Brigham Exploration 10Q 2007 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2007


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

For the transition period from to

Commission File Number: 000-22433

Brigham Exploration Company

(Exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

Large Accelerated Filer o Accelerated Filerþ Non-Accelerated Filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ


Class		Outstanding

Common Stock, par value $.01 per share as of November 4, 2007		45,740,160

Brigham Exploration Company

Third Quarter 2007 Form 10-Q Report

TABLE OF CONTENTS


	Page

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets – September 30, 2007 and December 31, 2006		1

Consolidated Statements of Operations – Three and nine months ended September 30, 2007 and 2006		2

Consolidated Statement of Stockholders’ Equity – Nine months ended September 30, 2007		3

Consolidated Statements of Cash Flows – Nine months ended September 30, 2007 and 2006		4

Notes to the Consolidated Financial Statements		5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		16

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		33

ITEM 4. CONTROLS AND PROCEDURES		36

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		37

ITEM 1.A. RISK FACTORS		37

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		37

ITEM 3. DEFALTS UPON SENIOR SECURITIES		37

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		37

ITEM 5. OTHER INFORMATION		37

ITEM 6. EXHIBITS		37

SIGNATURES		38

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)


	September 30,			December 31,
	2007			2006

ASSETS
Current assets:
Cash and cash equivalents	$	10,496		$	4,300
Accounts receivable		17,991			18,352
Derivative assets		2,766			5,676
Other current assets		2,809			2,390
Property held for sale		—			500

Total current assets		34,062			31,218

Oil and natural gas properties, using the full cost method including
Proved, net		422,272			410,474
Unproved		65,560			75,051

		487,832			485,525

Other property and equipment, net		1,072			936
Deferred loan fees		3,858			3,420
Other noncurrent assets		1,646			1,488

Total assets	$	528,470		$	522,587


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	16,657		$	19,464
Royalties payable		6,700			5,012
Accrued drilling costs		3,568			23,310
Participant advances received		670			3,990
Other current liabilities		10,490			5,677

Total current liabilities		38,085			57,453


Senior Notes		158,432			123,434
Senior credit facility		—			25,900
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 September 30, 2007 and December 31, 2006		10,101			10,101
Deferred income taxes		38,394			34,609
Other taxes payable		2,159			—
Other noncurrent liabilities		5,034			5,075

Commitments and contingencies (Note 3)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,225,529 and 45,090,398 shares issued and 45,121,806 and 44,011,362 shares outstanding at September 30, 2007 and December 31, 2006, respectively		452			451
Additional paid-in capital		206,500			203,643
Treasury stock, at cost; 103,723 and 79,036 shares at September 30, 2007 and December 31, 2006, respectively		(836	)		(662	)
Accumulated other comprehensive income (loss)		206			1,006
Retained earnings		69,943			61,577

Total stockholders’ equity		276,265			266,015

Total liabilities and stockholders’ equity	$	528,470		$	522,587

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

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006

Revenues:
Oil and natural gas sales	$	29,481		$	26,089		$	92,250		$	78,019
Gain (loss) on derivatives, net		1,648			(123	)		420			(709	)
Other revenue		17			57			73			87

		31,146			26,023			92,743			77,397


Costs and expenses:
Lease operating		2,564			2,672			8,458			7,938
Production taxes		951			1,259			1,573			3,455
General and administrative		2,514			1,985			6,973			5,936
Depletion of oil and natural gas properties		14,776			11,910			45,347			33,272
Impairment of oil and natural gas properties		—			—			6,505			—
Depreciation and amortization		147			140			468			376
Accretion of discount on asset retirement obligations		87			80			298			229

		21,039			18,046			69,622			51,206

Operating income		10,107			7,977			23,121			26,191


Other income (expense):
Interest income		271			518			536			1,072
Interest expense, net		(3,976	)		(2,669	)		(11,071	)		(6,899	)
Other income (expense)		105			2,507			1,007			4,394

		(3,600	)		356			(9,528	)		(1,433	)

Income before income taxes		6,507			8,333			13,593			24,758

Income tax expense:
Current		—			—			—			—
Deferred		(2,324	)		(3,087	)		(5,227	)		(9,971	)

		(2,324	)		(3,087	)		(5,227	)		(9,971	)

Net income	$	4,183		$	5,246		$	8,366		$	14,787


Net income per share available to common stockholders:
Basic	$	0.09		$	0.12		$	0.19		$	0.33

Diluted	$	0.09		$	0.12		$	0.18		$	0.33


Weighted average shares outstanding:
Basic		45,123			45,027			45,085			45,005

Diluted		45,477			45,294			45,490			45,451

The accompanying notes are an integral part of these consolidated 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, 2006		45,090	$	451	$	203,643		$	(662	)	$	1,006		$	61,577	$	266,015
Comprehensive income:
Net income		—		—		—			—			—			8,366		8,366
Net (gains) losses included in net income		—		—		—			—			(1,231	)		—		(1,231	)
Tax benefit (provision) related to hedges		—		—		—			—			431			—		431

Comprehensive income																	7,566
Exercises of employee stock options		57		—		230			—			—			—		230
Vesting of restricted stock		78		1		(1	)		—			—			—		—
Stock based compensation		—		—		2,628			—			—			—		2,628
Repurchases of common stock		—		—		—			(174	)		—			—		(174	)


Balance, September 30, 2007		45,225	$	452	$	206,500		$	(836	)	$	206		$	69,943	$	276,265

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

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended
	September 30,
	2007			2006

Cash flows from operating activities:
Net income	$	8,366		$	14,787
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		45,347			33,272
Impairment of oil and natural gas properties		6,505			—
Depreciation and amortization		468			376
Stock based compensation		1,455			1,134
Write-off of deferred loan costs		—			965
Amortization of deferred loan fees and debt issuance costs		713			508
Market value adjustment for derivative instruments		2,985			(2,926	)
Accretion of discount on asset retirement obligations		298			229
Deferred income taxes		5,227			9,971
Other noncash items		(4	)		64
Changes in operating assets and liabilities:
Accounts receivable		361			7,926
Other current assets		77			(1,378	)
Accounts payable		(2,807	)		4,928
Royalties payable		1,688			(1,585	)
Participant advances received		(3,320	)		248
Other current liabilities		5,593			6,032
Other noncurrent assets		514			—
Other noncurrent liabilities		(114	)		(256	)

Net cash provided by operating activities		73,352			74,295


Cash flows from investing activities:
Additions to oil and natural gas properties		(108,453	)		(125,054	)
Proceeds from the sale of oil and natural gas properties		35,435			—
Purchases of short term investments		—			(52,409	)
Sales and redemptions of short term investments		—			51,405
Additions to other property and equipment		(600	)		(335	)
Decrease (increase) in drilling advances paid		(1,545	)		254

Net cash used by investing activities		(75,163	)		(126,139	)


Cash flows from financing activities:
Proceeds from senior notes offering		34,825			123,286
Increase in senior credit facility		46,400			24,200
Repayment of senior credit facility		(72,300	)		(57,300	)
Repayment of senior subordinated notes		—			(30,000	)
Deferred loan fees paid and equity costs		(974	)		(2,868	)
Proceeds from issuance of stock, net of issuance costs		—			37
Proceeds from exercise of employee stock options		230			339
Repurchases of common stock		(174	)		(211	)

Net cash provided by financing activities		8,007			57,483

Net increase (decrease) in cash and cash equivalents		6,196			5,639
Cash and cash equivalents, beginning of year		4,300			3,975

Cash and cash equivalents, end of period	$	10,496		$	9,614

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. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in the onshore Texas 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 2006 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

See Note 10 for a discussion of the accounting policy pertaining to the adoption of Statement of Financial Accounting Standard (SFAS) No. 123R, “Share-Based Payment” (SFAS 123R) effective January 1, 2006 using the modified prospective approach.

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 September 30, 2007, there are no known environmental or other regulatory matters related to Brigham’s operations that were 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 nine months ended September 30, 2007 and 2006 are as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Weighted average common shares outstanding – basic		45,123		45,027		45,085		45,005
Plus: Potential common shares
Stock options and restricted stock		354		267		405		446

Weighted average common shares outstanding – diluted		45,477		45,294		45,490		45,451


Stock options excluded from diluted EPS due to the anti-dilutive effect		2,595		2,633		2,525		1,700

5. Income Taxes

The income tax expense (benefit) for the nine months ended September 30, 2007 and 2006 consists of the following (in thousands):


	September 30,		September 30,
	2007		2006
Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		4,926		8,630
State		301		1,341

	$	5,227	$	9,971

In May 2006, the State of Texas enacted legislation establishing a new franchise tax (referred to as the “Margin Tax”), that is based on modified gross revenue. Within the context of generally accepted accounting principles in the United States, the Margin Tax is based on a measure of income and is thus accounted for in accordance with SFAS 109 “Accounting for Income Taxes”. The provisions of SFAS 109 require recognition of the effects of the tax law change in the period of enactment. As a result, Brigham recognized deferred state income taxes in the second quarter of 2006 of $1.3 million.

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 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.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


	(In thousands)
Increases (decreases) resulting from adoption of FIN 48	$	2,139
Increases (decreases) resulting from tax positions taken in the current period		20
Decreases relating to settlements with taxing authorities		—
Reductions resulting from the lapse of applicable statutes of limitations		—

Unrecognized tax benefits at 09/30/2007	$	2,159

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

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 2006, 2005, 2004, and 2003.

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.

Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. On October 1, 2006, Brigham de-designated all derivatives that were previously classified as cash flow hedges and, in addition, Brigham has elected not to designate any additional derivative contracts as cash flow hedges for accounting purposes under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activity”. Beginning on October 1, 2006, 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. As such, the 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. 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 nine months ended September 30, 2007 and 2006:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006
*Natural Gas*
Average price per Mcf realized excluding gas hedging results	$	6.71		$	6.48	$	7.23		$	6.78
Average price per Mcf including gas hedging settlement results	$	7.31		$	6.99	$	7.56		$	7.12
Increase (decrease) in revenue, in thousands	$	1,996		$	1,328	$	3,313		$	2,619
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	7.31		$	7.02	$	7.34		$	7.08
Increase (decrease) in revenue, in thousands	$	1,967		$	1,427	$	1,121		$	2,307
*Oil*
Average price per Bbl realized excluding oil hedging results	$	73.65		$	71.86	$	66.95		$	67.22
Average price per Bbl including oil hedging settlement results	$	73.43		$	72.36	$	67.26		$	67.22
Increase (decrease) in revenue, in thousands	$	(21	)	$	52	$	92		$	2
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	70.35		$	72.36	$	64.60		$	67.29
Increase (decrease) in revenue, in thousands	$	(319	)	$	52	$	(701	)	$	27

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Ineffectiveness associated with Brigham’s derivative commodity instruments designated as cash flow hedges is included in other income (expense). Effective October 1, 2006, Brigham de-designated all existing cash flow hedges. Subsequent derivative contracts are undesignated for accounting purposes. Brigham continues to designate derivative contracts as cash flow hedges for tax purposes. The following table provides a summary of the impact on earnings from ineffectiveness for the three and nine months ended September 30 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Increase (decrease) in earnings due to ineffectiveness	$	—	$	2,336	$	—	$	3,213

Natural Gas and Crude Oil Derivative Contracts

Cash-flow hedges

Prior to October 1, 2006, 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. Additionally, any unrealized gains (losses) relating to the ineffective portion of the cash flow hedges was recorded as an increase or decrease in other income (expense).

On October 1, 2006, Brigham de-designated all derivates that were previously classified as cash flow hedges and, in addition, Brigham has elected not to designate any additional derivative contracts as accounting hedges 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).

During 2006, derivative positions included written put options that were not designated as cash flow hedges and were reflected at fair value on the balance sheet. These positions were entered into in conjunction with a costless collar to offset the cost of other option positions that were designated as cash flow hedges. Historically, at each balance sheet date, the value of written put options not designated as cash flow hedges was adjusted to reflect current fair value and any realized and unrealized gains or losses were recorded as an increase or decrease in other income (expense). During 2006, any realized and unrealized gains or losses associated with the written put options were recorded as gain (loss) on derivatives, net, as an in increase or decrease in revenue on the consolidated statement of operations with any other undesignated derivatives. The following table provides a summary of the fair value of the written put options included in other current liabilities (in thousands):


	September 30,
	2007		2006
Fair value of undesignated written put options	$	—	$	(293	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table provides a summary of the impact on earnings from non-cash gains (losses) related to changes in the fair values of these derivative contracts for the three and nine months ended September 30 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Increase (decrease) in earnings due to changes in fair value of written put options	$	—	$	115	$	—	$	(168	)

The following table reflects open commodity derivative contracts at September 30, 2007, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
10/01/07 - 10/31/07		150,000			$	7.00	$	10.20
10/01/07 - 10/31/07		40,000			$	7.00	$	15.45
10/01/07 - 10/31/07		40,000			$	7.25	$	15.25
10/01/07 - 10/31/07		40,000			$	7.00	$	14.85
10/01/07 - 10/31/07		100,000			$	7.50	$	11.00
10/01/07 - 10/31/07		50,000			$	7.00	$	11.60
10/01/07 - 10/31/07		50,000			$	7.00	$	9.10
10/01/07 - 10/31/07		50,000			$	7.25	$	9.60
10/01/07 - 10/31/07		100,000			$	7.00	$	9.55
10/01/07 - 10/31/07		30,000			$	7.00	$	9.35
11/01/07 - 12/31/07		60,000			$	7.25	$	9.20
11/01/07 - 03/31/08		250,000			$	8.00	$	13.40
11/01/07 - 03/31/08		300,000			$	8.85	$	15.00
11/01/07 - 03/31/08		300,000			$	9.30	$	15.00
11/01/07 - 03/31/08		500,000			$	7.50	$	13.30
11/01/07 - 03/31/08		150,000			$	8.00	$	10.20
11/01/07 - 03/31/08		250,000			$	8.00	$	12.65
11/01/07 - 03/31/08		250,000			$	8.00	$	13.15
04/01/08 - 09/30/08		420,000			$	6.75	$	9.75
04/01/08 - 09/30/08		540,000			$	7.00	$	9.68
04/01/08 - 10/31/08		350,000			$	7.25	$	10.40
*Oil Costless Collars*
10/01/07 - 04/30/08				14,000	$	60.00	$	74.75
10/01/07 - 12/31/07				3,000	$	55.00	$	79.00
10/01/07 - 12/31/07				4,000	$	60.00	$	76.00
10/01/07 - 12/31/07				7,000	$	55.00	$	80.30
10/01/07 - 10/31/07				2,500	$	58.00	$	90.50
10/01/07 - 12/31/07				9,000	$	59.20	$	90.00
10/01/07 - 02/28/08				12,000	$	65.00	$	82.10
10/01/07 - 03/31/08				18,000	$	56.00	$	89.95
10/01/07 - 03/31/08				6,000	$	65.00	$	80.25
11/01/07 - 03/31/08				10,000	$	68.40	$	90.00
01/01/08 - 03/31/08				7,500	$	57.60	$	90.00
01/01/08 - 12/31/08				24,000	$	57.50	$	75.50
02/01/08 - 06/30/08				5,000	$	65.00	$	82.60
04/01/08 - 06/30/08				9,000	$	62.00	$	81.60
04/01/08 - 10/31/08				21,000	$	65.70	$	90.00
04/01/08 - 12/31/08				18,000	$	57.50	$	76.00
07/01/08 - 08/31/08				4,000	$	65.00	$	80.60
11/01/08 - 06/30/09				24,000	$	62.00	$	81.75

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects commodity derivative contracts entered subsequent to September 30, 2007, the associated volumes and the corresponding weighted average NYMEX reference price.


	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMBTU)		Nymex		Nymex		Nymex
*Natural Gas Collars*
04/01/08 - 06/30/08		120,000	$	7.00	$	9.00	$	—
07/01/08 - 09/30/08		90,000	$	6.75	$	9.62	$	—
10/01/08 - 03/31/09		300,000	$	8.00	$	10.35	$	5.50

Interest rate swap

Periodically, Brigham may use interest rate swap contracts to adjust the proportion of its total debt that is subject to variable interest rates. Under such an interest rate swap contract, Brigham agrees to pay an amount equal to a specified fixed-rate of interest for a certain notional amount and receive in return an amount equal to a variable-rate. The notional amounts of the contract are not exchanged. No other cash payments are made unless the contract is terminated prior to maturity. Although no collateral is held or exchanged for the contract, the interest rate swap contract is entered into with a major financial institution in order to minimize Brigham’s counterparty credit risk. The interest rate swap contract is designated as a cash flow hedge against changes in the amount of future cash flows associated with Brigham’s interest payments on variable-rate debt. The effect of this accounting on operating results is that interest expense on a portion of variable-rate debt being hedged is recorded based on fixed interest rates.

At March 31, 2006, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 7.6% on $20.0��million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract was to mature in March 2009. During April 2006, Brigham used the net proceeds from the Senior Notes offering to repay all amounts currently outstanding under its senior and subordinated credit agreements which totaled $78.4 million at the time the offering closed. Subsequent to this repayment, Brigham terminated the subordinated credit agreement and the associated interest rate swap.

Fair values

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.


	September 30,			December 31,
	2007			2006
	(In thousands)

Other current liabilities	$	(373	)	$	(5	)
Other noncurrent liabilities		(65	)		—
Current derivative assets		2,766			5,676
Other noncurrent assets		31			904

	$	2,359		$	6,575

7. 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 9.875% and are fully and unconditionally guaranteed by Brigham Exploration and its wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P. The guarantees are joint and several. Brigham Exploration does not have any independent assets or operations and the aggregate assets and revenues of the subsidiaries not guaranteeing are less than 3% of Brigham’s consolidated assets and revenues.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

In April 2007, Brigham issued an additional $35 million in 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% and were issued under a transaction exempt from the registration requirements of the Securities Act of 1933. Brigham completed the offering to exchange the unregistered notes for registered notes on July 6, 2007. Brigham used the proceeds from the add-on offering to repay amounts outstanding under the existing senior credit agreement and for general corporate purposes. Upon completion of the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes due 2014.

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. At the end of the second quarter 2007, the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit and Brigham was required to record a writedown of its oil and gas properties in the amount of $4.1 million, net of tax.

Based on oil and gas prices in effect at the end of September 2007 ($6.38 per MMBtu for Henry Hub gas and $81.67 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 $13.5 million, net of tax. However, subsequent to the end of the quarter, oil and natural gas prices increased and, on October 31, 2007, reached $6.99 per MMBtu for natural gas and $94.53 per barrel for oil. Utilizing these prices, Brigham’s net capitalized costs of oil and natural gas properties would not have exceeded the ceiling limit. As a result of the increase in the ceiling limit using subsequent prices, Brigham was not required to writedown the net capitalized costs of its oil and gas properties.

During the third quarter 2007, Brigham sold its Anadarko Basin Granite Wash oil and gas properties for net proceeds of $35.4 million with an effective date of September 1, 2007.

9. Asset Retirement Obligations

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the nine months ended September 30, 2007 and 2006 (in thousands):


	Nine Months Ended
	September 30,
	2007			2006

Beginning asset retirement obligations	$	5,002		$	4,389
Liabilities incurred for new wells placed on production		325			395
Liabilities settled		(41	)		(218	)
Revisions to estimates due to sale of oil and gas properties		(615	)		—
Accretion of discount on asset retirement obligations		298			229

	$	4,969		$	4,795

10. Stock Based Compensation

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

The estimated fair value of the options granted during the nine months ended September 30, 2007 and 2006 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 nine months ended September 30, 2007 and 2006:


	2007			2006
Risk-free interest rate		4.6	%		4.6	%
Expected life (in years)		5.0			5.0
Expected volatility		49	%		74 - 87	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	2.97		$	6.54

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

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 nine months ended September 30, 2007 and 2006.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006

Pre-tax stock based compensation expense	$	1,100		$	516		$	2,628		$	2,072
Capitalized stock based compensation		(481	)		(225	)		(1,171	)		(938	)
Tax benefit		(217	)		(102	)		(510	)		(397	)

Stock based compensation expense, net	$	402		$	189		$	947		$	737

The adoption of SFAS 123R did not impact basic and diluted net income per share for the three and nine months ended September 30, 2006.

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 September 30, 2007, approximately 652,223 shares remained available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one stock option grant, options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham’s common stock on the date of grant, vest over five years and have a contractual life of seven years.

Brigham also maintains a director stock option plan under which stock options are awarded to non-employee directors. Options granted under this plan have an exercise price equal to the fair market value of Brigham common stock on the date of grant and vest over five years. Stockholders have authorized the issuance of 1,000,000 shares to non-employee directors and approximately 618,300 remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for the nine months ended September 30:


	2007					2006
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Options outstanding at the beginning of the year		3,243,566		$	7.08		2,946,333		$	6.96
Granted		35,000		$	6.18		20,000		$	9.73
Forfeited or cancelled		(145,300	)	$	8.06		(194,067	)	$	4.84
Exercised		(57,000	)	$	4.05		(48,600	)	$	5.99

Options outstanding at the end of the quarter		3,076,266		$	7.08		2,723,666		$	7.15

Options exercisable at the end of the quarter		1,645,366		$	6.34		1,021,733		$	5.58

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The weighted-average grant-date fair value of share options granted during the nine months ended September 30, 2007 and 2006 was $2.97 and $6.54, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2007 and 2006 was $122,313 and $317,000, respectively.

The following table summarizes information about stock options outstanding and exercisable at September 30, 2007:


	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average	Weighted-
	September 30,		Remaining	Average		September 30,		Remaining	Average
Exercise Price	2007		Contractual Life	Exercise Price		2007		Contractual Life	Exercise Price
$ 3.05 to $3.41		220,366	1.2 years	$	3.35		220,366	1.2 years	$	3.35
3.66 to 5.08		444,400	1.9 years	$	4.23		407,700	1.7 years	$	4.23
6.10 to 6.73		1,255,000	4.1 years	$	6.49		524,000	3.4 years	$	6.61
7.22 to 8.84		776,500	4.3 years	$	8.54		403,300	4.0 years	$	8.70
8.93 to 12.31		380,000	5.1 years	$	11.50		90,000	4.8 years	$	11.12

$ 3.05 to $12.31		3,076,266	3.8 years	$	7.08		1,645,366	2.9 years	$	6.34

The aggregate intrinsic value of options outstanding and exercisable at September 30, 2007 was $1.3 million. 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 September 30, 2007. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of September 30, 2007, there was approximately $4.4 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 4.6 years.

Restricted Stock

During the nine months ended September 30, 2007 and 2006, Brigham issued 379,550 and 129,595, 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 September 30, 2007, there was approximately $3.6 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.9 years. During 2006, stock compensation expense related to unvested restricted stock was adjusted to recognize actual forfeitures during the year as they occurred. 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 nine months ended September 30:


	2007					2006
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Restricted shares outstanding at the beginning of the year		391,367		$	8.60		397,650		$	7.37
Shares granted		379,550		$	5.78		129,595		$	10.84
Lapse of restrictions		(78,131	)	$	6.46		(65,000	)	$	5.23
Forfeitures		(27,053	)	$	8.35		(27,500	)	$	8.05

Shares outstanding at the end of the quarter		665,733		$	7.25		434,745		$	8.68

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. Comprehensive Income

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006

Net income	$	4,183		$	5,246		$	8,366		$	14,787
Unrealized gains (losses) on cash flow hedges					3,527						8,015
Net (gains) losses included in net income		(68	)		—			(1,231	)		—
Tax benefits (provisions) related to cash flow hedges		24			(417	)		431			(1,681	)
Reclassification adjustments for settled hedging positions		—			(2,336	)		—			(3,213	)

Other Comprehensive Income, net	$	4,139		$	6,020		$	7,566		$	17,908

12. New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157 “Fair Value Measurements”, 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 is required on January 1, 2008. Brigham is currently evaluating the impact of adopting SFAS 157 on the financial statements.

In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities”, that provides an option to report selected financial assets and liabilities at fair value. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for the first fiscal year beginning after November 15, 2007. The Company is currently evaluating the impact of SFAS 159.

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 2006 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month and nine month periods ended September 30, 2007 and September 30, 2006. 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 2006 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 3-D seismic imaging and other advanced 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 accumulated significant acreage positions in the Williston Basin of North Dakota and Montana and the Powder River Basin of Wyoming. In April 2007, we announced that we had further added to our Williston Basin acreage by entering into joint ventures that encompassed acreage in Mountrail County, North Dakota and Sheridan County, Montana. Since April, we have grown our total acreage in Mountrail County and extensional areas to approximately 42,600 acres. Operations within the Williston and Powder River Basins are included in and constitute the bulk of our activity in our Rocky Mountains province. We also entered into two joint ventures in Southern Louisiana in 2006 and entered into a work program with a proven Southern Louisiana operator in the third quarter 2007. We consider the Southern Louisiana joint ventures and work program to be logical extensions of our prospect generating activities in the onshore Texas Gulf Coast. Effective September 1, 2007, we sold our non-strategic Anadarko Basin Granite Wash assets for proceeds of $35.4 million.

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 believe our operations will likely result in a high 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 Third Quarter and First Nine Months 2007 Financial Results

During the third quarter, Henry Hub natural gas spot prices were highly volatile and ranged from a low of $5.29 per Mcf to a high of $7.30 per Mcf. Pricing conditions are likely to remain highly volatile as summer natural gas injections have resulted in natural gas inventories nearing underground storage capacity limitations. In particular, volatility can be expected each Thursday with the Energy Information Agency’s weekly update on natural gas storage. Excluding realized and unrealized derivative hedging results, the average sales price that we received for natural gas in the third quarter and first nine months 2007 increased by 4% and 7%, respectively, from the comparable period last year to $6.71 and $7.23 per Mcf, respectively.

West Texas intermediate crude oil spot prices ranged from a low of $69.30 per barrel to a high of $83.85 per barrel during the third quarter. Excluding realized and unrealized derivative hedging results, the average sales price that we received for oil in the third quarter and first nine months 2007 was $73.65 and $66.95 per barrel, respectively, which represents a 2% increase from the third quarter 2006 and no change from the first nine months 2006.

Daily production volumes for the third quarter 2007 averaged 43.4 MMcfe, up 20% from the third quarter 2006. Daily production for the first nine months 2007 averaged 43.6 MMcfe per day, which represents a 21% increase from the first nine months 2006. These increases were primarily attributable to production from our recently completed Southern Louisiana and Vicksburg wells.

Third quarter operating income increased 27% to $10.1 million from last year’s third quarter. Operating income increased because of our higher production volumes and lower lease operating expense and production taxes. These amounts were partially offset by an increase in both our depletion and general and administrative expense. First nine months 2007 operating income decreased 12% to $23.1 million from the comparable period last year. The primary driver behind the decrease in operating income was a $6.5 million ($4.1 million after-tax) non-cash expense related to the full cost ceiling test impairment of our oil and natural gas properties that we recorded in the second quarter 2007. Natural gas prices were $6.80 per Mcfe at the end of June, which resulted in the capitalized costs (net of accumulated depreciation) of our oil and gas properties exceeding the discounted present value of our estimated proved reserves using a 10% discounted rate. In addition to the ceiling test impairment, operating income was impacted by higher depletion, lease operating and general and administrative expense. These factors were partially offset by increased production, higher average realized prices and lower severance taxes.

For the quarter ended September 30, 2007, excluding the impact of our Anadarko Basin Granite Wash asset sale, we spent $26.4 million on oil and gas capital expenditures, which represents a decrease of 52% from the third quarter 2006 and a 10% decrease from the second quarter 2007.

As of September 30, 2007, we had $10.5 million in cash and $528.5 million in total assets. Our net debt to book capitalization ratio was 38%, which is calculated as debt plus preferred stock divided by book equity plus debt plus preferred stock.

Overview of Third Quarter 2007 Operational Results

Onshore Gulf Coast

Vicksburg

In late August, we completed the Home Run Sullivan C-36 at an initial rate of 5.5 MMcfe per day. Additional pay remains behind pipe for future completion.

We are currently reprocessing our 3-D seismic data over the field and anticipate resuming our drilling program either late in the fourth quarter or early in 2008 after updating our structural interpretation of the field.

Southern Louisiana

We are currently drilling the Blue Heron #1 as part of a two well drilling program with a Southern Louisiana operator. Our working interest in the well is 40%. Upon completion of the Blue Heron #1, we will commence the Robin #1, which will test a 3-D delineated fault trap at a depth of 14,452’.

In early October, we announced that our sidetrack of the Cotten Land #2 was unsuccessful and the well was plugged and abandoned after encountering wet sands.

Anadarko Basin

In September, we announced closing on the sale of our previously announced Granite Wash divestiture package for net proceeds of $35.4 million based on an effective date of September 1, 2007. The properties sold had current net production of 1.8 MMcfe per day and proved reserves at the time of sale of approximately 23.8 Bcfe. Year-end 2006 proved reserves associated with the properties were 13.6 Bcfe.

Rocky Mountains

Williston Basin

In April 2007, we announced the formation of a joint venture in Mountrail County, North Dakota with Northern Oil & Gas. The joint venture, which totals 3,000 net acres, is proximate to high rate producing wells in the Parshall Field where the pace of drilling activity is rapidly accelerating. Since the formation of the joint venture, we have grown our acreage position in Mountrail County to approximately 28,600 net acres and have acquired an additional 14,000 net acres in areas proximate to Mountrail County.

Current drilling plans include spudding two to three Brigham operated horizontal wells in Mountrail County during the fourth quarter. Our first well, the Bergstrom Family Trust 26#1H, is located approximately 6.5 miles northeast of the Parshall field and it is estimated that we will have a 57% working interest in the well. The second well, the Bakke 23#1H, is located approximately 12 miles west of the recently announced EOG Austin discovery and it is estimated that we will have a 97% working interest in the well. The laterals are anticipated to be approximately 4,500’ in length and the wells will be completed using swell packers and multi-stage fracture stimulations, which is the completion methodology used effectively in the Parshall field.

We are also participating in three non-operated wells with small working interests. The wells include the EOG Risan 1-34H, the Hess En-England 1256-94-3229H-1 and the Petrohunt Torgerson 15B-2-2H.

During the fourth quarter, we also anticipate spudding the Richardson 25#1 in Sheridan County, Montana, which will target the Red River formation. We will operate the drilling of the well and currently estimate that we will have a 90% working interest subject to a back-in after payout.

Powder River Basin

We plan to spud the Krejci Federal #1-32H, our third well in our 2007 Mowry drilling program, in the fourth quarter 2007. We anticipate completing the well with swell packers and multi-stage facture stimulations.

Third Quarter and First Nine Months 2007 Results

Comparison of the three-month and nine month periods ended September 30, 2007 and 2006.

Production volumes


	Three months ended September 30,							Nine months ended September 30,
	2007		% Change			2006		2007		% Change			2006

Oil (MBbls)		97		(8	%)		105		298		(10	%)		330
Natural gas (MMcf)		3,327		27	%		2,616		9,997		28	%		7,789
Total (MMcfe)(1)		3,909		20	%		3,245		11,784		21	%		9,766
Average daily production ( MMcfe/d)(2)		43.4					36.1		43.6					36.2


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

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

Natural gas represented 85% of our third quarter 2007 production volumes and 85% of our first nine months 2007 volumes, compared to 81% in the third quarter of last year and 80% in the first nine months of last year.

Revenue, Commodity Prices and Hedging

The following table presents our oil and natural gas revenue and average prices for the periods indicated. On October 1, 2006, we de-designated all derivatives that were previously classified as cash flow hedges and, as a result, we are currently marking-to-market these derivatives. In addition, all derivatives entered into since October 1, 2006 have been undesignated and therefore subject to mark-to-market accounting. Mark-to-market accounting requires that we record both derivative settlements and unrealized gains (losses) to the consolidated statement of operations within a single income statement line item. On October 1, 2006, we began including both derivative settlements and unrealized gains (losses) within revenue. As such, unrealized gains (losses) on derivatives are no longer included within either other comprehensive income or other income (expense).


	Three months ended September 30,								Nine months ended September 30,
	2007			% Change			2006		2007			% Change			2006

Oil revenue:
Oil revenue	$	7,145			(5	%)	$	7,541	$	19,953			(10	%)	$	22,150
Oil derivative settlement gains (losses)		(21	)	NM				52		92			4500	%		2

Oil revenue including oil derivative settlements	$	7,124			(6	%)	$	7,593	$	20,045			(10	%)	$	22,152
Oil derivative unrealized gains (losses)		(299	)	NM				—		(793	)	NM				23

Oil revenue including derivative settlements and unrealized gains (losses)	$	6,825			(10	%)	$	7,593	$	19,252			(13	%)	$	22,175
Natural gas revenue:
Natural gas revenue	$	22,336			32	%	$	16,946	$	72,297			37	%	$	52,827
Natural gas derivative settlement gains (losses)		1,996			50	%		1,328		3,313			26	%		2,619

Natural gas revenue including derivative settlements	$	24,332			33	%	$	18,274	$	75,610			36	%	$	55,446
Natural gas derivative unrealized gains (losses)		(28	)	NM				99		(2,192	)		605	%		(311	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	24,304			32	%	$	18,373	$	73,418			33	%	$	55,135
Oil and natural gas revenue:
Oil and natural gas revenue	$	29,481			20	%	$	24,487	$	92,250			23	%	$	74,977
Oil and natural gas derivative settlement gains (losses)		1,975			43	%		1,380		3,405			30	%		2,621

Oil and natural gas revenue including derivative settlement gains (losses)		31,456			22	%		25,867		95,655			23	%		77,598
Oil and natural gas derivative unrealized gains (losses)		(327	)	NM				99		(2,985	)		936	%		(288	)

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		31,129			20	%		25,966		92,670			20	%		77,310
Other revenue		17			(70	%)		57		73			(16	%)		87

Total revenue	$	31,146			20	%	$	26,023	$	92,743			20	%	$	77,397


	Three months ended September 30,							Nine months ended September 30,
	2007		% Change			2006		2007		% Change			2006

Average oil prices:
Oil price (per Bbl)	$	73.65		2	%	$	71.86	$	66.95		(0	%)	$	67.22
Oil price including derivative settlement gains (losses) (per Bbl)		73.43		1	%		72.36		67.26		0	%		67.22
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)		70.35		(3	%)		72.36		64.60		(4	%)		67.29
Average natural gas prices:
Natural gas price (per Mcf)	$	6.71		4	%	$	6.48	$	7.23		7	%	$	6.78
Natural gas price including derivative settlement gains (losses) (per Mcf)		7.31		5	%		6.99		7.56		6	%		7.12
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	7.31		4	%	$	7.02	$	7.34		4	%	$	7.08
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	7.54		0	%	$	7.55	$	7.83		2	%	$	7.68
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		8.05		1	%		7.97		8.12		2	%		7.95
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	7.96		(1	%)	$	8.00	$	7.86		(1	%)	$	7.92


	For the three			For the nine
	month periods			month periods
	ended September 30,			ended September 30,
	2007 and 2006			2007 and 2006

Change in revenue from the sale of oil
Volume variance impact	$	(570	)	$	(2,117	)
Price variance impact		174			(80	)
Cash settlement of hedging contracts		(73	)		90
Unrealized hedge gain or loss		(299	)		(816	)


Total change	$	(768	)	$	(2,923	)

Change in revenue from the sale of natural gas
Volume variance impact	$	4,613		$	14,951
Price variance impact		777			4,519
Cash settlement of hedging contracts		668			694
Unrealized hedge gain or loss		(127	)		(1,881	)


Total change	$	5,931		$	18,283

Change in revenue from the sale of oil and natural gas
Volume variance impact	$	4,043		$	12,834
Price variance impact		951			4,439
Cash settlement of hedging contracts		595			784
Unrealized hedge gain or loss		(426	)		(2,697	)


Total change	$	5,163		$	15,360

Third quarter 2007 oil and natural gas revenue including derivative cash settlements and unrealized gains (losses), increased $5.2 million, or 20%, when compared to the third quarter 2006. The change in revenue was attributable to the following:

•		a 27% increase in natural gas production partially offset by an 8% decrease in oil production resulted in an overall $4.0 million increase in oil and natural gas revenue;

•		a 4% increase in the sales price for natural gas and a 2% increase in the sales price for oil resulted in a $1.0 million increase in our oil and natural gas revenue;

•		a $2.0 million derivative settlement gain in the third quarter 2007 versus a $1.4 million derivative settlement gain in third quarter 2006 increased revenue by $0.6 million; and

•		a $0.3 million unrealized derivative loss in third quarter 2007 versus a $0.1 million unrealized derivative gain in third quarter 2006 decreased revenue by $0.4 million.

First nine months 2007 oil and natural gas revenue including derivative cash settlements and unrealized gains (losses), increased $15.4 million, or 20%, compared to the first nine months 2006. The change in revenue was attributable to the following:

•		a 28% increase in natural gas production partially offset by a 10% decrease in oil production resulted in a $12.8 million increase in oil and natural gas revenue;

•		a 7% increase in the sales price for natural gas and a minimal change in the sales price for oil resulted in a $4.4 million increase in oil and natural gas revenue;

•		a $3.4 million derivative settlement gain in the first nine months 2007 versus a $2.6 million derivative settlement gain in third quarter 2006 increased revenue by $0.8 million; and

•		a $3.0 million unrealized derivative loss in first nine months 2007 versus a $0.3 million unrealized derivative loss in the first nine months 2006 decreased revenue by $2.7 million.

Hedging.We utilize hedges to reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans. In recent periods, we have executed our hedging strategy using costless collars and three way costless collars.

The following table details derivative contracts that settled during the third quarter and nine months ended 2007 and 2006 and includes the type of derivative contract, the volume hedged, the weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon settlement.


	Three months ended September 30,									Nine months ended September 30,
	2007			% Change			2006			2007		% Change			2006

*Oil collars*
Volumes (Bbls)		58,500			31	%		44,500			207,500		80	%		115,500
Average floor price ($ per Bbl)	$	56.00			(4	%)	$	58.20		$	56.01		2	%	$	55.18
Average ceiling price ($ per Bbl)	$	82.00			6	%	$	77.45		$	80.86		10	%	$	73.80
Gain (loss) upon settlement ($ in thousands)	$	(21	)	NM			$	52		$	92		4500	%	$	2

*Oil written puts*
Volumes (Bbls)		—			(100	%)		15,000			—		(100	%)		40.500
Average price ($ per Bbl)	$	—			(100	%)	$	48.00		$	—		(100	%)	$	43.56
Gain (loss) upon settlement ($ in thousands)	$	—			0	%	$	—		$	—		0	%	$	—

*Total oil*
Gain (loss) upon settlement ($ in thousands)	$	(21	)	NM			$	52		$	92		4500	%	$	2

*Natural gas basis swaps*
Volumes (MMbtu)		—			(100	%)		840,000			—		(100	%)		840,000
Gain (loss) upon settlement ($ in thousands)	$	—			(100	%)	$	(106	)	$	—		(100	%)	$	(106	)

*Natural gas collars*
Volumes (MMbtu)		2,090,000			71	%		1,220,000			5,885,000		99	%		2,960,000
Average floor price ($ per MMbtu)	$	7.10			(7	%)	$	7.60		$	7.25		(9	%)	$	7.94
Average ceiling price ($ per MMbtu)	$	10.89			(18	%)	$	13.23		$	12.44		(4	%)	$	12.94
Gain (loss) upon settlement ($ in thousands)	$	1,996			29	%	$	1,549		$	3,313		9	%	$	3,039

*Natural gas written puts*
Volumes (MMbtu)		—			(100	%)		390,000			—		(100	%)		1,380,000
Average price ($ per MMbtu)	$	—			(100	%)	$	6.65		$	—		(100	%)	$	6.83
Gain (loss) upon settlement ($ in thousands)	$	—			(100	%)	$	(115	)	$	—		(100	%)	$	(314	)

*Total gas*
Gain (loss) upon settlement ($ in thousands)	$	1,996			29	%	$	1,328		$	3,313		9	%	$	2,619

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

Operating costs and expenses

Production costs.We believe that per unit 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 September 30,							Three months ended September 30,
	2007		% Change			2006		2007		% Change			2006

Production costs:
Operating & maintenance	$	0.48		(25	%)	$	0.64	$	1,847		(11	%)	$	2,076
Expensed workovers		0.07		75	%		0.04		292		118	%		134
Ad valorem taxes		0.11		(21	%)		0.14		425		(8	%)		462

Lease operating expenses	$	0.66		(20	%)	$	0.82	$	2,564		(4	%)	$	2,672

Production taxes		0.24		(38	%)		0.39		951		(24	%)		1,259

Production costs	$	0.90		(26	%)	$	1.21	$	3,515		(11	%)	$	3,931

Third quarter 2007 per unit of production costs decreased $0.31 per Mcfe, or 26%, when compared to the third quarter 2006 because of the following:

•		Per unit operating and maintenance (O&M) expense decreased by $0.16 per Mcfe, or 25%, from the corresponding period last year because of decreases in salt water disposal costs attributable to our Granite Wash sale, chemical treating, and compressor and equipment rental expense;

•		Production tax expense decreased $0.15 per Mcfe, or 38%, from the third quarter 2006. The decrease was due to an increase in tax credits associated with high cost gas production tax abatements. The increase in tax credits is partially attributable to the fact that we are recording credits immediately upon commencing production from our Vicksburg and Mills Ranch wells given our 100% success rate in applying for credits. We now book credits immediately rather than deferring recognition until receiving approval from the relevant government authority.

•		Ad valorem taxes decreased $0.03 per Mcfe, or 21%, due to a decrease in estimated property valuations for our oil and natural gas properties; and

•		These decreases were offset by an increase in expensed workovers of $0.03 per Mcfe, or 75%, due to an increase in workover activity as compared to that in the third quarter 2006.


	Unit-of-Production							Amount
	(Per Mcfe)							(In thousands)
	Nine months ended September 30,							Nine months ended September 30,
	2007		% Change			2006		2007		% Change			2006

Production costs:
Operating & maintenance	$	0.56		(11	%)	$	0.63	$	6,585		7	%	$	6,127
Expensed workovers		0.05		25	%		0.04		616		50	%		411
Ad valorem taxes		0.11		(21	%)		0.14		1,257		(10	%)		1,400

Lease operating expenses	$	0.72		(11	%)	$	0.81	$	8,458		7	%	$	7,938

Production taxes		0.13		(63	%)		0.35		1,573		(54	%)		3,455

Production costs	$	0.85		(27	%)	$	1.16	$	10,031		(12	%)	$	11,393

First nine months 2007 per unit of production costs decreased $0.31 per Mcfe, or 27%, when compared to the first nine months of last year because of the following:

•		Production taxes decreased $0.22 per Mcfe, or 63%, due to an increase in tax credits partially attributable to the aforementioned change in recording production tax credits;

•		O&M expense decreased $0.07 per Mcfe, or 11% because of decreases in salt water disposal and chemical treating expense; and

•		Ad valorem taxes decreased $0.03 per Mcfe, or 21%, due to a decrease in estimated property valuations for our oil and natural gas properties.

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 September 30,									Nine months ended September 30,
	2007			% Change			2006			2007			% Change			2006
	(In thousands, except per unit measurements)

General and administrative costs	$	4,636			25	%	$	3,702		$	13,163			21	%	$	10,878
Capitalized general and administrative costs		(2,122	)		24	%		(1,717	)		(6,190	)		25	%		(4,942	)

General and administrative expenses	$	2,514			27	%	$	1,985		$	6,973			17	%	$	5,936


General and administrative expense ($ per Mcfe)	$	0.64			5	%	$	0.61		$	0.59			(3	%)	$	0.61

Our general and administrative (G&A) expenses for the third quarter 2007 were 27% higher when compared to the third quarter of last year. G&A costs increased primarily because of higher compensation expense and travel expenses. Higher compensation expense was largely attributable to $0.6 million in additional non-cash share-based compensation expense under SFAS 123R. G&A expense on a per unit basis increased 5% to $0.64 per Mcfe.

G&A expenses for the first nine months 2007 were 17% higher than the first nine months last year. G&A costs increased primarily because of $1.1 million in additional non-cash share-based compensation expense under SFAS 123R. G&A costs also increased because of higher payroll, software and travel expenses. Increased production resulted in our G&A expense decreasing on a per unit basis by 3% to $0.59 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 September 30,							Nine months ended September 30,
	2007		% Change			2006		2007		% Change			2006
	(In thousands, except per unit measurements)

Depletion of oil and natural gas properties	$	14,776		24	%	$	11,910	$	45,347		36	%	$	33,272
Depletion of oil and natural gas properties ($ per Mcfe)	$	3.78		3	%	$	3.67	$	3.85		13	%	$	3.41

Our depletion expense for the third quarter 2007 was $2.9 million higher than that in the third quarter 2006. Approximately 85% of the increase was due to an increase in our production volumes, while the remaining 15% of the increase was due to an increase in our depletion rate. Our depletion expense for the first nine months 2007 was $12.1 million higher than that in the comparable period in 2006. Approximately 57% of the increase was due to an increase in our production volumes, while the remaining 43% of the increase was due to an 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 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; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of oil and gas properties exceed this ceiling amount, we are subject to a ceiling test 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 be required to write down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed, even if the low prices are temporary. In addition, capitalized ceiling impairment charges may occur if we experience poor drilling results or estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not impact cash flows, but does impact operating income and stockholders’ equity. Once recognized, a capitalized ceiling impairment charge to oil and natural gas properties cannot be reversed at a later date. No assurance can be given that we will not experience a capitalized ceiling impairment charge in future periods.

Based on oil and gas prices in effect on September 30, 2007 ($6.38 per MMBtu for Henry Hub gas and $81.67 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit by $21.5 million before tax ($13.5 million after tax). However, subsequent to the end of the quarter, oil and natural gas prices increased, and on October 31, 2007, reached $6.99 per MMBtu for natural gas and $94.53 per barrel for oil. Utilizing these prices, our net capitalized costs of oil and natural gas properties would not have exceeded the ceiling limit. As a result of the increase in the ceiling limit using subsequent prices, we were not required to write-down the net capitalized costs of our oil and gas properties. Write-downs required by these rules do not impact our cash flow from operating activities, but do reduce net income and stockholders’ equity.

During the first nine months of 2007, we recorded a $6.5 million ($4.1 million after tax) impairment to our oil and gas properties. The unamortized costs of Brigham’s oil and gas properties based on the 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) exceeded the ceiling limit causing the impairment change in the second quarter 2007.

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 represents 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 September 30,									Nine months ended September 30,
	2007			% Change			2006			2007			% Change			2006
	(In thousands)

Interest on Senior Notes	$	3,490			16	%	$	3,008		$	10,273			92	%	$	5,347
Interest on senior credit facility		811		NM				—			2,159			191	%		743
Interest on senior subordinated notes (a)		—			0	%		—			—			(100	%)		699
Commitment fees		57			39	%		41			157			27	%		124
Dividend on mandatorily redeemable preferred stock		153			0	%		153			453			0	%		453
Amortization of deferred loan and debt issuance cost		243			23	%		197			686			(53	%)		1,465
Other general interest expense		1			0	%		1			2			(67	%)		6
Capitalized interest expense		(779	)		7	%		(731	)		(2,659	)		37	%		(1,938	)

Net interest expense	$	3,976			49	%	$	2,669		$	11,071			60	%	$	6,899


Weighted average debt outstanding	$	186,562			38	%	$	135,101		$	183,174			61	%	$	114,067

Average interest rate on outstanding indebtedness (b)		9.8	%					9.5	%		9.6	%					8.6	%


a)		Includes the effects of interest rate swaps.

b)		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.

Third quarter 2007 interest expense was $1.3 million higher than the corresponding period last year primarily due to a 38% increase in our weighted average debt outstanding and a higher weighted average cost of debt attributable to our $35 million April 2007 Senior Notes add-on. First nine months 2007 interest expense was $4.2 million higher than the comparable period in 2006 because of a higher weighted average debt outstanding and higher weighted average interest rate attributable to our $125 million April 2006 Senior Notes issuances and our $35 million April 2007 Senior Notes add-on.

We made $0.5 million in cash payments for interest during the third quarter 2007. For the first nine months of 2007, we made $9.7 million in aggregate cash payments for interest.

Other income (expense).Prior to October 1, 2006, other income (expense) included non-cash gains (losses) resulting from the change in fair market value of oil and gas derivative contracts that did not qualify as cash flow hedges under SFAS 133, cash gains (losses) on the settlement of these contracts and non-cash gains (losses) related to charges for the ineffective portions of our derivative contracts that qualified as cash flow hedges under SFAS 133. On October 1, 2006, we de-designated all derivatives that were previously classified as cash flow hedges and began using mark-to-market accounting for these derivatives. Subsequent to September 30, 2006, all newly entered into derivatives are undesignated and therefore subject to mark-to-market accounting. Mark-to-market accounting requires that we record both derivative settlements and unrealized gains (losses) to the consolidated statement of operations within a single income statement line item. On October 1, 2006, we began including both derivative settlements and unrealized gains (losses) within revenue. As such, amounts that were previously recorded in other income (expense) are incorporated within revenue.

Other income (expense) included:


	Three months ended September 30,							Nine months ended September 30,
	2007		% Change			2006		2007		% Change			2006
	(In thousands)
Other income (expense):
Non-cash gain (loss) for the ineffective portion of cash flow hedges	$	—		(100	%)	$	2,336	$	—		(100	%)	$	3,213
Non-cash gain (loss)		—		0	%		—		40	NM				—
Cash income (expense)		105		(39	%)		171		967		(18	%)		1,181

Total other income	$	105		(96	%)	$	2,507	$	1,007		(77	%)	$	4,394

Nine months ended 2007 cash income includes $0.4 million related to the receipt of a bankruptcy claim that had previously been written down and $0.l million related to the sale of a production barge. Nine months ended 2006 cash income includes $0.8 million in income related to the termination of our subordinated debt interest rate swap, which we recorded in April 2006.

Income taxes.We recorded deferred federal income tax expense of $2.2 million in the third quarter of this year, compared to deferred federal income tax expense of $3.1 million in the third quarter of last year. The decrease in our deferred federal income taxes was primarily due to lower third quarter 2007 income before income taxes and adjustments to our accruals for our 2006 income taxes.

In May 2006, the State of Texas enacted legislation establishing a new franchise tax (referred to as the “Margin Tax”) based on modified gross income. As a result, we recognized deferred state income taxes in the third quarter 2006 of $1.3 million. In June 2007, the Texas legislature made technical corrections to the Margin Tax. We recorded deferred state income tax expense of $0.2 million in the third quarter of this year, consisting of the Margin Tax, taxes reflecting our increased activity in Louisiana and North Dakota and adjustments to our accruals for our 2006 income taxes.

We recorded deferred federal income tax expense of $4.9 million in the first nine months of this year, compared to deferred federal income tax expense of $8.6 million in the first nine months of last year. The decrease in our deferred federal income taxes was primarily due to lower 2007 income before income taxes and adjustments to our accruals for our 2006 income taxes. We recorded deferred state income tax expense of $0.3 million in the first nine months of this year, consisting of the Margin Tax, taxes reflecting our increased activity in Louisiana and North Dakota and adjustments to our accruals for our 2006 income taxes.

For the first nine months of 2007, the following table reconciles the difference between the statutory tax rate of 35% and the effective tax rate of 38%:


	Nine months ended
	September 30, 2007			Tax Rate
	(In thousands)
*Reconciliation to effective tax rate:*
Tax at the statutory rate	$	4,757			35.00	%
Add the effect of:
Non-deductible expenses		5			0.01	%
Preferred stock dividends		159			1.16	%
Incentive stock options not exercised		124			0.91	%
State taxes (after-tax)		267			1.96	%
Adjustments to 2006 tax accruals		(165	)		(1.21	%)
Other		80			0.62	%

Total	$	5,227			38.45	%

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 our exploration professional staff.

The table below summarizes our 2007 oil and gas capital expenditure budget, the amount spent on oil and gas capital expenditures through September 30, 2007 and the amount of our 2007 oil and gas capital expenditure budget that remains to be spent.


			Amount
	2007		Spent Through		Amount
	Budget		September 30, 2007		Remaining (a)
	(In millions)
Drilling	$	91.2	$	71.1	$	20.1
Net land and seismic		11.2		10.0		1.2
Capitalized costs (b)		11.5		9.1		2.4

Total oil and gas capital expenditures (c)(d)	$	113.9	$	90.2	$	23.7


(a)		Calculated based on the 2007 capital expenditure budget announced in February 2007 less capital expenditures on a pre-asset sale basis through September 30, 2007.

(b)		Capitalized costs include capitalized interest, G&A, stock compensation expense and asset retirement obligation.

(c)		Excludes other property capital expenditures.

(d)		Excludes the impact of our September 1, 2007 Anadarko Basin Granite Wash asset sale. See Analysis of Changes in Cash Flows Used in Investing Activities for reconciliation of total oil and gas capital expenditures to cash used in investing activities.

Determination of Capital Expenditure Budget

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

This value creation measure and the final determination with respect to our 2007 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 2007 and into 2008, we intend to fund our capital expenditure program and contractual commitments with cash flows from operations, borrowing 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 September 30, 2007.

Senior Credit Agreement

In September 2007, in conjunction with our Anadarko Basin Granite Wash asset sale, we concluded our semi-annual redetermination and the borrowing base was reaffirmed at $101 million.

As of September 30, 2007, we had no amount outstanding and $101 million of unused committed borrowing capacity available under our senior credit agreement. As of November 2, 2007, we had $3.0 million of borrowings outstanding under the senior credit agreement. We strive to manage the amounts we borrow under our senior credit agreement in order to maintain excess borrowing capacity.

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

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


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


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

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


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

Our senior credit agreement also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at September 30, 2007 and interest coverage ratio for the twelve-month period ended September 30, 2007 were 3.5 to 1 and 7.4 to 1, respectively. As of September 30, 2007, 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 September 30, 2007, 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. In July 2004, we sold 2,598,500 shares of our common stock and in November and December 2005, we sold 8,625,000 total shares of our common stock under the first of our two registration statements. We have $73.4 million remaining available under this shelf registration statement.

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

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

Off Balance Sheet Arrangements

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

Analysis of Changes in Cash and Cash Equivalents

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


	Nine months ended September 30,
	2007			% Change			2006
	(In thousands)
Net income	$	8,366			(43	%)	$	14,787
Non-cash items		62,994			45	%		43,593
Changes in working capital and other items		1,992			(87	%)		15,915

Cash flows provided by operating activities	$	73,352			(1	%)	$	74,295
Cash flows used by investing activities		(75,163	)		(40	%)		(126,139	)
Cash flows provided by financing activities		8,007			(86	%)		57,483

Net increase in cash and cash equivalents	$	6,196			10	%	$	5,639

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 nine months of 2007, cash flows provided by operating activities decreased by 1% from the comparable period last year. Our net income for the first nine months 2007 was lower than the comparable period last year because of higher depletion expense and the non-cash ceiling test write-down. These increased costs were partially offset by increased production and higher realized prices. Our non-cash items increased because of higher depletion expense and the non-cash impairment. Changes in working capital were lower in 2007 as we experienced an $8 million decrease in accounts receivable and a $5 million increase in accounts payable in the first nine months of 2006.

Analysis of changes in cash flows used in investing activities


	Nine months ended September 30,
	2007			% Change			2006
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	71,068			(34	%)	$	106,931
Land and seismic		9,969			(59	%)		24,244
Capitalized cost		8,849			22	%		7,273
Capitalized asset retirement obligation		325			(18	%)		395

Total	$	90,211			(35	%)	$	138,843


Reconciling Items:
Asset Sale Proceeds and ARO liability reduction	$	(36,050	)	NM			$	—
Change in accrued drilling costs		19,742		NM				(12,453	)
Change in short-term investments		—			(100	%)		1,004
Other		1,260		NM				(1,255	)

Total Reconciling Items		(15,048	)		18	%		(12,704	)

Net cash used in investing activities	$	75,163			(40	%)	$	126,139

Net cash used by investing activities in the first nine month 2007 decreased by 40% over the comparable period in 2006 due to the following:

•

Drilling capital expenditures decreased by $35.9 million primarily because of our reduced level of drilling activity in the first nine months 2007 versus the corresponding period last year;

•		Land and seismic expenditures decreased by $14.3 million due to a decreased level of land and seismic acquisitions from 2006, when we acquired large acreage positions in the Bakken and Mowry Shale;

•		Our Granite Wash asset sale reduced cash used in investing activities by $36.1 million; and

•		Offsetting the above decreases was a $32.2 million decrease in our accrued drilling costs, which increased cash used in investing activities.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first nine months 2007 was 86% lower than the first nine months 2006. During first nine months 2007, we borrowed approximately $49.5 million less than the comparable period last year due to our reduced levels of drilling activity and land acquisitions.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the nine months ended September 30, 2007 and 2006.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
*2007 common stock transactions:*
Exercise of employee stock options		57,000	$	231

*2006 common stock transactions:*
Exercise of employee stock options		77,100	$	392

Other Matters

Derivative Instruments

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

All derivatives are accounted for in accordance with the Financial Accounting Standards Board (FASB) requirement SFAS 133 and carried at fair value on the balance sheet. Prior to October 1, 2006, our derivatives were classified as either cash flow hedges or were undesignated. Cash flow hedges were valued quarterly and adjustments to the fair value of the contract prior to settlement were recorded to stockholders’ equity in other comprehensive income. Upon settlement, the gain (loss) on the cash flow hedge was recorded to revenue. Any unrealized gains (losses) for the ineffective portion of cash flow hedges were recorded to other income (expense). For undesignated hedges, both the changes in the fair market value of derivatives prior to settlement and the gains (losses) on the settlement of contracts were recorded to other income (expense). On October 1, 2006, we de-designated all cash flow hedges. In addition, all subsequent hedges are undesignated. At the end of each quarter, our derivatives are marked-to-market to reflect the current fair value and both derivative settlements and unrealized gains (losses) are recorded to the consolidated statement of operations. We elected to include all derivative settlement and unrealized gains (losses) within revenue.

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. Inflation has had a minimal effect on us.

Environmental and Other Regulatory Matters

Our operations and properties are, like the oil and natural gas industry in general, subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands. Future regulations may add to the cost of, or significantly limit, drilling activity.

New Accounting Pronouncements

In September 2006, the FASB 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 is required on January 1, 2008. We are currently evaluating the impact of adopting SFAS 157 on the financial statements.

In July 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 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. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is greater than 50 percent likely of being recognized upon ultimate settlement with the taxing authority is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We have recognized a liability of $2.1 million upon the adoption of adopting FIN 48.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) that provides an option to report selected financial assets and liabilities at fair value. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for the second fiscal year beginning after November 15, 2007. We are currently evaluating the impact of SFAS 159.

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 2007 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, 2006 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 prices and interest rate risks. Our objectives for holding derivatives are to achieve a consistent level of cash flow to support a portion of our planned capital spending. Our use of derivative instruments for hedging activities could materially affect our results of operations in particular quarterly or annual periods since such instruments can limit our ability to benefit from favorable price movements. We do not enter into derivative instruments for trading purposes.

Derivative Instruments and Hedging Activities

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

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

During 2006, we were party to natural gas costless collars, natural gas three-way costless collars, natural gas basis swaps, oil costless collars, oil three-way costless collars and interest rate swaps. During the first nine months of 2007, we used 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 price (written call option) on our anticipated future oil and natural gas production. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is above the ceiling price (written call option), we pay our counterparty. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us. Prior to October 1, 2006, we designated these instruments as cash flow hedges as they were designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility.

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. Prior to October 1, 2006, the costless collar portion of the three-way costless collar was designated as a cash flow hedge while the written put was undesignated.

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 September 30, 2007, the associated volumes and the corresponding weighted average NYMEX floor and cap price.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
10/01/07 - 10/31/07		40,000	$	7.00	$	15.45
10/01/07 - 10/31/07		40,000	$	7.25	$	15.25
10/01/07 - 10/31/07		40,000	$	7.00	$	14.85
10/01/07 - 10/31/07		100,000	$	7.50	$	11.00
10/01/07 - 10/31/07		50,000	$	7.00	$	11.60
10/01/07 - 10/31/07		50,000	$	7.00	$	9.10
10/01/07 - 10/31/07		50,000	$	7.25	$	9.60
10/01/07 - 10/31/07		100,000	$	7.00	$	9.55
10/01/07 - 10/31/07		150,000	$	7.00	$	10.20
10/01/07 - 10/31/07		30,000	$	7.00	$	9.35
11/01/07 - 11/30/07		50,000	$	8.00	$	10.20
11/01/07 - 11/30/07		40,000	$	7.25	$	9.20
11/01/07 - 03/31/08		250,000	$	8.00	$	13.40
11/01/07 - 03/31/08		300,000	$	8.85	$	15.00
11/01/07 - 03/31/08		300,000	$	9.30	$	15.00
11/01/07 - 03/31/08		500,000	$	7.50	$	13.30
11/01/07 - 03/31/08		250,000	$	8.00	$	12.65
11/01/07 - 03/31/08		250,000	$	8.00	$	13.15
12/01/07 - 12/31/07		20,000	$	7.25	$	9.20
12/01/07 - 12/31/07		40,000	$	8.00	$	10.20
01/01/08 - 01/31/08		30,000	$	8.00	$	10.20
02/01/08 - 02/29/08		20,000	$	8.00	$	10.20
03/01/08 - 03/31/08		10,000	$	8.00	$	10.20
04/01/08 - 09/30/08		420,000	$	6.75	$	9.75
04/01/08 - 09/30/08		540,000	$	7.00	$	9.68
04/01/08 - 10/31/08		350,000	$	7.25	$	10.40


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars*
10/01/07 - 10/31/07		2,500	$	58.00	$	90.50
10/01/07 - 10/31/07		3,000	$	55.00	$	80.30
10/01/07 - 10/31/07		2,000	$	60.00	$	76.00
10/01/07 - 11/31/07		6,000	$	65.00	$	82.10
10/01/07 - 12/31/07		9,000	$	59.20	$	90.00
10/01/07 - 12/31/07		3,000	$	55.00	$	79.00
10/01/07 - 03/31/08		18,000	$	56.00	$	89.95
10/01/07 - 03/31/08		6,000	$	65.00	$	80.25
10/01/07 - 04/31/08		14,000	$	60.00	$	74.75
11/01/07 - 12/31/07		4,000	$	55.00	$	80.30
11/01/07 - 12/31/07		2,000	$	60.00	$	76.00
11/01/07 - 03/31/08		10,000	$	68.40	$	90.00
12/01/07 - 12/31/07		2,000	$	65.00	$	82.10
01/01/08 - 01/31/08		3,000	$	65.00	$	82.10
01/01/08 - 03/31/08		7,500	$	57.60	$	90.00
01/01/08 - 12/31/08		24,000	$	57.50	$	75.50
02/01/08 - 02/29/08		1,000	$	65.00	$	82.10
02/01/08 - 06/30/08		5,000	$	65.00	$	82.60
04/01/08 - 06/30/08		9,000	$	62.00	$	81.60
04/01/08 - 10/31/08		21,000	$	65.70	$	90.00
04/01/08 - 12/31/08		18,000	$	57.50	$	76.00


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars (continued)*
07/01/08 - 08/31/08		4,000	$	65.00	$	80.60
07/01/08 - 08/31/08		4,000	$	65.00	$	80.60
11/01/08 - 06/31/09		24,000	$	62.00	$	81.75

The following table reflects commodity derivative contracts entered into subsequent to September 30, 2007, the associated volumes and the corresponding weighted average NYMEX reference price.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
04/01/08 - 06/30/08		120,000	$	7.00	$	9.00
07/01/08 - 09/30/08		90,000	$	6.75	$	9.62

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

Beginning October 1, 2006, Brigham de-designated all derivatives that were previously designated as cash flow hedges and will mark-to-market all derivatives in future periods. At the end of each period, the derivatives will be marked-to-market to reflect the current fair value and the realized and unrealized gains or losses will be recorded on the consolidated statement of operations rather than as a component of other comprehensive income.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2007, 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 third quarter of 2007 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, Brigham is party to various legal actions arising in the ordinary course of business and does not expect these matters to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

None.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

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

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

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on November 7, 2007.


	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 INDEX


Exhibit
No.		Description
31.1		Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934

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

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

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. sophomore Avg

Brigham Exploration (BEXP) Inactive 10-Q2007 Q3 Quarterly report

Content analysis