Brigham Exploration (BEXP) 10-Q 2009 Q2 Quarterly report

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 June 30, 2009

OR

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. Yesþ Noo

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). Yeso Noo

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 Filero Accelerated Filerþ Non-Accelerated Filero Small Reporting Companyo

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

Class	Outstanding
Common Stock, par value $.01 per share as of August 3, 2009	82,957,972

Brigham Exploration Company

Second Quarter 2009 Form 10-Q Report

TABLE OF CONTENTS

	Page
PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets — June 30, 2009 and December 31, 2008		1
Consolidated Statements of Operations — Three and six months ended June 30, 2009 and 2008		2
Consolidated Statement of Stockholders’ Equity — Six months ended June 30, 2009		3
Consolidated Statements of Cash Flows — Six months ended June 30, 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		34
ITEM 4. CONTROLS AND PROCEDURES		36
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		37
ITEM 1.A. RISK FACTORS		37
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		37
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		37
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		37
ITEM 5. OTHER INFORMATION		38
ITEM 6. EXHIBITS		39
SIGNATURES		41
Exhibit 10.48
Exhibit 10.49
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)

	June 30,			December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	68,086		$	40,043
Restricted cash		—			555
Investments		5,268			—
Accounts receivable		13,751			24,558
Derivative assets		1,638			5,140
Inventory		7,276			6,070
Other current assets		719			2,154
Total current assets		96,738			78,520
Oil and natural gas properties, using the full cost method including
Proved, net		219,776			298,833
Unproved		80,957			106,006
		300,733			404,839
Other property and equipment, net		2,359			1,873
Deferred loan fees		3,647			3,122
Other noncurrent assets		931			702
Total assets	$	404,408		$	489,056
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	9,996		$	14,297
Royalties payable		4,568			6,859
Accrued drilling costs		5,862			19,768
Participant advances received		515			2,226
Other current liabilities		7,448			5,065
Total current liabilities		28,389			48,215
Senior Notes		158,849			158,730
Senior Credit Facility		110,000			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 June 30, 2009 and December 31, 2008		10,101			10,101
Deferred income taxes		149			149
Other noncurrent liabilities		6,783			5,592
Commitments and contingencies (Note 4)
Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 82,223,628 and 45,829,277 shares issued and 82,053,843 and 45,686,295 shares outstanding at June 30, 2009 and December 31, 2008, respectively		822			458
Additional paid-in capital		307,099			212,473
Treasury stock, at cost; 169,785 and 142,982 shares at June 30, 2009 and December 31, 2008, respectively		(1,293	)		(1,202	)
Retained earnings (deficit)		(216,491	)		(90,460	)
Total stockholders’ equity		90,137			121,269
Total liabilities and stockholders’ equity	$	404,408		$	489,056

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

1

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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues:
Oil and natural gas sales	$	13,209		$	38,871		$	27,018		$	69,381
Gain (loss) on derivatives, net		(2,727	)		(13,907	)		1,916			(19,363	)
Other revenue		32			62			66			79
		10,514			25,026			29,000			50,097
Costs and expenses:
Lease operating		3,573			2,548			7,372			5,534
Production taxes		831			1,441			1,645			2,724
General and administrative		2,264			2,596			4,386			5,189
Depletion of oil and natural gas properties		6,233			12,405			16,066			24,848
Impairment of oil and natural gas properties		—			—			114,781			—
Depreciation and amortization		167			158			316			305
Accretion of discount on asset retirement obligations		105			89			206			180
Loss on inventory valuation		128			—			2,167			—
		13,301			19,237			146,939			38,780
Operating income (loss)		(2,787	)		5,789			(117,939	)		11,317
Other income (expense):
Interest income		111			39			204			114
Interest expense, net		(4,251	)		(3,482	)		(8,378	)		(6,901	)
Other income (expense)		(33	)		96			82			403
		(4,173	)		(3,347	)		(8,092	)		(6,384	)
Income (loss) before income taxes		(6,960	)		2,442			(126,031	)		4,933
Income tax expense:
Current		—			—			—			—
Deferred		—			(925	)		—			(1,889	)
		—			(925	)		—			(1,889	)
Net income (loss)	$	(6,960	)	$	1,517		$	(126,031	)	$	3,044
Net income (loss) per share available to common stockholders:
Basic	$	(0.12	)	$	0.03		$	(2.39	)	$	0.07
Diluted	$	(0.12	)	$	0.03		$	(2.39	)	$	0.07
Weighted average shares outstanding:
Basic		59,687			45,332			52,745			45,296
Diluted		59,687			46,444			52,745			46,171

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

2

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In thousands)
(Unaudited)

					Additional									Total
	Common Stock				Paid In			Treasury						Stockholders’
	Shares		Amounts		Capital			Stock			Retained Earnings			Equity
Balance, December 31, 2008		45,829	$	458	$	212,473		$	(1,202	)	$	(90,460	)	$	121,269
Net income (loss)		—		—		—			—			(126,031	)		(126,031	)
Issuance of common stock		36,292		363		93,160			—			—			93,523
Exercises of employee stock options		1		—		1			—			—			1
Vesting of restricted stock		102		1		(1	)		—			—			—
Stock based compensation		—		—		1,466			—			—			1,466
Repurchases of common stock		—		—		—			(91	)		—			(91	)
Balance, June 30, 2009		82,224	$	822	$	307,099		$	(1,293	)	$	(216,491	)	$	90,137

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

3

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)

	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(126,031	)	$	3,044
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion of oil and natural gas properties		16,066			24,848
Impairment of oil and natural gas properties		114,781			—
Depreciation and amortization		316			305
Stock based compensation		797			818
Amortization of deferred loan fees and debt issuance costs		626			528
Market value adjustment for derivative instruments		6,891			15,944
Accretion of discount on asset retirement obligations		206			180
Deferred income taxes		—			1,889
Other noncash items		35			4
Changes in operating assets and liabilities:
Accounts receivable		10,807			(11,044	)
Other current assets		36			(1,303	)
Accounts payable		(4,301	)		5,615
Royalties payable		(2,291	)		3,332
Participant advances received		(1,711	)		(581	)
Other current liabilities		(265	)		(158	)
Other noncurrent assets and liabilities		(15	)		(381	)
Net cash provided by operating activities		15,947			43,040
Cash flows from investing activities:
Additions to oil and natural gas properties		(39,703	)		(83,956	)
Decrease (increase) in restricted cash		555			—
Decrease (increase) in short term investments		(5,268	)		—
Additions to other property and equipment		(1,245	)		(357	)
Decrease (increase) in drilling advances paid		163			(399	)
Net cash provided (used) by investing activities		(45,498	)		(84,712	)
Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		93,523			—
Increase in Senior Credit Facility		—			38,600
Repayment of Senior Credit Facility		(35,000	)		—
Deferred loan fees paid and equity costs		(839	)		(188	)
Proceeds from exercise of employee stock options		1			552
Repurchases of common stock		(91	)		(142	)
Net cash provided (used) by financing activities		57,594			38,822
Net increase (decrease) in cash and cash equivalents		28,043			(2,850	)
Cash and cash equivalents, beginning of year		40,043			13,863
Cash and cash equivalents, end of period	$	68,086		$	11,013

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

4

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 partnership 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 of $555,000 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 June 30, 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 June 30, 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.

5

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 and six months ended June 30, 2009 and 2008 are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Weighted average common shares outstanding — basic		59,687		45,332		52,745		45,296
Plus: Potential common shares
Stock options and restricted stock		—		1,112		—		875
Weighted average common shares outstanding — diluted		59,687		46,444		52,745		46,171
Stock options excluded from diluted EPS due to the anti-dilutive effect		4,915		327		4,915		485

6. Income Taxes

The income tax expense for the six months ended June 30, 2009 and 2008 consists of the following (in thousands):

	June 30,		June 30,
	2009		2008
Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		—		1,707
State		—		182
	$	—	$	1,889

No deferred federal or state income tax benefit was recorded in the second 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 six months ended June 30:

	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.

6

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 consist 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 are no net premiums paid or received when Brigham enters 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 and six months ended June 30, 2009 and 2008:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Natural Gas
Average price per Mcf realized excluding gas hedging results	$	3.50		$	11.93		$	3.93		$	10.29
Average price per Mcf including gas hedging settlement results	$	4.53		$	11.03		$	6.33		$	9.99
Increase (decrease) in revenue, in thousands	$	1,509		$	(1,756	)	$	7,948		$	(1,231	)
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	3.86		$	7.61		$	5.56		$	7.14
Increase (decrease) in revenue, in thousands	$	529		$	(8,409	)	$	5,397		$	(13,041	)
Oil
Average price per Bbl realized excluding oil hedging results	$	49.41		$	122.22		$	41.63		$	109.46
Average price per Bbl including oil hedging settlement results	$	48.06		$	109.71		$	44.18		$	100.53
Increase (decrease) in revenue, in thousands	$	(222	)	$	(1,600	)	$	860		$	(2,186	)
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	29.56		$	79.25		$	31.32		$	83.64
Increase (decrease) in revenue, in thousands	$	(3,256	)	$	(5,498	)	$	(3,481	)	$	(6,322	)

For the six months ended June 30, 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.

7

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at June 30, 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
10/01/09 - 03/31/10		420,000			$	5.75	$	7.05
11/01/09 - 12/31/10		980,000			$	5.15	$	7.00
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
07/01/09 - 05/31/10				110,000	$	57.50	$	75.95
07/01/09 - 12/31/09				60,000	$	49.00	$	70.00
07/01/09 - 12/31/09				40,000	$	62.50	$	76.75
01/01/10 - 03/31/10				6,000	$	65.00	$	87.50
01/01/10 - 12/31/10				120,000	$	48.70	$	80.00
01/01/10 - 12/31/10				54,000	$	60.00	$	86.50
06/01/10 - 12/31/10				56,000	$	57.50	$	82.15
07/01/10 - 09/30/10				6,000	$	70.00	$	87.25
10/01/10 - 12/31/10				3,000	$	70.00	$	88.50
01/01/11 - 12/31/11				84,000	$	65.00	$	88.25

	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
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
07/01/09 - 08/31/09		140,000			$	4.75
07/01/09 - 09/30/09		150,000			$	4.09
07/01/09 - 09/30/09		150,000			$	3.96
07/01/09 - 09/30/09		390,000			$	4.00
07/01/09 - 12/31/09		258,000			$	4.44
07/01/09 - 10/31/09		280,000			$	4.03
10/01/09 - 12/31/09		60,000			$	4.90
Oil Swaps
07/01/09 - 12/31/09				60,000	$	50.75

8

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Additional Disclosures about Derivative Instruments and Hedging Activities

At June 30, 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	$	1,638
Natural gas and oil contracts	Other non-current assets		186
Total Derivative Assets		$	1,824
Derivative Liabilities:
Natural gas and oil contracts	Other current liabilities	$	(2,653	)
Natural gas and oil contracts	Other non-current liabilities		(725	)
Total Derivative Liabilities		$	(3,378	)

For the three and six months ended June 30, 2009, the effect on income in the consolidated statement of operations for derivative financial instruments under SFAS No. 133 was as follows:

		Three Months			Six Months
		Ended June 30th			Ended June 30th
	Statement of Operations	Amount of			Amount of
Type of Contract	Location of Gain (Loss)	Gain (Loss)			Gain (Loss)
		(in thousands)			(in thousands)
Derivatives Not Designated as Hedging Instruments
Natural gas contracts	Gain (loss) on derivatives, net	$	529		$	5,397
Oil contracts	Gain (loss) on derivatives, net		(3,256	)		(3,481	)
Total Derivative Gain (loss)		$	(2,727	)	$	1,916

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.

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.

9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 June 30, 2009 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	June 30,			for Identical Assets		Inputs			Inputs
Description	2009			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(2,653	)	$	—	$	(2,653	)	$	—
Other non-current liabilities		(725	)		—		(725	)		—
Current derivative assets		1,638			—		1,638			—
Other non-current assets		186			—		186			—
	$	(1,554	)	$	—	$	(1,554	)	$	—

				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 June 30, 2009 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	June 30,			for Identical Assets		Inputs		Inputs
Description	2009			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(6,058	)		—		—		(6,058	)
	$	(6,058	)	$	—	$	—	$	(6,058	)

				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	)

See Note 13 for a rollforward of the asset retirement obligation.

As of June 30, 2009, Brigham held $5.3 million of investments in certificates of deposit which have maturities of less than a year. There were no investments at December 31, 2008. The fair value of the investments is reflected on the balance sheet as detailed below.

			Fair Value Measurements at June 30, 2009 Using
			Quoted Prices in		Significant Other		Significant
			Active Markets		Observable		Unobservable
	June 30,		for Identical Assets		Inputs		Inputs
Description	2009		(Level 1)		(Level 2)		(Level 3)
Investments		5,268		5,268		—		—
	$	5,268	$	5,268	$	—	$	—

Brigham’s other financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The carrying value of Brigham’s senior credit facility approximates its fair market value since it bears interest at floating market interest rates. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:

	June 30, 2009				December 31, 2008
	(in millions)				(in millions)
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior Notes	$	160,000	$	109,600	$	160,000	$	84,000
Series A Preferred Stock	$	10,101	$	10,114	$	10,101	$	10,032

The fair value of Brigham’s Senior Notes is based upon current market quotes and is the estimated amount required to purchase the Senior Notes on the open market.

10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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.

Based on oil and gas prices in effect on June 30, 2009 ($3.885 per MMBtu for Henry Hub natural gas and $69.89 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties did not exceed the ceiling limit. Therefore, Brigham was not required to writedown the net capitalized costs of its oil and gas properties at June 30, 2009.

10. Common Stock Offering

In May 2009, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 36,292,117 shares at a price of $2.75 and received net proceeds of $93.5 million after underwriting fees and offering expenses. Brigham used the net proceeds from the offering to repay $35 million of outstanding borrowings under its Senior Credit Facility. Brigham is using the remaining net proceeds to fund an expanded capital budget in 2009 and a portion of the 2010 capital budget.

11. 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 June 30, 2009, Brigham was in compliance with all covenants under the indenture.

11

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

12. Senior Credit Facility

In November 2008, in conjunction with Brigham’s regularly scheduled semi-annual redetermination, the borrowing base was reset to $145 million. In May 2009, in conjunction with Brigham’s regularly scheduled semi-annual redetermination and Brigham’s common stock offering, the borrowing base was reset to $110 million. As of June 30, 2009, Brigham had $110.0 million in borrowings outstanding under the Senior Credit Facility. On July 24, 2009, Brigham amended and restated the Senior Credit Facility to extend the maturity of the agreement from June 2010 to July 2012.

Borrowings under the Senior Credit Facility bear interest, at Brigham’s election, at a base rate (as the term is defined in the Senior Credit Facility) or Eurodollar rate, plus in each case an applicable margin that is reset quarterly (3.5% at June 30, 2009). The applicable interest rate margin varies from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term is defined in the Senior Credit Facility) and from 2.5% to 3.5% in the case of borrowings based on the Eurodollar rate, depending on percentage of the available borrowing base utilized. In addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base (0.50% at June 30, 2009). Borrowings under the Senior Credit Facility are collateralized by substantially all of Brigham’s oil and natural gas properties under first liens.

The Senior Credit Facility contains various covenants, including among others restrictions on liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on investments, and restrictions on hedging activity of a speculative nature or with counterparties having credit ratings below specified levels. The Senior Credit Facility requires Brigham to maintain a current ratio (as defined) of at least 1 to 1. The Senior Credit Facility also requires Brigham to maintain an interest coverage ratio for the four most recent quarters as of June 30, 2009 and September 30, 2009 of at least 2.5 to 1, for the quarters ending December 31, 2009 and March 31, 2010 of at least 2.0 to 1, and thereafter must be at least 2.5 to 1. In conjunction with the July 24, 2009 amendment, a net leverage ratio (as defined therein) was added. The net leverage ratio beginning with the quarters ending September 30, 2009 through September 30, 2010 must not be greater than 4.50 to 1, the quarters ending December 31, 2010 and March 31, 2011 must not be greater than 4.25 to 1, and thereafter must not be greater than 4.00 to 1. At June 30, 2009, Brigham was in compliance with all covenants under the Senior Credit Facility.

13. 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 six months ended June 30, 2009 and 2008 (in thousands):

	Six Months Ended
	June 30,
	2009			2008
Beginning asset retirement obligations	$	5,592		$	5,047
Liabilities incurred for new wells placed on production		275			132
Liabilities settled		(15	)		(50	)
Accretion of discount on asset retirement obligations		206			180
	$	6,058		$	5,309

12

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

14. 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 ten 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 six months ended June 30, 2009 and 2008 was calculated using a Black-Scholes Merton option pricing model (Black-Scholes). The following table summarizes the weighted average assumptions used in the Black-Scholes model for options granted during the six months ended June 30, 2009 and 2008:

	2009			2008
Risk-free interest rate		2.52	%		3.0	%
Expected life (in years)		5.0			5.0
Expected volatility		77	%		47	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	2.19		$	4.70

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 six months ended June 30, 2009 and 2008.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Pre-tax stock based compensation expense	$	816		$	744		$	1,466		$	1,507
Capitalized stock based compensation		(372	)		(340	)		(669	)		(689	)
Tax benefit		(155	)		(141	)		(279	)		(286	)
Stock based compensation expense, net	$	289		$	263		$	518		$	532

13

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 6,962,648 or 15% of the total number of shares of common stock outstanding. At June 30, 2009, approximately 97,779 shares remain available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one series of stock option grants, 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 616,800 shares remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans (see also Part II, Item 4(c)3) and non-plan director activity (see also Part II, Item 4(c)4) for the six months ended June 30:

	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		1,150,000		$	2.21		18,000		$	10.56
Forfeited or cancelled		(10,000	)	$	3.73		(64,800	)	$	7.83
Exercised		—		$	—		(126,566	)	$	4.36
Options outstanding at the end of the quarter		4,268,651		$	5.71		2,872,800		$	7.27
Options exercisable at the end of the quarter		1,976,451		$	7.21		1,760,000		$	6.79

The weighted-average grant-date fair value of share options granted during the six months ended June 30, 2009 and 2008 was $2.19 and $4.70 respectively. There were no options exercised during the six months ended June 30, 2009. The total intrinsic value of options exercised during the six months ended June 30, 2008 was $177,798.

The following table summarizes information about stock options outstanding and exercisable at June 30, 2009:

	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average	Weighted-
	June 30,		Remaining	Average		June 30,		Remaining	Average
Exercise Price	2009		Contractual Life	Exercise Price		2009		Contractual Life	Exercise Price
$2.21 to $3.41		1,243,000	9.4 years	$	2.28		43,000	1.2 years	$	3.41
3.66 to 5.08		795,200	4.0 years	$	4.76		329,200	0.8 years	$	4.30
6.10 to 6.73		1,134,576	2.4 years	$	6.49		869,676	1.8 years	$	6.59
7.22 to 8.84		736,875	2.7 years	$	8.45		515,975	2.4 years	$	8.58
8.93 to 12.31		359,000	3.3 years	$	11.64		218,600	3.2 years	$	11.53
$3.11 to $12.31		4,268,651	4.9 years	$	5.71		1,976,451	2.0 years	$	7.21

The aggregate intrinsic value of options outstanding and exercisable at June 30, 2009 was $1.5 million and $4,100, respectively. The aggregate intrinsic value represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the quarter and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on June 30, 2009. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

14

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

As of June 30, 2009 there was approximately $5.3 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.9 years.

Restricted Stock

During the six months ended June 30, 2009 and 2008, Brigham issued 155,018 and 109,000, 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 June 30, 2009, there was approximately $2.7 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 4.5 years. Brigham has assumed a 6% weighted average forfeiture rate for restricted stock. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods.

The following table reflects the outstanding restricted stock awards and activity related thereto for the three months ended June 30:

	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		155,018		$	2.62		109,000		$	8.40
Lapse of restrictions		(101,734	)	$	5.10		(58,000	)	$	5.39
Forfeitures		—		$	—		(29,940	)	$	6.58
Shares outstanding at the end of the quarter		646,544		$	6.78		674,683		$	7.54

15. Comprehensive Income

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009			2008
Net income (loss)	$	(6,960	)	$	1,517	$	(126,031	)	$	3,044
Net (gains) losses included in net income		—			—		—			(177	)
Tax benefits (provisions) related to cash flow hedges		—			—		—			62
Other Comprehensive Income, net	$	(6,960	)	$	1,517	$	(126,031	)	$	2,929

16. Subsequent Events

Brigham commenced an exchange offer on July 13, 2009 pursuant to which eligible employees were offered the opportunity to exchange outstanding stock options granted prior to April 21, 2009 for new stock options at an exercise price per share equal to the mean of the high and low sales prices per share on the last business day of the exchange offer, or August 10, 2009, unless the exchange offer is extended.

15

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

17. New Accounting Pronouncements and SEC Rulemaking

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

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This 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 adoption of SFAS 141R did not have a material impact on the financial statements.

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

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.

In May 2009, the Financial Accounting Standards Statement of Financial Accounting Standards No. 165 “Subsequent Events” (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 will apply with respect to interim or annual reporting periods ending after June 15, 2009. Brigham evaluated subsequent events through August 7, 2009, the date the financial statements were issued for the period ending June 30, 2009.

16

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 and six month periods ended June 30, 2009 and June 30, 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 exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. We focus our activities in provinces where we believe these technologies, including 3-D seismic imaging, horizontal drilling and multi-stage fracture stimulations, can be used to effectively maximize our return on invested capital.

Historically, our exploration and development activities have been focused in the Onshore Gulf Coast, the Anadarko Basin and West Texas. Beginning in late 2005, we began to acquire acreage within the Williston Basin in North Dakota and Montana, and since then have invested in excess of $170��million on drilling, land and seismic in this region. In late 2007, the majority of our drilling capital expenditures shifted from our historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West Texas to the Williston Basin, where we are currently targeting Bakken, Three Forks and Red River objectives. At present, we have approximately 290,000 net leasehold acres in the Williston Basin and have identified over 800 horizontal drilling locations on our acreage.

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 attractive rates of return on our invested capital. Key elements of our business strategy include:

• Focus on Provinces;

• Leverage Our Engineering and Operational Expertise;

• Capitalize on Exploration Successes Through Disciplined Development Activities;

• Enhance Returns Through Operational Control; and

• Internally Generate an Inventory of High Quality Exploratory Prospects.

Overview of Second Quarter 2009

In May 2009, we completed a public offering of common stock pursuant to a shelf registration statement. We sold 36,292,117 shares at a price of $2.75 and received net proceeds of $93.5 million after underwriting fees and offering expenses. We used the net proceeds from the offering to repay $35 million of our outstanding indebtedness under our Senior Credit Facility. We are using the remaining net proceeds to fund our expanded capital budget in 2009 as well as fund a portion of our 2010 capital budget.

In May 2009, in connection with our common stock offering, we increased our 2009 capital budget to $64.5 million from $37.1 million. The increase in our budget was used to fund the restart of our operated Bakken and Three Forks drilling program in the Williston Basin in North Dakota. We anticipate that our revised 2009 budget will allow us to complete three wells that we deferred completing in early 2009 due to low commodity prices, high service costs and high differentials. In addition, our expanded 2009 capital budget is anticipated to allow us to drill two new long lateral horizontal wells in Williams County, North Dakota. To date, we have completed one of the three wells that we deferred completing in early 2009 and have commenced drilling one of the two new long lateral wells. See Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview of Second Quarter 2009 Operational Results — Rocky Mountain Province — Williston Basin.

17

Second quarter 2009 oil and natural gas prices, excluding realized and unrealized derivative hedging results, decreased 60% and 71%, respectively, from the second quarter 2008. In the second quarter 2009, the average sales price that we received for oil, excluding realized and unrealized derivative hedging results, was $49.41 per barrel, which represents a $72.81 per barrel decrease from that in the second quarter 2008. In the second quarter 2009, the average sales price that we received for natural gas, excluding realized and unrealized derivative hedging results, was $3.50 per Mcf, which represents an $8.43 per Mcf decrease from that in the second quarter 2008.

Our second quarter 2009 production averaged 27.2 MMcfe per day, which represents a 10% decrease from the second quarter 2008. The natural production decline from our wells, decreased drilling activity, and the higher than forecasted decline rates associated with our Bayou Postillion wells in Southern Louisiana led to reduced production. During the second quarter 2009, our oil volumes increased by 28% to approximately 164,000 barrels versus that in the second quarter 2008 as a result of our increased activity level in the Williston Basin.

Our second quarter 2009 oil and natural gas revenues, including hedge settlements but excluding unrealized hedging gains and losses, were down $21.0 million, or 59%, compared to that in the second quarter 2008. Oil revenues in the second quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, decreased $6.2 million from the second quarter 2008. Lower oil prices reduced revenues by $11.9 million while both higher production volumes and hedge settlements increased revenues by $4.4 million and $1.4 million, respectively. Natural gas revenues in the second quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, decreased $14.9 million compared to the second quarter 2008. Lower natural gas prices and reduced production volumes decreased revenues $12.3 million and $5.8 million, respectively, while increased hedge settlements increased revenues by $3.3 million.

Second quarter 2009 operating income decreased $8.6 million from that in the second quarter last year. This decrease was attributable to the decline in commodity prices, natural gas volumes and higher lease operating expense. These items were partially offset by higher oil volumes and lower depletion, general and administrative and production tax expenses.

As of June 30, 2009, we had $73.4 million in cash and marketable securities and $404.4 million in total assets.

Overview of Second Quarter 2009 Operational Results

Rocky Mountain Province

Williston Basin

Following our equity offering in May 2009, we restarted our operated drilling program in the Williston Basin. In June, we re-entered the Anderson 28-33 #1H and began drilling the horizontal portion of the wellbore in the Bakken formation. Currently, we are fracture stimulating the well with 24 stages planned. The Anderson is located approximately 2 miles west of our Carkuff 22 #1H discovery. We own an approximate 66% working interest and 55% net revenue interest in the Anderson well.

In late June, we began fracture stimulating the Strobeck 27-34 #1H, which is a long lateral Three Forks well, with 20 stimulation stages. The Strobeck well is located approximately one mile west of our operated Carkuff 22 #1H in Mountrail County, North Dakota. We own an approximate 77% working interest and a 63% revenue interest in the well.

In late July, we began completion operations on the Figaro 29-32 #1H, which is a long lateral Bakken well, with 20 stimulation stages. Currently, we are continuing completion operations. We own an approximate 90% working interest and a 72% revenue interest in the well.

Onshore Gulf Coast Province

Southern Louisiana

In May 2009, we successfully brought on line our third joint venture well with Clayton Williams Energy, Inc., the Breton Sound SL 19054 #1. The Breton Sound well was completed from 60 feet of pay. We own an approximate 50% working interest and a 39% revenue interest in the well.

18

Subsequent Events

On July 24, 2009, we entered into the Fifth Amendment to our Senior Credit Facility. The amendment extended the maturity of the agreement to July 24, 2012, amended our Interest Coverage Ratio (as defined in the Senior Credit Facility), added a Net Leverage Ratio (as defined in the Fifth Amendment) and requires us to maintain $10 million in liquidity until our preferred stock is redeemed in October 2010. Our Interest Coverage Ratio for the four quarters ended as of June 30, 2009 and September 30, 2009 must be a minimum of 2.50 to 1.00, for the four quarters ended as of December 31, 2009 and March 31, 2010 must be a minimum of 2.00 to 1.00 and for the four quarters thereafter must be a minimum of 2.50 to 1.00. Our Net Leverage Ratio beginning with the quarter ended September 30, 2009 through September 30, 2010 must be not greater than 4.50 to 1.00, ending December 31, 2010 and March 31, 2011 must be not greater than 4.25 to 1.00 and thereafter must be not greater than 4.00 to 1.00.

Results for the Three and Six Months Ended June 30, 2009

Comparison of the three month and six month periods ended June 30, 2009 and 2008.

Production volumes

	Three months ended June 30,							Six months ended June 30,
	2009		% Change			2008		2009		% Change			2008
Oil (MBbls)		164		28	%		128		338		38	%		245
Natural gas (MMcf)		1,460		(25	%)		1,947		3,302		(20	%)		4,139
Total (MMcfe)(1)		2,444		(10	%)		2,715		5,328		(5	%)		5,609
Average daily production (MMcfe/d)(2)		27.2		(10	%)		30.2		29.6		(5	%)		31.2
Average daily production (Boe/d)(2)		4,526		(10	%)		5,027		4,933		(5	%)		5,193

(1)	MMcfe is defined as one million cubic feet equivalent of natural gas, determined using the ratio of six MMcf of natural gas to one MBbl of crude oil, condensate or natural gas liquids.
(2)	Average daily production is calculated using 30 days per calendar month.

Natural gas represented 60% of our second quarter 2009 production volumes and 62% of our first six months 2009 production volumes, compared to 72% in the second quarter 2008 and 74% in the first six months 2008.

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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 June 30,									Six months ended June 30,
	2009			% Change			2008			2009			% Change			2008
Oil revenue:
Oil revenue	$	8,105			(48	%)	$	15,640		$	14,055			(48	%)	$	26,797
Oil derivative settlement gains (losses)		(222	)		(86	%)		(1,601	)		860		NM				(2,187	)
Oil revenue including oil derivative settlements	$	7,883			(44	%)	$	14,039		$	14,915			(39	%)	$	24,610
Oil derivative unrealized gains (losses)		(3,034	)		(22	%)		(3,897	)		(4,341	)		5	%		(4,135	)
Oil revenue including derivative settlements and unrealized gains (losses)	$	4,849			(52	%)	$	10,142		$	10,574			(48	%)	$	20,475
Natural gas revenue:
Natural gas revenue	$	5,104			(78	%)	$	23,231		$	12,963			(70	%)	$	42,584
Natural gas derivative settlement gains (losses)		1,508		NM				(1,756	)		7,947		NM				(1,232	)
Natural gas revenue including derivative settlements	$	6,612			(69	%)	$	21,475		$	20,910			(49	%)	$	41,352
Natural gas derivative unrealized gains (losses)		(979	)		(85	%)		(6,653	)		(2,550	)		(78	%)		(11,809	)
Natural gas revenue including derivative settlements and unrealized gains (losses)	$	5,633			(62	%)	$	14,822		$	18,360			(38	%)	$	29,543
Oil and natural gas revenue:
Oil and natural gas revenue	$	13,209			(66	%)	$	38,871		$	27,018			(61	%)	$	69,381
Oil and natural gas derivative settlement gains (losses)		1,286		NM				(3,357	)		8,807		NM				(3,419	)
Oil and natural gas revenue including derivative settlement gains (losses)		14,495			(59	%)		35,514			35,825			(46	%)		65,962
Oil and natural gas derivative unrealized gains (losses)		(4,013	)		(62	%)		(10,550	)		(6,891	)		(57	%)		(15,944	)
Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		10,482			(58	%)		24,964			28,934			(42	%)		50,018
Other revenue		32			(48	%)		62			66			(16	%)		79
Total revenue	$	10,514			(58	%)	$	25,026		$	29,000			(42	%)	$	50,097

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	Three months ended June 30,							Six months ended June 30,
	2009		% Change			2008		2009		% Change			2008
Average oil prices:
Oil price (per Bbl)	$	49.41		(60	%)	$	122.22	$	41.63		(62	%)	$	109.46
Oil price including derivative settlement gains (losses) (per Bbl)		48.06		(56	%)		109.71		44.18		(56	%)		100.53
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	29.56		(63	%)	$	79.25	$	31.32		(63	%)	$	83.64
Average natural gas prices:
Natural gas price (per Mcf)	$	3.50		(71	%)	$	11.93	$	3.93		(62	%)	$	10.29
Natural gas price including derivative settlement gains (losses) (per Mcf)		4.53		(59	%)		11.03		6.33		(37	%)		9.99
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	3.86		(49	%)	$	7.61	$	5.56		(22	%)	$	7.14
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	5.40		(62	%)	$	14.32	$	5.07		(59	%)	$	12.37
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		5.93		(55	%)		13.08		6.72		(43	%)		11.76
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	4.29		(53	%)	$	9.19	$	5.43		(39	%)	$	8.92

	For the three			For the six
	month periods			month periods
	ended June 30,			ended June 30, 2009 and
	2009 and 2008			2008
Change in revenue from the sale of oil
Volume variance impact	$	4,410		$	10,154
Price variance impact		(11,945	)		(22,896	)
Cash settlement of hedging contracts		1,379			3,047
Unrealized hedge gain or loss		863			(206	)
Total change	$	(5,293	)	$	(9,901	)
Change in revenue from the sale of natural gas
Volume variance impact	$	(5,813	)	$	(8,603	)
Price variance impact		(12,314	)		(21,018	)
Cash settlement of hedging contracts		3,264			9,179
Unrealized hedge gain or loss		5,674			9,259
Total change	$	(9,189	)	$	(11,183	)
Change in revenue from the sale of oil and natural gas
Volume variance impact	$	(1,403	)	$	1,551
Price variance impact		(24,259	)		(43,914	)
Cash settlement of hedging contracts		4,643			12,226
Unrealized hedge gain or loss		6,537			9,053
Total change	$	(14,482	)	$	(21,084	)

21

Second quarter 2009 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) decreased $14.5 million when compared to that in the second quarter 2008. The change in revenues was attributable to the following:

• a 62% decrease in pre-hedge per Mcfe sales prices resulted in a $24.3 million decrease in revenues;

• a decrease in natural gas production, which was partially offset by an increase in our oil volumes, resulted in a $1.4 million decrease in oil and natural gas revenues;

• a $1.3 million gain from the settlement of derivative contracts in the second quarter 2009 versus a $3.3 million loss from the settlement of derivative contracts in second quarter 2008 increased revenues by $4.6 million; and

• a $4.0 million unrealized derivative loss in second quarter 2009 versus a $10.5 million unrealized derivative loss in second quarter 2008 increased revenues by $6.5 million.

First six months 2009 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) decreased $21.0 million when compared to that in the first six months 2008. The change in revenues was attributable to the following:

• a 59% decrease in pre-hedge per Mcfe sales prices resulted in a $43.9 million decrease in revenues;

• an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $1.6 million increase in oil and natural gas revenues;

• an $8.8 million gain from the settlement of derivative contracts in the first six months 2009 versus a $3.4 million loss from the settlement of derivative contracts in first six months 2008 increased revenues by $12.2 million; and

• a $6.8 million unrealized derivative loss in first six months 2009 versus a $15.9 million unrealized derivative loss in first six months 2008 increased revenues by $9.1 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.

22

The following table details derivative contracts that settled during the second quarter and first six months 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 June 30,									Six months ended June 30,
	2009			% Change			2008			2009			% Change			2008
Oil collars
Volumes (Bbls)		19,000			(60	%)		47,000			49,000			(47	%)		92,500
Average floor price ($  per Bbl)	$	59.63			(13	%)	$	68.18		$	71.58			10	%	$	64.98
Average ceiling price ($  per Bbl)	$	78.70			(13	%)	$	90.91		$	96.96			10	%	$	88.29
Gain (loss) upon settlement ($ in thousands)	$	45		NM			$	(1,601	)	$	1,127		NM			$	(2,187	)
Oil swaps
Volumes (Bbls)		30,000		NM				—			30,000		NM				—
Average swap price ($  per Bbl)	$	50.75		NM			$	—		$	50.75		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	(267	)	NM			$	—		$	(267	)	NM			$	—
Total oil
Gain (loss) upon settlement ($ in thousands)	$	(222	)		(86	%)	$	(1,601	)	$	860		NM			$	(2,187	)
Natural gas collars
Volumes (MMbtu)		250,000			(82	%)		1,370,000			1,220,000			(58	%)		2,890,000
Average floor price ($  per MMbtu)	$	6.89			(3	%)	$	7.14		$	7.74			3	%	$	7.52
Average ceiling price ($  per MMbtu)	$	8.19			(14	%)	$	9.54		$	9.42			(15	%)	$	11.06
Gain (loss) upon settlement ($ in thousands)	$	676		NM			$	(1,756	)	$	6,931		NM			$	(1,232	)
Natural gas swaps
Volumes (MMbtu)		882,000		NM				—			1,062,000		NM				—
Average swap price ($  per MMbtu)	$	4.438		NM			$	—		$	4.572		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	832		NM			$	—		$	1,016		NM			$	—
Total gas
Gain (loss) upon settlement ($ in thousands)	$	1,508		NM			$	(1,756	)	$	7,947		NM			$	(1,232	)

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 June 30,							Three months ended June 30,
	2009		% Change			2008		2009		% Change			2008
Production costs:
Operating & maintenance	$	1.17		56	%	$	0.75	$	2,853		40	%	$	2,036
Expensed workovers		0.18		20	%		0.15		445		9	%		410
Ad valorem taxes		0.11		175	%		0.04		275		170	%		102
Lease operating expenses	$	1.46		55	%	$	0.94	$	3,573		40	%	$	2,548
Production taxes		0.34		(36	%)		0.53		831		(42	%)		1,441
Production costs	$	1.80		22	%	$	1.47	$	4,404		10	%	$	3,989

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Second quarter 2009 per unit of production costs increased $0.33 per Mcfe, or 22%, when compared to that in the second quarter last year mainly due to the following:

• O&M expense increased $0.42 per Mcfe, or 56%, due to an increase in compressor rental and maintenance, electricity, salt water disposal, surface equipment repair and well service and repair; and

• production taxes decreased $0.19 per Mcfe, or 36%, due to lower commodity prices.

	Unit-of-Production							Amount
	(Per Mcfe)							(In thousands)
	Six months ended June 30,							Six months ended June 30,
	2009		% Change			2008		2009		% Change			2008
Production costs:
Operating & maintenance	$	1.07		55	%	$	0.69	$	5,697		48	%	$	3,858
Expensed workovers		0.21		(5	%)		0.22		1,125		(8	%)		1,224
Ad valorem taxes		0.10		25	%		0.08		550		22	%		452
Lease operating expenses	$	1.38		39	%	$	0.99	$	7,372		33	%	$	5,534
Production taxes		0.31		(37	%)		0.49		1,645		(40	%)		2,724
Production costs	$	1.69		14	%	$	1.48	$	9,017		9	%	$	8,258

First six months 2009 per unit of production costs increased $0.21 per Mcfe, or 14%, when compared to the first six months last year mainly due to the following:

• O&M expense increased $0.38 per Mcfe, or 55%, due to an increase in compressor rental and maintenance, electricity, and salt water disposal; and

• production taxes decreased $0.18 per Mcfe, or 37%, 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 June 30,									Six months ended June 30,
	2009			% Change			2008			2009			% Change			2008
	(In thousands, except per unit measurements)
General and administrative costs	$	4,087			(15	%)	$	4,799		$	7,759			(20	%)	$	9,755
Capitalized general and administrative costs		(1,823	)		(17	%)		(2,203	)		(3,373	)		(26	%)		(4,566	)
General and administrative expenses	$	2,264			(13	%)	$	2,596		$	4,386			(15	%)	$	5,189
General and administrative expense ($  per Mcfe)	$	0.93			(3	%)	$	0.96		$	0.82			(12	%)	$	0.93

Our general and administrative costs for the second quarter 2009 decreased primarily because of a $0.6 million reduction in employee compensation costs associated with our cost cutting measures implemented earlier in the year.

General and administrative costs for the first six months 2009 decreased primarily because of a $2.4 million reduction in employee compensation costs associated with our cost cutting measures implemented earlier in the year. Lower compensation costs were partially offset by $0.4 million in higher legal and audit 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 June 30,							Six months ended June 30,
	2009		% Change			2008		2009		% Change			2008
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	6,233		(50	%)	$	12,405	$	16,066		(35	%)	$	24,848
Depletion of oil and natural gas properties ($ per Mcfe)	$	2.55		(44	%)	$	4.57	$	3.02		(32	%)	$	4.43

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Our depletion expense for the second quarter 2009 was $6.2 million lower than that in the second quarter 2008. This decrease was due to a reduction in our depletion rate associated with our fourth quarter 2008 and first quarter 2009 ceiling test write-downs, which reduced depletion expense by $5.0 million, and reduced production levels, which reduced depletion expense by $1.2 million.

Our depletion expense for the first six months 2009 was $8.7 million lower than that in the first six months 2008. This decrease was due to the aforementioned ceiling test write-downs, which reduced depletion expense by $7.5 million, and our reduced production, which reduced depletion expense by $1.2 million.

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 experienced in the second half of 2008 continued in the first quarter 2009 and was partially responsible for a first quarter 2009 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 natural gas cash price was $3.63 per MMbtu. Lower natural gas prices, combined with the impact from a deferred tax asset that was added to the full cost pool 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 six months 2009 was attributable to the $2.2 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.

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 Facility. 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.

25

	Three months ended June 30,										Six months ended June 30,
	2009			% Change				2008			2009			% Change				2008
	(In thousands)
Interest on Senior Notes	$	3,850				0	%	$	3,850		$	7,700				0	%	$	7,700
Interest on Senior Credit Facility		1,021				194	%		347			2,026				305	%		500
Commitment fees		24				(65	%)		69			45				(66	%)		134
Dividend on mandatorily redeemable preferred stock		151				0	%		151			300				(1	%)		302
Amortization of deferred loan and debt issuance cost		306				21	%		252			581				17	%		498
Other general interest expense		(1	)		NM				—			16			NM				—
Capitalized interest expense		(1,100	)			(7	%)		(1,187	)		(2,290	)			3	%		(2,233	)
Net interest expense	$	4,251				22	%	$	3,482		$	8,378				21	%	$	6,901
Weighted average debt outstanding	$	301,640				47	%	$	205,536		$	308,333				59	%	$	194,178
Average interest rate on outstanding indebtedness (a)		6.7	%						8.6	%		6.6	%						8.9	%

(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.

Second quarter 2009 interest expense was $0.8 million higher than the corresponding period last year primarily due to a $0.7 million increase in interest expense associated with higher levels of outstanding debt on our Senior Credit Facility. Similarly, the higher levels of debt outstanding under our Senior Credit Facility for the first six months of 2009 increased interest expense under the Senior Credit Facility by $1.5 million.

Other income (expense)

Other income (expense) included:

	��	Three months ended June 30,						Six months ended June 30,
		2009			% Change	2008		2009		% Change			2008
		(In thousands)
Other income (expense):
Total other income		$	(33	)	NM	$	96	$	82		(79	%)	$	403

Second quarter 2009 other income (expense) includes a $0.1 million loss from the sale of pipe inventory. First six months 2009 other income (expense) includes $0.2 million in equipment rental income, which was partially offset by the aforementioned pipe inventory loss.

Income taxes.We recorded no deferred federal or state income tax benefit in the second quarter of this year, compared to deferred federal income tax expense of $0.8 million and deferred state income tax expense of $0.1 million in the second quarter last year. We recorded no deferred federal or state income tax benefit for the first six months 2009, compared to deferred federal income tax expense of $1.7 million and deferred state income tax expense of $0.2 million for the first six months 2008. The decreases were primarily due to ceiling test write-downs in the fourth quarter 2008 and in the first quarter 2009. For the first six months 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;

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

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

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

The table below summarizes our 2009 oil and gas capital expenditure budget, the amount spent through June 30, 2009 and the amount of our 2009 oil and gas capital expenditure budget that remains to be spent.

				Amount
	Revised 2009			Spent Through			Amount
	Budget			June 30, 2009			Remaining (a)
	(In millions)
Drilling	$	57.2		$	26.5		$	30.7
Net land and seismic (b)		(4.1	)		(5.7	)		1.6
Capitalized costs (c)		11.0			5.6			5.4
Asset retirement obligation		0.4			0.3			0.1
Total oil and gas capital expenditures (d)	$	64.5		$	26.7		$	37.8

(a)	Calculated based on the revised 2009 capital expenditure budget announced in May 2009 in conjunction with our equity offering less amounts spent through June 30, 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.

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9 5/8% Senior Notes Due 2014

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

The Senior Notes are our unsecured senior obligations, and:

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

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

• are effectively junior in right of payment to all of our and the Guarantors’ existing and future secured indebtedness, including debt of our Senior Credit Facility.

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

Additionally, the Indenture governing the Senior Notes contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the Senior Notes as of June 30, 2009.

Senior Credit Facility

In November 2008, in conjunction with our regularly scheduled semi-annual redetermination, the borrowing base was reset to $145 million. In May 2009, in conjunction with our regularly scheduled semi-annual redetermination and our common stock offering, the borrowing base was reset to $110 million. As of June 30, 2009, we had $110.0 million outstanding under our Senior Credit Facility. On July 24, 2009, our Senior Credit Facility was amended to extend the maturity date from June 2010 to July 24, 2012.

Since the borrowing base for our Senior Credit Facility is redetermined at least semi-annually, the amount of borrowing capacity available to us under our Senior Credit Facility 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 may be required to repay amounts outstanding under our Senior Credit Facility.

Covenants under our Senior Notes preclude us from incurring additional debt under the Senior Credit Facility to the extent our total debt under the Senior Credit Facility exceeds 25% of a calculated proved PV10 value based on year-end prices, as defined in our Indenture, which is referred to as Adjusted Consolidated Net Tangible Assets. 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, we elected to draw down our remaining unused capacity under our Senior Credit Facility before the lower year-end 2008 prices limited our access to this unused capacity and therefore negatively impacted our corporate liquidity.

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Borrowings under our Senior Credit Facility 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 Facility reaches certain percentages of the available borrowing base, as shown below:

Percent of	Eurodollar
Borrowing Base	Rate			Base Rate
Utilized	Advances			Advances(1)
< 25%		2.500	%		1.500	%
25% and < 50%		2.750	%		1.750	%
50% and < 75%		3.000	%		2.000	%
75% and < 90%		3.250	%		2.250	%
³ 90%		3.500	%		2.500	%

(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
< 25%		0.500	%
25% and < 50%		0.500	%
50% and < 75%		0.500	%
75% and < 90%		0.500	%
³ 90%		0.500	%

Our Senior Credit Facility 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 Facility, our current ratio must be at least 1.0 to 1.0. Our current ratio was 3.7 to 1.0 as of June 30, 2009. Pursuant to our Senior Credit Facility, our interest coverage ratio for the four most recent quarters as of June 30, 2009 and September 30, 2009 must be at least 2.5 to 1.0, as of December 31, 2009 and March 31, 2010 must be at least 2.0 to 1.0, and thereafter must be at least 2.5 to 1.0. Our interest coverage ratio for the last twelve-month period ended June 30, 2009 was 4.2 to 1.0. In conjunction with the Fifth Amendment to our Senior Credit Facility, a Net Leverage Ratio (as defined therein) was added. Our Net Leverage Ratio beginning with the quarters ended September 30, 2009 through September 30, 2010 must not be greater than 4.50 to 1.00, ending December 31, 2010 and March 31, 2011 must not be greater than 4.25 to 1.00, and thereafter must not be greater than 4.00 to 1.00. As of June 30, 2009, we were in compliance with all covenant requirements in connection with our Senior Credit Facility.

Mandatorily Redeemable Preferred Stock

As of June 30, 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.

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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.

	Six months ended June 30,
	2009			% Change			2008
	(In thousands)
Net income (loss)	$	(126,031	)	NM			$	3,044
Non-cash items		139,718			214	%		44,516
Changes in working capital and other items		2,260		NM				(4,520	)
Cash flows provided by operating activities	$	15,947			(63	%)	$	43,040
Cash flows used by investing activities		(45,498	)		(46	%)		(84,712	)
Cash flows provided by financing activities		57,594			48	%		38,822
Net increase in cash and cash equivalents	$	28,043		NM			$	(2,850	)

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 six months of 2009, cash flows provided by operating activities decreased by 63% to $15.9 million from the same period last year. The decrease in operating cash flow is primarily attributable to the decreases in commodity prices.

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Analysis of changes in cash flows used in investing activities

	Six months ended June 30,
	2009			% Change			2008
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	26,492			(58	%)	$	62,689
Land and seismic		(5,687	)	NM				19,029
Capitalized cost		5,663			(17	%)		6,799
Capitalized asset retirement obligation		275			108	%		132
Total	$	26,743			(70	%)	$	88,649
Reconciling Items:
Change in accrued drilling costs	$	13,906		NM			$	(3,872	)
Change in short term investments		5,268		NM				—
Other		(419	)		545	%		(65	)
Total Reconciling Items		18,755		NM				(3,937	)
Net cash used in investing activities	$	45,498			(46	%)	$	84,712

Net cash used by investing activities in the first six months 2009 decreased by $39.2 million, or 46%, over the same period in 2008. The reduction was mainly due to the following:

• net land and seismic expenditures decreased by $24.7 million;

• drilling expenditures decreased by $36.2 million;

• capitalized costs decreased by $1.1 million;

• the change in accrued drilling costs increased cash used in investing activities by $17.8 million; and

• the change in short term investments increased cash used in investing activities by $5.3 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first six months of 2009 was 48% greater than the first six months of 2008. During the first six months 2009, we received net proceeds of $93.5 million from our common stock offering and used a portion of the proceeds to repay $35 million of our outstanding indebtedness under our Senior Credit Facility.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the six months ended June 30, 2009 and 2008.

	Shares Issued		Net Proceeds
	(In thousands, except share data)
2009 common stock transactions:
Common stock offering		36,292,117	$	93,523
Exercise of employee stock options		500	$	1
2008 common stock transactions:
Exercise of employee stock options		126,566	$	552

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.

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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 and SEC Rulemaking

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

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This 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 adoption of SFAS 141R did not have a material impact on the financial statements..

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

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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 period ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.

In May 2009, the Financial Accounting Standards Statement of Financial Accounting Standards No. 165 “Subsequent Events” (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 will apply with respect to interim or annual reporting periods ending after June 15, 2009. Brigham evaluated subsequent events through August 7, 2009, the date the financial statements were issued for the period ending June 30, 2009.

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, and our Form 10-Q report for the quarter ended March 31, 2009 and this Form 10-Q report for the quarter ended June 30, 2009, including, but not limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

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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. See Item 1. Condensed Consolidated Financial Statements — Notes 7 and 8 for more details.

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 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 June 30, 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.

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The following tables reflect our open natural gas and oil derivative contracts as of June 30, 2009, the associated volumes and the corresponding weighted average NYMEX floor and cap price. As of August 5, 2009, we had not entered into any commodity derivative contracts subsequent to June 30, 2009.

	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
Natural Gas Costless Collars
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
11/01/09 - 12/31/10		980,000	$	5.15	$	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
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
07/01/09 - 08/31/09		140,000	$	4.745
10/01/09 - 12/31/09		60,000	$	4.900
07/01/09 - 12/31/09		258,000	$	4.440
07/01/09 - 09/30/09		150,000	$	4.090
07/01/09 - 09/30/09		150,000	$	3.960
07/01/09 - 09/30/09		390,000	$	4.000
07/01/09 - 10/31/09		280,000	$	4.030

	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
Oil Costless Collars
07/01/09 - 12/31/09		60,000	$	49.00	$	70.00
01/01/10 - 12/31/10		120,000	$	48.70	$	80.00
07/01/09 - 05/31/10		110,000	$	57.50	$	75.95
06/01/10 - 12/31/10		56,000	$	57.50	$	82.15
01/01/10 - 12/31/10		54,000	$	60.00	$	86.50
01/01/11 - 12/31/11		84,000	$	65.00	$	88.25
07/01/09 - 12/31/09		40,000	$	62.50	$	76.75
01/01/10 - 3/31/10		6,000	$	65.00	$	87.50
07/01/10 - 9/30/10		6,000	$	70.00	$	87.25
10/01/10 - 12/31/10		3,000	$	70.00	$	88.50

	Crude		Swap
	Oil		Price
Settlement Period	(Bbls)		(Nymex)
Oil Swaps
07/01/09 - 12/31/09		60,000	$	50.75

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 30, 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 second quarter of 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

As discussed in Note 4 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

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. One of the purposes of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions. Under ACESA, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to company operations and the refining, processing, and use of oil and gas.

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

Issuer Purchases of Equity Securities

In the second quarter 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
May 2009		3,201	$	3.642
June 2009		12,170	$	3.595
TOTAL		15,371	$	3.605

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

(a) We convened our Annual Stockholders meeting on Thursday, May 28, 2009, in Austin, Texas at 9:00 a.m. local time. Subsequent to the approval of Proposals One, Two, and Three, we adjourned the meeting and the vote on Proposal Four until June 19, 2009. On June 19, 2009, we reconvened the Annual Stockholders meeting.

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(b) Proxies were solicited by our Board of Directors pursuant to Regulation 14A under the Securities Exchange Act of 1934. There were no solicitations in opposition to the Board of Directors’ nominees as listed in the proxy statement and all of such nominees were duly elected.

(c) Out of the total 46,596,425 shares of our common stock outstanding and entitled to vote, 42,295,913 shares were present in person or by proxy at the original annual meeting, representing approximately 91% of our common stock outstanding, and 42,687,853 shares were present in person or by proxy at the reconvened annual meeting, representing approximately 92% of our common stock outstanding. The only matters voted on by our stockholders, as fully described in the definitive proxy materials for the annual meeting, are set forth below. The results were as follows:

1. To elect seven directors to serve until the Annual Meeting of Stockholders in 2010.

					Number of shares
	Number of shares		Number of shares		withholding authority
	voting for election as		voting against		to vote for election as
Nominee	director		election as director		director
Ben M. “Bud” Brigham		38,103,665		—		4,192,247
David T. Brigham		38,262,336		—		4,033,576
Harold D. Carter		31,999,180		—		10,296,732
Stephen C. Hurley		38,294,290		—		4,001,622
Stephen P. Reynolds		38,282,630		—		4,013,282
Hobart A. Smith		37,771,348		—		4,524,564
Scott W. Tinker, Ph.D.		34,953,279		—		7,342,633

2. To approve the appointment of KPMG LLP for the year ending December 31, 2009.

For	41,450,505
Against	759,475
Abstained	85,927

3. To consider and vote on a proposal to approve an amendment to the 1997 Incentive Plan to increase the number of shares of common stock available under the plan.

For	27,212,939
Against	2,636,151
Abstained	71,247
Broker non-votes	12,375,576

4. To consider and vote on a proposal to approve and ratify certain non-plan stock options granted to non-employee directors.

For	20,732,779
Against	9,532,223
Abstained	182,272
Broker non-votes	12,240,579

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

3.1 Certificate of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference)

3.2 Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to Brigham’s Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated herein by reference)

3.3 Bylaws, as amended through May 28, 2009 (incorporated by reference to Exhibit 3.5 to Brigham’s Current Report on Form 8-K filed May 28, 2009)

3.4 Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated June 14, 2006 (filed as Exhibit 3.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference)

4.1 Form of Common Stock Certificate (filed as Exhibit 4.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference)

4.2 Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference)

4.3 Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference)

4.4 Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2002 (filed March 31, 2003) and incorporated herein by reference)

4.5 Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit 99.2 to Brigham’s Current Report on Form 8-K (filed July 20, 2004), and incorporated herein by reference)

4.6 Indenture, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)

4.7 Notations of Guarantees, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)

4.8 Rule 144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)

4.9 Reg S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.4 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)

4.10 Notations of Guarantees dated as of April 9, 2007, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference)

4.11 Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference)

4.12 Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 on Form 8-K filed to Brigham’s Current Report on April 13, 2007 and incorporated in by reference)

4.13 Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)

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4.14	Certificate of Designations of Series C Junior Preferred Stock of Brigham Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
10.46	Fourth Amendment to the Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.43 to Brigham’s Current Report on Form 8-K filed May 28, 2009)
10.47*	1997 Incentive Plan, as amended through May 28, 2009 (incorporated by reference to Exhibit 10.44 to Brigham’s Current Report on Form 8-K filed May 28, 2009)
10.48*	Amendment to Options Agreement
10.49*	Form of Non-qualified Stock Option Grant for Non-employee Directors
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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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on August 7, 2009.

BRIGHAM EXPLORATION COMPANY
By:	/s/ BEN M. BRIGHAM
	Ben M. Brigham
	Chief Executive Officer, President and Chairman of the Board
By:	/s/ EUGENE B. SHEPHERD, JR.
	Eugene B. Shepherd, Jr.
	Executive Vice President and Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.	Description
3.1	Certificate of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference)
3.2	Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to Brigham’s Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated herein by reference)
3.3	Bylaws, as amended through May 28, 2009 (incorporated by reference to Exhibit 3.5 to Brigham’s Current Report on Form 8-K filed May 28, 2009)
3.4	Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated June 14, 2006 (filed as Exhibit 3.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference)
4.1	Form of Common Stock Certificate (filed as Exhibit 4.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference)
4.2	Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference)
4.3	Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference)
4.4	Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2002 (filed March 31, 2003) and incorporated herein by reference)
4.5	Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit 99.2 to Brigham’s Current Report on Form 8-K (filed July 20, 2004), and incorporated herein by reference)
4.6	Indenture, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)
4.7	Notations of Guarantees, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)
4.8	Rule 144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)
4.9	Reg S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.4 to Brigham’s Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference)
4.10	Notations of Guarantees dated as of April 9, 2007, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference)
4.11	Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference)
4.12	Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 on Form 8-K filed to Brigham’s Current Report on April 13, 2007 and incorporated in by reference)
4.13	Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
4.14	Certificate of Designations of Series C Junior Preferred Stock of Brigham Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)
10.46	Fourth Amendment to the Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.43 to Brigham’s Current Report on Form 8-K filed May 28, 2009)
10.47*	1997 Incentive Plan, as amended through May 28, 2009 (incorporated by reference to Exhibit 10.44 to Brigham’s Current Report on Form 8-K filed May 28, 2009)
10.48*	Amendment to Options Agreement
10.49*	Form of Non-qualified Stock Option Grant for Non-employee Directors
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.