Form 10-Q

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, 2009


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: 001-34224

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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


Large Accelerated Filer o		Accelerated Filer þ		Non-Accelerated Filer o		Smaller Reporting Company o

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 5, 2009			46,596,425

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)


	March 31,			December 31,
	2009			2008

ASSETS
Current assets:
Cash and cash equivalents	$	27,031		$	40,598
Accounts receivable		21,396			24,558
Derivative assets		2,512			5,140
Inventory		7,582			6,070
Other current assets		1,494			2,154

Total current assets		60,015			78,520

Oil and natural gas properties, using the full cost method including
Proved, net		218,540			298,833
Unproved		81,066			106,006

		299,606			404,839

Other property and equipment, net		1,788			1,873
Deferred loan fees		2,908			3,122
Other noncurrent assets		714			702

Total assets	$	365,031		$	489,056


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	16,131		$	14,297
Royalties payable		5,010			6,859
Accrued drilling costs		11,673			19,768
Participant advances received		674			2,226
Other current liabilities		8,842			5,065

Total current liabilities		42,330			48,215


Senior Notes		158,789			158,730
Senior credit facility		145,000			145,000
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, 2009 and December 31, 2008		10,101			10,101
Deferred income taxes		149			149
Other noncurrent liabilities		5,849			5,592

Commitments and contingencies (Note 4)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,879,777 and 45,829,277 shares issued and 45,725,364 and 45,686,295 shares outstanding at March 31, 2009 and December 31, 2008, respectively		459			458
Additional paid-in capital		213,123			212,473
Treasury stock, at cost; 154,413 and 142,982 shares at March 31, 2009 and December 31, 2008, respectively		(1,238	)		(1,202	)
Retained earnings		(209,531	)		(90,460	)

Total stockholders’ equity		2,813			121,269

Total liabilities and stockholders’ equity	$	365,031		$	489,056

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,
	2009			2008

Revenues:
Oil and natural gas sales	$	13,809		$	30,510
Gain (loss) on derivatives, net		4,643			(5,456	)
Other revenue		34			17

		18,486			25,071

Costs and expenses:
Lease operating		3,799			2,986
Production taxes		814			1,283
General and administrative		2,122			2,593
Depletion of oil and natural gas properties		9,833			12,443
Impairment of oil and natural gas properties		114,781			—
Depreciation and amortization		149			147
Accretion of discount on asset retirement obligations		101			91
Loss on inventory valuation		2,039			—

		133,638			19,543

Operating income (loss)		(115,152	)		5,528

Other income (expense):
Interest income		93			75
Interest expense, net		(4,127	)		(3,419	)
Other income (expense)		115			307

		(3,919	)		(3,037	)

Income (loss) before income taxes		(119,071	)		2,491

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

		—			(964	)


Net income (loss)	$	(119,071	)	$	1,527


Net income (loss) per share available to common stockholders:
Basic	$	(2.60	)	$	0.03

Diluted	$	(2.60	)	$	0.03


Weighted average shares outstanding:
Basic		45,726			45,261

Diluted		45,726			45,770

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,
	2009			2008

Cash flows from operating activities:
Net income (loss)	$	(119,071	)	$	1,527
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		9,833			12,443
Impairment of oil and natural gas properties		114,781			—
Depreciation and amortization		149			147
Stock based compensation		353			414
Amortization of deferred loan fees and debt issuance costs		296			255
Market value adjustment for derivative instruments		2,878			5,394
Accretion of discount on asset retirement obligations		101			91
Deferred income taxes		—			964
Other noncash items		36			(28	)
Changes in operating assets and liabilities:
Accounts receivable		3,162			(5,803	)
Other current assets		(852	)		(285	)
Accounts payable		1,834			7,691
Royalties payable		(1,849	)		3,753
Participant advances received		(1,552	)		(1,966	)
Other current liabilities		3,351			3,924
Other noncurrent assets and liabilities		(15	)		(186	)

Net cash provided by operating activities		13,435			28,335


Cash flows from investing activities:
Additions to oil and natural gas properties		(27,007	)		(44,484	)
Decrease (increase) in restricted cash		555			—
Additions to other property and equipment		(100	)		(157	)
Decrease (increase) in drilling advances paid		163			(393	)

Net cash provided (used) by investing activities		(26,389	)		(45,034	)


Cash flows from financing activities:
Increase in senior credit facility		—			9,000
Repayment of senior credit facility		—			—
Deferred loan fees paid and equity costs		(23	)		(11	)
Proceeds from exercise of employee stock options		1			134
Repurchases of common stock		(36	)		(121	)

Net cash provided (used) by financing activities		(58	)		9,002

Net increase (decrease) in cash and cash equivalents		(13,012	)		(7,697	)
Cash and cash equivalents, beginning of year		40,043			13,863

Cash and cash equivalents, end of period	$	27,031		$	6,166

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 Rocky Mountains, onshore Gulf Coast, the Anadarko Basin, 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 (U.S. GAAP). The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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 2008 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

3. Restricted Cash

Restricted cash at December 31, 2008 included deposits in an interest bearing escrow account under the terms of a turnkey drilling contract executed during the third quarter of 2008. There was no restricted cash at March 31, 2009.

4. 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, 2009, 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.

5. 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, 2009 and 2008 are as follows (in thousands):


	Three Months Ended
	March 31,
	2009		2008

Weighted average common shares outstanding — basic		45,726		45,261
Plus: Potential common shares
Stock options and restricted stock		—		509


Weighted average common shares outstanding — diluted		45,726		45,770


Stock options excluded from diluted EPS due to the anti-dilutive effect		3,757		2,347

6. Income Taxes

The income tax expense (benefit) for the three months ended March 31, 2009 and 2008 consists of the following (in thousands):


	March 31,		March 31,
	2009		2008

Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		—		872
State		—		92

	$	—	$	964

No deferred federal or state income tax expense was recorded in the first quarter of 2009 because of ceiling test write-downs in the fourth quarter of 2008 and in the first quarter of 2009 resulting in increased valuation allowances on Brigham’s net deferred tax assets.

On January 1, 2007, Brigham adopted the provisions of Financial Accounting Standards Board Interpretation No. 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. In 2006 and 2007, Brigham examined the tax positions taken in its tax returns and determined that the full values of the uncertain tax positions were reflected as part of its deferred tax liabilities and reclassified these liabilities to other tax liabilities on the consolidated balance sheet. In 2008, Brigham received approval from the Internal Revenue Service to change its method of accounting for certain geological and geophysical costs and no longer has a liability for uncertain tax positions. As a result, as of December 31, 2008, Brigham eliminated the other tax liabilities in its consolidated balance sheet.

The following table sets forth the reconciliation of unrecognized tax benefits for the three months ended March 31:


	2009		2008
	(In thousands)		(In thousands)
Unrecognized tax benefits at beginning of the year	$	—	$	2,162
Increases (decreases) resulting from tax positions taken in the current period		—		—

Unrecognized tax benefits at end of the quarter	$	—	$	2,162

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 2008, 2007, 2006, and 2005. In addition, Brigham is open to examination for the years 1997 through 2004, resulting from net operating losses generated and available for carryforward.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

7. Derivative Instruments and Hedging Activities

Brigham utilizes various commodity swap and 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

Brigham enters into contracts to hedge against the variability in cash flows associated with the forecasted sale of future oil and gas production. Brigham’s cash flow hedges consisted of swaps, costless collars (purchased put options and written call options), and three-way collars (a standard collar plus a sold put below the floor price of the collar). The costless collars and three-way collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums paid or received when Brigham entered into these option agreements. Brigham has elected not to designate any of its derivative contracts as cash flow hedges for accounting purposes under SFAS No. 133. As such, 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. See Note 8, “Fair Values”, for a discussion of the calculation of the fair values of natural gas and oil derivative contracts. 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.

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, 2009 and 2008:


	Three Months Ended
	March 31,
	2009			2008
*Natural Gas*
Average price per Mcf realized excluding gas hedging results	$	4.27		$	8.83
Average price per Mcf including gas hedging settlement results	$	7.76		$	9.07
Increase (decrease) in revenue, in thousands	$	6,439		$	523
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	6.91		$	6.71
Increase (decrease) in revenue, in thousands	$	4,868		$	(4,633	)
*Oil*
Average price per Bbl realized excluding oil hedging results	$	34.29		$	95.50
Average price per Bbl including oil hedging settlement results	$	40.53		$	90.48
Increase (decrease) in revenue, in thousands	$	1,082		$	(586	)
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	32.99		$	88.45
Increase (decrease) in revenue, in thousands	$	(225	)	$	(823	)

For the three months ended March 31, 2009, settlements for natural gas included $3.2 million received for the monetization of a portion of our natural gas hedges which would have settled from May through September of 2009.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at March 31, 2009, 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*
04/01/09 – 04/30/09		50,000			$	7.00	$	7.50
04/01/09 – 04/30/09		20,000			$	7.25	$	9.80
04/01/09 – 04/30/09		70,000			$	8.00	$	8.00
04/01/09 – 04/30/09		40,000			$	5.75	$	7.50
10/01/09 – 03/31/10		420,000			$	5.75	$	7.05
04/01/10 – 09/30/10		420,000			$	5.75	$	7.30
04/01/10 – 09/30/10		240,000			$	5.75	$	7.00
10/01/10 – 03/31/11		240,000			$	6.50	$	8.25
*Oil Costless Collars*
04/01/09 – 06/30/09				9,000	$	62.00	$	81.75


	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMBTU)		Nymex		Nymex		Nymex
*Natural Gas Three Way Costless Collars*
04/01/09 – 04/30/09		70,000	$	6.25	$	8.80	$	4.75
10/01/09 – 03/31/10		420,000	$	8.00	$	10.00	$	5.50
10/01/09 – 03/31/10		360,000	$	5.75	$	7.00	$	3.50


	Natural				Written
	Gas		Oil		Swap
Settlement Period	(MMBTU)		(Barrels)		Nymex
*Natural Gas Swaps*
04/01/09 – 05/31/09		80,000			$	5.87
04/01/09 – 06/30/09		90,000			$	4.64
04/01/09 – 08/31/09		350,000			$	4.75
10/01/09 – 12/31/09		60,000			$	4.90
05/01/09 – 12/31/09		300,000			$	4.44
05/01/09 – 09/30/09		250,000			$	4.09
05/01/09 – 09/30/09		250,000			$	3.96
05/01/09 – 09/30/09		650,000			$	4.00
*Oil Swaps*
04/01/09 – 12/31/09				90,000	$	50.75

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Additional Disclosures about Derivative Instruments and Hedging Activities

At March 31, 2009, Brigham had derivative financial instruments under SFAS No. 133 recorded on the consolidated balance sheet as set forth below:


		Estimated
Type of Contract	Balance Sheet Location	Fair Value
		(in thousands)
Derivatives Not Designated as Hedging Instruments

Derivative Assets:
Natural gas and oil contracts	Derivative assets — current	$	2,512
Natural gas and oil contracts	Other non-current assets		377

Total Derivative Assets		$	2,889

Derivative Liabilities:
Natural gas and oil contracts	Other current liabilities	$	(431	)
Natural gas and oil contracts	Other non-current liabilities		1

Total Derivative Liabilities		$	(430	)

For the three months ended March 31, 2009, the effect on income in the consolidated statement of operations for derivative financial instruments under SFAS No. 133 was as follows:


	Statement of Operations	Amount of
Type of Contract	Location of Gain (Loss)	Gain (Loss)
		(in thousands)
Derivatives Not Designated as Hedging Instruments

Natural gas contracts	Gain (loss) on derivatives, net	$	4,868
Oil contracts	Gain (loss) on derivatives, net		(225	)

Total Derivative Gain (loss)		$	4,643

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Brigham’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty and Brigham has netting arrangements with all of its counterparties that provide for offsetting payables against receivables from separate derivative instruments with that counterparty.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Fair Values

Brigham adopted Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157) on January 1, 2008, as it relates to financial assets and liabilities. Brigham adopted FSP SFAS 157-2 “Effective Date of FASB Statement No. 157” on January 1, 2009, as it relates to nonfinancial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

•

Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

•

Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

•

Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

As such, effective January 1, 2008, the fair values of Brigham’s derivative financial instruments reflect Brigham’s estimate of the default risk of the parties in accordance with 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, 2009 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	March 31,			for Identical Assets		Inputs			Inputs
Description	2009			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(431	)	$	—	$	(431	)	$	—
Other non-current liabilities		1			—		1			—
Current derivative assets		2,512			—		2,512			—
Other non-current assets		377			—		377			—

	$	2,459		$	—	$	2,459		$	—


				Fair Value Measurements at December 31, 2008 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2008			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(5	)	$	—	$	(5	)	$	—
Other non-current liabilities		—			—		—			—
Current derivative assets		5,140			—		5,140			—
Other non-current assets		202			—		202			—

	$	5,337		$	—	$	5,337		$	—

Brigham’s assessment of the significance of a particular input to the fair value measurement requires judgment and may effect the valuation on the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of Brigham’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. The fair value of the asset retirement obligations is reflected on the balance sheet as detailed below.


				Fair Value Measurements at March 31, 2009 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	March 31,			for Identical Assets		Inputs		Inputs
Description	2009			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(5,850	)		—		—		(5,850	)

	$	(5,850	)	$	—	$	—	$	(5,850	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


				Fair Value Measurements at December 31, 2008 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	December 31,			for Identical Assets		Inputs		Inputs
Description	2008			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(5,592	)		—		—		(5,592	)

	$	(5,592	)	$	—	$	—	$	(5,592	)

9. Oil and Gas Properties

Brigham uses the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain payroll, asset retirement costs, other internal costs, and interest incurred for the purpose of finding oil and natural gas reserves, are capitalized. Internal costs and capitalized interest are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved oil and natural gas reserves, based on the oil and natural gas prices in effect on the balance sheet date including the impact of qualifying cash flow hedging instruments; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of oil and gas properties exceed this ceiling amount, Brigham is subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower depreciation, depletion and amortization expense in future periods.

The risk that Brigham will experience a ceiling test write-down increases when oil and gas prices are depressed or if Brigham has substantial downward revisions in its estimated proved reserves. Based on oil and gas prices in effect at the end of March 2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit by $71.9 million, net of tax. As a result, Brigham was required to record a write-down of the net capitalized costs of its oil and gas properties in the amount of $114.8 million at March 31, 2009.

10. 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 and its wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. The guarantees are joint and several. Brigham 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 Brigham’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%. 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, 2009, Brigham was in compliance with all covenants under the indenture.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. 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.

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, 2009 and 2008 (in thousands):


	Three Months Ended
	March 31,
	2009			2008

Beginning asset retirement obligations	$	5,592		$	5,047
Liabilities incurred for new wells placed on production		172			61
Liabilities settled		(15	)		(19	)
Accretion of discount on asset retirement obligations		101			91

	$	5,850		$	5,180

12. 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.

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 2009. 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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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, 2009 and 2008.

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


	Three Months Ended
	March 31,
	2009			2008

Pre-tax stock based compensation expense	$	650		$	763
Capitalized stock based compensation		(297	)		(349	)
Tax benefit		(124	)		(145	)

Stock based compensation expense, net	$	229		$	269

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, 2009, approximately 60,563 shares remained 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 540,800 remain available for grant under the director stock option plan.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


	2009				2008
			Weighted-					Weighted-
			Average					Average
			Exercise					Exercise
	Shares		Price		Shares			Price

Options outstanding at the beginning of the year		3,128,651	$	7.00		3,046,166		$	7.14
Granted		—	$	—		5,000		$	7.73
Forfeited or cancelled		—	$	—		(37,800	)	$	7.91
Exercised		—	$	—		(33,500	)	$	4.00

Options outstanding at the end of the quarter		3,128,651	$	7.00		2,979,866		$	7.17

Options exercisable at the end of the quarter		1,969,851	$	7.18		1,837,566		$	6.67

As noted on the previous page, there were no options granted during the three months ended March 31, 2009. 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, 2009 and 2008 was zero and $107,900, respectively.

The following table summarizes information about stock options outstanding and exercisable at March 31, 2009:


	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	2009		Contractual Life	Exercise Price		2009		Contractual Life	Exercise Price
$3.11 to $3.41		93,000	3.9 years	$	3.24		43,000	0.5 years	$	3.41
3.66 to 5.08		805,200	4.0 years	$	4.75		339,200	0.5 years	$	4.29
6.10 to 6.73		1,134,576	2.6 years	$	6.49		864,676	2.1 years	$	6.60
7.22 to 8.84		736,875	3.0 years	$	8.45		506,975	2.7 years	$	8.59
8.93 to 12.31		359,000	3.5 years	$	11.64		216,000	3.4 years	$	11.52

$3.11 to $12.31		3,128,651	3.2 years	$	7.00		1,969,851	2.0 years	$	7.18

The aggregate intrinsic value of options outstanding and exercisable at March 31, 2009 were zero. 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, 2009. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of March 31, 2009 there was approximately $3.2 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 4.8 years.

Restricted Stock

During the three months ended March 31, 2009 and 2008, Brigham issued 85,000 and 90,000, 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, 2009, there was approximately $2.9 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.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


	2009					2008
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Restricted shares outstanding at the beginning of the year		593,260		$	7.58		653,623		$	7.16
Shares granted		85,000		$	3.15		90,000		$	7.41
Lapse of restrictions		(50,000	)	$	7.35		(50,000	)	$	5.23
Forfeitures		—		$	—		(15,204	)	$	6.34

Shares outstanding at the end of the quarter		628,260		$	7.00		678,419		$	7.35

The Compensation Committee met on March 25, 2009 and approved the grant of 41,934 shares of restricted stock effective April 1, 2009 and also met on April 22, 2009 and approved the grant of 28,084 shares of restricted stock effective April 22, 2009. In addition, 950,000 options were granted on April 22, 2009 subject to shareholder approval.

13. Comprehensive Income

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


	Three Months Ended
	March 31,
	2009			2008

Net income (loss)	$	(119,071	)	$	1,527
Unrealized gains (losses) on cash flow hedges		—			—
Net gains (losses) included in net income		—			(177	)
Tax benefits (provisions) related to cash flow hedges		—			62
Reclassification adjustments for settled hedging positions		—			—

Other comprehensive income (loss), net	$	(119,071	)	$	1,412

14. New Accounting Pronouncements and SEC Rulemaking

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 was effective for the fiscal year beginning January 1, 2009. This pronouncement did not 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.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 standard requires that transaction costs relatd to business combinations be expensed rather than be included in the acquisition cost. 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. The impact of this standard will be on the fair value recorded for future business combinations after adoption.

In February 2007, the Financial Accounting Standards 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.

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. Adoption of this standard did not have a material impact on Brigham’s 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.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. It is not clear what, if any, impact the SEC guidance will have on ceiling test impairment calculations for full cost companies. SFAS No 69 “Disclosures about Oil and Gas Producing Activities—an amendment of FASB Statements 19, 25, 33, and 39” provides guidance for oil and natural gas reserve related disclosures in the financial statements. Brigham is currently evaluating the impact that the adoption will have on the financial statements.

In April 2009, the Financial Accounting Standards Board issued FASB Staff Position (FSP) FAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments,” which enhances consistency in financial reporting by increasing the frequency of fair value disclosures. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Adoption of this FSP is not expected to have a material impact on Brigham’s financial statements.

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 2008 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month periods ended March 31, 2009 and March 31, 2008. 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 2008 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 Rocky Mountains, the Onshore Gulf Coast, the Anadarko Basin, 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, since late 2005, 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 three 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:

•

Focus on Core Provinces and Trends;

•

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; and

•

Enhance Returns Through Operational Control.

Overview of First Quarter 2009 Financial Results

First quarter 2009 oil and natural gas prices, excluding realized and unrealized derivative hedging results, decreased 64% and 52%, respectively, from that in the first quarter 2008. In the first quarter 2009 the average sales price that we received for oil, excluding realized and unrealized derivative hedging results, was $34.29 per barrel, which represents a $61.21 per barrel decrease from the first quarter 2008. In the first quarter 2009 the average sales price that we received for natural gas, excluding realized and unrealized derivative hedging results, was $4.27 per Mcf, which represents a $4.56 per Mcf decrease from that in the first quarter 2008.

Our first quarter 2009 production of 2.88 Bcfe was flat with last years first quarter production of 2.89 Bcfe. The natural decline in production from our wells along the Onshore Gulf Coast, Anadarko Basin and West Texas was offset by the increase in our oil volumes in the Williston Basin. During the first quarter 2009 our oil volumes increased by 49% to approximately 174,000 barrels as compared to 117,000 barrels in the first quarter 2008.

Our first quarter 2009 oil and natural gas revenue, including hedge settlements but excluding unrealized hedging gains and losses, was down $9.1 million, or 30%, compared to that in the first quarter 2008. Oil revenue decreased $10.6 million due to lower oil prices and was partially offset by $5.4 million in increased revenue due to a rise in our oil production volumes. Natural gas revenue decreased $8.4 million due to lower natural gas prices and decreased an additional $3.1 million due to a reduction in our natural gas production. In the first quarter 2009, a rise in hedge settlement gains increased oil and natural gas revenue by $7.6 million versus the first quarter 2008.

First quarter 2009 operating income decreased $120.7 million from the first quarter last year. This decrease was attributable to a $114.8 million ceiling test write-down, a $2.0 million non-cash loss on inventory valuation, the aforementioned drop in commodity prices and higher lease operating expense. These factors were partially offset by lower depletion expense, general and administrative expense and production taxes.

As of March 31, 2009, we had $27.0 million in cash and $365.0 million in total assets.

Overview of First Quarter 2009 Operational Results

Rocky Mountain Province

Williston Basin

In February 2009, we announced the successful completion of our operated Olson 10-15 #1H, a long lateral totaling approximately 9,000 feet, which was completed with 20 fracture stimulation stages. The Olson well is located between our Field 18-19H and Erickson 8-17H wells in Williams County, North Dakota. We own an approximate 100% working interest and an 79% revenue interest in the well. Another late 2008 long lateral Bakken well, our operated Figaro 29-32 #1H well, which is located in McKenzie County, is waiting to be completed with an estimated 20 fracture stimulation stages.

Also in February 2009, we announced the successful completion of our operated Friedrich Trust 31 #1, a Red River well located approximately one mile from our Richardson 25 #1 in Sheridan County, Montana. We own an approximate 77% working interest and 59% revenue interest in the Friedrich Trust.

Subsequent to drilling the Olson and Figaro, we moved both of our operated rigs east of the Nesson Anticline to drill the Strobeck 27-34 #1H, which will be a Three Forks test to be completed with 20 fracture stimulation stages, and the Anderson 28-33 #1H, which will be a Bakken well to be completed with 20 fracture stimulation stages. We are awaiting declines in service costs prior to completing both the Strobeck and Anderson wells.

Onshore Gulf Coast Province

Southern Louisiana

Our second joint venture well, the Chandeleur Sound SL 19312 #1, encountered approximately 24 feet of apparent pay. The Chandeleur Sound well commenced production to sales in late January 2009.

Frio

Our G.S. Harrison Unit #2 came on line in late March from the lowest pay interval in the primary Frio objective. We own an approximate 63% working interest and 47% revenue interest in the well. The G.S. Harrison Unit #2 is located in Matagorda County, Texas and encountered approximately 61 feet of net pay in the upper and lower target sands. The well was perforated and fractured stimulated from 20 feet of net pay in the lower sands, with the upper 41 feet of apparent net pay remaining behind pipe for completion at a later date.

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 prices including derivative settlements and unrealized gains (losses).


	Three Months Ended March 31,
	2009			% Change			2008
	(In thousands)

Oil revenue:
Oil revenue	$	5,950			(47	%)	$	11,157
Oil derivative settlement gains (losses)		1,082		NM				(586	)

Oil revenue including derivative settlements	$	7,032			(33	%)	$	10,571
Oil derivative unrealized gains (losses)		(1,307	)		449	%		(238	)

Oil revenue including derivative settlements and unrealized gains (losses)	$	5,725			(45	%)	$	10,333
Natural gas revenue:
Natural gas revenue	$	7,859			(59	%)	$	19,353
Natural gas derivative settlement gains (losses)		6,439			1,129	%		524

Natural gas revenue including derivative settlements	$	14,298			(28	%)	$	19,877
Natural gas derivative unrealized gains (losses)		(1,571	)		(70	%)		(5,156	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	12,727			(14	%)	$	14,721
Oil and natural gas revenue:
Oil and natural gas revenue	$	13,809			(55	%)	$	30,510
Oil and natural gas derivative settlement gains (losses)		7,521		NM				(62	)

Oil and natural gas revenue including derivative settlements		21,330			(30	%)		30,448
Oil and natural gas derivative unrealized gains (losses)		(2,878	)		(47	%)		(5,394	)

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		18,452			(26	%)		25,054
Other revenue		34			100	%		17

Total revenue	$	18,486			(26	%)	$	25,071

Average oil prices:
Oil price (per Bbl)	$	34.29			(64	%)	$	95.50
Oil price including derivative settlement gains (losses) (per Bbl)		40.53			(55	%)		90.48
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)		32.99			(63	%)		88.45
Average natural gas prices:
Natural gas price (per Mcf)	$	4.27			(52	%)	$	8.83
Natural gas price including derivative settlement gains (losses) (per Mcf)		7.76			(14	%)		9.07
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	6.91			3	%	$	6.71
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	4.79			(55	%)	$	10.54
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		7.40			(30	%)		10.52
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	6.40			(26	%)	$	8.66


	For the three
	month periods
	ended March 31,
	2009 and 2008
	(In thousands)

Change in revenue from the sale of oil:

Price variance impact	$	(10,622	)
Volume variance impact		5,415
Cash settlement of derivative hedging contracts		1,668
Unrealized gains (losses) due to derivative hedging contracts		(1,069	)

Total change	$	(4,608	)


Change in revenue from the sale of natural gas:
Price variance impact	$	(8,409	)
Volume variance impact		(3,085	)
Cash settlement of derivative hedging contracts		5,915
Unrealized gains (losses) due to derivative hedging contracts		3,585

Total change	$	(1,994	)


Change in revenue from the sale of oil and natural gas:
Price variance impact	$	(19,031	)
Volume variance impact		2,330
Cash settlement of derivative hedging contracts		7,583
Unrealized gains (losses) due to derivative hedging contracts		2,516

Total change	$	(6,602	)

First quarter 2009 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) decreased $6.6 million when compared to the first quarter 2008. The change in revenues was attributable to the following:

•

a 55% decrease in pre-hedge per Mcfe sales prices resulted in a $19.0 million decrease in revenues;

•

an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $2.3 million increase in oil and natural gas revenues;

•

a $7.5 million gain from the settlement of derivative contracts in the first quarter 2009 (includes $3.2 million from the monetization of a portion of our natural gas hedges which would have settled from May through September, 2009) versus a $0.1 million loss from the settlement of derivative contracts in first quarter 2008 increased revenues by $7.6 million; and

•

a $2.9 million unrealized derivative loss in first quarter 2009 versus a $5.4 million unrealized derivative loss in first quarter 2008 increased revenues by $2.5 million.

Hedging. We utilize collars, three way costless collars and swaps 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 2009 and 2008 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,
	2009			% Change			2008

*Oil collars*
Volumes (Bbls)		30,000			(34	%)		45,500
Average floor price ($ per Bbl)	$	79.15			28	%	$	61.68
Average ceiling price ($ per Bbl)	$	108.53			27	%	$	85.59
Gain (loss) upon settlement ($ in thousands)	$	1,082		NM			$	(586	)

*Natural gas collars and Three Ways*
Volumes (MMbtu)		970,000			(36	%)		1,520,000
Average floor price ($ per MMbtu)	$	7.96			1	%	$	7.87
Average ceiling price ($ per MMbtu)	$	9.73			(22	%)	$	12.44
Gain (loss) upon settlement ($ in thousands)	$	6,270			1,097	%	$	524

*Natural gas swaps*
Volumes (MMbtu)		180,000		NM				—
Average swap price ($ per MMbtu)	$	5.23		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	183		NM			$	—

*Natural Gas Caps*
Volumes (MMbtu)		250,000		NM				—
Average price ($ per MMbtu)	$	9.73		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	(14	)	NM			$	—

Total Natural Gas Gain (loss) upon settlement ($ in thousands)	$	6,439			1,129	%	$	524

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 are 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,
	2009		% Change			2008		2009		% Change			2008

Production costs:
Operating & maintenance	$	0.99		57	%	$	0.63	$	2,844		56	%	$	1,822
Expensed workovers		0.24		(14	%)		0.28		680		(16	%)		814
Ad valorem taxes		0.10		(17	%)		0.12		275		(21	%)		350

Lease operating expenses	$	1.33		29	%	$	1.03	$	3,799		27	%	$	2,986

Production taxes		0.28		(36	%)		0.44		814		(37	%)		1,283

Production costs	$	1.61		10	%	$	1.47	$	4,613		8	%	$	4,269

First quarter 2009 per unit of production costs increased $0.14 per Mcfe, or 10%, when compared to the first quarter last year mainly due to the following:

•

O&M expense increased $0.36 per Mcfe, or 57%, due to an increase in compressor rental and maintenance, electricity, salt water disposal and well service and repair; offset by

•

production taxes decreased $0.16 per Mcfe, or 36%, due to lower commodity prices.

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,
	2009			% Change			2008
	(In thousands, except per unit measurements)

General and administrative costs	$	3,672			(26	%)	$	4,956
Capitalized general and administrative costs		(1,550	)		(34	%)		(2,363	)

General and administrative expenses	$	2,122			(18	%)	$	2,593


General and administrative expense ($ per Mcfe)	$	0.74			(18	%)	$	0.90

Our general and administrative costs prior to capitalization decreased primarily because of a $1.8 million reduction in employee compensation costs. Lower compensation costs were partially offset by $0.5 million in higher legal, audit fees, and consulting fees.

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,
	2009		% Change			2008
	(In thousands, except per unit measurements)

Depletion of oil and natural gas properties	$	9,833		(21	%)	$	12,443
Depletion of oil and natural gas properties ($ per Mcfe)	$	3.41		(21	%)	$	4.30

Our depletion expense for the first quarter 2009 was $2.6 million lower than the first quarter 2008. This decrease was due to a reduction in our depletion rate associated with our fourth quarter 2008 ceiling test write-down.

Impairment of oil and natural gas properties. We use the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain payroll, asset retirement costs, other internal costs, and interest incurred for the purpose of finding oil and natural gas reserves, are capitalized. Internal costs and capitalized interest are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved oil and natural gas reserves, based on the oil and natural gas prices in effect on the balance sheet date; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of oil and gas properties exceed this ceiling amount, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings and reduces stockholders’ equity in the period of occurrence.

The downward trend in natural gas prices continued in the first quarter and was partially responsible for a first quarter before tax ceiling test write-down of $114.8 million. On December 31, 2008, the Henry Hub natural gas cash price was $5.71 per MMbtu and on March 31, 2009 the Henry Hub natural gas cash price was $3.63 per MMbtu. Lower natural gas prices, combined with the impact of a change in our deferred tax position as a result of the year-end 2008 ceiling test write-down, resulted in our capitalized costs, net of accumulated depreciation, of our oil and gas properties to exceed the discounted present value of our estimated proved reserves using a 10% discount rate.

Inventory Valuation. Our non-cash loss in the first quarter 2009 was attributable to the $2.0 million lower of cost or market write-down of oil country tubular goods (OCTG). Market prices of OCTG have experienced a substantial reduction associated with lower steel costs, oversupply of OCTG and reduced levels of drilling activity associated with lower commodity prices.

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,
	2009			% Change			2008
	(In thousands)
Interest on Senior Notes	$	3,850			0	%	$	3,850
Interest on senior credit facility		1,005			557	%		153
Commitment fees		21			(68	%)		65
Dividend on mandatorily redeemable preferred stock		149			(1	%)		151
Amortization of deferred loan and debt issuance cost		275			12	%		246
Other general interest expense		17		NM				0
Capitalized interest expense		(1,190	)		14	%		(1,046	)

Net interest expense	$	4,127			21	%	$	3,419


Weighted average debt outstanding	$	315,101			72	%	$	182,821
Average interest rate on outstanding indebtedness (a)		6.5	%					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 2009 interest expense was $0.7 million higher than the corresponding period last year primarily due to a $0.9 million increase in interest expense associated with higher levels of outstanding debt on our senior credit facility. The increase in our debt outstanding was partially offset by a lower weighted average cost of debt due to lower one month LIBOR rates in the first three months of 2009 as compared to that in the first three months of 2008.

Other income (expense).

Other income (expense) included:


	Three months ended March 31,
	2009		% Change			2008
	(In thousands)
Other income (expense):
Non-cash gain (loss)	$	21		2000	%	$	1
Income (expense)		94		(69	%)		306

Total other income (expense)	$	115		(63	%)	$	307

Income taxes. We recorded no deferred federal or state income tax expense in the first quarter of this year, compared to deferred federal income tax expense of $0.9 million and deferred state income tax expense of $0.1 million in the first quarter last year. The decrease was primarily due to ceiling test write-downs in 2008 and in the first quarter 2009. For the first three months of 2009, our effective tax rate was 0%, which was lower than the statutory rate of 35% primarily due to increases in our valuation allowances on federal and state net operating losses and our inability to deduct 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 financial crisis and dramatic downturn in commodity prices have caused us to dramatically reduce our planned capital expenditure budget for 2009. As a consequence, after completing the drilling phase of wells that were in progress at year-end 2008, we have elected to shut down all drilling activity. The capital budget for 2009 mainly consists of completing wells that were in progress at year-end 2008 and participating in non-operated wells in the Parshall, Austin and Sanish fields, which are located east of the Nesson Anticline in Mountrail County, North Dakota. Factors that could cause us to increase our level of activity in 2009 include an appropriate decline in service costs that are commensurate with commodity prices at the time, the formation of a joint venture with another exploration and production company, the completion of a sale of a portion of our acreage position, the completion of a financing transaction or a rebound in commodity prices.

The table below summarizes our 2009 oil and gas capital expenditure budget, the amount spent through March 31, 2009 and the amount of our 2009 oil and gas capital expenditure budget that remains to be spent.


				Amount
	2009			Spent Through			Amount
	Budget			March 31, 2009			Remaining (a)
	(In millions)
Drilling	$	26.7		$	22.9		$	3.8
Net land and seismic (b)		(2.4	)		(6.5	)	NM
Capitalized costs (c)		12.5			2.7			9.8
Asset retirement obligation		0.3			0.2			0.1

Total oil and gas capital expenditures (d)	$	37.1		$	19.3		$	13.7


(a)		Calculated based on the 2009 capital expenditure budget included with our Form 10-K for 2008 less amounts spent through March 31, 2009.

(b)		Net land and seismic expenditures include $6 million in proceeds from the sale of our Mountrail County mineral interests and $0.5 million in reimbursements in connection with our G&G activity.

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

(d)		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 drilling schedule to ensure that we are optimizing our capital expenditure plan.

This value creation measure and the final determination with respect to our 2009 budgeted expenditures will depend on a number of factors, including:

•

commodity prices;

•

production from our existing producing wells;

•

the results of our current exploration and development drilling efforts;

•

economic conditions at the time of drilling;

•

industry conditions at the time of drilling, including the availability of drilling and completion equipment;

•

our liquidity and the availability of external sources of financing; and

•

the availability of more economically attractive prospects.

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

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2009, we intend to fund our capital expenditure program and contractual commitments with cash on hand, cash flows from operations, 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 under 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 25% or more in aggregate principal amount 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, 2009.

Senior Credit Agreement

Our senior credit agreement provides for revolving credit borrowings up to $200 million and matures June 29, 2010. In May and November 2008, in conjunction with our regularly scheduled semi-annual redeterminations, the borrowing base was reset to $135 million and $145 million, respectively. As of March 31, 2009, we had $145.0 million outstanding under our senior credit agreement.

Covenants under our Senior Notes preclude us from incurring additional debt under the senior credit agreement to the extent our total debt under the senior credit agreement exceeds the greater of $50.0 million or 25% of a calculated proved PV10 value based on year-end prices, as defined in our Indenture, which value is referred to as Adjusted Consolidated Net Tangible Assets. In December 2008, we were permitted to borrow up to $167.8 million and we elected to borrow a total of $145 million under our senior credit agreement. Because of the dramatic downturn in commodity prices during the second half of 2008 and because covenant calculations will rely on year-end 2008 prices for the above referenced calculation for the entirety of 2009, the lower year-end 2008 prices limit our present ability to make further borrowings of secured debt and therefore have negatively impacted our corporate liquidity.

Since the borrowing base for our senior credit agreement is redetermined at least semi-annually, the amount of borrowing capacity available to us under our senior credit agreement could fluctuate. 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 pay off the borrowing base deficiency and carry out our planned spending for exploration and development activities. If our borrowing base is reduced, we will be required to repay amounts outstanding under our senior credit facility until our borrowings no longer exceed the borrowing base.

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%		1.500	%		0.000	%
>50% and < 75%		1.750	%		0.250	%
>75% and < 90%		2.000	%		0.500	%
>90%		2.250	%		0.750	%


(1)		Base rate is defined as for any day a fluctuating rate per annum equal to the highest of the following, in each case, to the extent determinable by the Administrative Agent: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of one month determined as of approximately 11:00 a.m. (London time) on such day plus 1.50% and (c) 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%		0.300	%
>50% and < 75%		0.375	%
>75% and < 90%		0.500	%
> 90%		0.500	%

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, 2009 and interest coverage ratio for the twelve-month period ended March 31, 2009 were 1.37 to 1 and 5.75 to 1, respectively. As of March 31, 2009, we were in compliance with all covenant requirements in connection with our senior credit agreement.

Covenants governing our Indenture limit our ability to incur additional secured debt. Based on these covenants and the value of our proved reserves as of March 31, 2009, we calculated that at the end of the first quarter 2009 we are unable to incur additional secured debt beyond the $145 million that is currently outstanding under our senior credit agreement. Growth in our proved reserves could give us the flexibility to incur additional secured debt.

Mandatorily Redeemable Preferred Stock

As of March 31, 2009, 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 one effective universal shelf registration statement 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. It has not been utilized to date and has $300 million available; however, it expires in June 2009. Additionally, our ability to raise additional capital using our shelf registration statement 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,
	2009			%Change			2008
	(In thousands)

Net income (loss)	$	(119,071	)	NM			$	1,527
Non-cash items		128,427			553	%		19,680
Changes in working capital and other items		4,079			(43	%)		7,128

Cash flows provided by operating activities	$	13,435			(53	%)	$	28,335
Cash flows used by investing activities		(26,389	)		(41	%)		(45,034	)
Cash flows provided by financing activities		(58	)	NM				9,002

Net increase in cash and cash equivalents	$	(13,012	)		69	%	$	(7,697	)

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 2009, cash flows provided by operating activities decreased by 53% to $13.4 million from the same period last year. The decrease in operating cash flow is primarily attributable to the aforementioned decrease in commodity prices.

Analysis of changes in cash flows used in investing activities


	Three months ended March 31,
	2009			%Change			2008
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	22,940			(26	%)	$	31,200
Land and seismic		(6,471	)	NM				10,833
Capitalized cost		2,740			(20	%)		3,410
Capitalized asset retirement obligation		172			182	%		61

Total	$	19,381			(57	%)	$	45,504


Reconciling Items:
Change in accrued drilling costs	$	8,095		NM			$	(609	)
Other		(1,087	)	NM				139

Total Reconciling Items		7,008		NM				(470	)

Net cash used in investing activities	$	26,389			(41	%)	$	45,034

Net cash used by investing activities in the first quarter 2009 decreased by $18.6 million, or 41%, over the same period in 2008. The following were the reasons for the change:

	•		net land and seismic expenditures decreased by $17.3 million;

	•		drilling expenditures decreased by $8.3 million;

	•		capitalized costs decreased by $0.7 million; and

	•		the change in accrued drilling costs increased cash used in investing activities by $8.7 million.

Analysis of changes in cash flows from financing activities

We had no net cash provided by financing activities in the first quarter 2009 since we were fully drawn under our senior credit agreement. During the first quarter 2008, we borrowed an incremental $9.0 million under our senior credit facility.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the three months ended March 31, 2009 and 2008.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
*2009 common stock transactions:*
Exercise of employee stock options		500	$	1

*2008 common stock transactions:*
Exercise of employee stock options		33,500	$	134

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.

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

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 standard requires that transaction costs related to business combinations be expensed rather than be included in the acquisition cost. 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. The impact of this standard will be on the fair value recorded for future business combinations after adoption.

In February 2007, the Financial Accounting Standards 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. We have not elected the fair value option for any eligible items.

SEC Rulemaking

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

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 2009 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, 2008 including, but not limited to, the Risk Factors identified in Item 1A. of such report. 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 2008 and 2009 through March 31, we were party to natural gas costless collars, natural gas three-way costless collars, natural gas swaps, oil costless collars and oil swaps.

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, 2009, the associated volumes and the corresponding weighted average NYMEX floor and cap price. As of May 1, 2009 we did not enter into any commodity derivative contracts subsequent to March 31, 2009.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
04/01/09 – 04/30/09		50,000	$	7.00	$	7.50
04/01/09 – 04/30/09		20,000	$	7.25	$	9.80
04/01/09 – 04/30/09		70,000	$	8.00	$	8.00
04/01/09 – 04/30/09		40,000	$	5.75	$	7.50
10/01/09 – 03/31/10		420,000	$	5.75	$	7.05
04/01/10 – 09/30/10		420,000	$	5.75	$	7.30
10/01/10 – 03/31/11		240,000	$	6.50	$	8.25
04/01/10 – 09/30/10		240,000	$	5.75	$	7.00


	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMbtu)		(Nymex)		(Nymex)		(Nymex)
*Natural Gas Three Way Costless Collars*
10/01/09 – 03/31/10		420,000	$	8.00	$	10.00	$	5.50
04/01/09 – 04/30/09		70,000	$	6.25	$	8.80	$	4.75
10/01/09 – 03/31/10		360,000	$	5.75	$	7.00	$	3.50


	Natural		Swap
	Gas		Price
Settlement Period	(MMbtu)		(Nymex)
*Natural Gas Swaps*
04/01/09 – 05/31/09		80,000	$	5.865
04/01/09 – 06/30/09		90,000	$	4.640
04/01/09 – 08/31/09		350,000	$	4.745
10/01/09 – 12/31/09		60,000	$	4.900
05/01/09 – 12/31/09		300,000	$	4.440
05/01/09 – 09/30/09		250,000	$	4.090
05/01/09 – 09/30/09		250,000	$	3.960
05/01/09 – 09/30/09		650,000	$	4.000

Crude

Purchased

Written

Oil

Put

Call

Settlement Period

(Bbls)

(Nymex)

Oil Costless Collars

04/01/09 – 06/30/09

9,000

62.00

81.75


	Crude		Swap
	Oil		Price
Settlement Period	(Bbls)		(Nymex)
*Oil Swaps*
04/01/09 – 12/31/09		90,000	$	50.75

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 2009, 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 2009 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

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2008, other than the following:

The proposed United States federal budget for fiscal year 2010 and other pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

In March 2009, the Obama administration released its budget proposals, which included numerous tax changes. In April 2009, additional legislation was introduced to further these objectives. The proposed budget and legislation repeal many tax incentives and deductions that are currently used by US oil and gas companies and impose new taxes. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion in excess of basis; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

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

Issuer Purchases of Equity Securities

In 2009, 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 2009		11,431	$	3.105

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

On January 1, 2009, the Consulting Agreement dated May 1, 1997 between Brigham Oil & Gas, L.P. and Harold D. Carter, one of our directors, was terminated in an effort to reduce general and administrative expense.

ITEM 6. EXHIBITS


10.41*		Agreement terminating the Consulting Agreement dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter

10.42*		Form of Amendment to Option Agreement

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


*		Management contract or compensatory plan.

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	Page
PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets — March 31, 2009 and December 31, 2008		1

Consolidated Statements of Operations — Three months ended March 31, 2009 and 2008		2

Consolidated Statement of Stockholders’ Equity — Three months ended March 31, 2009		3

Consolidated Statements of Cash Flows — Three months ended March 31, 2009 and 2008		4

Notes to the Consolidated Financial Statements		5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		31

ITEM 4. CONTROLS AND PROCEDURES		33

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		34

ITEM 1A. RISK FACTORS		34

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		34

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		34

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		34

ITEM 5. OTHER INFORMATION		34

ITEM 6. EXHIBITS		34

SIGNATURES		35

Exhibit 10.41
Exhibit 10.42
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


					Additional									Total
	Common Stock				Paid In			Treasury			Retained			Stockholders’
	Shares		Amounts		Capital			Stock			Earnings			Equity
Balance, December 31, 2008		45,829	$	458	$	212,473		$	(1,202	)	$	(90,460	)	$	121,269
Net income (loss)		—		—		—			—			(119,071	)		(119,071	)
Exercises of employee stock options		1		—		1			—			—			1
Vesting of restricted stock		50		1		(1	)		—			—			—
Stock based compensation		—		—		650			—			—			650
Repurchases of common stock		—		—		—			(36	)		—			(36	)


Balance, March 31, 2009		45,880	$	459	$	213,123		$	(1,238	)	$	(209,531	)	$	2,813


(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.


	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


Exhibit No.		Description

10.41*		Agreement terminating the Consulting Agreement dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter

10.42*		Form of Amendment to Option Agreement

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


COMPANY:		CONSULTANT:

BRIGHAM OIL & GAS, L.P. By: Brigham, Inc. Its: Managing General Partner

By: /s/ David T. Brigham		By: /s/ Harold D. Carter

David T. Brigham		Harold D. Carter
Executive Vice President


		BRIGHAM EXPLORATION COMPANY

		By:

				Ben. M. Brigham, President & CEO

1.		I have reviewed this quarterly report on Form 10-Q of Brigham Exploration Company;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


/s/ Ben M. Brigham
Ben M. Brigham
Chief Executive Officer, President and Chairman of the Board

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Dated: May 8, 2009	/s/ Ben M. Brigham
	Ben M. Brigham
	Chief Executive Officer, President and Chairman of the Board