Filed by Bowne Pure Compliance

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2008


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

For the transition period from to

Commission File Number: 000-22433

Brigham Exploration Company

(Exact name of registrant as specified in its charter)


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

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

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

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

Yes þ No o

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


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

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

Yes o No þ


Class		Outstanding
Common Stock, par value $.01 per share as of July 29, 2008		46,323,976

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

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


	June 30,			December 31,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	11,013		$	13,863
Accounts receivable		25,653			14,609
Derivative assets		—			1,416
Other current assets		4,022			2,617

Total current assets		40,688			32,505

Oil and natural gas properties, using the full cost method including
Proved, net		484,879			448,663
Unproved		89,129			61,544

		574,008			510,207

Other property and equipment, net		1,082			1,034
Deferred loan fees, net		3,466			3,687
Other noncurrent assets		1,705			995

Total assets	$	620,949		$	548,428


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	17,916		$	12,301
Royalties payable		9,310			5,978
Accrued drilling costs		18,713			14,841
Participant advances received		1,514			2,095
Derivative liabilities		15,874			1,812
Other current liabilities		4,533			4,691

Total current liabilities		67,860			41,718


Senior Notes		158,611			158,492
Senior credit facility		48,600			10,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at June 30, 2008 and December 31, 2007		10,101			10,101
Deferred income taxes		43,554			41,625
Other taxes payable		2,162			2,162
Other noncurrent liabilities		6,188			5,303

Commitments and contingencies (Note 3)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,488,705 and 45,304,139 shares issued and 45,363,423 and 45,197,303 shares outstanding at June 30, 2008 and December 31, 2007, respectively		455			453
Additional paid-in capital		209,583			207,526
Treasury stock, at cost; 125,282 and 106,836 shares at June 30, 2008 and December 31, 2007, respectively		(996	)		(854	)
Accumulated other comprehensive income (loss)		—			115
Retained earnings		74,831			71,787

Total stockholders’ equity		283,873			279,027

Total liabilities and stockholders’ equity	$	620,949		$	548,428

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

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007

Revenues:
Oil and natural gas sales	$	38,871		$	34,283		$	69,381		$	62,769
Gain (loss) on derivatives, net		(13,907	)		2,264			(19,363	)		(1,228	)
Other revenue		62			29			79			56

		25,026			36,576			50,097			61,597

Costs and expenses:
Lease operating		2,548			3,325			5,534			5,894
Production taxes		1,441			551			2,724			622
General and administrative		2,596			2,281			5,189			4,459
Depletion of oil and natural gas properties		12,405			16,612			24,848			30,571
Impairment of oil and natural gas properties		—			6,505			—			6,505
Depreciation and amortization		158			158			305			321
Accretion of discount on asset retirement obligations		89			94			180			211

		19,237			29,526			38,780			48,583

Operating income		5,789			7,050			11,317			13,014


Other income (expense):
Interest income		39			134			114			265
Interest expense, net		(3,482	)		(3,678	)		(6,901	)		(7,095	)
Other income (expense)		96			712			403			902

		(3,347	)		(2,832	)		(6,384	)		(5,928	)

Income before income taxes		2,442			4,218			4,933			7,086

Income tax expense:
Current		—			—			—			—
Deferred		(925	)		(1,908	)		(1,889	)		(2,903	)

		(925	)		(1,908	)		(1,889	)		(2,903	)

Net income	$	1,517		$	2,310		$	3,044		$	4,183


Net income per share available to common stockholders:
Basic	$	0.03		$	0.05		$	0.07		$	0.09

Diluted	$	0.03		$	0.05		$	0.07		$	0.09


Weighted average shares outstanding:
Basic		45,332			45,080			45,296			45,067

Diluted		46,444			45,455			46,171			45,478

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

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

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


											Accumulated
					Additional						Other					Total
	Common Stock				Paid In			Treasury			Comprehensive			Retained		Stockholders’
	Shares		Amounts		Capital			Stock			Income (Loss)			Earnings		Equity
Balance, December 31, 2007		45,304	$	453	$	207,526		$	(854	)	$	115		$	71,787	$	279,027
Comprehensive income:
Net income		—		—		—			—			—			3,044		3,044
Net (gains) losses included in net income		—		—		—			—			(177	)		—		(177	)
Tax benefit (provision) related to hedges		—		—		—			—			62			—		62

Comprehensive income																	2,929
Exercises of employee stock options		127		1		551			—			—			—		552
Vesting of restricted stock		58		1		(1	)		—			—			—		—
Stock based compensation		—		—		1,507			—			—			—		1,507
Repurchases of common stock		—		—		—			(142	)		—			—		(142	)


Balance, June 30, 2008		45,489	$	455	$	209,583		$	(996	)	$	—		$	74,831	$	283,873

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

PART I — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

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


	Six Months Ended
	June 30,
	2008			2007

Cash flows from operating activities:
Net income	$	3,044		$	4,183
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		24,848			30,571
Impairment of oil and natural gas properties		—			6,505
Depreciation and amortization		305			321
Stock based compensation		818			838
Amortization of deferred loan fees and debt issuance costs		528			461
Market value adjustment for derivative instruments		15,944			2,658
Accretion of discount on asset retirement obligations		180			211
Deferred income taxes		1,889			2,903
Other noncash items		4			—
Changes in operating assets and liabilities:
Accounts receivable		(11,044	)		(2,932	)
Other current assets		(1,303	)		816
Accounts payable		5,615			(2,585	)
Royalties payable		3,332			2,232
Participant advances received		(581	)		(785	)
Other current liabilities		(158	)		1,478
Other noncurrent assets		(330	)		514
Other noncurrent liabilities		(51	)		(113	)

Net cash provided by operating activities		43,040			47,276


Cash flows from investing activities:
Additions to oil and natural gas properties		(83,956	)		(72,919	)
Additions to other property and equipment		(357	)		(563	)
Decrease (increase) in drilling advances paid		(399	)		(8	)

Net cash used by investing activities		(84,712	)		(73,490	)


Cash flows from financing activities:
Proceeds from senior notes offering		—			34,825
Increase in senior credit facility		38,600			42,700
Repayment of senior credit facility		—			(42,500	)
Deferred loan fees paid and equity costs		(188	)		(917	)
Proceeds from exercise of employee stock options		552			223
Repurchases of common stock		(142	)		(134	)

Net cash provided by financing activities		38,822			34,197

Net increase (decrease) in cash and cash equivalents		(2,850	)		7,983
Cash and cash equivalents, beginning of year		13,863			4,300

Cash and cash equivalents, end of period	$	11,013		$	12,283

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Organization and Nature of Operations

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

2. Basis of Presentation

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

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

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

3. Commitments and Contingencies

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

As of June 30, 2008, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.

4. Net Income Available Per Common Share

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2008 and 2007 are as follows (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007

Weighted average common shares outstanding — basic		45,332		45,080		45,296		45,067
Plus: Potential common shares
Stock options and restricted stock		1,112		375		875		411

Weighted average common shares outstanding — diluted		46,444		45,455		46,171		45,478


Stock options excluded from diluted EPS due to the anti-dilutive effect		327		2,617		485		2,547

5. Income Taxes

The income tax expense (benefit) for the six months ended June 30, 2008 and 2007 consists of the following (in thousands):


	June 30,		June 30,
	2008		2007

Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		1,707		2,761
State		182		142

	$	1,889	$	2,903

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

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


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

Unrecognized tax benefits at June 30, 2008	$	2,162

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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

6. Derivative Instruments and Hedging Activities

Brigham utilizes various commodity 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

Cash flow hedges

Historically, all derivative positions that qualified for hedge accounting were designated on the date Brigham entered into the contract as a hedge against the variability in cash flows associated with the forecasted sale of future oil and gas production. Brigham’s cash flow hedges consisted of costless collars (purchased put options and written call options). The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums paid or received when Brigham entered into these option agreements. The cash flow hedges were valued at the end of each period and adjustments to the fair value of the contract prior to settlement were recorded on the consolidated statement of stockholders’ equity as other comprehensive income. Upon settlement, the gain (loss) on the cash flow hedge was recorded as an increase or decrease in revenue on the consolidated statement of operations.

On October 1, 2006, Brigham de-designated all derivatives that were previously classified as cash flow hedges and, in addition, Brigham elected not to designate any additional 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. Any realized and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the consolidated statement of operations rather than as a component of other comprehensive income or as other income (expense).

Brigham 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, 2008 and 2007:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
*Natural Gas*
Average price per Mcf realized excluding gas hedging results	$	11.93		$	7.80		$	10.29		$	7.58
Average price per Mcf including gas hedging settlement results	$	11.03		$	7.80		$	9.99		$	7.78
Increase (decrease) in revenue, in thousands	$	(1,756	)	$	6		$	(1,232	)	$	1,317
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	7.61		$	8.49		$	7.14		$	7.44
Increase (decrease) in revenue, in thousands	$	(8,409	)	$	2,405		$	(13,041	)	$	(847	)
*Oil*
Average price per Bbl realized excluding oil hedging results	$	122.22		$	62.25		$	109.46		$	58.44
Average price per Bbl including oil hedging settlement results	$	109.71		$	62.25		$	100.53		$	58.91
Increase (decrease) in revenue, in thousands	$	(1,601	)	$	—		$	(2,187	)	$	113
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	79.25		$	61.05		$	83.64		$	56.85
Increase (decrease) in revenue, in thousands	$	(5,498	)	$	(141	)	$	(6,322	)	$	(381	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at June 30, 2008, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
07/01/08 – 07/31/08		30,000			$	7.00	$	9.25
07/01/08 – 09/30/08		210,000			$	6.75	$	9.75
07/01/08 – 09/30/08		90,000			$	7.00	$	8.35
07/01/08 – 09/30/08		270,000			$	7.00	$	9.68
07/01/08 – 10/31/08		200,000			$	7.25	$	10.40
07/01/08 – 07/31/08		50,000			$	7.50	$	10.20
07/01/08 – 07/31/08		20,000			$	8.50	$	10.40
07/01/08 – 09/30/08		60,000			$	7.25	$	9.53
07/01/08 – 09/30/08		90,000			$	6.75	$	9.62
08/01/08 – 12/31/08		400,000			$	9.75	$	11.50
04/01/09 – 09/30/09		120,000			$	7.25	$	9.80
10/01/08 – 03/31/09		180,000			$	8.00	$	10.20
10/01/08 – 03/31/09		300,000			$	8.00	$	11.20
10/01/08 – 03/31/09		300,000			$	7.75	$	9.82
01/01/09 – 03/31/09		220,000			$	10.25	$	12.25
04/01/09 – 09/30/09		420,000			$	8.00	$	10.70
04/01/09 – 09/30/09		300,000			$	7.00	$	9.73
*Oil Costless Collars*
07/01/08 – 10/31/08				12,000	$	65.70	$	90.00
07/01/08 – 12/31/08				12,000	$	57.50	$	75.50
07/01/08 – 12/31/08				12,000	$	85.00	$	117.00
07/01/08 – 12/31/08				12,000	$	57.50	$	76.00
07/01/08 – 10/31/08				24,000	$	90.00	$	120.00
07/01/08 – 08/31/08				4,000	$	65.00	$	80.60
11/01/08 – 12/31/08				8,000	$	87.75	$	120.00
11/01/08 – 06/30/09				24,000	$	62.00	$	81.75
01/01/09 – 03/31/09				21,000	$	86.50	$	120.00

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMBTU)

Nymex

Natural Gas Three Way Costless Collars

10/01/08 – 03/31/09

300,000

8.00

10.35

5.50

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

7. Fair Values

Effective January 1, 2008, the fair values of Brigham’s derivative financial instruments also reflect Brigham’s estimate of the default risk of the parties in accordance with Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157). Under SFAS 157, the fair value of a derivative asset would reflect an estimate of the counterparties’ default risk and the fair value of a derivative liability would reflect an estimate of Brigham’s default risk. The fair value of Brigham’s derivative financial instruments is determined based on 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, 2008 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2007			(Level 1)		(Level 2)			(Level 3)
Current derivative liabilities	$	(1,812	)	$	—	$	(15,874	)	$	—
Other non-current liabilities		(256	)		—		(880	)		—
Current derivative assets		1,416			—		—			—
Other non-current assets		25			—		6			—

	$	(627	)	$	—	$	(16,748	)	$	—

8. 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 interest capitalized 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 writedown to the extent of such excess. A ceiling test writedown 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 writedown 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 June 2007 ($6.80 per MMBtu for Henry Hub gas and $70.47 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 $4.1 million, net of tax. As a result, Brigham was required to record a writedown of the net capitalized costs of its oil and gas properties in the amount of $4.1 million, net of tax, at June 30, 2007.

Based on oil and gas prices in effect on June 30, 2008 ($13.10 per MMBtu for Henry Hub natural gas and $140.00 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, 2008.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

9. 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 “Guarantors”). 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, 2008, Brigham was in compliance with all covenants under the indenture.

10. 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, 2008 and 2007 (in thousands):


	Six Months Ended
	June 30,
	2008			2007

Beginning asset retirement obligations	$	5,047		$	5,002
Liabilities incurred for new wells placed on production		132			228
Liabilities settled		(50	)		(40	)
Accretion of discount on asset retirement obligations		180			211

	$	5,309		$	5,401

11. Stock Based Compensation

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The estimated fair value of the options granted during the six months ended June 30, 2008 and 2007 were 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, 2008 and 2007:


	2008			2007
Risk-free interest rate		3.0	%		4.6	%
Expected life (in years)		5.0			5.0
Expected volatility		47	%		49	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	4.70		$	2.97

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 based on the historical exercise data of Brigham’s option grants with the guidance of Staff Accounting Bulletin No. 107 and Staff Accounting Bulletin No. 110 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, 2008 and 2007.

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,
	2008			2007			2008			2007

Pre-tax stock based compensation expense	$	744		$	758		$	1,507		$	1528
Capitalized stock based compensation		(340	)		(341	)		(689	)		(690	)
Tax benefit		(141	)		(146	)		(286	)		(293	)

Stock based compensation expense, net	$	263		$	271		$	532		$	545

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 5,915,414 or 15% of the total number of shares of common stock outstanding. At June 30, 2008, approximately 630,563 shares remain available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one stock option grant, options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham’s common stock on the date of grant, vest over five years and have a contractual life of seven years.

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

The following table summarizes option activity under the incentive plans for the six months ended June 30:


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

Options outstanding at the beginning of the year		3,046,166		$	7.14		3,243,566		$	7.08
Granted		18,000		$	10.56		35,000		$	6.17
Forfeited or cancelled		(64,800	)	$	7.83		(124,300	)	$	8.23
Exercised		(126,566	)	$	4.36		(55,000	)	$	4.06

Options outstanding at the end of the quarter		2,872,800		$	7.27		3,099,266		$	7.07

Options exercisable at the end of the quarter		1,760,000		$	6.79		1,439,866		$	6.18

The weighted-average grant-date fair value of share options granted during the six months ended June 30, 2008 and 2007 was $4.70 and $2.97, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2008 and 2007 was $578,868 and $117,798, respectively.

The following table summarizes information about stock options outstanding and exercisable at June 30, 2008:


	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	2008		Contractual Life	Exercise Price		2008		Contractual Life	Exercise Price
$3.05 to $3.41		137,200	0.5 years	$	3.35		137,200	0.5 years	$	3.35
3.66 to 5.08		353,700	1.2 years	$	4.31		351,700	1.2 years	$	4.31
6.10 to 6.73		1,226,000	3.4 years	$	6.50		708,800	2.7 years	$	6.62
7.22 to 8.84		792,900	3.7 years	$	8.47		412,300	3.2 years	$	8.65
8.93 to 12.31		363,000	4.3 years	$	11.62		150,000	4.2 years	$	11.45

$3.05 to $12.31		2,872,800	3.2 years	$	7.27		1,760,000	2.5 years	$	6.79

The aggregate intrinsic value of options outstanding and exercisable at June 30, 2008 was $24.5 million and $15.9 million, respectively. The aggregate intrinsic value represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the quarter and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on June 30, 2008. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

As of June 30, 2008 there was approximately $3.2 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.9 years.

Restricted Stock

During the six months ended June 30, 2008 and 2007, Brigham issued 109,000 and 105,000, 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, 2008, there was approximately $3.5 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 4.9 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 six months ended June 30:


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

Restricted shares outstanding at the beginning of the year		653,623		$	7.16		391,367		$	8.60
Shares granted		109,000		$	8.40		105,000		$	7.13
Lapse of restrictions		(58,000	)	$	5.39		(55,000	)	$	8.12
Forfeitures		(29,940	)	$	6.58		(25,320	)	$	5.23

Shares outstanding at the end of the quarter		674,683		$	7.54		416,047		$	8.71

12. 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,
	2008		2007			2008			2007

Net income	$	1,517	$	2,310		$	3,044		$	4,183
Net (gains) losses included in net income		—		(69	)		(177	)		(1,163	)
Tax benefits (provisions) related to cash flow hedges		—		24			62			407

Other Comprehensive Income, net	$	1,517	$	2,265		$	2,929		$	3,427

13. New Accounting Pronouncements

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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

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

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

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

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

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

The following updates information as to our financial condition provided in our 2007 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month and six month periods ended June 30, 2008 and June 30, 2007. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the “Glossary of Oil and Gas Terms” provided in our 2007 Annual Report on Form 10-K. Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes hereto.

General Overview

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

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

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

•

Focus on Core Provinces and Trends;

•

Internally Generate Inventory of High Quality Exploratory Prospects;

•

Leverage Our Operational Expertise;

•

Evaluate and Selectively Pursue New Potential Plays;

•

Capitalize on Exploration Successes Through Development of Our Field Discoveries;

•

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

•

Enhance Returns Through Operational Control.

Overview of Second Quarter and First Six Months 2008 Financial Results

NYMEX natural gas prices increased 43% and 29%, respectively, during the second quarter and first six months of 2008 from the comparable periods last year. Natural gas prices were strong throughout the second quarter because of record oil prices, increased electrical generating usage due to summer air conditioning needs and higher demand for liquefied natural gas (LNG) imports from Asian and European markets, which diverted cargoes from the U.S. These factors caused second quarter NYMEX spot prices to exceed prices from last year’s heating season and rise to their highest level since the aftermath of Hurricane Katrina in 2005. Though prices were relatively stable during the second quarter, volatility should increase for the remainder of the year due to the winter heating season. In particular, large fluctuations can be expected each Thursday as the Energy Information Administration (EIA) reports weekly natural gas storage statistics at that time. Excluding realized and unrealized derivative hedging results, the average sales price that we received for natural gas in the second quarter and first six months of 2008 was $11.93 and $10.29 per Mcf, respectively, which represents a $4.13 per Mcf increase from the second quarter 2007 and a $2.71 per Mcf increase from the first six months of 2007. Excluding realized and unrealized derivative hedging results, the average sales price that we received for oil in the second quarter and first six months of 2008 was $122.22 and $109.46 per Bbl, respectively, which represents a $59.97 per Bbl increase from the second quarter 2007 and a $51.02 per Bbl increase from the first six months of 2007.

Daily production for the second quarter 2008 averaged 30.2 MMcfe, down 35% from the second quarter 2007 and down 6% sequentially from the first quarter 2008. Daily production for the first six months of 2008 averaged 31.2 MMcfe per day, down 29% from the first half of 2007. The decrease in our production volumes was primarily attributable to the natural decline in our Southern Louisiana wells and the fact that these wells were shut in from April 18^th to May 19^th due to flooding in the Atchafalaya Basin.

Second quarter operating income decreased 18% to $5.8 million from last year’s second quarter. The primary drivers behind the decrease in operating income were the decrease in our production volumes, unrealized hedging losses and cash settlement losses on our hedging contracts. These factors were partially offset by higher oil and natural gas prices, lower lease operating expense, lower depletion expense and the absence of an impairment charge as compared to the second quarter 2007. For the first half of 2008, operating income decreased 13% from the comparable period last year to $11.3 million. The drivers behind the first half 2008 decrease in operating income were consistent with those experienced during the second quarter 2008.

For the quarter ended June 30, 2008, we spent $43.1 million on oil and gas capital expenditures, which represents a 48% increase from the second quarter 2007 and a 5% decrease from the first quarter 2008.

As of June 30, 2008, we had $11.0 million in cash and $620.9 million in total assets. Our net debt to book capitalization ratio was 43%, which is calculated as debt plus preferred stock divided by book equity plus debt plus preferred stock.

Overview of Second Quarter 2008 Operational Results

Rocky Mountain Province

Williston Basin

In July, we announced the successful completion of the sidetrack of our Mrachek 15-22 #1H well, located west of the Nesson Anticline, at an early flowing production rate of approximately 727 barrels of oil equivalent per day. Over a sixteen day period during the second half of May the well averaged approximately 331 barrels of oil equivalent per day. Since that time the well has been periodically shut in, but was recently brought back on line and was flowing approximately 166 barrels of oil and 115 Mcfg per day. In 2006, we drilled the original Mrachek well, but due to operational problems the well was never stimulated.

We also announced the successful completion of our first well in the North Stanley area of Mountrail County, North Dakota, the Johnson 33 #1H, at an early peak flowing rate of 618 barrels of oil equivalent per day. Prior to July 11^th, the Johnson 33 #1H flowed oil intermittently as production was apparently hampered by numerous sand plugs in the borehole. Subsequent to a portion of the lateral being cleaned out, the well flowed at an early peak rate of approximately 568 barrels of oil and 300 Mcf of natural gas per day and over a three day period the well flowed at an average rate of approximately 515 barrels of oil and 267 Mcf of natural gas per day.

We successfully completed our third Ross Area well, the Manitou State 36 #1H. The Manitou State 36 #1H produced at an initial rate of approximately 272 barrels of oil and 200 Mcf of natural gas per day in June. After being placed on rod pump in July, the well was producing 240 barrels of oil per day.

We also successfully completed our fourth Ross area well, the Carkuff 22 #1H. We announced the well flowed at an early rate of 1,110 barrels of oil per day.

In July, we announced that we were expanding our operations in the Williston Basin by picking up a second Brigham-operated rig likely during September. Current plans include drilling two consecutive horizontal Bakken wells west of the Nesson Anticline in McKenzie and Williams Counties, North Dakota, to capitalize on the apparent success achieved with the Mrachek 15-22 #1H well.

Powder River Basin

In November 2007, we spud the Krejci Federal #1-32H well, which is proximate to our first well in the basin, the Krejci Federal 29 #3H. In June, we announced that the well was flowing approximately 25 barrels of oil per day. We do not currently have any plans to drill additional Powder River Basin wells as a part of our revised 2008 capital expenditures budget that was announced on July 15^th.

Onshore Gulf Coast Province

Vicksburg Trend

In June, we successfully completed the Sullivan F-35 in our Triple Crowne Field at an initial rate of approximately 6.8 MMcfe per day. The Sullivan F-35 is a Dawson Sand completion, which likely added two additional proved undeveloped locations to our existing drilling inventory.

Also in June, we completed the Sullivan C-39 in our Home Run Field at an initial rate of approximately 3.9 MMcfe per day. The Sullivan C-39 was completed in the Vicksburg 8 and Lower Vicksburg 7 intervals. The best apparent pay, in the Vicksburg 6 and Upper 7 intervals, remains behind pipe for future completion.

Southern Louisiana Trend

In December 2007, we entered into a joint venture to operate the drilling of at least six prospects over the next 18 months. Five of these prospects have been planned for 2008 and target 3-D delineated, primarily amplitude related prospects at depths of 9,000 to 10,500 feet in Plaquemines and Saint Bernard Parishes.

Our first joint venture well, Main Pass SL 18826 #1, encountered approximately 100 feet of apparent Miocene pay in four intervals at depths of between 7,140 and 7,680 feet. All intervals were commingled and production tested at a rate of approximately 15.4 MMcf of natural gas per day. We anticipate production to sales by late August.

Our second joint venture well, the Chandeleur Sound SL 19312 #1, was recently logged and encountered approximately 24 feet of apparent pay. The Chandeleur Sound SL 19312 #1 was flow tested at a rate of approximately 2.7 MMcf of natural gas per day. We anticipate production to sales in November.

Our third joint venture well, the Breton Sound SL 19054 #1, was recently logged and encountered 60 feet of apparent pay. Approximately 15 feet of pay has apparent porosities greater than 20%, while 45 feet of pay has porosities ranging from 18% to 20%. Production testing operations are underway and the well is expected to be producing to sales by late October.

Our fourth joint venture well, the Romere Pass BLM 013045 #1, is expected to commence in either September or October.

Second Quarter and First Six Months 2008 Results

Comparison of the three month and six month periods ended June 30, 2008 and 2007.

Production volumes


	Three months ended June 30,							Six months ended June 30,
	2008		% Change			2007		2008		% Change			2007

Oil (MBbls)		128		8	%		118		245		3	%		239
Natural gas (MMcf)		1,947		(44	%)		3,457		4,139		(36	%)		6,439
Total (MMcfe)(1)		2,715		(35	%)		4,163		5,609		(29	%)		7,875
Average daily production (MMcfe/d)(2)		30.2					46.3		31.2					43.8


(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 calculated using 30 days per calendar month.

Natural gas represented 72% of our second quarter 2008 production volumes and 74% of our first six months 2008 volumes, compared to 83% in the second quarter of last year and 82% in the first six months of last year.

Revenue, Commodity Prices and Hedging

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


	Three months ended June 30,									Six months ended June 30,
	2008			% Change			2007			2008			% Change			2007

Oil revenue:
Oil revenue	$	15,640			113	%	$	7,328		$	26,797			92	%	$	13,991
Oil derivative settlement gains (losses)		(1,601	)	NM				—			(2,187	)	NM				113

Oil revenue including oil derivative settlements	$	14,039			92	%	$	7,328		$	24,610			74	%	$	14,104
Oil derivative unrealized gains (losses)		(3,897	)		2,664	%		(141	)		(4,135	)		737	%		(494	)

Oil revenue including derivative settlements and unrealized gains (losses)	$	10,142			41	%	$	7,187		$	20,475			50	%	$	13,610
Natural gas revenue:
Natural gas revenue	$	23,231			(14	%)	$	26,955		$	42,584			(13	%)	$	48,778
Natural gas derivative settlement gains (losses)		(1,756	)	NM				6			(1,232	)	NM				1,317

Natural gas revenue including derivative settlements	$	21,475			(20	%)	$	26,961		$	41,352			(17	%)	$	50,095
Natural gas derivative unrealized gains (losses)		(6,653	)	NM				2,399			(11,809	)		446	%		(2,164	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	14,822			(50	%)	$	29,360		$	29,543			(38	%)	$	47,931
Oil and natural gas revenue:
Oil and natural gas revenue	$	38,871			13	%	$	34,283		$	69,381			11	%	$	62,769
Oil and natural gas derivative settlement gains (losses)		(3,357	)	NM				6			(3,419	)	NM				1,430

Oil and natural gas revenue including derivative settlement gains (losses)		35,514			4	%		34,289			65,962			3	%		64,199
Oil and natural gas derivative unrealized gains (losses)		(10,550	)	NM				2,258			(15,944	)		500	%		(2,658	)

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		24,964			(32	%)		36,547			50,018			(19	%)		61,541
Other revenue		62			114	%		29			79			41	%		56

Total revenue	$	25,026			(32	%)	$	36,576		$	50,097			(19	%)	$	61,597


	Three months ended June 30,							Six months ended June 30,
	2008		% Change			2007		2008		% Change			2007

Average oil prices:
Oil price (per Bbl)	$	122.22		96	%	$	62.25	$	109.46		87	%	$	58.44
Oil price including derivative settlement gains (losses) (per Bbl)		109.71		76	%		62.25		100.53		71	%		58.91
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	79.25		30	%	$	61.05	$	83.64		47	%	$	56.85
Average natural gas prices:
Natural gas price (per Mcf)	$	11.93		53	%	$	7.80	$	10.29		36	%	$	7.58
Natural gas price including derivative settlement gains (losses) (per Mcf)		11.03		41	%		7.80		9.99		28	%		7.78
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	7.61		(10	%)	$	8.49	$	7.14		(4	%)	$	7.44
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	14.32		74	%	$	8.24	$	12.37		55	%	$	7.97
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		13.08		59	%		8.24		11.76		44	%		8.15
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	9.19		5	%	$	8.78	$	8.92		14	%	$	7.81


	For the three			For the six
	month periods			month periods
	ended June 30,			ended June 30,
	2008 and 2007			2008 and 2007

Change in revenue from the sale of oil
Volume variance impact	$	638		$	315
Price variance impact		7,674			12,491
Cash settlement of hedging contracts		(1,601	)		(2,300	)
Unrealized hedge gain or loss		(3,756	)		(3,641	)

Total change	$	2,955		$	6,865

Change in revenue from the sale of natural gas
Volume variance impact	$	(11,771	)	$	(17,402	)
Price variance impact		8,047			11,208
Cash settlement of hedging contracts		(1,762	)		(2,549	)
Unrealized hedge gain or loss		(9,052	)		(9,645	)

Total change	$	(14,538	)	$	(18,388	)

Change in revenue from the sale of oil and natural gas
Volume variance impact	$	(11,133	)	$	(17,087	)
Price variance impact		15,721			23,699
Cash settlement of hedging contracts		(3,363	)		(4,849	)
Unrealized hedge gain or loss		(12,808	)		(13,286	)

Total change	$	(11,583	)	$	(11,523	)

Second quarter 2008 oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), decreased 32%, when compared to the second quarter 2007. The change in revenues was attributable to the following:

•

a 74% increase in the sales price we received for our oil and natural gas resulted in a $15.7 million increase in revenues;

•

a 35% decrease in production volumes for the quarter resulted in a $11.1 million decrease in oil and natural gas revenues;

•

a $3.4 million loss from the settlement of derivative contracts in the second quarter 2008 versus a slight gain from the settlement of derivative contracts in second quarter 2007 decreased revenues by $3.4 million; and

•

a $10.6 million unrealized derivative loss in second quarter 2008 versus a $2.3 million unrealized derivative gain in second quarter 2007 decreased revenues by $12.8 million.

During the first six months of 2008, oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), decreased $11.5 million, or 19%, compared to the first six months of 2007. The change in revenues was attributable to the following:

•

a 55% increase in the sales price we received for our oil and natural gas resulted in a $23.7 million increase in oil and natural gas revenues;

•

a 29% decrease in production volumes resulted in a $17.1 million decrease in oil and natural gas revenues;

•

a $3.4 million loss from the settlement of derivative contracts in the first half of 2008 versus a $1.4 million derivative settlement gain in the first half of 2007 decreased revenue by $4.8 million, and

•

a $15.9 million unrealized derivative loss in first six months of 2008 versus a $2.7 million unrealized derivative loss in the first half of 2007 decreased revenues by $13.3 million.

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

The following table details derivative contracts that settled during the three month and six month periods ended June 30, 2008 and June 30, 2007 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon settlement.


	Three months ended June 30,								Six months ended June 30,
	2008			% Change			2007		2008			% Change			2007

*Oil collars*
Volumes (Bbls)		47,000			(36	%)		73,000		92,500			(38	%)		149,000
Average floor price ($ per Bbl)	$	68.18			21	%	$	56.29	$	64.98			16	%	$	56.02
Average ceiling price ($ per Bbl)	$	90.91			11	%	$	81.84	$	88.29			10	%	$	80.42
Gain (loss) upon settlement ($ in thousands)	$	(1,601	)	NM			$	—	$	(2,187	)	NM			$	113

*Total oil*
Gain (loss) upon settlement ($ in thousands)	$	(1,601	)	NM			$	—	$	(2,187	)	NM			$	113

*Natural gas collars*
Volumes (MMbtu)		1,370,000			(31	%)		1,990,000		2,890,000			(24	%)		3,795,000
Average floor price ($ per MMbtu)	$	7.14			0	%	$	7.11	$	7.52			3	%	$	7.33
Average ceiling price ($ per MMbtu)	$	9.54			(11	%)	$	10.70	$	11.06			(17	%)	$	13.29
Gain (loss) upon settlement ($ in thousands)	$	(1,756	)	NM			$	6	$	(1,232	)	NM			$	1,317

*Total gas*
Gain (loss) upon settlement ($ in thousands)	$	(1,756	)	NM			$	6	$	(1,232	)	NM			$	1,317

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

Operating costs and expenses

Production costs. We believe that per unit 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,
	2008		% Change			2007		2008		% Change			2007

Production costs:
Operating & maintenance	$	0.75		27	%	$	0.59	$	2,036		(16	%)	$	2,434
Expensed workovers		0.15		36	%		0.11		410		(12	%)		466
Ad valorem taxes		0.04		(60	%)		0.10		102		(76	%)		425

Lease operating expenses	$	0.94		18	%	$	0.80	$	2,548		(23	%)	$	3,325

Production taxes		0.53		308	%		0.13		1,441		162	%		551

Production costs	$	1.47		58	%	$	0.93	$	3,989		3	%	$	3,876

Second quarter 2008 per unit of production costs increased $0.54 per Mcfe, or 58%, when compared to the second quarter of last year because of the following:

•

production taxes increased $0.40 per Mcfe, due to recording production tax credits on our Vicksburg and Mills Ranch wells in the second quarter 2007 rather than deferring recording credits until receipt of regulatory approval;

•

O&M expense increased $0.16 per Mcfe, or 27%, due to declining production from our wells with fixed costs; and

•

ad valorem taxes decreased $0.06 per Mcfe, or 60%, due to an anticipated decrease in property value assessments during 2008.


	Unit-of-Production							Amount
	(Per Mcfe)							(In thousands)
	Six months ended June 30,							Six months ended June 30,
	2008		% Change			2007		2008		% Change			2007

Production costs:
Operating & maintenance	$	0.69		15	%	$	0.60	$	3,858		(19	%)	$	4,738
Expensed workovers		0.22		450	%		0.04		1,224		278	%		324
Ad valorem taxes		0.08		(27	%)		0.11		452		(46	%)		832

Lease operating expenses	$	0.99		32	%	$	0.75	$	5,534		(6	%)	$	5,894

Production taxes		0.49		513	%		0.08		2,724		338	%		622

Production costs	$	1.48		78	%	$	0.83	$	8,258		27	%	$	6,516

During the first six months of 2008, per unit production costs increased $0.65 per Mcfe, or 78%, when compared to the same period last year because of the following:

•

production taxes increased $0.41 per Mcfe due to a $2.3 million decrease in production tax abatements in the first six months of 2008 versus the first six months of 2007;

•

O&M expense increased $0.09 per Mcfe, or 15%, due to declining production from our wells with fixed costs;

•

expensed workovers increased $0.18 per Mcfe due to the unanticipated workover of two of our wells during the first quarter 2008; and

•

ad valorem taxes decreased $0.03 per Mcfe, or 27%, due to an anticipated decrease in property value assessments during 2008.

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,
	2008			% Change			2007			2008			% Change			2007
	(In thousands, except per unit measurements)

General and administrative costs	$	4,799			12	%	$	4,298		$	9,755			14	%	$	8,527
Capitalized general and administrative costs		(2,203	)		9	%		(2,017	)		(4,566	)		12	%		(4,068	)

General and administrative expenses	$	2,596			14	%	$	2,281		$	5,189			16	%	$	4,459


General and administrative expense ($ per Mcfe)	$	0.96			75	%	$	0.55		$	0.93			63	%	$	0.57

Our general and administrative (G&A) expense for the second quarter 2008 was 14% higher when compared to the second quarter of last year. G&A costs increased primarily because of an 11% increase in total compensation expense driven by new hiring and higher salaries to retain experienced employees given the current high demand for knowledgeable industry personnel. In addition, contract and professional expenses, including audit and legal fees, increased 24%. Lower production volumes contributed to the increase in our general and administrative expense on a per unit basis by 75% to $0.96 per Mcfe.

G&A expense for the first six months of 2008 was 16% higher than the first six months of 2007. G&A costs increased primarily because of a 14% increase in compensation expense and 32% higher contract and professional fees. Decreased production contributed to our G&A expense increasing on a per unit basis by 63% to $0.93 per Mcfe.

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,
	2008		% Change			2007		2008		% Change			2007
	(In thousands, except per unit measurements)

Depletion of oil and natural gas properties	$	12,405		(25	%)	$	16,612	$	24,848		(19	%)	$	30,571
Depletion of oil and natural gas properties ($ per Mcfe)	$	4.57		15	%	$	3.99	$	4.43		14	%	$	3.88

Our depletion expense for the second quarter 2008 was $4.2 million lower than the second quarter 2007. Our reduced production volumes decreased depletion expense by $5.8 million. This decrease was offset by a $1.6 million increase in our depletion rate.

Our depletion expense for the first six months of 2008 was $5.7 million lower than the first six months of 2007. Our reduced production volumes decreased depletion expense by $8.8 million. This decrease was offset by a $3.1 million increase in our depletion rate.

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; and 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 writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings and reduces stockholders’ equity in the period of occurrence.

The risk that we will experience a ceiling test writedown increases when oil and gas prices are depressed or if we have substantial downward revisions to our estimated proved reserves. Based on oil and gas prices in effect on June 30, 2008 ($13.10 per MMBtu for Henry Hub gas and $140.00 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties did not exceed the ceiling limit and we therefore did not record an impairment to our oil and gas properties.

Based on oil and gas prices in effect on June 29, 2007 ($6.80 per MMBtu for Henry Hub gas and $70.47 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit and we therefore recorded a $6.5 million ($4.1 million after tax) impairment to our oil and gas properties.

Net interest expense. Interest on borrowings under our 9 5/8% senior notes due 2014 (the “Senior Notes”), our senior credit agreement and dividends on our Series A mandatorily redeemable preferred stock represent the largest portion of our interest costs. Other costs include commitment fees that we pay on the unused portion of the borrowing base and amortization of debt issuance costs. We capitalize a portion of our interest costs associated with major capital projects.


	Three months ended June 30,									Six months ended June 30,
	2008			% Change			2007			2008			% Change			2007
	(In thousands)

Interest on Senior Notes	$	3,850			2	%	$	3,775		$	7,700			14	%	$	6,783
Interest on senior credit facility		347			(41	%)		585			500			(63	%)		1,348
Commitment fees		69			33	%		52			134			34	%		100
Dividend on mandatorily redeemable preferred stock		151			0	%		151			302			1	%		300
Amortization of deferred loan and debt issuance cost		252			6	%		238			498			12	%		443
Other general interest expense		—		NM				—			—			(100	%)		1
Capitalized interest expense		(1,187	)		6	%		(1,123	)		(2,233	)		19	%		(1,880	)

Net interest expense	$	3,482			(5	%)	$	3,678		$	6,901			(3	%)	$	7,095


Weighted average debt outstanding	$	205,536			2.2	%	$	201,164		$	194,178			1.4	%	$	191,552

Average interest rate on outstanding indebtedness (a)		8.6	%					9.2	%		8.9	%					9.0	%


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 2008 and first six months 2008 interest expense was $0.2 million lower than the corresponding periods in 2007 due to a lower weighted average cost of debt and higher level of capitalized interest.

We made $8.1 million in cash payments for interest during the second quarter 2008. For the first six months of 2008, we made $8.3 million in cash payments for interest.

Other income (expense).

Other income (expense) included:


	Three months ended June 30,							Six months ended June 30,
	2008		% Change			2007		2008		% Change			2007
	(In thousands)
Other income (expense):
Non-cash gain (loss)		—	NM				—		—		(100	%)		40
Cash income (expense)		96		(87	%)		712		403		(53	%)		862

Total other income	$	96		(87	%)	$	712	$	403		(55	%)	$	902

Second quarter 2007 other income (expense) includes $0.4 million in cash income related to the receipt of a bankruptcy claim that had been previously written down and $0.1 million in cash income related to the sale of a production barge that was not being utilized.

Income taxes. We recorded deferred federal income tax expense of $1.7 million in the six months ended June 30, 2008, compared to deferred federal income tax expense of $2.8 million in the six months ended June 30, 2007. We also recorded deferred state income tax expense of $0.2 million in the six months ended June 30, 2008, compared to deferred state income tax expense of $0.1 million in the six months ended June 30, 2007. The decrease in the deferred federal income tax expense was primarily due to lower income before income taxes for the six months ended June 30, 2008. For the first six months of 2008, our effective tax rate was 38.3%, which was higher than the statutory rate of 35% primarily due to state income taxes and non-deductibility of preferred stock dividends and certain portions of our non-cash stock compensation expense for federal income tax purposes.

Capital Expenditures

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

•

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

•

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

•

cost of installing new production infrastructure;

•

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

•

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

•

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

The table below summarizes our 2008 oil and gas capital expenditure budget, the amount spent through June 30, 2008 and the amount of our 2008 oil and gas capital expenditure budget that remains to be spent.


			Amount
	2008		Spent Through		Amount
	Budget		June 30, 2008		Remaining (a)
	(In thousands)
Drilling	$	140,633	$	62,689	$	77,944
Net land and seismic		34,191		19,029		15,162
Capitalized costs (b)		13,636		6,799		6,837
Asset retirement obligation		491		132		359

Total oil and gas capital expenditures (c)	$	188,951	$	88,649	$	100,302


(a)		Calculated based on the revised 2008 capital expenditure budget announced in July 2008 less amount spent through June 30, 2008.

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

(c)		Excludes other property capital expenditures.

Determination of Capital Expenditure Budget

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

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

•

changes in commodity prices;

•

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

•

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

•

variances in a prospect’s risked reserve size;

•

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

•

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

•

economic and industry conditions at the time of drilling; and

•

the availability of more economically attractive prospects.

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

Liquidity and Capital Resources

Sources of Capital

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

9 5/8% Senior Notes Due 2014

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

The Senior Notes are our unsecured senior obligations, and:

•

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

•

rank senior to all of our future subordinated indebtedness; and

•

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

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

Additionally, the indenture governing the Senior Notes contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the Senior Notes as of June 30, 2008.

Senior Credit Agreement

Our senior credit agreement provides for revolving credit borrowings up to $200 million and matures June 2010. In May 2008, in conjunction with our regularly scheduled redetermination, the borrowing base was reset to $135 million. As of June 30, 2008, we had $48.6 million outstanding and $86.4 million of unused committed borrowing capacity available under our senior credit agreement. We strive to manage the amounts we borrow under our senior credit agreement in order to maintain excess borrowing capacity.

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

Borrowings under our senior credit agreement bear interest, at our election, at a base rate or a Eurodollar rate, plus an applicable margin. These margins are reset quarterly based on the percent of the borrowing base utilized as shown below:


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


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

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


Percent of
Borrowing Base		Quarterly
Utilized		Commitment Fee
<50%		0.250%
50% and < 75%		0.250%
75% and < 90%		0.375%
90% – 100%		0.375%

Our senior credit agreement also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio on June 30, 2008 and interest coverage ratio for the twelve-month period ended June 30, 2008 were 2.44 to 1 and 7.25 to 1, respectively. As of June 30, 2008, we were in compliance with all covenant requirements in connection with our senior credit agreement.

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

Mandatorily Redeemable Preferred Stock

As of June 30, 2008, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC. We are required to satisfy all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

Access to Capital Markets

We currently have two effective universal shelf registration statements covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. We have $73.4 million remaining available under one of the shelf registration statements. The other universal shelf registration statement has not been utilized to date and has $300 million available.

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

Off Balance Sheet Arrangements

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

Analysis of Changes in Cash and Cash Equivalents

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


	Six months ended June 30,
	2008			% Change			2007
	(In thousands)

Net income	$	3,044			(27	%)	$	4,183
Non-cash items		44,516			0	%		44,468
Changes in working capital and other items		(4,520	)		229	%		(1,375	)

Cash flows provided by operating activities	$	43,040			(9	%)	$	47,276
Cash flows used by investing activities		(84,712	)		15	%		(73,490	)
Cash flows provided by financing activities		38,822			14	%		34,197

Net increase in cash and cash equivalents	$	(2,850	)	NM			$	7,983

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 2008, cash flows provided by operating activities decreased by 9% to $43.0 million from the same period last year. The decrease in operating cash flow is attributable to lower net income and higher utilization of cash for working capital purposes.

Analysis of changes in cash flows used in investing activities


	Six months ended June 30,
	2008			% Change			2007
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	62,689			20	%	$	52,227
Land and seismic		19,029			251	%		5,424
Capitalized cost		6,799			14	%		5,948
Capitalized asset retirement obligation		132			(42	%)		228

Total	$	88,649			39	%	$	63,827


Reconciling Items:
Change in accrued drilling costs	$	(3,872	)	NM			$	10,009
Change in short-term investments		—		NM				—
Other		(65	)		(81	%)		(346	)

Total Reconciling Items		(3,937	)	NM				9,663

Net cash used in investing activities	$	84,712			15	%	$	73,490

Net cash used by investing activities in the first six months of 2008 increased by $11.2 million, or 15%, over the comparable period in 2007 due to the following:

•		drilling capital expenditures increased $10.5 million because of an overall increase in our level of drilling activity in the first six months of 2008 versus that in the corresponding period last year;

•		land and seismic expenditures increased by $13.6 million due to an increase in acreage acquisitions, including our acquisition of significant acreage in the Bakken during the first six months of 2008;

•		capitalized costs increased by $0.9 million because of an increase in the level of our debt outstanding; and

•		the change in accrued drilling costs reduced cash used in investing activities by $13.9 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first six months of 2008 was 14% greater than the first six months of 2007. During first six months of 2008, we borrowed more than in the first six months of 2007 due to our increased levels of drilling and land acquisitions.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the six months ended June 30, 2008 and 2007.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
*2008 common stock transactions:*
Exercise of employee stock options		126,566	$	552

*2007 common stock transactions:*
Exercise of employee stock options		55,000	$	223

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

Effects of Inflation and Changes in Prices

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

Environmental and Other Regulatory Matters

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

New Accounting Pronouncements

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

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

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

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

Forward Looking Information

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

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

Derivative Instruments and Hedging Activities

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

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

During 2007 and 2008 through June 30, we were party to natural gas costless collars, natural gas three-way costless collars and oil costless collars.

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

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

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

The following tables reflect our open natural gas and oil derivative contracts as of June 30, 2008, the associated volumes and the corresponding weighted average NYMEX floor and cap price. As of July 30, 2008 we did not enter into any commodity derivative contracts subsequent to June 30, 2008.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
07/01/08 – 09/30/08		210,000		6.75		9.75
07/01/08 – 09/30/08		270,000		7.00		9.68
07/01/08 – 09/30/08		60,000		7.25		9.53
07/01/08 – 07/31/08		30,000		7.00		9.25
07/01/08 – 10/31/08		200,000		7.25		10.40
07/01/08 – 09/30/08		90,000		6.75		9.62
07/01/08 – 09/30/08		90,000		7.00		8.35
07/01/08 – 07/31/08		50,000		7.50		10.20
07/01/08 – 07/31/08		20,000		8.50		10.40
08/01/08 – 12/31/08		400,000		9.75		11.50
10/01/08 – 03/31/09		300,000		7.75		9.82
10/01/08 – 03/31/09		180,000		8.00		10.20
10/01/08 – 03/31/09		300,000		8.00		11.20
01/01/09 – 01/31/09		80,000		10.25		12.25
02/01/09 – 03/31/09		140,000		10.25		12.25
04/01/09 – 09/30/09		300,000		7.00		9.73
04/01/09 – 09/30/09		120,000		7.25		9.80
04/01/09 – 09/30/09		420,000		8.00		10.70

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMbtu)

(Nymex)

Natural Gas Three Way Costless Collars

10/01/08 – 03/31/09

300,000

8.00

10.35

5.50


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars*
07/01/08 – 08/31/08		4,000		65.00		80.60
07/01/08 – 12/31/08		12,000		85.00		117.00
07/01/08 – 10/31/08		24,000		90.00		120.00
07/01/08 – 12/31/08		12,000		57.50		76.00
07/01/08 – 10/31/08		12,000		65.70		90.00
07/01/08 – 12/31/08		12,000		57.50		75.50
11/01/08 – 06/30/09		24,000		62.00		81.75
11/01/08 – 12/31/08		8,000		87.75		120.00
01/01/09 – 03/31/09		21,000		86.50		120.00

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 30, 2008, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our principal executive officer and our principal financial officer concluded that the design and operation of our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

None.

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

Issuer Purchases of Equity Securities

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


	Total Number of		Average Price
Second Quarter 2008	Shares Purchased		Paid per Share
May 2008		2,116	$	10.14

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

(a)		We held our Annual Stockholders meeting on Friday, May 23, 2008, in Austin, Texas at 9:00 a.m. local time.

(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 46,129,710 shares of our common stock outstanding and entitled to vote, 42,743,876 shares were present in person or by proxy, representing approximately 93%. 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:

To elect seven directors to serve until the Annual Meeting of Stockholders in 2009.


			Number of shares		Number of shares
	Number of shares		voting against		withholding
	voting for election as		election as		authority to vote for
Nominee	director		director		election as director

Ben M. “Bud” Brigham		41,135,581		—		1,608,295
David T. Brigham		41,026,431		—		1,717,445
Harold D. Carter		29,486,341		—		13,257,535
Stephen C. Hurley		41,151,696		—		1,592,180
Stephen P. Reynolds		41,135,135		—		1,608,741
Hobart A. Smith		38,470,202		—		4,273,674
Scott W. Tinker, Ph.D.		41,147,696		—		1,596,180


For			42,236,584
Against			428,583
Abstained			78,708

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

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

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

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


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

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


Exhibit
Number		Description

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

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

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

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

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	Page
PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets — June 30, 2008 and December 31, 2007		1

Consolidated Statements of Operations — Three and six months ended June 30, 2008 and 2007		2

Consolidated Statement of Stockholders’ Equity — Six months ended June 30, 2008		3

Consolidated Statements of Cash Flows — Six months ended June 30, 2008 and 2007		4

Notes to the Consolidated Financial Statements		5

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		32

ITEM 4. CONTROLS AND PROCEDURES		33

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		34

ITEM 1.A. RISK FACTORS		34

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		34

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

ITEM 5. OTHER INFORMATION		35

ITEM 6. EXHIBITS		35

SIGNATURES		36

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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

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

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

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

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

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

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

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

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

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


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


/s/ Eugene B. Shepherd, Jr. Eugene B. Shepherd, Jr.
Executive Vice President and
Chief Financial Officer


Dated: July 31, 2008	/s/ Ben M. Brigham
	Ben M. Brigham
	Chief Executive Officer, President and Chairman of the Board