10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2005

OR

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

For the transition period from __________ to __________

Commission File Number: 000-22433

Brigham Exploration Company

(Exact name of registrant as specified in its charter)

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

6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730

(Address of principal executive offices)

(512) 427-3300

(Registrant's telephone number, including area code)

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

Yes x No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12 b-2 of the Act).

Yes xNo ¨

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

Yes ¨No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Class	Outstanding
Common Stock, par value $.01 per share as of November 4, 2005	42,748,513

Brigham Exploration Company

Third Quarter 2005 Form 10-Q Report

TABLE OF CONTENTS

		Page
	PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance Sheets - September 30, 2005 and December 31, 2004	1
	Consolidated Statements of Operations - Three and nine months ended September 30, 2005 and 2004	2
	Consolidated Statement of Stockholders’ Equity - Nine months ended September 30, 2005	3
	Consolidated Statements of Cash Flows - Nine months ended September 30, 2005 and 2004	4
	Notes to the Consolidated Financial Statements	5
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	14
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
ITEM 4.	CONTROLS AND PROCEDURES	34
	PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	35
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	35
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	35
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	35
ITEM 5.	OTHER INFORMATION	35
ITEM 6.	EXHIBITS	35
SIGNATURES		36

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	September 30,			December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	5,873		$	2,281
Accounts receivable		18,882			17,573
Deferred income taxes		2,324			239
Other current assets		1,251			901
Total current assets		28,330			20,994
Oil and natural gas properties, net (full cost method)		324,693			261,979
Other property and equipment, net		997			1,209
Deferred loan fees		2,264			1,745
Other noncurrent assets		695			380
Total assets	$	356,979		$	286,307
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	16,837		$	22,465
Royalties payable		6,461			6,072
Accrued drilling costs		6,634			6,099
Participant advances received		1,798			3,633
Other current liabilities		8,907			2,225
Total current liabilities		40,637			40,494
Senior credit facility		58,100			21,000
Senior subordinated notes		30,000			20,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 and 475,986 shares issued and outstanding at September 30, 2005 and December 31, 2004, respectively		10,101			9,520
Deferred income taxes		17,524			9,031
Other noncurrent liabilities		3,428			2,986
Commitments and contingencies (Note 5)
Stockholders' equity:
Common stock, $.01 par value, 50 million shares authorized, 43,513,978 and 43,231,499 shares issued and 42,295,601 and 42,034,351 shares outstanding at September 30, 2005 and December 31, 2004, respectively		435			432
Additional paid-in capital		177,087			175,270
Treasury stock, at cost; 1,218,377 and 1,197,148 shares at September 30, 2005 and December 31, 2004, respectively		(4,897	)		(4,707	)
Unearned stock compensation		(1,671	)		(1,570	)
Accumulated other comprehensive income (loss)		(3,655	)		(503	)
Retained earnings		29,890			14,354
Total stockholders’ equity		197,189			183,276
Total liabilities and stockholders' equity	$	356,979		$	286,307

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

1

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
				Restated						Restated
Revenues:
Oil and natural gas sales	$	25,189		$	17,240		$	60,326		$	51,975
Other revenue		37			27			136			69
		25,226			17,267			60,462			52,044
Costs and expenses:
Lease operating		1,541			1,648			5,149			4,362
Production taxes		741			675			1,909			2,434
General and administrative		1,317			1,304			3,719			3,723
Depletion of oil and natural gas properties		7,953			5,860			21,612			16,508
Depreciation and amortization		183			179			543			544
Accretion of discount on asset retirement obligations		44			40			126			117
		11,779			9,706			33,058			27,688
Operating income		13,447			7,561			27,404			24,356
Other income (expense):
Interest income		62			26			153			55
Interest expense, net		(1,138	)		(872	)		(2,645	)		(2,508	)
Other income (expense)		(497	)		(168	)		(851	)		(159	)
		(1,573	)		(1,014	)		(3,343	)		(2,612	)
Income before income taxes		11,874			6,547			24,061			21,744
Income tax expense:
Current		—			—			—			—
Deferred		(4,196	)		(2,056	)		(8,525	)		(7,190	)
		(4,196	)		(2,056	)		(8,525	)		(7,190	)
Net income	$	7,678		$	4,491		$	15,536		$	14,554
Net income per share available to common stockholders:
Basic	$	0.18		$	0.11		$	0.37		$	0.37
Diluted	$	0.18		$	0.11		$	0.36		$	0.35
Weighted average shares outstanding:
Basic		42,236			41,227			42,175			39,921
Diluted		43,528			42,340			43,244			41,078

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

2

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(In thousands)

(Unaudited)

	Common Stock				Additional Paid In			Treasury			Unearned Stock			Accumulated Other Comprehensive			Retained		Total Stockholders'
	Shares		Amounts		Capital			Stock			Compensation			Income (Loss)			Earnings		Equity
Balance, December 31, 2004		43,231	$	432	$	175,270		$	(4,707	)	$	(1,570	)	$	(503	)	$	14,354	$	183,276
Comprehensive income:
Net income		—		—		—			—			—			—			15,536		15,536
Unrealized gain (losses) on cash flow hedges		—		—		—			—			—			(5,738	)		—		(5,738	)
Tax benefits related to cash flow hedges		—		—		—			—			—			1,696			—		1,696
Net losses realized and included in net income		—		—		—			—			—			890			—		890
Comprehensive income																				12,384
Exercises of employee stock options		218		2		795			—			—			—			—		797
Vesting of restricted stock		65		1		(1	)		—			—			—			—		—
Issuance of restricted stock		—		—		602			—			(602	)		—			—		—
Tax benefit from the exercise of stock options		—		—		421			—			—			—			—		421
Repurchases of common stock		—		—		—			(190	)		—			—			—		(190	)
Amortization of unearned stock compensation		—		—		—			—			501			—			—		501
Balance, September 30, 2005		43,514	$	435	$	177,087		$	(4,897	)	$	(1,671	)	$	(3,655	)	$	29,890	$	197,189

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

3

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2005			2004
				Restated (1)
Cash flows from operating activities:
Net income	$	15,536		$	14,554
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		21,612			16,508
Depreciation and amortization		543			544
Interest paid through issuance of additional mandatorily redeemable preferred stock		581			538
Amortization of deferred loan fees and debt issuance costs		373			574
Market value adjustment for derivative instruments		995			227
Accretion of discount on asset retirement obligations		126			117
Deferred income taxes		8,525			7,190
Other noncash items		103			—
Changes in operating assets and liabilities:
Accounts receivable		(1,320	)		(48	)
Other current assets		(459	)		2,427
Accounts payable		(5,628	)		(3,249	)
Royalties payable		389			614
Participant advances received		(1,835	)		(628	)
Other current liabilities		543			(1,737	)
Other noncurrent assets and liabilities		(22	)		(126	)
Net cash provided by operating activities		40,062			37,505
Cash flows from investing activities:
Additions to oil and natural gas properties		(83,306	)		(61,160	)
Additions to other property and equipment		(184	)		(186	)
Decrease (increase) in drilling advances paid		205			(137	)
Net cash used by investing activities		(83,285	)		(61,483	)
Cash flows from financing activities:
Increase in senior credit facility		49,100			28,000
Repayment of senior credit facility		(12,000	)		(23,500	)
Increase in senior subordinated notes		10,000			—
Proceeds from the issuance of common stock, net of issuance costs		—			22,132
Deferred loan fees paid and equity costs		(892	)		(10	)
Proceeds from exercise of employee stock options		797			684
Repurchases of common stock		(190	)		(156	)
Net cash provided by financing activities		46,815			27,150
Net increase (decrease) in cash and cash equivalents		3,592			3,172
Cash and cash equivalents, beginning of year		2,281			5,779
Cash and cash equivalents, end of period	$	5,873		$	8,951

(1) Only individual line items in cash flows from operating activities have been restated. Total cash flows from operating, investing and financing activities were unaffected.

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

4

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Nature of Operations

Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the “Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as “Brigham.” Brigham, 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 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 statement 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 rules and regulations of the U.S. Securities and Exchange Commission 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 2004 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Stock Based Compensation

Brigham accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS 123).

5

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Had compensation cost for Brigham's stock options been determined based on the fair market value at the grant dates of the awards consistent with the methodology prescribed by SFAS 123, as amended by SFAS 148, Brigham's net income and net income per share for the three and nine month periods ended September 30, 2005 and 2004 would have been the pro forma amounts indicated below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(In thousands, except per share amounts)
Net income, as reported (as restated for 2004)	$	7,678		$	4,491		$	15,536		$	14,554
Add back: Stock compensation expense previously included in net income		111			103			333			340
Effect of total employee stock-based compensation expense, determined under fair value method for all awards		(355	)		(916	)		(1,036	)		(1,908	)
Pro forma	$	7,434		$	3,678		$	14,833		$	12,986
Net income per share:
Basic, as reported	$	0.18		$	0.11		$	0.37		$	0.37
Basic, pro forma		0.18			0.09			0.35			0.33
Diluted, as reported	$	0.18		$	0.11		$	0.36		$	0.35
Diluted, pro forma		0.17			0.09			0.34			0.32

3. Restatement

Brigham utilizes the full cost method of accounting for its proved oil and natural gas properties included in the consolidated financial statements. During March 2005, in conjunction with preparation of the financial statements for the year ended December 31, 2004, management evaluated the manner in which Brigham historically accounted for depletion expense associated with our oil and natural gas properties. Historically, Brigham had calculated a depletion rate at the end of each period within the year based on its updated reserve estimate. This depletion rate had then been retroactively applied to year-to-date production with the adjustment to previously recorded depletion expense recorded in the current quarter. Brigham determined that the revised depletion rate should have been applied on a prospective basis to production in the most current quarterly period only. As a result, depletion of oil and natural gas properties for the three and nine months ending September 30, 2004, has been restated.

The information in the quarterly financial statement information below represents only those consolidated statements of operations line items affected by the restatement (in thousands).

	Three months ended September 30, 2004						Nine months ended September 30, 2004
	As Reported			Restated			As Reported			Restated
Consolidated Statements of Operations:
Depletion of oil and natural gas properties	$	5,871		$	5,860		$	16,374		$	16,508
Deferred income tax benefit (expense)		(2,051	)		(2,056	)		(7,234	)		(7,190	)
Net income		4,485			4,491			14,644			14,554
Net income (loss) per share available to common stockholders:
Basic	$	0.11		$	0.11		$	0.37		$	0.37
Diluted	$	0.11		$	0.11		$	0.36		$	0.35

6

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

4. Senior Credit Facility and Senior Subordinated Notes

Senior Credit Facility

During June 2005, Brigham amended and restated its senior credit facility to provide for revolving credit borrowings up to a maximum principal amount of $200 million at any one time outstanding. Borrowings under Brigham’s senior credit facility cannot exceed its borrowing base, which is determined at least semiannually. Brigham’s initial borrowing base under the amended and restated senior credit facility is $80 million. As of September 30, 2005, Brigham had $58.1 million in borrowings outstanding under its senior credit facility.

Brigham also extended the maturity of its senior credit facility from March 2009 to June 2010 and changed the interest rate that it pays on borrowings under the facility. Borrowings under the senior credit facility bear interest, at Brigham’s election, at a base rate (as the term is defined in the senior credit facility) or Eurodollar rate, plus in each case an applicable margin. The applicable interest rate margin varies from 0.0% to 0.5% in the case of borrowings based on the base rate (as the term is defined in the senior credit facility) and from 1.25% to 2.0% in the case of borrowings based on the Eurodollar rate, depending on percentage of the available borrowing base utilized. In addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base. The applicable commitment fee varies from 0.25% to 0.375%, depending on the percentage of the available borrowing base utilized. 

The senior credit facility contains various covenants, including among others restrictions on liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on investments, and restrictions on hedging activity of a speculative nature or with counterparties having credit ratings below specified levels.  The senior credit facility requires Brigham to maintain a current ratio (as defined) of at least 1 to 1 and an interest coverage ratio (as defined) of at least 3 to 1.

Senior Subordinated Notes

During June 2005, Brigham amended its $20 million subordinated credit agreement to provide up to $40 million of borrowings and extended the maturity of the notes from March 2009 until June 2010. As of September 30, 2005, Brigham had $30 million of senior subordinated notes outstanding. The senior subordinated notes are secured obligations ranking junior to Brigham’s senior credit facility. Brigham will have the opportunity to draw the additional $10 million available under the subordinated credit agreement until December 29, 2006.

Borrowings under the subordinated credit agreement bear interest based on the Eurodollar rate plus a margin as defined.

Brigham has an interest rate swap that converts $20 million of the borrowings under its subordinated credit agreement from floating to fixed rate debt. At closing this interest rate was 7.61%. This interest rate could increase if Brigham borrows additional debt under its subordinated credit agreement and borrowings under its senior credit agreement reach or exceed 75% of Brigham’s available borrowing base. In addition, a commitment fee of 0.750% is payable on the unused portion subordinated credit agreement.

5. 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.

On October 8, 2002, relatives of a contractor’s employee filed a wrongful death action against Brigham and three other contractors in the District Court of Matagorda County, Texas in connection with the employee’s death on Brigham’s Burkhart #1-R location. On March 23, 2004, a jury determined that Brigham had no liability in the accidental death of the contractor’s employee. The trial judge, however, granted plaintiffs’ motion for a new trial. The new trial took place in September 2005. During jury deliberations, plaintiffs and Brigham’s insurer agreed in principle to settle the dispute. The settlement will result in a nominal payment to the plaintiffs.

7

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As of September 30, 2005, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.

6. Earnings 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.

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2005 and 2004 are as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Weighted average common shares outstanding - basic		42,236		41,227		42,175		39,921
Plus: Potential common shares
Stock options and restricted stock		1,292		1,113		1,069		1,157
Weighted average common shares outstanding - diluted		43,528		42,340		43,244		41,078
Stock options excluded from diluted EPS due to the anti-dilutive effect		—		656		10		676

7. Derivative Instruments and Hedging Activities

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

8

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table sets forth Brigham's realized oil and natural gas prices including and excluding the 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 month periods ended September 30, 2005 and 2004:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Natural Gas
Average price per Mcf as reported (including hedging results)	$	8.45		$	5.44		$	7.01		$	5.68
Average price per Mcf realized (excluding hedging results)	$	8.71		$	5.62		$	7.14		$	5.87
Decrease in revenue (in thousands)	$	(590	)	$	(390	)	$	(831	)	$	(1,250	)
Oil
Average price per Bbl as reported (including hedging results)	$	58.51		$	36.82		$	49.87		$	33.51
Average price per Bbl realized (excluding hedging results)	$	60.44		$	42.50		$	53.32		$	38.01
Decrease in revenue (in thousands)	$	(208	)	$	(843	)	$	(1,134	)	$	(2,018	)

Ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges is included in other income (expense). 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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Increase (decrease) in earnings due to ineffectiveness	$	(477	)	$	(146	)	$	(890	)	$	(206	)

Natural Gas and Crude Oil Derivative Contracts

Cash-flow hedges

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 received when Brigham entered into these option agreements.

Derivative positions included written put options that are not designated as hedges and are 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 are designated as hedges. At each balance sheet date, the value of derivatives not qualifying as hedging contracts is adjusted to reflect current fair value and any gains or losses are recognized as other income (expense). The following table provides a summary of the fair value of these derivatives included in other current liabilities (in thousands):

	September 30, 2005			December 31, 2004
Fair value of undesignated derivatives	$	(137	)	$	—

The following table provides a summary of the impact on earnings from non-cash gains (losses) included in other income (expense) 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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives	$	(52	)	$	(21	)	$	(105	)	$	(21	)

9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table reflects open commodity derivative contracts at September 30, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
10/01/05 - 10/31/05		Purchased put		Cash flow		60,000			$	5.45
		Written call		Cash flow		60,000				8.00
01/01/06 - 03/31/06		Purchased put		Cash flow				7,500	$	62.00
		Written call		Cash flow				7,500		74.50
04/01/06 - 06/30/06		Purchased put		Cash flow				16,500	$	54.80
		Written call		Cash flow				16,500		75.00
Three Way Costless Collars
10/01/05 - 03/31/06		Purchased put		Cash flow				36,000	$	48.00
		Written call		Cash flow				36,000		60.70
		Written put		Undesignated				36,000		38.00
10/01/05 - 10/31/05		Purchased put		Cash flow		100,000			$	6.00
		Written call		Cash flow		100,000				7.20
		Written put		Undesignated		100,000				5.00
10/01/05 - 12/31/05		Purchased put		Cash flow				15,000	$	40.00
		Written call		Cash flow				15,000		53.00
		Written put		Undesignated				15,000		30.00
10/01/05 - 10/31/05		Purchased put		Cash flow		60,000			$	7.00
		Written call		Cash flow		60,000				7.76
		Written put		Undesignated		60,000				5.75
11/01/05 - 03/31/06		Purchased put		Cash flow		250,000			$	6.75
		Written call		Cash flow		250,000				8.80
		Written put		Undesignated		250,000				5.50
11/01/05 - 03/31/06		Purchased put		Cash flow		350,000			$	8.00
		Written call		Cash flow		350,000				9.75
		Written put		Undesignated		350,000				6.50
11/01/05 - 03/31/06		Purchased put		Cash flow		400,000			$	10.00
		Written call		Cash flow		400,000				13.08
		Written put		Undesignated		400,000				8.50
04/01/06 - 06/30/06		Purchased put		Cash flow				7,500	$	63.00
		Written call		Cash flow				7,500		75.25
		Written put		Undesignated				7,500		48.00
07/01/06 - 09/30/06		Purchased put		Cash flow				15,000	$	63.00
		Written call		Cash flow				15,000		75.65
		Written put		Undesignated				15,000		48.00
04/01/06 - 10/31/06		Purchased put		Cash flow		420,000			$	7.50
		Written call		Cash flow		420,000				9.15
		Written put		Undesignated		420,000				6.25
04/01/06 - 10/31/06		Purchased put		Cash flow		490,000			$	8.50
		Written call		Cash flow		490,000				9.96
		Written put		Undesignated		490,000				7.00

10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table reflects commodity derivative contracts entered subsequent to September 30, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)	Nymex Reference Price
Costless Collars
04/01/06 - 10/31/06		Purchased put		Cash flow		490,000		$	8.00
		Written call		Cash flow		490,000			14.85
11/01/06 - 03/31/07		Purchased put		Cash flow		450,000		$	8.00
		Written call		Cash flow		450,000			21.20

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 September 30, 2005, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 7.61% on $20.0 million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract matures in March 2009. As of September 30, 2005, approximately $0.5 million of unrealized gains are included in accumulated other comprehensive income (loss) on the balance sheet and the fair value of the interest rate swap agreement represents approximately $0.5 million of other noncurrent assets. The fair value of the interest rate swap contract is based on quoted market prices and third-party provided calculations, which reflect the present values of the difference between estimated future variable-rate receipts and future fixed-rate payments.

Fair values

The fair value of hedging and interest rate swap contracts is reflected on the consolidated balance sheets as detailed in the following table. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the next twelve months.

	September 30,  2005			December 31, 2004
	(In thousands)
Other current liabilities	$	(6,872	)	$	(870	)
Other noncurrent liabilities		(115	)		(1	)
Other current assets		33			142
Other noncurrent assets		523			3
	$	(6,431	)	$	(726	)

11

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Asset Retirement Obligations

Brigham has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes Brigham's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the nine months ended September 30, 2005 and 2004 (in thousands):

	Nine Months Ended September 30,
	2005			2004
Beginning asset retirement obligations	$	2,896		$	2,320
Liabilities incurred for new wells placed on production		244			394
Liabilities settled		(10	)		(92	)
Accretion of discount on asset retirement obligations		126			117
	$	3,256		$	2,739

9. Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment” (SFAS 123R), which is a revision of SFAS 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. In addition, companies must also recognize compensation expense related to any awards that are not fully vested as of the effective date. The fair value is determined using a variety of assumptions, including those related to volatility rates, forfeiture rates and the option pricing model used (e.g. binomial or Black Scholes). These assumptions could differ from those Brigham has utilized in determining its pro forma compensation expense. SFAS 123R will also impact the manner in which Brigham recognizes the income tax impacts of its stock compensation programs in the consolidated financial statements. The effective date of SFAS 123R is January 1, 2006, for calendar year companies. Upon adoption Brigham will apply SFAS 123R prospectively for new stock-based compensation arrangements and to the unvested portion of existing arrangements. Brigham is currently assessing the impact of adopting SFAS 123R to its consolidated financial statements.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarifies the impact that uncertainty surrounding the timing or method of settling an obligation should have on accounting for that obligation under SFAS No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005, or December 31, 2005 for calendar year companies. Brigham does not expect the adoption of FIN 47 to have a material impact on its consolidated financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). SFAS 154 establishes retrospective application as the required method for reporting a change in accounting principle, unless it is impracticable in which the changes should be applied to the latest practicable date presented for voluntary accounting changes and in the absence of specific guidance provided for in a new pronouncement issued by an authoritative body. SFAS 154 also requires that a correction of an error be reported as a prior period adjustment by restating prior period financial statements. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

12

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

10. Subsequent Event

On November 1, 2005, Brigham paid $4.6 million in cash for the acquisition of approximately 46,000 net acres in the Bakken play located in 126 sections in northwestern North Dakota. Brigham acquired a 100% working interest in the Bakken Shale formation within the acreage.

13

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 2004 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2005, and the comparable periods of 2004. For definitions of commonly used gas and oil terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2004 Annual Report on Form 10-K.

Overview of Third Quarter and First Nine Months of 2005

The price of natural gas during the first nine months of 2005 remained relatively high compared to historical prices due to forecasts for continued U.S. production declines, weather, increasing natural gas demand and similarly high crude oil prices, which limit fuel-switching flexibility. The average sales price, excluding hedging results, that we received for our natural gas in the third quarter and first nine months of 2005 was $8.71 and $7.14, respectively. This represents an increase of 55% over the price we received in third quarter of 2004 and an increase of 22% over the sales price we received during the first nine months of last year. Similarly, the average sales price that we received for oil in the third quarter and first nine months of 2005 also increased over the sales prices we received in those periods last year. The average sales price, excluding hedging results, that we received for oil during the third quarter 2005 and first nine months of 2005 was $60.44 and $53.32, respectively, up 42% when compared to the third quarter of last year and up 40% when compared to the first nine months of last year.

Our net capital expenditures for oil and natural gas activities during the third quarter of 2005 were $25.3 million and year to date through September 30, 2005 we have spent $84.3 million. Our average production was 32 MMcfe/d for the third quarter 2005 and 30.5 MMcfe/d for the first nine months of 2005 compared to 34 MMcfe/d and 34.1 MMcfe/d during the third quarter and first nine months of 2004, respectively. The natural decline of our existing production was only partially offset by production from recently completed wells, causing an overall decline in production for the periods. Furthermore, we estimate that third quarter production of approximately 0.5 MMcfe/d and approximately 0.2 MMcfe/d of the first nine months of 2005 production were lost due the need to shut-in wells in preparation for Hurricane Rita.

Net income for the third quarter 2005 was $7.7 million, or $0.18 per diluted share, on total revenues of $25.2 million. This compares to reported net income of $4.5 million, or $0.11 per diluted share on revenue of $17.3 million in the third quarter last year. The increase in net income was primarily due to an increase in our revenue and lower lease operating expense. These were partially offset by increases in our depletion expense, interest expense, other expense and deferred income tax expense. Net income for the first nine months 2005 was $15.5 million, or $0.36 per diluted share, on total revenues of $60.5 million. This compares to reported net income of $14.6 million, or $0.35 per diluted share, on total revenue of $52 million in the first nine months of last year. The increase in our net income for the first nine months of 2005 was primarily due to increases in our revenue. These were partially offset by increases in our production costs, depletion expense, interest expense, other expense, and deferred income tax expense.

For the third quarter 2005, net cash provided by operating activities funded approximately 45% of our cash used by investing activities and year to date through September 30, 2005, has funded 48% of our cash used by investing activities. During the third quarter 2005, we borrowed an additional $13.7 million of debt, net of repayments, under our senior credit facility and year to date through September 30, 2005 we had borrowed an additional $37.1 million of debt, net of repayments, under our senior credit facility and an additional $10 million of senior subordinated notes.

At September 30, 2005, we had $5.9 million in cash, total assets of $357 million and a debt to capitalization ratio of 33%.

14

Capital Commitments

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 enhancing existing oil and natural gas wells and the associated infrastructure;

· 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.

On September 27, 2005, we announced that we increased our 2005 capital budget. For 2005, we now plan to spend approximately $119.1 million, which represents an increase of 32% over our original 2005 budget announced in March 2005. As part of our revised budget we now plan to drill 36 wells with an average working interest of 63% compared to 37 wells with an average working interest of 55% in our original budget.

The table below summarizes our budgeted capital expenditures, the amount we have spent through September 30, 2005 and the amount of our 2005 budget that remains to be spent.

	Revised 2005 Budget		Amount Spent Through 09/30/05		Amount Remaining (1)
	(In thousands)
Drilling	$	95,823	$	66,172	$	29,651
Net land and seismic		16,354		12,754		3,600
Capitalized interest and G&A		6,654		5,156		1,498
Asset retirement obligation		—		244		—
Other PP&E		313		184		129
Total	$	119,144	$	84,510	$	34,878

(1) Represents amount of our revised 2005 budget that remains to be spent. Calculated as the amount budgeted for 2005 less amount spent through September 30, 2005.

Approximately $46.1 million of the drilling capital in our revised budget is allocated to drill 14 exploration wells with an average working interest of 65%. The drilling capital allocated to exploration drilling in our revised budget represents an increase of 33% over the amount in our original budget, where we planned to spend $34.7 million to drill 17 wells with an average working interest of 60%.

The remaining $49.7 million of drilling capital in our revised budget is allocated to drill 22 development wells with an average working interest of 62% and on other development activities. The drilling capital allocated to development activities in our revised budget represents an increase of 39% over the amount in our original budget, where we planned to spend $35.6 million to drill 20 development wells with an average working interest of 51% and on other development activities. Additionally, we now plan to spend $30.5 million to develop our proved undeveloped reserves compared to $26.5 million in our original budget.

15

Province Breakout

	Revised Budget							Original Budget							Change
	Gross Well		Net Well		Avg. WI%			Gross Well		Net Well		Avg. WI%			Gross Well			Net Well		Avg. WI%
Onshore Gulf Coast		18		13.2		73	%		17		11.0		65	%		1			2.2		8	%
Anadarko Basin		15		7.1		47	%		17		6.9		40	%		(2	)		0.2		7	%
West Texas		3		2.5		83	%		3		2.4		82	%		-			0.1		1	%
Total		36		22.8		63	%		37		20.3		55	%		(1	)		2.5		8	%

Onshore Gulf Coast

Our revised 2005 budget for our Onshore Gulf Coast province is $74.9 million and is 42% higher than the $52.8 million allocated to this province in our original 2005 budget.

Approximately $63.9 million of our capital expenditures in our revised 2005 budget allocated to our Onshore Gulf Coast province will be spent to drill seven exploration wells with an average working interest of 65%, to drill 11 development wells with an average working interest of 78% and for other development activities. This compares to $43.8 million in our original budget to drill seven exploration wells with an average working interest of 64%, to drill 10 development wells with an average working interest of 65% and for other development activities.

The amount we now plan to spend in 2005 to drill exploration wells in our Onshore Gulf Coast province increased by $9.1 million, to $26 million, when compared to our original 2005 budget. As of September 30, 2005, three of the seven exploration wells in our revised 2005 budget planned for this province had been completed or were completing. The remaining four exploration wells that we plan to spud in 2005 will commence drilling in the fourth quarter of 2005. Three of these wells are higher risk but higher reserve potential wells.

The amount of drilling capital we plan to spend in 2005 on development activities in our Onshore Gulf Coast province increased by $11.1 million, to $37.9 million, when compared to our original 2005 budget. We have increased both the number of planned development wells for this province from 10 to 11 and our average working interest in these wells from 65% to 78%. As of September 30, 2005, eight of the eleven development wells in our revised 2005 budget for this province had been completed or were completing, while two were drilling. The remaining development well for this province will spud in the fourth quarter of 2005.

We also increased our 2005 budget for land and seismic activities in our Onshore Gulf Coast province from $9.0 million to $10.9 million.

Anadarko Basin

Our revised 2005 budget for our Anadarko Basin province is $30.9 million and is 14% higher than the $27 million allocated to this province in our original 2005 budget.

Approximately $28 million of our 2005 capital expenditures in our revised 2005 budget allocated to our Anadarko Basin province will be spent to drill five exploration wells with an average working interest of 51%, to drill 10 development wells with an average working interest of 46% and for other development activities. This compares to $23.5 million in our original budget to drill seven exploration wells with an average working interest of 46%, to drill ten development wells with an average working interest of 37% and for other development activities.

The amount we plan to spend in 2005 to drill exploration wells in our Anadarko Basin province increased by $2.5 million, to $17.3 million, when compared to our original 2005 budget. Although our number of planned exploration wells for this province has decreased from seven to five, we have increased our average working interest in the wells that we plan to drill from 46% to 51%. As of September 30, 2005, two of the five exploration wells in our revised 2005 budget for this province had been completed or were completing, while one was drilling. Both of the remaining exploration wells that we expect to spud in 2005 will commence drilling in the fourth quarter. One of these two wells is a higher risk but higher reserve potential well.

16

The amount of drilling capital we plan to spend on development activities in our Anadarko Basin province in 2005 increased by $2 million, to $10.7 million, when compared to our original 2005 budget. Although our number of planned development wells for this province has not changed, we have increased our average working interest in the development wells that we plan to drill from 37% to 46%. Seven of the ten development wells in our revised 2005 budget for this province have been completed or are currently completing. We expect the remaining three development wells to commence drilling in the fourth quarter of 2005. Two of these wells are Granite Wash wells in our Hobart Project.

We decreased our 2005 budget for land and seismic activities in our Anadarko Basin province from $3.5 million to $2.9 million.

West Texas

Our revised 2005 budget for our West Texas province is $6.4 million, which represents an increase of 78% over the $3.6 million allocated to this province in our original 2005 budget.

Approximately $3.8 million of our capital expenditures in our revised 2005 budget allocated to our West Texas province will be spent to drill two exploration wells with an average working interest of 100%, to drill one development well with an average working interest of 50% and for other development activities. This compares to $3 million in our original budget to drill three exploration wells with an average working interest of 82% and for other development activities.

The amount we plan to spend in 2005 to drill exploration wells in our West Texas province decreased by $200,000, to $2.7 million, when compared to our original 2005 budget. Although we have decreased the number of planned exploration wells for this province from three to two, we have increased our average working interest in the wells we plan to drill in 2005 from 82% to 100%. As of September 30, 2005, one of the two exploration wells currently planned for 2005 in our West Texas province had been completed and the other will be spud in the fourth quarter.

The amount of drilling capital we plan to spend in 2005 on development activities in our West Texas province has increased by $1 million, to $1.1 million, when compared to our original 2005 budget. We now plan to drill one development well in this province with a 50% working interest. This development well is planned to spud in the fourth quarter of 2005.

We also increased our 2005 budget for land and seismic activities in our West Texas province from $600,000 million to $2.5 million.

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. The primary factors that impact this value creation measure include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our budgeted expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. 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.

Additionally, we currently plan to capitalize approximately $6.7 million of our forecasted total general and administrative cost and forecasted interest in 2005.

The final determination with respect to our 2005 budgeted expenditures will depend on a number of factors, including:

· commodity prices;

· production from our existing producing wells;

· the results of our current exploration and development drilling efforts;

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

· the availability of more economically attractive prospects.

17

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

Senior Credit Facility

On June 29, 2005, we amended and restated our $100 million senior credit agreement to provide up to $200 million in borrowing capacity and to extend the maturity of our senior credit agreement from March 21, 2009, to June 29, 2010. Our committed borrowing base under our amended and restated senior credit agreement, which prior to amendment was $72 million, is $80 million.

As of September 30, 2005, we had $58.1 million in borrowings outstanding under our senior credit facility. During the first nine months of 2005 we borrowed an additional $49.1 million of additional debt under our senior credit facility and repaid $12 million. Approximately, $8.2 million of the total $12 million was repaid using proceeds from additional borrowing of senior subordinated notes. Borrowings outstanding under our senior credit facility at November 4, 2005, were $63.1 million which represented 79% of our available borrowing base.

During the third quarter 2005, we borrowed an additional $17.5 million of debt under our senior credit facility and repaid $3.8 million.

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, 2005 and interest coverage ratio for the twelve-month period ended September 30, 2005, were 1.8 to 1 and 20.2 to 1, respectively. At September 30, 2005, and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our senior credit agreement.

Senior Subordinated Notes

On June 29, 2005, we amended our $20 million subordinated credit agreement, dated January 21, 2005, to provide up to $40 million in borrowings and to extend the maturity of our subordinated credit agreement from March 21, 2009, to June 29, 2010. Upon closing, we borrowed an additional $10 million of senior subordinated notes under our subordinated credit agreement, which increased the total notes we have borrowed under our subordinated credit agreement to $30 million. We will have the opportunity to draw the remaining $10 million of our senior notes available under our subordinated credit agreement until December 29, 2006.

As of September 30, 2005, we had $30 million of senior subordinated notes outstanding. Pursuant to our subordinated 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, 2005 and interest coverage ratio for the twelve-month period ended September 30, 2005, were 1.8 to 1 and 20.2 to 1, respectively. At September 30, 2005 and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our subordinated credit agreement.

Mandatorily Redeemable Preferred Stock

As of September 30, 2005, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by merchant banking funds managed by affiliates of CSFB Private Equity. During the third quarter of 2005 we issued 9,987 shares of additional shares of preferred stock to satisfy our third quarter 2005 dividend requirements. Year to date through September 30, 2005, we have issued 29,065 shares of additional preferred stock to satisfy our dividend requirements. Our option to pay the mandatorily redeemable Series A preferred stock dividend by issuing additional shares of our preferred stock expired on October 31, 2005. We are now required to pay the dividends on our Series A preferred stock in cash at an annual rate of 6%.

Capital Resources

We intend to fund our remaining 2005 capital expenditure program and contractual commitments through cash flows from operations, borrowings under both our senior credit facility and subordinated credit agreement and, if required and available, alternative financing sources. Our primary sources of cash during first nine months of 2005 were net cash provided by operations and additional borrowings under both our senior credit facility and subordinated credit agreement. We made aggregate cash payments of $2.7 million for interest in the first nine months of 2005.

18

Net cash provided by operating activities

Net cash provided by operating activities is a function of 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 derivative contracts, production, operating cost and our cost of capital. Our asset base, as with other extractive industries, is a depleting one in which each Mcf of natural gas or barrel of oil produced must be replaced or our ability to generate cash flow, and thus sustain our exploration and development activities, will diminish. Net cash provided by operating activities during the first nine months of 2005 funded 48% of our net cash used by investing activities compared to 61% in the first nine months last year.

Senior Credit Facility

As of November 4, 2005 the unused committed borrowing capacity available to us under our senior credit facility was $16.9 million. On June 29, 2005, our borrowing base increased from $72 million to $80 million when we amended and restated our senior credit agreement.

Senior Subordinated Notes

As of September 30, 2005, we had an additional $10 million of senior subordinated notes available to us under our subordinated credit agreement. These additional notes are available to us for borrowing until December 29, 2006.

The future amount of debt that we borrow under our senior credit facility and subordinated credit agreement will depend primarily on net cash provided by operating activities proceeds from other financing activities and proceeds generated from asset dispositions. We strive to manage the borrowings outstanding under our senior credit facility and subordinated credit agreement in order to maintain excess borrowing capacity.

Access to Capital Markets

We currently have an effective universal shelf registration statement covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. In July 2004, we sold 2,598,500 shares of our common stock under the universal shelf registration statement. Following this sale, our remaining capacity under the shelf registration statement is approximately $176.9 million. However, our ability to raise additional capital using our shelf registration statement may be limited due to overall conditions of the stock market or the oil and natural gas industry.

19

Results of Operations

Comparison of the three and nine month periods ended September 30, 2005 and 2004.

Revenues

Production volumes

	Three months ended Sept. 30,							Nine months ended Sept 30,
	2005		% Change			2004		2005		% Change			2004
Oil (MBbls)		108		(27	%)		148		329		(27	%)		449
Natural gas (MMcf)		2,233		3	%		2,167		6,268		(4	%)		6,506
Total (MMcfe)(1)		2,881		(6	%)		3,057		8,240		(10	%)		9,199
Average daily production (MMcfe/d)		32.0					34.0		30.5					34.1

(1) Mcfe is defined one million cubic feet equivalent of natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Our net equivalent production volumes for the third quarter of 2005 were 2.9 Bcfe (32 MMcfe/d) down from 3.1 Bcfe (34 MMcfe/d) in the third quarter of 2004. Our net equivalent production volumes for the first nine months of 2005 were 8.2 Bcfe (30.5 MMcfe/d) down from 9.2 Bcfe (34.1 MMcfe/d) in 2004.

Natural gas represented 78% of our third quarter 2005 production volumes and 76% of our production volumes in the first nine months of 2005. Comparably, natural gas represented 71% of our third quarter 2004 production and 71% of our production for the first nine months of 2004.

The natural decline of our existing production was only partially offset by production from recently completed wells, causing an overall decline in production for the periods. Additionally, we estimate that approximately 0.5 MMcfe/d of our third quarter 2005 production and approximately 0.2 MMcfe/d of the first nine months of the year production were lost due to the need to shut-in wells in preparation for Hurricane Rita.

20

Hedging Results

The following table shows the type of derivative commodity contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated gain /(loss) upon settlement of those contracts for the periods indicated.

	Three months ended Sept. 30,									Nine months ended Sept 30,
	2005			% Change			2004			2005			% Change			2004
Oil swaps
Volumes (Bbls)		—			(100	%)		13,800			—			(100	%)		63,850
Average swap price ($ per Bbl)	$	—			(100	%)	$	23.91		$	—			(100	%)	$	24.77
Gain /(loss) upon settlement ($ in thousands)	$	—			(100	%)	$	(275	)	$	—			(100	%)	$	(848	)
Oil collars
Volumes (Bbls)		33,000			(32	%)		48,760			85,105			(41	%)		144,310
Average floor price ($ per Bbl)	$	44.36			68	%	$	26.34		$	34.71			42	%	$	24.51
Average ceiling price ($ per Bbl)	$	57.20			78	%	$	32.20		$	43.32			39	%	$	31.09
Gain /(loss) upon settlement ($ in thousands)	$	(208	)		(63	%)	$	(568	)	$	(1,134	)		(3	%)	$	(1,170	)
Total oil
Volumes (Bbls)		33,000			(47	%)		62,560			85,105			(59	%)		208,160
Gain /(loss) upon settlement ($ in thousands)	$	(208	)		(75	%)	$	(843	)	$	(1,134	)		(44	%)	$	(2,018	)
Natural gas swaps
Volumes (MMbtu)		—			(100	%)		138,000			—			(100	%)		661,250
Average swap price ($ per MMbtu)	$	—			(100	%)	$	4.18		$	—			(100	%)	$	4.56
Gain /(loss) upon settlement ($ in thousands)	$	—			(100	%)	$	(230	)	$	—			(100	%)	$	(836	)
Natural gas collars
Volumes (MMbtu)		660,000			(9	%)		722,200			2,022,500			14	%		1,777,800
Average floor price ($ per MMbtu)	$	6.12			33	%	$	4.61		$	5.40			25	%	$	4.32
Average ceiling price ($ per MMbtu)	$	7.57			17	%	$	6.48		$	7.30			7	%	$	6.85
Gain /(loss) upon settlement ($ in thousands)	$	(590	)		269	%	$	(160	)	$	(831	)		101	%	$	(414	)
Total natural gas
Volumes (MMbtu)		660,000			(23	%)		860,200			2,022,500			(17	%)		2,439,050
Gain /(loss) upon settlement ($ in thousands)	$	(590	)		51	%	$	(390	)	$	(831	)		(34	%)	$	(1,250	)

Reported revenues from the sale of oil and natural gas are based on the market price we receive for our commodities, adjusted for marketing charges and the results from the settlement of our derivative commodity contracts that qualify for cash flow hedge accounting treatment under SFAS 133.

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

The effective portions of changes in the fair values of our derivative commodity contracts that qualify for cash flow hedge accounting treatment under SFAS 133 are reported as increases or decreases to stockholders’ equity until the underlying contract is settled. Consequentially, changes in the effective portions of these derivative contracts add volatility to our reported stockholders’ equity until the contract is settled or is terminated.

Gains or losses related to the settlement and the changes in the fair values of our derivative commodity contracts that do not qualify for cash flow hedge accounting treatment under SFAS 133 are reported in other income (expense).

21

Commodity prices and revenues

The following table shows our revenue from the sale of oil and natural gas for the periods indicated.

	Three months ended Sept. 30,								Nine months ended Sept 30,
	2005			% Change		2004			2005			% Change		2004
	(In thousands, except per unit measurements)
Revenue from the sale of oil and natural gas:
Oil sales	$	6,529			4%	$	6,304		$	17,531			3%	$	17,058
Gain (loss) due to hedging		(208	)		(75%)		(843	)		(1,134	)		(44%)		(2,018	)
Total revenue from the sale of oil	$	6,321			16%	$	5,461		$	16,397			9%	$	15,040
Natural gas sales	$	19,458			60%	$	12,169		$	44,760			17%	$	38,185
Gain (loss) due to hedging		(590	)		51%		(390	)		(831	)		(34%)		(1,250	)
Total revenue from the sale of natural gas	$	18,868			60%	$	11,779		$	43,929			19%	$	36,935
Oil and natural gas sales	$	25,987			41%	$	18,473		$	62,291			13%	$	55,243
Gain (loss) due to hedging		(798	)		(35%)		(1,233	)		(1,965	)		(40%)		(3,268	)
Total revenue from the sale of oil and natural gas	$	25,189			46%	$	17,240		$	60,326			16%	$	51,975
Average prices:
Oil sales price (per Bbl)	$	60.44			42%	$	42.50		$	53.32			40%	$	38.01
Gain (loss) due to hedging (per Bbl)		(1.93	)		(66%)		(5.68	)		(3.45	)		(23%)		(4.50	)
Realized oil price (per Bbl)	$	58.51			59%	$	36.82		$	49.87			49%	$	33.51
Natural gas sales price (per Mcf)	$	8.71			55%	$	5.62		$	7.14			22%	$	5.87
Gain (loss) due to hedging (per Mcf)		(0.26	)		44%		(0.18	)		(0.13	)		(32%)		(0.19	)
Realized natural gas price (per Mcf)	$	8.45			55%	$	5.44		$	7.01			23%	$	5.68
Natural gas equivalent sales price (per Mcfe)	$	9.02			49%	$	6.04		$	7.56			26%	$	6.01
Gain (loss) due to hedging (per Mcfe)		(0.28	)		(30%)		(0.40	)		(0.24	)		(33%)		(0.36	)
Realized natural gas equivalent (per Mcfe)	$	8.74			55%	$	5.64		$	7.32			30%	$	5.65

	For the three month periods ended Sept 30 2005 and 2004			For the nine month periods ended Sept 30 2005 and 2004
Change in revenue from the sale of oil
Price variance impact	$	1,938		$	5,034
Volume variance impact		(1,713	)		(4,561	)
Cash settlement of hedging contracts		635			884
Total change	$	860		$	1,357
Change in revenue from the sale of natural gas
Price variance impact	$	6,909		$	7,969
Volume variance impact		380			(1,394	)
Cash settlement of hedging contracts		(200	)		419
Total change	$	7,089		$	6,994

Our revenue from the sale of oil and natural gas for the third quarter of 2005 increased by 46% when compared to our revenue in last year’s third quarter. The following were the primary factors that led to the changes in our third quarter 2005 revenue from the sale of oil and natural gas.

· A 49% increase in the sales price we received for our oil and natural gas combined with a 35% decrease in losses from the cash settlement of derivative commodity contracts led to increases of $8.8 million and $435,000, respectively, to our revenue from the sale of oil and natural gas during the third quarter 2005.

· A decrease in this year’s third quarter production partially offset these increases and reduced our third quarter 2005 revenue from the sale of oil and natural gas by $1.3 million.

22

Our revenue from the sale of oil and natural gas for the first nine months of 2005 increased by 16% when compared to revenue in the first nine months of last year. The following were the primary factors that led to the changes in our revenue from the sale of oil and natural gas for the first nine months of 2005.

· A 26% increase in the sales price we received for our oil and natural gas combined with a 40% decrease in losses from the cash settlement of derivative commodity contracts led to increases of $13 million and $1.3 million, respectively, to our revenue from the sale of oil and natural gas during the first nine months of 2005.

· A decrease in our production for the first nine months of 2005 partially offset these increases and reduced our revenue for the first nine months of 2005 by $6 million.

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 third party gas pipeline systems. Other revenue for the third quarter of 2005 was $37,000 compared to $27,000 in the third quarter last year. Other revenue for the first nine months of 2005 was $136,000 compared to $69,000 in the first nine months of 2004. Costs related to our gas gathering systems are reported as lease operating expenses.

Operating costs and expenses

Production costs. Production costs include lease operating expenses and production taxes.

	Three months ended Sept. 30,							Nine months ended Sept 30,
	2005			% Change		2004		2005		% Change		2004
	(In thousands, except per unit measurements)
Production costs:
Operating & maintenance	$	1,410			17%	$	1,201	$	4,221		30%	$	3,248
Expensed workovers		(73	)		NM		278		238		(61%)		617
Ad valorem taxes		204			21%		169		690		39%		497
Lease operating expenses	$	1,541			(6%)	$	1,648	$	5,149		18%	$	4,362
Production taxes		741			10%		675		1,909		(22%)		2,434
Production costs	$	2,282			(2%)	$	2,323	$	7,058		4%	$	6,796
Production cost ($ per Mcfe):
Operating & maintenance	$	0.49			26%	$	0.39	$	0.51		46%	$	0.35
Expensed workovers		(0.03	)		NM		0.09		0.03		(57%)		0.07
Ad valorem taxes		0.07			17%		0.06		0.08		60%		0.05
Lease operating expenses	$	0.53			(2%)	$	0.54	$	0.62		32%	$	0.47
Production taxes		0.26			18%		0.22		0.23		(12%)		0.26
Production costs	$	0.79			4%	$	0.76	$	0.85		16%	$	0.73

Our production costs for the third quarter 2005 decreased by 2% when compared to the third quarter last year. The following were the primary factors that led to the changes in third quarter 2005 production costs.

· A decrease in expensed workovers during the third quarter 2005. This decrease is a result of less workover activity and actual costs associated with expensed workovers that were lower than estimated costs previously accrued. This decrease was partially offset by the following increases.

· An increase in operating and maintenance expenses due to cost associated with our new wells that were not producing in the third quarter last year. Our third quarter 2005 operating and maintenance expenses include $254,000 related to these new wells. Excluding costs associated with these new wells our operating and maintenance expenses for the third quarter 2005 decreased by 4% when compared to the third quarter last year. In the future we anticipate that our operating and maintenance expenses and total production costs will increase as we add new wells and production facilities and continue to maintain production from existing maturing properties.

23

· An increase in our third quarter ad valorem taxes due to an increase in property values due to higher oil and natural gas prices during 2004.

· An increase in production taxes due to an increase in commodity prices partially offset by a reduction in production taxes due to lower production volumes and production tax credits of approximately $517,000 related to six high cost gas wells.

Our production costs for the first nine months of 2005 increased 4% from 2004. The following were the primary reasons for the changes to our production costs for the first nine months of 2005.

· An increase in operating and maintenance expenses due to cost associated with our new wells that were not producing during the first nine months of last year. Our operating and maintenance expenses for the first nine months of 2005 included $610,000 related to these new wells. Excluding costs associated with these new wells, our operating and maintenance expenses for the first nine months of this year increased by 11% when compared to last year. Other expenses that contributed to the increase in our operating and maintenance expenses were increases in costs for saltwater disposal, compressor rental and maintenance, third party overhead fees, water treating, contract service and labor, equipment rental and miscellaneous lease operating expenses. In the future we anticipate that our operating and maintenance costs and total production costs will increase as we add new wells and production facilities and continue to maintain production from existing maturing properties.

· An increase in our ad valorem taxes due to an increase in property values due to higher oil and natural gas prices during 2004.

· These increases were partially offset by a decrease in production taxes and expensed workovers. A reduction in production for the first nine months of 2005 combined with production tax credits of approximately $1.1 million related to 12 high cost gas wells were the primary reasons for the decrease in our production taxes for the first nine months of 2005. These decreases were partially offset by increases in the sales price we received from the sale of our oil and natural gas.

We believe that per unit of production measures is the best way to evaluate our production cost information. We use this information to evaluate our performance relative to our peers and to internally evaluate our performance.

For the third quarter of 2005, our unit production cost increased by 4% when compared to last year. The following were the primary factors that led to the changes in our unit production cost.

· Our unit O&M expenses for the third quarter were up $0.10 per Mcfe when compared to last year. Approximately 90% of this increase was due to new wells that were not producing during the third quarter last year. The remainder of the increase was due to a decrease in our third quarter 2005 production volumes.

· Our unit ad valorem taxes for the third quarter 2005 were up $0.01 per Mcfe when compared to last year. This increase is primarily due to an increase in total ad valorem taxes due to an increase in property values due to higher oil and natural gas prices in 2004 combined with a decrease in our third quarter 2005 production volumes.

· Our unit production taxes for the third quarter 2005 were up $0.04 per Mcfe when compared to last year. This increase is primarily due to an increase in the sales price that we received from the sale of our oil and natural gas partially offset by production tax credits of approximately $517,000 related to six high cost gas wells. 

· These increases were partially offset by a $0.12 per Mcfe decrease in our third quarter 2005 unit expensed workover costs.This decrease is a result of less workover activity and actual costs associated with expensed workovers that were lower than estimated costs previously accrued.

24

For the first nine months of 2005, our unit production cost increased 16% when compared to last year. The following were the primary factors that led to the changes to our unit production cost for the first nine months of 2005.

· Our unit O&M expenses for the first nine months of 2005 were up $0.16 per Mcfe when compared to last year. Approximately 44% of this increase was due to an increase in costs related to new wells that were not producing during the first nine months of last year. Increases in our unit costs for saltwater disposal, compressor rental and maintenance, third party overhead fees, water treating, contract service and labor, equipment rental and miscellaneous expense combined with a decrease in production volumes were the primary reasons for the remaining increase.

· Our unit ad valorem taxes for the first nine months of 2005 were up $0.03 per Mcfe when compared to last year. This increase is primarily due to higher ad valorem taxes due to an increase property values due to higher oil and natural gas prices in 2004 combined with a decrease in our production volumes.

· These increases were partially offset by a $0.03 per Mcfe decrease in our unit production taxes and $0.04 decrease in our unit workover expenses. The decrease in our production taxes was primarily due to a decrease in production for the first nine months of 2005 and production tax credits of approximately $1.1 million related to 12 high cost gas wells. The decrease in our unit workover expense for the first nine months of 2005 was due to a result of less workover activity and actual costs associated with expensed workovers that were lower than estimated costs previously accrued.

General and administrative expenses. We capitalize a portion of our general and administrative costs. The costs capitalized represent the cost of technical employees, who work directly on capital projects. An engineer designing a well is an example of a technical employee working on a capital project. The cost of a technical employee includes associated technical organization costs such as supervision, telephone and postage.

	Three months ended Sept. 30,								Nine months ended Sept 30,
	2005			% Change		2004			2005			% Change		2004
	(In thousands, except per unit measurements)
General and administrative costs	$	2,551			5%	$	2,441		$	7,355			0%	$	7,334
Capitalized general and administrative costs		(1,234	)		9%		(1,137	)		(3,636	)		1%		(3,611	)
General and administrative expenses	$	1,317			1%	$	1,304		$	3,719			(0%)	$	3,723
General and administrative expense ($ per Mcfe)	$	0.46			7%	$	0.43		$	0.45			13%	$	0.40

For the third quarter of 2005, our general and administrative expenses increased by 1% when compared to last year. The following were the primary factors that led to the changes to our third quarter 2005 general and administrative expenses.

· A 7% increase in compensation expense, primarily due to increases in salaries and wages, represented approximately 61% of the total increase in our third quarter 2005 general and administrative costs. Other costs that contributed to the increase of our third quarter 2005 general and administrative costs were increases in costs for financial reporting, office expenses, travel and miscellaneous expenses.

· These increases were partially offset by decreases in costs for contract employees and outside consultants, office rent and equipment rental and maintenance cost. Together, these cost decreases represented approximately 95% of the total decrease in our third quarter 2005 general and administrative costs.

25

For the first nine months of 2005, our general and administrative expenses decreased by 3% when compared to last year. The following were the primary factors that led to the changes to our general and administrative expenses for the first nine months of 2005.

· A decrease in costs for incentive compensation, legal expenses, third party reserve engineering, office rent, financial reporting, advertising and franchise taxes. Together, these decreases represented approximately 92% of the total decrease in our general and administrative costs for the first nine months of 2005.

· These decreases were partially offset by increases in costs for salaries and wages, third party consultants, audit and tax fees, office expenses, corporate insurance, travel, continuing education and miscellaneous general and administrative costs. Together these increases represented approximately 92% of the total increase in our general and administrative costs for the first nine months of 2005.

Depletion of oil and natural gas properties. Our full-cost depletion expense is driven by many factors including certain costs spent in the exploration and development of producing reserves, production levels, and estimates of proved reserve quantities and the costs required to develop proved undeveloped reserves. Our 2004 information pertaining to depletion and accumulated depletion that are part of our net proved oil and natural gas properties has been restated. See “Item 1. Financial Statements—Note 3” for further discussion.

	Three months ended Sept. 30,						Nine months ended Sept 30,
	2005		% Change		2004		2005		% Change		2004
					(Restated)						(Restated)
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	7,953		36%	$	5,860	$	21,612		31%	$	16,508
Depletion of oil and natural gas properties ($ per Mcfe)	$	2.76		44%	$	1.92	$	2.62		46%	$	1.79

For the third quarter 2005, an increase in our depletion rate resulted in a $2.4 million increase in our depletion expense, and was partially offset by a $328,000 decrease to our depletion expense due to a decrease in production volumes.

For the first nine months of 2005, an increase in our depletion rate resulted in a $6.9 million increase in our depletion expense, and was partially offset by $1.8 million decrease due to lower production volumes.

The increase in our depletion rate was primarily the result of increased costs of reserve additions during the first nine months of 2005.

Net interest expense. We capitalize interest expense on borrowings associated with major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.

	Three months ended Sept. 30,								Nine months ended Sept 30,
	2005			% Change		2004			2005			% Change		2004
	(In thousands)
Interest on senior credit facility	$	668			211%	$	215		$	1,538			137%	$	649
Interest on senior subordinated notes		574			32%		436			1,333			1%		1,320
Commitment fees		36			(44%)		64			92			(46%)		171
Dividend on mandatorily redeemable preferred stock		200			9%		184			581			8%		538
Amortization of deferred loan and debt issuance cost		120			(37%)		191			373			(35%)		574
Other general interest expense		1			(83%)		6			7			(65%)		20
Capitalized interest expense		(461	)		106%		(224	)		(1,279	)		67%		(764	)
Net interest expense	$	1,138			31%	$	872		$	2,645			5%	$	2,508
Weighted average debt outstanding	$	91,985			69%	$	54,508		$	76,241			33%	$	57,275
Average interest rate on outstanding indebtedness (a)		6.4	%				6.6	%		6.2	%				6.2	%

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

Our net interest expense for the third quarter of 2005 was 31% higher than last year and 5% higher for the first nine months of 2004.

26

The following were the primary factors that led to the changes to our third quarter 2005 net interest expense.

· An increase in the total interest expense related to our senior credit facility. An increase in the amounts borrowed under our senior credit facility and the rate that we paid on those borrowings were the primary reasons for this increase. Our weighted average borrowings outstanding under our senior credit facility during the third quarter 2005 were $52.1 million which represented 65% of our available borrowing base during the quarter. This compares to $25.4 million representing 37% of our available borrowing base during the third quarter last year. The increase in the interest rate that we paid on those borrowings was primarily due to an increase in the Eurodollar rate. A decrease in the commitment fees we paid on the unused portion of our borrowing base and a decrease amortized deferred loan costs for the third quarter 2005 partially offset the increases due to additional borrowings and higher interest rates.

· An increase in the total interest expense related to our subordinated notes. An increase in the amount borrowed under our subordinated credit agreement and an increase in commitment fees paid on the unused portion of the subordinated credit agreement were the primary reasons for this increase. In the second quarter 2005, we increased our borrowings under our senior credit agreement from $20 million to $30 million and expanded the agreement to provide up to $40 million of total borrowings. A decrease amortized deferred loan costs for the third quarter 2005 partially offset the increases due to increased borrowings and commitment fees.

· A $237,000 increase in the amount of interest that we capitalized during the third quarter partially offset the increases discussed above.

The following were the primary factors that led to the changes to our net interest expense for the first nine months of 2005.

· An increase in the total interest expense related to our senior credit facility. An increase in the amounts borrowed under our senior credit facility and an increase in the rate that we paid on those borrowings were primary reason for the increase. Our weighted average borrowings outstanding under our senior credit facility during the first nine months of 2005 were $43.1 million which represented 59% of our available borrowing during that period. This compares to $28.3 million outstanding representing 41% of our available borrowing base during the first nine months last year. An increase in the Eurodollar rate was the primary reason for the increase in the interest rate that we paid on those borrowings. A decrease in the commitment fees paid on the unused portion of our senior credit facility and a decrease in amortized deferred loan costs for first nine months of 2005 partially offset the increases due to additional borrowings and higher interest rates.

· A $515,000 increase in the amount of interest that we capitalized during the first nine months of 2005 partially offset the increases discussed above.

Other income (expense). Other income (expense) primarily includes non-cash gains (losses) resulting from the change in fair market value of oil and gas derivative contracts not designated as cash flow hedges, cash gains (losses) on the settlement of these contracts and non-cash gains (losses) related to charges for the ineffective portions of cash flow hedges.

Other income (expense) included:

	Three months ended Sept. 30,								Nine months ended Sept 30,
	2005			% Change		2004			2005			% Change		2004
	(In thousands)
Non-cash gain (loss) due to change in fair market value of derivative contracts not designated as cash flow hedges	$	(52	)		148%	$	(21	)	$	(105	)		400%	$	(21	)
Non-cash gain (loss) for ineffective portion of cash flow hedges		(477	)		227%		(146	)		(890	)		332%		(206	)
Other non-cash gain (loss)		(44	)		NM		—			(103	)		NM		—
Other cash income (expense)		76			NM		(1	)		247			263%		68
Other income (loss)	$	(497	)		196%	$	(168	)	$	(851	)		435%	$	(159	)

27

The following table shows the volumes and the weighted average NYMEX reference price for those volumes for our derivative commodity contracts that we did not designate as cash flow hedges for the periods indicated.

	Three months ended Sept. 30,						Nine months ended Sept 30,
	2005		% Change		2004		2005		% Change		2004
Written puts
Oil
Volumes (Bbl)		33,000		NM		—		39,000		NM	$	—
Average price ($ per Bbl)	$	34.36		NM	$	—	$	34.92		NM	$	—
Gain /(loss) upon settlement ($ in thousands)	$	—		NM	$	—	$	—		NM	$	—
Natural gas
Volumes (MMbtu)		480,000		NM		—		690,000		NM	$	—
Average price ($ per MMbtu)	$	5.28		NM	$	—	$	5.35		NM	$	—
Gain /(loss) upon settlement ($ in thousands)	$	—		NM	$	—	$	—		NM	$	—

28

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 Sept 30,
	2005			% Change		2004
	(In thousands)
Net income	$	15,536			7%	$	14,554
Non-cash items		32,858			28%		25,698
Changes in working capital and other items		(8,332	)		203%		(2,747	)
Cash flows provided by operating activities	$	40,062			7%	$	37,505
Cash flows used by investing activities		(83,285	)		35%		(61,483	)
Cash flows provided by financing activities		46,815			72%		27,150
Net increase in cash and cash equivalents	$	3,592			13%	$	3,172

Analysis of net cash provided by operating activities

Cash flows provided by operating activities for the first nine months of 2005 were 7% higher than cash flows provided by operating activities in the same period of 2004. The following were the primary factors that led to the changes to our cash flows provided by operating activities during the first nine months of 2005.

· Our total revenues for the first nine months of 2005 increased $14.3 million due to an increase in the prices we received for our oil and natural gas and a decrease in the amounts we lost upon the settlement of our derivative contracts. These changes were partially offset by a $6 million decrease to our total revenue due to a decrease in our production volumes for the first nine months of 2005.

· Increases in our production costs and cash interest expense during the first nine months of 2005 resulted in decreases to cash flows provided by operating activities of $262,000 and $295,000 respectively.

· The payment of accounts payable in excess of the collection of accounts receivable during the first nine months of 2005 reduced our cash flows provided by operating activities by $3.6 million.

· An increase in the amount of royalties we paid during the first nine months of 2005 decreased our cash flows provided by operating activities by $225,000.

· A decrease in the amount of participant advances during the first nine months of 2005 resulted in a $1.2 million decrease to our cash flows provided by operating activities.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. It is normal for us to report a working capital deficit at the end of a period. These deficits are primarily the result of accounts payable related to lease operating expenses, exploration and development costs and royalties payable. Settlement of these payables will be funded by cash flows from operations or, if necessary, by additional borrowing under our senior credit facility or subordinated notes agreement.

Our working capital deficit at September 30, 2005 was $12.3 million compared to a working capital deficit of $19.5 million at December 31, 2004. Our working capital deficit at September 30, 2005, included a net liability of $7 million related to the fair value of our derivative contracts.

29

Capital expenditures for oil and natural gas activities

	Nine months ended Sept 30,
	2005		% Change		2004
	(In thousands)
Drilling (1)	$	66,172		36%	$	48,710
Land and seismic		12,754		19%		10,749
Capitalized cost (2)		5,156		12%		4,595
Capitalized ARO		244		(38%)		392
Total	$	84,326		31%	$	64,446

(1) Includes $6.6 million and $6.5 million of accrued drilling costs for 2005 and 2004, respectively.

(2) For 2005 includes $3.6 million in capitalized general and administrative cost, $1.3 million in capitalized interest cost and $241,000 of capitalized stock compensation expense. For 2004 includes $3.6 million in capitalized general and administrative cost, $764,000 in capitalized interest cost and $220,000 of capitalized stock compensation expense.

Analysis of changes in cash flows from financing activities

Senior Credit Facility

During first nine months of 2005 we borrowed an additional $49.1 million under our senior credit facility, repaid $12 million of the amount borrowed under our senior credit facility and paid $646,000 in fees to amend and restate our senior credit agreement in January and June 2005. This compares to our borrowing $28 million, repaying $23.5 million and paying $10,000 in deferred loan costs during the first nine months of 2004.

Senior Subordinated Notes

During the first nine months of 2005 we borrowed an additional $10 million under our subordinated credit agreement and paid $245,000 in fees to amend and restate our credit agreement on June 29, 2005. We did not borrow anything under our subordinated credit agreement during the first nine months of 2004.

Common Stock Transactions

	Shares Issued		Net Proceeds
			(In thousands)
2005 common stock transactions:
Exercise of employee stock options		217,479	$	797
2004 common stock transactions:
Exercise of employee stock options		235,581	$	684
Sale of common stock under universal shelf registration statement (a)		2,598,500	$	22,132

(a) The net proceeds from the sale were used to repay outstanding indebtedness under our senior credit facility. 2,300,000 shares were sold in July 2004 and 298,500 shares were sold in August 2004 when the underwriter exercised its over-allotment option.

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Other Matters

Effects of Inflation and Changes in Prices

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

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment” (SFAS 123R), which is a revision of SFAS 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. In addition, companies must also recognize compensation expense related to any awards that are not fully vested as of the effective date. The fair value is determined using a variety of assumptions, including those related to volatility rates, forfeiture rates and the option pricing model used (e.g. binomial or Black Scholes). These assumptions could differ from those we have utilized in determining our pro forma compensation expense. SFAS 123R will also impact the manner in which we recognize the income tax impacts of our stock compensation programs in the consolidated financial statements. The effective date of SFAS 123R is January 1, 2006 for calendar year companies. Upon adoption we will apply SFAS 123R prospectively for new stock-based compensation arrangements and to the unvested portion of existing arrangements. We are currently assessing the impact of adopting SFAS 123R to our consolidated financial statements.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which clarifies the impact that uncertainty surrounding the timing or method of settling an obligation should have on accounting for that obligation under SFAS No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005, or December 31, 2005 for calendar year companies. We do not expect the adoption of FIN 47 to have a material impact on our consolidated financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). SFAS 154 establishes retrospective application as the required method for reporting a change in accounting principle, unless it is impracticable in which the changes should be applied to the latest practicable date presented for voluntary accounting changes and in the absence of specific guidance provided for in a new pronouncement issued by an authoritative body. SFAS 154 also requires that a correction of an error be reported as a prior period adjustment by restating prior period financial statements. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

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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 gas production, the number of wells we anticipate drilling during 2005 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 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 the description of our business in Item 1 of our Form 10-K report for the year ended December 31, 2004 or in our Management’s Discussion Analysis of Financial Condition in Item 7 of our Form 10-K report for the year ended December 31, 2004. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in our Annual Report on Form 10-K for the fiscal year ended December 31, 2004. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the fiscal year ended December 31, 2004.

Derivative Contracts

The following table reflects open commodity derivative contracts at September 30, 2005, the associated volumes and the corresponding NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)		NYMEX Reference Price
Costless Collars
10/01/05 - 10/31/05		Purchased put		Cash flow		60,000			$	5.45
		Written call		Cash flow		60,000				8.00
01/01/06 - 03/31/06		Purchased put		Cash flow				7,500	$	62.00
		Written call		Cash flow				7,500		74.50
04/01/06 - 06/30/06		Purchased put		Cash flow				16,500	$	54.80
		Written call		Cash flow				16,500		75.00
Three Way Costless Collars
10/01/05 - 10/31/05		Purchased put		Cash flow		100,000			$	6.00
		Written call		Cash flow		100,000				7.20
		Written put		Undesignated		100,000				5.00
10/01/05 - 10/31/05		Purchased put		Cash flow		60,000			$	7.00
		Written call		Cash flow		60,000				7.76
		Written put		Undesignated		60,000				5.75
10/01/05 - 12/31/05		Purchased put		Cash flow				15,000	$	40.00
		Written call		Cash flow				15,000		53.00
		Written put		Undesignated				15,000		30.00
10/01/05 - 03/31/06		Purchased put		Cash flow				36,000	$	48.00
		Written call		Cash flow				36,000		60.70
		Written put		Undesignated				36,000		38.00
11/01/05 - 03/31/06		Purchased put		Cash flow		250,000			$	6.75
		Written call		Cash flow		250,000				8.80
		Written put		Undesignated		250,000				5.50
11/01/05 - 03/31/06		Purchased put		Cash flow		350,000			$	8.00
		Written call		Cash flow		350,000				9.75
		Written put		Undesignated		350,000				6.50
11/01/05 - 03/31/06		Purchased put		Cash flow		400,000			$	10.00
		Written call		Cash flow		400,000				13.08
		Written put		Undesignated		400,000				8.50
04/01/06 - 06/30/06		Purchased put		Cash flow				7,500	$	63.00
		Written call		Cash flow				7,500		75.25
		Written put		Undesignated				7,500		48.00
07/01/06 - 09/30/06		Purchased put		Cash flow				15,000	$	63.00
		Written call		Cash flow				15,000		75.65
		Written put		Undesignated				15,000		48.00
04/01/06 - 10/31/06		Purchased put		Cash flow		420,000			$	7.50
		Written call		Cash flow		420,000				9.15
		Written put		Undesignated		420,000				6.25
04/01/06 - 10/31/06		Purchased put		Cash flow		490,000			$	8.50
		Written call		Cash flow		490,000				9.96
		Written put		Undesignated		490,000				7.00

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The following table reflects commodity derivative contracts entered into subsequent to September 30, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)	NYMEX Reference Price
Costless Collars
04/01/06 - 10/31/06		Purchased put		Cash flow		490,000		$	8.00
		Written call		Cash flow		490,000			14.85
11/01/06 - 03/31/07		Purchased put		Cash flow		450,000		$	8.00
		Written call		Cash flow		450,000			21.20

ITEM 4.CONTROLS AND PROCEDURES

Material Control Weakness Previously Disclosed

In our 2004 Annual Report on Form 10-K, we reported that we did not maintain effective control, as of December 31, 2004, over the accounting for depletion expense and accumulated depletion. This resulted in a material control weakness at December 31, 2004 related to accounting for depletion expense and accumulated depletion. Specifically, our controls related to the preparation and review of the quarterly depletion computations were not adequate to ensure that that the changes in depletion rate estimates used to determine depletion expense and the related accumulated depletion of net proved oil and natural gas properties are only applied prospectively in accordance with accounting principles generally accepted in the United States of America. The remedial actions implemented in the first quarter of 2005 related to this material weakness are described below.

Evaluation of Disclosure Controls and Procedures

As of September 30, 2005, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures effectively ensure that the information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified by the SEC.

Changes in Internal Control over Financial Reporting

During the first quarter of 2005, we took action to remediate the material weakness identified at December 31, 2004 and update related accounting policies and procedures. Due to such remediation, our depletion rate at each respective period end has been applied to the respective current period production only, as required by accounting principles generally accepted in the United States of America. There were no other changes in our internal controls or in other factors that have materially affected, or are reasonably likely to materially affect, our internal controls subsequent to the date of their evaluation of our disclosure controls and procedures.

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PART II - OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

As discussed in Note 5 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 2.UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased		Average Price Paid per Share
July 1, 2005 - September 30, 2005		0	$	- -

No purchases were made under a publicly announced plan.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS

None

ITEM 5.OTHER INFORMATION

None.

ITEM 6.EXHIBITS

Number		Description
10.1* †	—	Form of Restricted Stock Agreement
31.1†	—	Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
31.2†	—	Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
32.1 †	—	Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350
32.2†	—	Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

* Management contract or compensatory contract

† Filed herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on November 4, 2005.

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

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EX-10.1

BRIGHAM EXPLORATION COMPANY

1997 INCENTIVE PLAN

RESTRICTED STOCK AGREEMENT

THIS AGREEMENT, made as of the 10th day of October, 2005, by and between BRIGHAM EXPLORATION COMPANY, a Delaware corporation (the “Company”), and __________________ (“Employee”);

W I T N E S S E T H:

WHEREAS, the Compensation Committee of the Board of Directors of the Company (the “Committee”), acting under the Company’s 1997 Incentive Plan (the “Plan”), has determined that it is desirable to award shares of restricted stock to Employee under the Plan; and

WHEREAS, pursuant to the Plan, the Committee has determined that the shares of restricted stock so awarded shall be subject to the restrictions, terms and conditions of this Agreement;

NOW, THEREFORE, in consideration of the premises and mutual covenants and agreements herein contained, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:

1.Plan Provisions. Capitalized terms used and not otherwise defined herein shall have the respective meanings given such terms in the Plan. By execution of this Agreement, Employee agrees that the Restricted Stock covered hereby shall be governed by and subject to all applicable provisions of the Plan. This Agreement is subject to the Plan, and the Plan shall govern where there is any inconsistency between the Plan and this Agreement.

2.Restricted Stock. On the terms and conditions and subject to the restrictions, including forfeiture, hereinafter set forth, the Company hereby makes to Employee, and Employee hereby accepts, the awards of Restricted Stock (each such issuance is herein called an “Award”) set forth on Exhibit A hereto, which awards are being issued by the Company pursuant to the Plan. The number of shares of Restricted Stock of each Award covered hereby (the “Restricted Shares”), the date of issuance of such shares (the “Issue Date”), and the Restricted Period applicable to such shares, including the date on which such Restricted Period is scheduled to terminate (the “Scheduled Termination Date”), are set forth on Exhibit A attached hereto. A certificate or certificates representing the Restricted Shares shall be issued in the name of Employee as of the applicable Issue Date and delivered to Employee on such Issue Date or as soon thereafter as practicable. Employee shall cause the certificate(s) representing the Restricted Shares, upon receipt thereof by Employee, to be deposited, together with stock powers and any other instrument of transfer reasonably requested by the Company duly endorsed in blank, with the Company, to be held by the Company in escrow for Employee’s benefit until such time as any Restricted Shares represented by such certificate(s) are forfeited to the Company or the restrictions thereon terminate. Restricted Shares shall be delivered to Employee upon vesting or assigned and transferred to and reacquired by the Company upon forfeiture, as hereinafter set forth.

3.Vesting/Forfeiture.

(a)   Subject to Sections 3(b), 3(c) and 3(d), with respect to each Award of Restricted Shares to Employee, the Restricted Shares subject to such Award shall be forfeited to the Company at no cost to the Company if Employee’s employment with the Company or a subsidiary of the Company terminates prior to the termination of the Restricted Period applicable to such Restricted Shares.

(b)   Upon Employee’s termination of employment during the Restricted Period due to death during the Restricted Period, then, the Awards covered hereby that have not vested shall be deemed to have vested as of the date of the Employee’s death and the Restricted Period applicable to such shares shall terminate.

(c)   Upon (i) Employee’s termination of employment during the Restricted Period due to Disability (as defined below), or (ii) the involuntary termination of Employee’s employment with the Company and its subsidiaries by action of the Company (or its subsidiary, if Employee is employed by a subsidiary of the Company) during the Restricted Period for reasons other than Just Cause (as defined below) (each, a “Termination Event”), then, with respect to the Award covered hereby with the earliest Scheduled Termination Date after such Termination Event, (A) a ratable portion of the number of Restricted Shares applicable to such Scheduled Termination Date (the “Next Vested Shares”) shall be deemed to have vested as of the date of such Termination Event, determined by multiplying the number of Next Vested Shares by a fraction with a numerator equal to the number of full months which have then elapsed since the last date of termination of a Restricted Period pursuant to this Agreement (or Issue Date in the event that no shares had previously vested) and a denominator equal to the total number of months between the last date of termination of a Restricted Period pursuant to this Agreement (or Issue Date in the event that no shares had previously vested) and the next Scheduled Termination Date under this Agreement, and rounding to the closest whole number, and (B) the Restricted Period applicable to such ratable portion of Next Vested Shares shall terminate.

(d)   If either (1) Ben M. Brigham is no longer both the Chief Executive Officer and Chairman of the Board of the Company, or (2) any “person,” as that term is defined in Section 3(a)(9) of the Securities Exchange Act of 1934 (the “Exchange Act”) (other than the Company, any of its subsidiaries, any employee benefit plan of the Company or any of its subsidiaries, or any entity organized, appointed or established by the Company for or pursuant to the terms of such a plan), together with all “affiliates” and “associates” (as such terms are defined in Rule 12b-2 under the Exchange Act) of such person, or any “Person” or “group” (as those terms are used in Sections 13(d) and 14(d) of the Exchange Act), becomes the “beneficial owner” or “beneficial owners” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, of securities of the Company representing in the aggregate forty-nine percent (49%) or more of either the then outstanding shares of Common Stock of the Company or the voting power of the Company, in either such case (each of the events described in (1) and (2) above being referred to herein as a "Fundamental Change"), and Recipient’s employment with the Company is involuntarily terminated within two (2) years of such Fundamental Change, then immediately upon such termination, the unvested Restricted Shares shall be forfeited to the Company at no cost to the Company and Employee shall receive a new separate grant of __________________ (___00) shares of fully vested and unrestricted Company common stock

2

(the “Additional Grant”). In the event that within two (2) years of a Fundamental Change Employee’s job responsibilities are substantially reduced, his annual salary is reduced, or he is required to move his office location more than 30 miles from its existing location, and Employee terminates his employment due to such reduction or required move within 15 days of such reduction or the announcement of the required move, then Employee shall be deemed to have been involuntarily terminated for purposes of this paragraph, and immediately upon such termination, the unvested Restricted Shares shall be forfeited to the Company at no cost to the Company and Employee shall receive the Additional Grant of _____________ (____00) shares. However, notwithstanding the above, the Company’s obligation to issue the Additional Grant shall be contingent upon the Company having availability under the Plan.

(e)   Unless and until Restricted Shares are delivered to Employee upon vesting, such Restricted Shares shall not be sold, assigned, transferred, discounted, exchanged, pledged, or otherwise encumbered or disposed of by Employee in any manner. Transfer of employment without interruption of service between or among the Company and any of its subsidiaries shall not be considered a termination of employment.

(f)    With respect to each Award of Restricted Shares to Employee, upon the termination of the Restricted Period applicable to such shares, the restrictions applicable to the Restricted Shares that have not theretofore been forfeited shall terminate, and as soon as practicable thereafter a stock certificate for the number of Restricted Shares with respect to which the restrictions have terminated, together with any dividends or other distributions with respect to such shares then being held by the Company pursuant to the provisions of this Agreement, shall be delivered, free of all such restrictions, to Employee or Employee’s beneficiary or estate, as the case may be.

(g)   Notwithstanding anything contained herein to the contrary, the Committee shall have the right to cancel all or any portion of any outstanding restrictions prior to the termination of such restrictions with respect to any or all of the Restricted Shares on such terms and conditions as the Committee may, in writing, deem appropriate.

(h)   For purposes of this Agreement, the following terms shall have the indicated meanings:

Disability: The “Disability” of Employee shall be deemed to have occurred if, in the good faith judgment of the Committee, Employee shall become unable to continue the proper performance of Employee’s duties as an employee of the Company or a subsidiary thereof on a full-time basis as a result of Employee’s physical or mental incapacity.

Just Cause: The term “Just Cause” shall mean any of the following: (i) conduct by Employee that constitutes willful misconduct or gross negligence in the performance of his duties; (ii) conduct by the Employee that constitutes fraud, dishonesty, or a criminal act, whether or not with respect to the Company; (iii) embezzlement of funds or misappropriation of other property by Employee, (iv) any act or conduct by Employee that, in the good faith opinion of the Board of Directors or the President of the Company, is materially detrimental to the Company or reflects unfavorably on the Company or the Employee to such an extent that the Company’s best interests reasonably require the Employee’s discharge.

3

4.Rights as Stockholder. Upon the issuance of a certificate or certificates representing any Restricted Shares to Employee, Employee shall become the owner thereof for all purposes and shall have all rights as a stockholder, including voting rights and the right to receive dividends and distributions, with respect to such Restricted Shares, subject to the provisions hereof. If the Company shall pay or declare a dividend or make a distribution of any kind, whether due to a reorganization, recapitalization or otherwise, with respect to the shares of Common Stock constituting Restricted Shares, then the Company shall pay or make such dividend or other distribution with respect to such Restricted Shares; provided, however, that the cash, stock or other securities and other property constituting such dividend or other distribution shall be held by the Company subject to the restrictions applicable to any Restricted Shares until such Restricted Shares with respect to which such dividend or other distribution was paid or made are either vested or forfeited. If any Restricted Shares with respect to which such dividend or distribution was paid or made do not vest but instead are forfeited pursuant to the provisions hereof, then Employee shall not be entitled to receive such dividend or distribution with respect to such forfeited shares and such dividend or distribution with respect to such forfeited shares shall likewise be forfeited and automatically transferred to and reacquired by the Company. If any Restricted Shares with respect to which such dividend or distribution was paid or made become vested pursuant to the provisions hereof, then Employee shall be entitled to receive such dividend or distribution with respect to such vested shares, without interest, and such dividend or distribution with respect to such vested shares shall likewise be delivered to Employee.

5.Withholding Taxes.

(a)   With respect to each Award of shares of Restricted Stock to Employee, Employee may elect, within 30 days of the Issue Date of such shares and on notice to the Company, to realize income for federal income tax purposes equal to the fair market value of the shares on the Issue Date. In such event, Employee shall make arrangements satisfactory to the Compensation Committee to pay in the year of the Award any federal, state, or local taxes required to be withheld with respect to such shares. If Employee fails to make such payments, then any provision of this Agreement to the contrary notwithstanding, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due from the Company or its subsidiaries to or with respect to Employee, whether or not pursuant to this Agreement or the Plan and regardless of the form of payment, any federal, state, or local taxes of any kind required by law to be withheld with respect to such shares.

(b)   (i)   No later than the date of the termination of the restrictions on any of the shares of Restricted Stock covered hereby, Employee will pay to the Company or its subsidiaries, or make arrangements satisfactory to the Compensation Committee regarding payment of, any statutory minimum taxes required by law to be withheld with respect to the shares of Restricted Stock with respect to which such restrictions have terminated.

  (ii)  The Company may elect to allow Employee, to the extent permitted by law, to deliver to the Company or its subsidiaries shares of Restricted Stock to which Employee shall be entitled upon the vesting thereof (or other unrestricted shares of Common Stock owned by Employee), valued at the fair market value of such shares at the time of such delivery to the Company or its subsidiaries, to satisfy the obligation of Employee under Section 5(b)(i) hereof.

4

  (iii) Any provision of this Agreement to the contrary notwithstanding, if Employee does not otherwise satisfy the obligation of Employee under Section 5(b)(i) hereof, then the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due from the Company or its subsidiaries to or with respect to Employee, whether or not pursuant to this Agreement or the Plan and regardless of the form of payment, any federal, state, or local taxes of any kind required by law to be withheld with respect to the shares of Restricted Stock with respect to which the restrictions on the Restricted Stock have terminated.

6.Legend. Each certificate representing shares of Restricted Stock covered hereby shall conspicuously set forth on the face or back thereof, in addition to any legends required by applicable law or other agreement, a legend in substantially the following form:

THE SHARES REPRESENTED BY THIS CERTIFICATE HAVE BEEN ASSIGNED AND TRANSFERRED TO THE RECORD HOLDER HEREOF PURSUANT TO THE TERMS OF THE BRIGHAM EXPLORATION COMPANY 1997 INCENTIVE PLAN AND MAY NOT BE SOLD, ASSIGNED, TRANSFERRED, DISCOUNTED, EXCHANGED, PLEDGED, OR OTHERWISE ENCUMBERED OR DISPOSED OF IN ANY MANNER EXCEPT AS SET FORTH IN THE TERMS OF THE AGREEMENT EMBODYING THE AWARD OF SUCH SHARES DATED OCTOBER 10, 2005. A COPY OF SUCH PLAN AND AGREEMENT IS ON FILE IN THE OFFICES OF THE CORPORATION.

7.Governing Law. This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of Delaware, without regard to the principles of conflicts of laws thereof.

8.Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, personal representatives, successors, and permitted assigns; provided, however, that Employee shall not assign or otherwise transfer this Agreement or any of Employee’s rights or obligations hereunder.

9.Entire Agreement; Amendment. This Agreement, together with the exhibits hereto and any other writings referred to herein or delivered pursuant hereto, constitute the entire agreement between the parties hereto with respect to the subject matter hereof and supersede all prior agreements and understandings, whether written or oral, between the parties with respect to the subject matter hereof. To the fullest extent provided by applicable law, this Agreement may be amended, modified, and supplemented by mutual consent of the parties hereto at any time, with respect to any of the terms contained herein, in such manner as may be agreed upon in writing by such parties.

10.   Notices. All notices and other communications hereunder shall be in writing and shall be deemed given:

(a)   If to the Company, when delivered by hand or on the third business day after being deposited in the United States mail (certified mail with postage prepaid) to:

5

  Brigham Exploration Company

  6300 Bridge Point Parkway

  Building 2, Suite 500

  Austin, Texas 78730

  Attention: Vice President Administration

(b)       If to Employee, when delivered by hand or on the third business day after being deposited in the United States mail (certified mail with postage prepaid) to the address for Employee contained in the Company’s records.

Either party may at any time give to the other notice in writing of any change of address of the party giving such notice and from and after the giving of such notice the address or addresses therein specified will be deemed to be the address of such party for the purposes of giving notice hereunder.

11.   Counterparts. This Agreement may be executed by the parties hereto in any number of counterparts, each of which shall be deemed an original, but all of which shall constitute one and the same agreement. Each counterpart may consist of a number of copies hereof each signed by less than all, but together signed by all, the parties hereto.

IN WITNESS WHEREOF, the Company and Employee have executed this Agreement as of the date first above written.

BRIGHAM EXPLORATION COMPANY
By:
	Name:  Ben M. Brigham
	Title:  President and CEO

6

EXHIBIT A

RESTRICTED STOCK AWARDS

Award	Number of Shares of Restricted Stock	Issue Date	Duration of Restricted Period	Scheduled Termination Date
1.	____	October 10, 2005	Commencing on October 10, 2005 and ending at 12:01 AM on October 10, 2006	12:01 AM on October 10, 2006
2.	____	October 10, 2005	Commencing on October 10, 2005 and ending at 12:01 AM on October 10, 2007	12:01 AM on October 10, 2007
3.	____	October 10, 2005	Commencing on October 10, 2005 and ending at 12:01 AM on October 10, 2008	12:01 AM on October 10, 2008
4.	____	October 10, 2005	Commencing on October 10, 2005 and ending at 12:01 AM on October 10, 2009	12:01 AM on October 10, 2009
5.	____	October 10, 2005	Commencing on October 10, 2005 and ending at 12:01 AM on October 10, 2010	12:01 AM on October 10, 2010

7

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) OF THE

SECURITIES EXCHANGE ACT OF 1934

I, Ben M. Brigham, certify that:

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

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

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

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

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

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

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

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

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

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

Date: November 4, 2005

/s/ Bud M. Brigham

Bud M. Brigham

Chief Executive Officer, President and Chairman of the Board

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) OF THE

SECURITIES EXCHANGE ACT OF 1934

I, Eugene B. Shepherd, Jr, certify that:

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

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

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

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

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

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

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

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

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

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

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

Date: November 4, 2005

/s/ Eugene B. Shepherd, Jr.

Eugene B. Shepherd, Jr.

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Brigham Exploration Company (the"Company") on Form 10-Q for the period ending June 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Ben M.Brigham, President, Chief Executive Officer and Chairman of the Board of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: November 4, 2005	/s/ Bud M. Brigham
	Bud M. Brigham
	Chief Executive Officer, President and Chairman of the Board

This certification shall not be deemed to be "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Brigham Exploration Company and will be retained by Brigham Exploration Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Brigham Exploration Company (the"Company") on Form 10-Q for the period ending June 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Eugene B. Shepherd, Jr., Executive Vice President and Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: November 4, 2005	/s/ Eugene B. Shepherd, Jr.
	Eugene B. Shepherd, Jr.
	Executive Vice President and Chief Financial Officer

This certification shall not be deemed to be "filed" for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided Brigham Exploration Company and will be retained by Brigham Exploration Company and furnished to the Securities and Exchange Commission or its staff upon request.