequent impact on the APIC pool and Consolidated Statements of Cash Flows of the tax effects of employee stock based compensation awards that are outstanding upon adoption of SFAS 123R.

Prior to the adoption of SFAS 123R, Brigham presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Brigham did not have any excess tax benefits during the three months ended March 31, 2008 and 2007.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes the components of stock based compensation included in general and administrative expense (in thousands):


	Three Months Ended
	March 31,
	2008			2007

Pre-tax stock based compensation expense	$	763		$	770
Capitalized stock based compensation		(349	)		(349	)
Tax benefit		(145	)		(147	)

Stock based compensation expense, net	$	269		$	274

Stock Based Plan Descriptions and Share Information

Brigham provides an incentive plan for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to provide incentive and reward key employees whose performance may have a significant impact on the success of Brigham. It is Brigham’s policy to use unissued shares of stock when stock options are exercised. The number of shares available under the plan is equal to the lesser of 5,915,414 or 15% of the total number of shares of common stock outstanding. At March 31, 2008, approximately 601,827 shares remain available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one stock option grant, options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham’s common stock on the date of grant, vest over five years and have a contractual life of seven years.

Brigham also maintains a director stock option plan under which stock options are awarded to non-employee directors. Options granted under this plan have an exercise price equal to the fair market value of Brigham common stock on the date of grant and vest over five years. Stockholders have authorized the issuance of 1,000,000 shares to non-employee directors and approximately 592,300 remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for the three months ended March 31:


	2008					2007
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Options outstanding at the beginning of the year		3,046,166		$	7.14		3,243,566		$	7.08
Granted		5,000		$	7.73		—		$	—
Forfeited or cancelled		(37,800	)	$	7.91		(86,600	)	$	8.14
Exercised		(33,500	)	$	4.00		(5,000	)	$	4.59

Options outstanding at the end of the quarter		2,979,866		$	7.17		3,151,966		$	7.05

Options exercisable at the end of the quarter		1,837,566		$	6.67		1,468,266		$	6.20

As noted on the previous page, there were no options granted during the three months ended March 31, 2007. The weighted-average grant-date fair value of share options granted during the three months ended March 31, 2008 was $3.26. The total intrinsic value of options exercised during the three months ended March 31, 2008 and 2007 was $107,900 and $6,112, respectively.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes information about stock options outstanding and exercisable at March 31, 2008:


	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average	Weighted-
	March 31,		Remaining	Average		March 31,		Remaining	Average
Exercise Price	2008		Contractual Life	Exercise Price		2008		Contractual Life	Exercise Price
$3.05 to $3.41		202,866	0.6 years	$	3.35		202,866	0.6 years	$	3.35
3.66 to 5.08		359,900	1.4 years	$	4.31		356,400	1.4 years	$	4.30
6.10 to 6.73		1,239,200	3.6 years	$	6.50		709,000	2.9 years	$	6.62
7.22 to 8.84		823,900	4.0 years	$	8.47		415,300	3.5 years	$	8.66
8.93 to 12.31		354,000	4.5 years	$	11.60		154,000	4.4 years	$	11.40

$3.05 to $12.31		2,979,866	3.4 years	$	7.17		1,837,566	2.6 years	$	6.67

The aggregate intrinsic value of options outstanding and exercisable at March 31, 2008 and March 31, 2007 was $1.2 million and $1.4 million, respectively. The aggregate intrinsic value represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the quarter and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on March 31, 2008. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of March 31, 2008 there was approximately $3.6 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.9 years.

Restricted Stock

During the three months ended March 31, 2008 and 2007, Brigham issued 90,000 and 75,000, respectively, restricted shares of common stock as compensation to officers and employees of Brigham. The restricted shares vest over five years or cliff-vest at the end of five years. As of March 31, 2008, there was approximately $3.6 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.8 years. Brigham has assumed a 6% weighted average forfeiture rate for restricted stock. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods.

The following table reflects the outstanding restricted stock awards and activity related thereto for the three months ended March 31:


	2008					2007
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Restricted shares outstanding at the beginning of the year		653,623		$	7.16		391,367		$	8.60
Shares granted		90,000		$	7.41		75,000		$	7.43
Lapse of restrictions		(50,000	)	$	5.23		(55,000	)	$	5.23
Forfeitures		(15,204	)	$	6.34		(25,160	)	$	8.09

Shares outstanding at the end of the quarter		678,419		$	7.35		386,207		$	8.89

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. Comprehensive Income

For the periods indicated, comprehensive income (loss) consisted of the following (in thousands):


	Three Months Ended
	March 31,
	2008			2007

Net income	$	1,527		$	1,873
Unrealized gains (losses) on cash flow hedges		—			—
Net gains (losses) included in net income		(177	)		(1,094	)
Tax benefits (provisions) related to cash flow hedges		62			383
Reclassification adjustments for settled hedging positions		—			—

Other comprehensive income, net	$	1,412		$	1,162

12. New Accounting Pronouncements

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for the fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on Brigham’s financial statements.

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157), which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 was required on January 1, 2008 for financial assets and liabilities, as well as other assets and liabilities that are carried at fair value on a recurring basis in financial statements. FASB Financial Staff Position No. FAS 157-2 deferred implementation for other non-financial assets and liabilities for one year. Examples of non-financial assets and liabilities are asset retirement obligations and non-financial assets and liabilities initially measured at fair value in a business combination. The adoption of SFAS 157 did not have a material impact on the financial statements.

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Brigham is currently evaluating the impact on the financial statements.

In February 2007, the Financial Accounting Standard Board issued Statement No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. Companies are required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. It does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. Brigham has not elected the fair value option for any eligible items.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements – an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. Brigham is currently evaluating the impact on the financial statements.

In March 2008, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 161 “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133” (SFAS 161), that requires new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data; financial statement presentation of fair values on a gross basis, including those that currently qualify for netting under FASB Interpretation No. 39; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following updates information as to our financial condition provided in our 2007 Annual Report on Form 10–K, and analyzes the changes in the results of operations between the three month periods ended March 31, 2008 and March 31, 2007. For definitions of commonly used oil and gas terms as used in this Form 10–Q, please refer to the “Glossary of Oil and Gas Terms” provided in our 2007 Annual Report on Form 10–K. Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes hereto.

General Overview

We are an independent exploration, development and production company that utilizes advanced 3–D seismic imaging, drilling and completion technologies to systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our exploration and development activities in provinces where we believe technology and the knowledge of our technical staff can be effectively used to maximize our return on invested capital by reducing drilling risk and enhancing our ability to grow reserves and production volumes. Our exploration and development activities are currently concentrated in four provinces: the onshore Gulf Coast, the Anadarko Basin, the Rocky Mountains and West Texas.

We regularly evaluate opportunities to expand our activities to other areas that may offer attractive exploration and development potential, with a particular interest in those areas with plays that complement our current exploration, development and production activities. As a result of this strategy, from late 2005 through 2008, we have been accumulating significant acreage positions in the Williston and Powder River Basins. Operations within these two basins are included in and constitute the bulk of our activity in our Rocky Mountains province. We have also entered into four joint ventures in Southern Louisiana over the last two years. We consider these joint ventures to be logical extensions of our prospect generating activities along the onshore Texas Gulf Coast.

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

•

Internally Generate Inventory of High Quality Exploratory Prospects;

•

Leverage Our Operational Expertise;

•

Evaluate and Selectively Pursue New Potential Plays;

•

Capitalize on Exploration Successes Through Development of Our Field Discoveries;

•

Continue to Actively Drill Our Multi-Year Prospect Inventory; and

•

Enhance Returns Through Operational Control.

Overview of First Quarter 2008 Financial Results

First quarter 2008 well head oil and natural gas prices increased 74% and 21%, respectively, from the comparable quarter last year. Excluding realized and unrealized derivative hedging results, the average sales price that we received for oil in the first quarter 2008 was $95.50 per barrel, which represents a $40.75 per barrel increase from that in the first quarter 2007. Excluding realized and unrealized derivative hedging results, the average sales price that we received for natural gas in the first quarter 2008 was $8.83 per Mcf, which represents a $1.51 per Mcf increase from that in the first quarter 2007.

Our first quarter 2008 production averaged 32.2 MMcfe per day, down 22% from the first quarter 2007 and down 9% sequentially from the fourth quarter 2007. This decrease compared to the prior year quarter was primarily attributable to: the temporary halt in our Vicksburg drilling program in August 2007 in order update our structural interpretation of the three fields, which are essentially one highly faulted structural feature; the decline experienced in our Southern Louisiana Bayou Postillion project; the sale of our Anadarko Basin Granite Wash assets, which was effective September 1, 2007; and the allocation of a larger percentage of our fourth quarter 2007 drilling capital away from our Gulf Coast prospects to the Bakken, which given their longer reserve lives generally does not provide the same initial production as our Gulf Coast prospects.

Our first quarter 2008 oil and natural gas sales, including hedge settlements but excluding unrealized hedging gains and losses, were up $0.5 million, or 2%, compared to the first quarter 2007. Improved commodity prices increased revenue by $8.1 million while decreased volumes and hedge settlements reduced revenue by $6.0 million and $1.5 million, respectively.

First quarter 2008 operating income decreased $0.4 million, or 7%, from the first quarter last year. This decrease was attributable to an increase in unrealized derivative hedging losses and higher lease operating expense, production taxes and general and administrative expense. These higher expenses were partially offset by lower depletion expense, which was attributable to our lower production volumes.

As of March 31, 2008, we had $6.2 million in cash and $578.9 million in total assets. Our net debt to book capitalization ratio was 40%, which is calculated as debt plus preferred stock divided by book equity plus debt plus preferred stock.

Overview of First Quarter 2008 Operational Results

Rocky Mountain Province

Williston Basin

On January 16, 2008, we reported that the Bergstrom Family Trust 26 #1H produced at an early peak rate of approximately 202 barrels of oil equivalent per day up 4.5” casing. After installing 2 7/8” production tubing and placing the well on rod pump, we reported on March 3, 2008 that the well was producing approximately 119 barrels of oil equivalent per day.

Approximately 25 miles to the northwest of the Bergstrom Family Trust 26 #1H, we successfully drilled and completed our second operated Mountrail County, North Dakota well, the Hynek 2 #1H. The Hynek 2 #1H produced at an early peak 24 hour rate of approximately 585 barrels of oil equivalent per day up 7” casing. After installing 2 7/8” production tubing and placing the well on rod pump, we reported on March 3, 2008 that the well was producing approximately 142 barrels of oil equivalent per day.

We successfully drilled and completed our third Mountrail County, North Dakota operated well, the Bakke 23 #1H, which produced at an early peak 24 hour rate of approximately 380 barrels of oil equivalent per day up 7” casing. After installing 2 7/8” production tubing and placing the well on rod pump, we reported on March 3, 2008 that the well was producing approximately 310 barrels of oil equivalent per day.

At year-end, we had commenced drilling our fourth operated Mountrail County, North Dakota horizontal Bakken well, the Hallingstad 27 #1H. The Hallingstad 27 #1H is located approximately one mile west of the Bergstrom Family Trust 26 #1H well. On March 3, 2008, we reported that after fracture stimulation the well was producing at an early rate of approximately 450 barrels of oil equivalent per day up 4.5” casing.

After completing the Hallingstad 27 #1H, we moved the rig to a location proximal to the Hynek 2 #1H to drill the 100% working interest Manitou State 36 #1H. The well is currently completing.

During late 2007, we reentered the Mrachek 15-22, which is a horizontal Bakken well that we drilled during late 2006 west of the Nesson Anticline in McKenzie County, North Dakota . The Mrachek 15-22 was sidetracked and is being completed using swell packers, which has proven effective east of the Nesson Anticline. The well has been remediated after experiencing a casing leak and we anticipate releasing results in late May or June.

In December 2007, we successfully drilled and completed the Richardson 25 #1, a Red River discovery, which commenced production at an initial production rate of approximately 220 barrels of oil equivalent per day. As of March 3, 2008, we reported that the well was producing approximately 279 barrels of oil equivalent per day. We spud our second Red River test, the Richardson 30 #1, in late April.

Powder River Basin

In November 2007, we spud the Krejci Federal #1-32H well, which is proximate to our first well in the basin, the Krejci Federal 29 #3H. The Krejci Federal #1-32H is being drilled and completed using the same technology that has contributed to success in the Bakken east of the Nesson Anticline, which includes the use of swell packers. As of March 3, 2008, we reported that the well had been drilled and swell packers had been installed. After being fracture stimulated, the well is currently being tested.

Onshore Gulf Coast Province

Vicksburg Trend

Subsequent to the Sullivan C-36, we temporarily halted drilling in the Vicksburg in order update our structural interpretation of the field. In February 2008, we resumed our Vicksburg drilling program and spud the Floyd Field Sullivan C-38, a development well, which is an attempt to extend the prolific Floyd fault block to the North. The well is currently producting 3.2 MMcfe per day from the Vicksburg 8, 9 and 10 sands.

We have also recently drilled the Sullivan C-39 to total depth and are currently drilling the Sullivan F-35. The Sullivan C-39 is in our Home Run Field and targets the 9800’, Vicksburg 6, 7 and 8 sands. The Sullivan C-39 is completing and encountered approximately 137 feet of apparent pay. The Sullivan F-35 is in our Triple Crowne Field and targets the Brigham, 9800’, Loma Blanca and Dawson sands. The well is currently drilling at 11,200 feet.

Southern Louisiana Trend

In December 2007, we entered into a joint venture to operate the drilling of at least six prospects over the next 18 months with a 50% working interest. Five of these prospects are planned for 2008 and will target 3-D delineated, primarily amplitude related prospects at depths of 9,000 to 10,500 feet in Plaquemines and Saint Bernard Parishes. It is currently anticipated that we will commence drilling the first well under this joint venture in May 2008.

First Quarter 2008 Results

Comparison of the three-month periods ended March 31, 2008 and 2007.

Production volumes


	Three Months Ended March 31,
	2008		% Change			2007
Oil (MBbls)		117		(4	%)		122
Natural gas (MMcf)		2,193		(26	%)		2,982
Total (MMcfe)(1)		2,894		(22	%)		3,712
Average daily production (MMcfe/d) (2)		32.2					41.2


(1)		MMcfe is defined as one million cubic feet equivalent of natural gas, determined using the ratio of six MMcf of natural gas to one MBbl of crude oil, condensate or natural gas liquids.

(2)		Average daily production is calculated using 30 days per calendar month.

Natural gas represented 76% of our first quarter 2008 production volumes, compared to 80% in the first quarter of last year.

Revenues, Commodity Prices and Hedging

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


	Three Months Ended March 31,
	2008			% Change			2007
	(In thousands)

Oil revenue:
Oil revenue	$	11,157			67	%	$	6,663
Oil derivative settlement gains (losses)		(586	)	NM				113

Oil revenue including derivative settlements	$	10,571			56	%	$	6,776
Oil derivative unrealized gains (losses)		(238	)		(33	%)		(353	)

Oil revenue including derivative settlements and unrealized gains (losses)	$	10,333			61	%	$	6,423
Natural gas revenue:
Natural gas revenue	$	19,353			(11	%)	$	21,823
Natural gas derivative settlement gains (losses)		524			(60	%)		1,311

Natural gas revenue including derivative settlements	$	19,877			(14	%)	$	23,134
Natural gas derivative unrealized gains (losses)		(5,156	)		13	%		(4,563	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	14,721			(21	%)	$	18,571
Oil and natural gas revenue:
Oil and natural gas revenue	$	30,510			7	%	$	28,486
Oil and natural gas derivative settlement gains (losses)		(62	)	NM				1,424

Oil and natural gas revenue including derivative settlements		30,448			2	%		29,910
Oil and natural gas derivative unrealized gains (losses)		(5,394	)		10	%		(4,916	)

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		25,054			0	%		24,994
Other revenue		17			(37	%)		27

Total revenue	$	25,071			0	%	$	25,021

Average oil prices:
Oil price (per Bbl)	$	95.50			74	%	$	54.75
Oil price including derivative settlement gains (losses) (per Bbl)		90.48			63	%		55.68
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)		88.45			68	%		52.78
Average natural gas prices:
Natural gas price (per Mcf)	$	8.83			21	%	$	7.32
Natural gas price including derivative settlement gains (losses) (per Mcf)		9.07			17	%		7.76
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	6.71			8	%	$	6.23
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	10.54			37	%	$	7.67
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		10.52			31	%		8.05
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	8.66			29	%	$	6.73


	For the three
	month periods
	ended March 31,
	2008 and 2007
	(In thousands)

Change in revenue from the sale of oil:
Price variance impact	$	4,761
Volume variance impact		(267	)
Cash settlement of derivative hedging contracts		(699	)
Unrealized gains (losses) due to derivative hedging contracts		115

Total change	$	3,910


Change in revenue from the sale of natural gas:
Price variance impact	$	3,303
Volume variance impact		(5,773	)
Cash settlement of derivative hedging contracts		(787	)
Unrealized gains (losses) due to derivative hedging contracts		(593	)

Total change	$	(3,850	)


Change in revenue from the sale of oil and natural gas:
Price variance impact	$	8,064
Volume variance impact		(6,040	)
Cash settlement of derivative hedging contracts		(1,486	)
Unrealized gains (losses) due to derivative hedging contracts		(478	)

Total change	$	60

First quarter 2008 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses), increased slightly, when compared to the first quarter 2007. The change in revenues was attributable to the following:

•

a 37% increase in the sales price we received for our oil and natural gas resulted in a $8.1 million increase in revenues;

•

a 22% decrease in production volumes for the quarter resulted in a $6.0 million decrease in oil and natural gas revenues;

•

a $0.1 million loss from the settlement of derivative contracts in the first quarter 2008 versus a $1.4 million gain from the settlement of derivative contracts in first quarter 2007 decreased revenues by $1.5 million; and

•

a $5.4 million unrealized derivative loss in first quarter 2008 versus a $4.9 million unrealized derivative loss in first quarter 2007 decreased revenues by $0.5 million.

Hedging. We utilize collars and three way costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans.

The following table details derivative contracts that settled during first quarter 2008 and 2007 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon settlement.


	Three months ended March 31,
	2008			% Change			2007

*Oil collars*
Volumes (Bbls)		45,500			(40	%)		76,000
Average floor price ($ per Bbl)	$	61.68			11	%	$	55.76
Average ceiling price ($ per Bbl)	$	85.59			8	%	$	79.05
Gain (loss) upon settlement ($ in thousands)	$	(586	)	NM			$	113

*Natural gas collars*
Volumes (MMbtu)		1,520,000			(16	%)		1,805,000
Average floor price ($ per MMbtu)	$	7.87			4	%	$	7.58
Average ceiling price ($ per MMbtu)	$	12.44			(23	%)	$	16.15
Gain (loss) upon settlement ($ in thousands)	$	524			(60	%)	$	1,311

Other revenue. Other revenue relates to fees that we charge other parties who use our gas gathering systems that we own to move their production from the wellhead to first party gas pipeline systems.

Operating costs and expenses

Production costs. We believe that per unit of production measures is the best way to evaluate our production costs. We use this information to internally evaluate our performance, as well as to evaluate our performance relative to our peers.


	Unit-of-Production								Amount
	(Per Mcfe)								(In thousands)
	Three months ended March 31,								Three months ended March 31,
	2008		% Change			2007			2008		% Change			2007

Production costs:
Operating & maintenance	$	0.63		2	%	$	0.62		$	1,822		(21	%)	$	2,304
Expensed workovers		0.28	NM				(0.04	)		814	NM				(142	)
Ad valorem taxes		0.12		9	%		0.11			350		(14	%)		407

Lease operating expenses	$	1.03		49	%	$	0.69		$	2,986		16	%	$	2,569

Production taxes		0.44		2100	%		0.02			1,283		1707	%		71

Production costs	$	1.47		107	%	$	0.71		$	4,269		62	%	$	2,640

First quarter 2008 per unit of production costs increased $0.76 per Mcfe, or 107%, when compared to the first quarter last year because of the following:

•

production taxes increased $0.42 per Mcfe, due to a $1.3 million decline in production tax abatement approvals on our Vicksburg and Mills Ranch wells from the first quarter 2007;

•

expensed workovers increased $0.32 per Mcfe due to the unanticipated workover of two of our wells;

•

ad valorem taxes increased $0.01 per Mcfe, or 9%, due to a decrease in production volumes; and

•

O&M expense increased $0.01 per Mcfe, or 2%.

General and administrative expenses. We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on capital projects and a portion of our associated technical organization costs such as supervision, telephone and postage.


	Three months ended March 31,
	2008			% Change			2007
	(In thousands, except per unit measurements)

General and administrative costs	$	4,956			17	%	$	4,229
Capitalized general and administrative costs		(2,363	)		15	%		(2,051	)

General and administrative expenses	$	2,593			19	%	$	2,178


General and administrative expense ($ per Mcfe)	$	0.90			53	%	$	0.59

Our general and administrative costs prior to capitalization increased primarily because of $0.5 million in higher employee compensation expense.

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


	Three months ended March 31,
	2008		% Change			2007
	(In thousands, except per unit measurements)

Depletion of oil and natural gas properties	$	12,443		(11	%)	$	13,959
Depletion of oil and natural gas properties ($ per Mcfe)	$	4.30		14	%	$	3.76

Our depletion expense for the first quarter 2008 was $1.5 million lower than the first quarter 2007. Our reduced production volumes reduced depletion expense by $3.1 million. This decrease was offset by a $1.6 million increase in our depletion rate.

Net interest expense. Interest on our Senior Notes, our senior credit facility and dividends that we pay on our Series A mandatorily redeemable preferred stock represents the largest portion of our interest expense. Other costs include commitment fees that we pay on the unused portion of the borrowing base for our senior credit agreement. In addition, we typically pay loan and debt issuance costs when we enter into new lending agreements or amend existing agreements. When incurred, these costs are recorded as non-current assets and are then amortized over the life of the loan. We capitalize interest costs on borrowings associated with our major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.


	Three months ended March 31,
	2008			% Change			2007
	(In thousands)
Interest on Senior Notes	$	3,850			28	%	$	3,008
Interest on senior credit facility		153			(80	%)		763
Commitment fees		65			35	%		48
Dividend on mandatorily redeemable preferred stock		151			1	%		149
Amortization of deferred loan and debt issuance cost		246			20	%		205
Other general interest expense		0			(100	%)		1
Capitalized interest expense		(1,046	)		38	%		(757	)

Net interest expense	$	3,419			0	%	$	3,417


Weighted average debt outstanding	$	182,821			6	%	$	171,733
Average interest rate on outstanding indebtedness (a)		9.4	%					9.4	%


a)		Calculated as the sum of the interest expense on our outstanding indebtedness, commitment fees that we pay on our unused borrowing capacity and the dividend on our mandatorily redeemable preferred stock divided by our weighted average debt and preferred stock outstanding for the period.

First quarter 2008 interest expense remained relatively consistent with that in the first quarter 2007.

Other income (expense).

Other income (expense) included:


	Three months ended March 31,
	2008		% Change			2007
	(In thousands)
Other income (expense):
Non-cash gain (loss)	$	1		(98	%)	$	40
Income (expense)		306		104	%		150

Total other income (expense)	$	307		62	%	$	190

Other income increased in the first quarter 2008 versus that in the comparable period last year.

Income taxes. We recorded deferred federal income tax expense of $0.9 million in the first quarter of this year, compared to deferred federal income tax expense of $1.2 million in the first quarter last year. The decrease was primarily due to lower first quarter 2008 income before income taxes. We also recorded deferred state income tax expense of $0.1 million in the first quarter 2008 compared to a deferred state tax benefit of $0.2 million in the first quarter last year. The increase was primarily attributable to increased activity in our resource plays. For the first three months of 2008, our effective tax rate was 38.7%, which was higher than the statutory rate of 35% primarily due to state income taxes and non-deductibility of preferred stock dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.

Capital Expenditures

The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital expenditure program includes the following:

	•		cost of acquiring and maintaining our lease acreage position and our seismic resources;

	•		cost of drilling and completing new oil and natural gas wells;

	•		cost of installing new production infrastructure;

	•		cost of maintaining, repairing and enhancing existing oil and natural gas wells;

	•		cost related to plugging and abandoning unproductive or uneconomic wells; and

	•		indirect costs related to our exploration activities, including payroll and other expenses attributable to our exploration professional staff.

The table below summarizes our 2008 oil and gas capital expenditure budget, the amount spent through March 31, 2008 and the amount of our 2008 oil and gas capital expenditure budget that remains to be spent.


			Amount
	2008		Spent Through		Amount
	Budget		March 31, 2008		Remaining (a)
	(In millions)
Drilling	$	102.6	$	31.2	$	71.4
Net land and seismic		18.3		10.8		7.5
Capitalized costs (b)		12.8		3.4		9.4
Asset retirement obligation		0.7		0.1		0.6

Total oil and gas capital expenditures (c)	$	134.4	$	45.5	$	88.9


(a)		Calculated based on the 2008 capital expenditure budget announced on February 6, 2008 less amount spent through March 31, 2008.

(b)		Capitalized costs include capitalized interest expense, general and administrative expense and stock compensation expense.

(c)		Excludes other property capital expenditures.

Determination of Capital Expenditure Budget

The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We start each year with a budget and reevaluate this budget monthly. Furthermore, as we move through the year, we continue to add to our inventory of drilling prospects. The outcome of our monthly analysis results in a reprioritization of our exploration and development well drilling schedule to ensure that we are optimizing our capital expenditure plan.

This value creation measure and the final determination with respect to our 2008 budgeted expenditures will depend on a number of factors, including:

	•		changes in commodity prices;

	•		variances in forecasted production and the resulting production of our newly drilled wells;

	•		variances in our production levels from our existing oil and gas properties;

	•		variances in a prospect’s risked reserve size;

	•		variances in drilling and completion costs, service costs and the availability of drilling equipment;

	•		variances in the availability and timing of drilling and completion services;

	•		economic and industry conditions at the time of drilling; and

	•		the availability of more economically attractive prospects.

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

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2008, we intend to fund our capital expenditure program and contractual commitments with cash flows from operations, borrowings under our senior credit agreement, reimbursements of prior land and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties or alternative financing sources.

9 5/8% Senior Notes Due 2014

We have $160 million of Senior Notes outstanding, $125 million of which was issued in April 2006 and $35 million of which was issued in April 2007. The notes are fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. We are obligated to pay the $160 million of Senior Notes in cash upon maturity in May 2014. Beginning November 2006, we paid 9 5/8% interest on the $125 million outstanding and beginning in May 2007, we paid 9 5/8% interest on the $160 million outstanding. Future interest payments are due semi-annually in arrears in November and May of each year.

The Senior Notes are our unsecured senior obligations, and:

	•		rank equally in right of payment with all our existing and future senior indebtedness;

	•		rank senior to all of our future subordinated indebtedness; and

	•		are effectively junior in right of payment to all of our and the Guarantors’ existing and future secured indebtedness, including debt of our senior credit agreement.

The Indenture governing the Senior Notes contains customary events of default. Upon the occurrence of certain events of default, the trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

Additionally, the Indenture governing the Senior Notes contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the Senior Notes as of March 31, 2008.

Senior Credit Agreement

Our senior credit agreement provides for revolving credit borrowings up to $200 million and matures June 2010. In April 2007, in conjunction with the issuance of our Senior Notes add-on, the borrowing base was reset to $101 million. As a result of our September 2007 Anadarko Basin Granite Wash asset sale, we conducted our semi-annual redetermination at the time of the asset sale and the borrowing base was reaffirmed at $101 million.

As of March 31, 2008, we had $19.0 million outstanding and $82.0 million of unused committed borrowing capacity available under our senior credit agreement. As of April 30, 2008, we had $32.1 million of borrowings outstanding under the senior credit agreement. We strive to manage the amounts we borrow under our senior credit agreement in order to maintain excess borrowing capacity.

Since the borrowing base for our senior credit agreement is re-determined at least semi-annually, the amount of borrowing capacity available to us under our senior credit agreement could fluctuate. While we do not expect the amount that we have borrowed under our senior credit agreement to exceed the borrowing base, in the event that the borrowing base is adjusted below the amount that we have borrowed, our access to further borrowings will be reduced, and we may not have the resources necessary to carry out our planned spending for exploration and development activities. The next semi-annual borrowing base redetermination is anticipated to be concluded in May 2008.

Borrowings under our senior credit agreement bear interest, at our election, at a base rate or a Eurodollar rate, plus in each case an applicable margin. These margins are reset quarterly and are subject to increase if the total amount borrowed under our senior credit agreement reaches certain percentages of the available borrowing base, as shown below:


Percent of	Eurodollar
Borrowing Base	Rate		Base Rate
Utilized	Advances		Advances(1)
<50%		1.250%		0.000%
50% and < 75%		1.500%		0.000%
75% and < 90%		1.750%		0.250%
90%		2.000%		0.500%


(1)		Base rate is defined as for any day a fluctuating rate per annum equal to the higher of: (a) the Federal Funds Rate plus 1/2 of 1% or (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate.” The “prime rate” is a rate set by Bank of America based upon various factors including Bank of America’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change.

We are also required to pay a quarterly commitment fee on the average daily unused portion of the borrowing base. The commitment fees we pay are reset quarterly and are subject to change as the percentage of the available borrowing base that we utilize changes. The margins and commitment fees that we pay are as follows:


Percent of
Borrowing Base	Quarterly
Utilized	Commitment Fee
<50%		0.250%
50% and < 75%		0.250%
75% and < 90%		0.375%
90%		0.375%

Our senior credit agreement also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at March 31, 2008 and interest coverage ratio for the twelve-month period ended March 31, 2008 were 2.1 to 1 and 7.1 to 1, respectively. As of March 31, 2008, we were in compliance with all covenant requirements in connection with our senior credit agreement.

Access to the committed and undrawn portion of our borrowing base could be limited based on the covenants that are part of the indenture governing the Senior Notes. The future amounts of debt that we borrow under our senior credit agreement will depend primarily on net cash provided by operating activities, proceeds from other financing activities, reimbursements of prior land and seismic costs by third party participants in our projects and proceeds generated from asset dispositions.

Mandatorily Redeemable Preferred Stock

As of March 31, 2008, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC. We are required to satisfy all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

Access to Capital Markets

We currently have two effective universal shelf registration statements covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. We have $73.4 million remaining available under this shelf registration statement.

Our other universal shelf registration statement has not been utilized to date and has $300 million available.

However, our ability to raise additional capital using our shelf registration statements may be limited due to overall conditions of the stock market or the oil and natural gas industry.

Off Balance Sheet Arrangements

We currently have operating leases, which are considered off balance sheet arrangements. We do not currently have any other off balance sheet arrangements or other such unrecorded obligations, and we have not guaranteed the debt of any other party.

Analysis of Changes In Cash and Cash Equivalents

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


	Three months ended March 31,
	2008			%Change			2007
	(In thousands)

Net income	$	1,527			(18	%)	$	1,873
Non-cash items		19,680			(5	%)		20,785
Changes in working capital and other items		7,128		NM				(7,074	)

Cash flows provided by operating activities	$	28,335			82	%	$	15,584
Cash flows used by investing activities		(45,034	)		(7	%)		(48,222	)
Cash flows provided by financing activities		9,002			(75	%)		35,489

Net increase in cash and cash equivalents	$	(7,697	)	NM			$	2,851

Analysis of net cash provided by operating activities

Net cash provided by operating activities is a function of the amount of oil and natural gas that we produce, the prices that we receive from the sale of oil and natural gas, which are inherently volatile and unpredictable, gains or losses related to the settlement of our derivative contracts, operating costs and our cost of capital. Our asset base, as with other extractive industries, is a depleting one in which each barrel of oil or Mcf of natural gas produced must be replaced or our ability to generate cash flow, and thus sustain our exploration and development activities, will diminish.

For the first three months of 2008, cash flows provided by operating activities increased by 82% to $28.3 million from the same period last year. The increase in operating cash flow is attributable to the change in working capital from period to period.

Analysis of changes in cash flows used in investing activities


	Three months ended March 31,
	2008			%Change			2007
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	31,200			9	%	$	28,677
Land and seismic		10,833			269	%		2,936
Capitalized cost		3,410			21	%		2,808
Capitalized asset retirement obligation		61			(71	%)		207

Total	$	45,504			31	%	$	34,628


Reconciling Items:
Change in accrued drilling costs	$	(609	)	NM			$	13,533
Other		139			128	%		61

Total Reconciling Items		(470	)	NM				13,594

Net cash used in investing activities	$	45,034			(7	%)	$	48,222

Net cash used by investing activities in the first quarter 2008 decreased by $3.2 million, or 7%, over the same period in 2007. The following were the reasons for the change:

	•		the change in accrued drilling costs reduced cash used in investing activities by $14.1 million;

	•		drilling expenditures increased by $2.5 million;

	•		land and seismic expenditures increased by $7.9 million; and

	•		capitalized costs increased by $0.6 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first quarter 2008 was 75% lower than the first quarter 2007. During the first three months of 2008, we borrowed $9.0 million under our senior credit agreement compared to $35.6 million of borrowings during the first quarter 2007.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the three months ended March 31, 2008 and 2007.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
*2008 common stock transactions:*
Exercise of employee stock options		33,500	$	134

*2007 common stock transactions:*
Exercise of employee stock options		5,000	$	23

Other Matters

Derivative Instruments

Our results of operations and operating cash flow are impacted by changes in market prices for oil and natural gas. We believe the use of derivative instruments, although not free of risk, allows us to reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our derivative contracts generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivative contracts will vary from time to time.

Effects of Inflation and Changes in Prices

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

Environmental and Other Regulatory Matters

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

New Accounting Pronouncements

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for our fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on our financial statements.

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. We are currently evaluating the impact on the financial statements.

In February 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities— Including an amendment of FASB Statement No. 115.” The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. Companies are required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. It does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. We have not elected the fair value option for any eligible items.

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements — an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. We are currently evaluating the impact on the financial statements.

In March 2008, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 161 “Disclosures about Derivative Instruments and Hedging Activities — An Amendment of FASB Statement No. 133” (SFAS 161), that requires new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data; financial statement presentation of fair values on a gross basis, including those that currently qualify for netting under FASB Interpretation No. 39; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008.

Forward Looking Information

We or our representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and natural gas production, the number of wells we anticipate drilling during 2008 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in our Form 10-K report for the year ended December 31, 2007 including, but not limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

We use derivative instruments to manage exposure to commodity prices and interest rate risks. Our objectives for holding derivatives are to achieve a consistent level of cash flow to support a portion of our planned capital spending. Our use of derivative instruments for hedging activities could materially affect our results of operations in particular quarterly or annual periods since such instruments can limit our ability to benefit from favorable price movements. We do not enter into derivative instruments for trading purposes.

Derivative Instruments and Hedging Activities

Our primary commodity market risk exposure is to changes in the prices that we receive for our oil and natural gas production. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future. As such, we employ established policies and procedures to manage our exposure to fluctuations in the sales prices we receive for our oil and natural gas production via using derivative instruments.

While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our derivative contracts generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivative contracts will vary from time to time.

During 2007 and 2008 through March 31, we were party to natural gas costless collars, natural gas three-way costless collars and oil costless collars.

We use costless collars to establish floor (purchased put option) and ceiling prices (written call option) on our anticipated future oil and natural gas production. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is above the ceiling price (written call option), we pay our counterparty. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us.

A three-way costless collar consists of a costless collar (purchased put option and written call option) plus a put (written put) sold by us with a price below the floor price (purchased put option) of the costless collar. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. The written put requires us to make a payment to our counterparty if the settlement price for a period is below the written put price. Combining the costless collar (purchased put option and written call option) with the written put results in us being entitled to a net payment equal to the difference between the floor price (purchased put option) of the costless collar and the written put price if the settlement price is equal to or less than the written put price. If the settlement price is greater than the written put price, the result is the same as it would have been with a costless collar. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while offsetting the associated cost with the sale of the written put.

Natural gas derivative transactions are generally settled based upon the average reported settlement prices on the NYMEX for the last three trading days of a particular contract month. Oil derivative transactions are generally settled based on the average reported settlement prices on the NYMEX for each trading day of a particular calendar month.

The following tables reflect our open natural gas and oil derivative contracts as of March 31, 2008, the associated volumes and the corresponding weighted average NYMEX floor and cap price. As of May 6, 2008 we did not enter into any commodity derivative contracts subsequent to March 31, 2008.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
04/01/08 - 04/30/08		60,000	$	7.25	$	9.00
04/01/08 - 05/31/08		140,000	$	7.00	$	8.35
04/01/08 - 05/31/08		60,000	$	7.00	$	8.70
04/01/08 - 06/30/08		120,000	$	7.00	$	9.00
04/01/08 - 07/31/08		120,000	$	7.00	$	9.25
04/01/08 - 07/31/08		200,000	$	7.50	$	10.20
04/01/08 - 09/30/08		420,000	$	6.75	$	9.75
04/01/08 - 09/30/08		540,000	$	7.00	$	9.68
04/01/08 - 10/31/08		350,000	$	7.25	$	10.40
05/01/08 - 05/31/08		30,000	$	8.50	$	10.40
06/01/08 - 06/30/08		40,000	$	8.50	$	10.40
06/01/08 - 09/30/08		80,000	$	7.25	$	9.53
06/01/08 - 09/30/08		120,000	$	7.00	$	8.35
07/01/08 - 07/31/08		20,000	$	8.50	$	10.40
07/01/08 - 09/30/08		90,000	$	6.75	$	9.62
08/01/08 - 12/31/08		400,000	$	9.75	$	11.50
10/01/08 - 03/31/09		300,000	$	7.75	$	9.82
10/01/08 - 03/31/09		180,000	$	8.00	$	10.20
10/01/08 - 03/31/09		300,000	$	8.00	$	11.20
01/01/09 - 01/31/09		80,000	$	10.25	$	12.25
02/01/09 - 03/31/09		140,000	$	10.25	$	12.25
04/01/09 - 09/30/09		300,000	$	7.00	$	9.73
04/01/09 - 09/30/09		120,000	$	7.25	$	9.80
04/01/09 - 09/30/09		420,000	$	8.00	$	10.70

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMbtu)

(Nymex)

Natural Gas Three Way Costless Collars

10/01/08 - 03/31/09

300,000

8.00

10.35

5.50


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars*
04/01/08 - 04/30/08		2,000	$	60.00	$	74.75
04/01/08 - 06/30/08		3,000	$	65.00	$	82.60
04/01/08 - 06/30/08		9,000	$	62.00	$	81.60
04/01/08 - 10/31/08		21,000	$	65.70	$	90.00
04/01/08 - 12/31/08		18,000	$	57.50	$	75.50
04/01/08 - 12/31/08		18,000	$	85.00	$	117.00
04/01/08 - 12/31/08		18,000	$	57.50	$	76.00
06/01/08 - 10/31/08		30,000	$	90.00	$	120.00
07/01/08 - 08/31/08		4,000	$	65.00	$	80.60
11/01/08 - 12/31/08		8,000	$	87.75	$	120.00
11/01/08 - 06/30/09		24,000	$	62.00	$	81.75
01/01/09 - 03/31/09		21,000	$	86.50	$	120.00

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 2008, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our principal executive officer and our principal financial officer concluded that the design and operation of our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the first quarter of 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

None.

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

Issuer Purchases of Equity Securities

In 2008, we elected to allow employees to deliver shares of vested restricted stock with a fair market value equal to their federal, state and local tax withholding amounts on the date of issue in lieu of cash payment.


	Total Number of		Average Price
Period	Shares Purchased		Paid per Share
January 2008		16,330	$	7.375

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSON OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

31.1		Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934

31.2		Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934

32.1		Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350

32.2		Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350


	BRIGHAM EXPLORATION COMPANY
	By:	/s/ BEN M. BRIGHAM
		Ben M. Brigham
		Chief Executive Officer, President and Chairman of the Board


	By:	/s/ EUGENE B. SHEPHERD, JR.
		Eugene B. Shepherd, Jr.
		Executive Vice President and Chief Financial Officer

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets — March 31, 2008 and December 31, 2007		1

Consolidated Statements of Operations — Three months ended March 31, 2008 and 2007		2

Consolidated Statement of Stockholders’ Equity — Three months ended March 31, 2008		3

Consolidated Statements of Cash Flows — Three months ended March 31, 2008 and 2007		4

Notes to the Consolidated Financial Statements		5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		15

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		28

ITEM 4. CONTROLS AND PROCEDURES		30

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		31

ITEM 1.A. RISK FACTORS		31

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		31

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		31

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		31

ITEM 5. OTHER INFORMATION		31

ITEM 6. EXHIBITS		31

SIGNATURES		32

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


Exhibit
No.		Description

	31.1	Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934

	31.2	Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934

	32.1	Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350

	32.2	Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350