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, 2006

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 þ No ¨

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

Large Accelerated Filer ¨ Accelerated Filer þ Non-Accelerated Filer ¨

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

Yes ¨ No þ

Class	Outstanding
Common Stock, par value $.01 per share as of November 6, 2006	45,527,508

Brigham Exploration Company

Third Quarter 2006 Form 10-Q Report

TABLE OF CONTENTS

		Page
PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance Sheets - September 30, 2006 and December 31, 2005	1
	Consolidated Statements of Operations - Three and nine months ended September 30, 2006 and 2005	2
	Consolidated Statement of Stockholders’ Equity - Nine months ended September 30, 2006	3
	Consolidated Statements of Cash Flows - Nine months ended September 30, 2006 and 2005	4
	Notes to the Consolidated Financial Statements	5
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4.	CONTROLS AND PROCEDURES	38
PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	39
ITEM 1.A.	RISK FACTORS	39
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
ITEM 3.	DEFALTS UPON SENIOR SECURITIES	39
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS	39
ITEM 5.	OTHER INFORMATION	39
ITEM 6.	EXHIBITS	39
SIGNATURES		40

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	September 30, 2006			December 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	9,614		$	3,975
Accounts receivable		14,899			22,825
Investments		1,004			-
Deferred income taxes		-			482
Derivative assets		5,630			34
Other current assets		2,394			1,009
Total current assets		33,541			28,325
Oil and natural gas properties, net (full cost method)		452,898			347,329
Other property and equipment, net		922			1,027
Deferred loan fees		3,467			2,174
Other noncurrent assets		1,800			1,572
Total assets	$	492,628		$	380,427
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	17,056		$	12,128
Royalties payable		5,301			6,886
Accrued drilling costs		24,671			12,218
Participant advances received		2,364			2,116
Other current liabilities		10,183			4,119
Total current liabilities		59,575			37,467
Senior Notes		123,381			-
Senior credit facility		-			33,100
Senior subordinated notes		-			30,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at September 30, 2006 and December 31, 2005		10,101			10,101
Deferred income taxes		32,922			23,563
Other noncurrent liabilities		4,864			4,556
Commitments and contingencies (Note 3)
Stockholders' equity:
Common stock, $.01 par value, 90 million shares authorized, 45,059,868 and 44,917,768 shares issued and 45,041,900 and 44,917,768 shares outstanding at September 30, 2006 and December 31, 2005, respectively		451			449
Additional paid-in capital		202,274			202,127
Treasury stock, at cost; 17,968 shares at September 30, 2006		(211	)		-
Unearned stock compensation		-			(2,299	)
Accumulated other comprehensive income (loss)		2,695			(426	)
Retained earnings		56,576			41,789
Total stockholders’ equity		261,785			241,640
Total liabilities and stockholders' equity	$	492,628		$	380,427

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 September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Revenues:
Oil and natural gas sales	$	26,088		$	25,189		$	78,018		$	60,326
Other revenue		57			37			87			136
		26,145			25,226			78,105			60,462
Costs and expenses:
Lease operating		2,672			1,541			7,938			5,149
Production taxes		1,259			741			3,455			1,909
General and administrative		1,985			1,317			5,936			3,719
Depletion of oil and natural gas properties		11,910			7,953			33,272			21,612
Depreciation and amortization		140			183			376			543
Accretion of discount on asset retirement obligations		80			44			229			126
		18,046			11,779			51,206			33,058
Operating income		8,099			13,447			26,899			27,404
Other income (expense):
Interest income		518			62			1,072			153
Interest expense, net		(2,669	)		(1,138	)		(6,899	)		(2,645	)
Gain (loss) on derivatives, net		2,214			(529	)		2,505			(995	)
Other income (expense)		171			32			1,181			144
		234			(1,573	)		(2,141	)		(3,343	)
Income before income taxes		8,333			11,874			24,758			24,061
Income tax expense:
Current		-			-			-			-
Deferred		(3,087	)		(4,196	)		(9,971	)		(8,525	)
		(3,087	)		(4,196	)		(9,971	)		(8,525	)
Net income	$	5,246		$	7,678		$	14,787		$	15,536
Net income per share available to common stockholders:
Basic	$	0.12		$	0.18		$	0.33		$	0.37
Diluted	$	0.12		$	0.18		$	0.33		$	0.36
Weighted average shares outstanding:
Basic		45,027			42,236			45,005			42,175
Diluted		45,294			43,528			45,451			43,244

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, 2005		44,918	$	449	$	202,127		$	—		$	(2,299	)	$	(426	)	$	41,789	$	241,640
Comprehensive income:
Net income		—		—		—			—			—			—			14,787		14,787
Unrealized gain (losses) on cash flow hedges		—		—		—			—			—			8,015			—		8,015
Tax provisions related to cash flow hedges		—		—		—			—			—			(1,681	)		—		(1,681	)
Net (gains) losses included in net income		—		—		—			—			—			(3,213	)		—		(3,213	)
Comprehensive income																				17,908
Adoption of SFAS No. 123R		—		—		(2,299	)		—			2,299			—			—		—
Issuance of common stock		—		—		37			—			—			—			—		37
Exercises of employee stock options		77		1		338			—			—			—			—		339
Vesting of restricted stock		65		1		(1	)		—			—			—			—		—
Stock based compensation		—		—		2,072			—			—			—			—		2,072
Repurchases of common stock		—		—		—			(211	)		—			—			—		(211	)
Balance, September 30, 2006		45,060	$	451	$	202,274		$	(211	)	$	-		$	2,695		$	56,576	$	261,785

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,
	2006			2005
Cash flows from operating activities:
Net income	$	14,787		$	15,536
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		33,272			21,612
Depreciation and amortization		376			543
Stock based compensation		1,134			-
Write-off of deferred loan costs		965			-
Interest paid through issuance of additional mandatorily redeemable preferred stock		-			581
Amortization of deferred loan fees and debt issuance costs		508			373
Market value adjustment for derivative instruments		(2,926	)		995
Accretion of discount on asset retirement obligations		229			126
Deferred income taxes		9,971			8,525
Other noncash items		64			103
Changes in operating assets and liabilities:
Accounts receivable		7,926			(1,320	)
Other current assets		(1,378	)		(459	)
Accounts payable		4,928			(5,628	)
Royalties payable		(1,585	)		389
Participant advances received		248			(1,835	)
Other current liabilities		6,032			543
Other noncurrent assets and liabilities		(256	)		(22	)
Net cash provided by operating activities		74,295			40,062
Cash flows from investing activities:
Additions to oil and natural gas properties		(125,054	)		(83,306	)
Purchases of short term investments		(52,409	)		-
Sales and redemptions of short term investments		51,405			-
Additions to other property and equipment		(335	)		(184	)
Decrease (increase) in drilling advances paid		254			205
Net cash used by investing activities		(126,139	)		(83,285	)
Cash flows from financing activities:
Proceeds from senior notes offering		123,286			-
Increase in senior credit facility		24,200			49,100
Repayment of senior credit facility		(57,300	)		(12,000	)
Increase in senior subordinated notes		-			10,000
Repayment of senior subordinated notes		(30,000	)		-
Deferred loan fees paid and equity costs		(2,868	)		(892	)
Proceeds from issuance of stock, net of issuance costs		37			-
Proceeds from exercise of employee stock options		339			797
Repurchases of common stock		(211	)		(190	)
Net cash provided by financing activities		57,483			46,815
Net increase (decrease) in cash and cash equivalents		5,639			3,592
Cash and cash equivalents, beginning of year		3,975			2,281
Cash and cash equivalents, end of period	$	9,614		$	5,873

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 presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham's 2005 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

See Note 11 for a discussion of the accounting policy pertaining to the adoption of Statement of Financial Accounting Standard (SFAS) No. 123R, “Share-Based Payment” (SFAS 123R) effective January 1, 2006 using the modified prospective approach.

3. Commitments and Contingencies

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

As of September 30, 2006, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.

4. Net Income Available Per Common Share

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

5

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2006 and 2005 are as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Weighted average common shares outstanding - basic		45,027		42,236		45,005		42,175
Plus: Potential common shares Stock options and restricted stock		267		1,292		446		1,069
Weighted average common shares outstanding - diluted		45,294		43,528		45,451		43,244
Stock options excluded from diluted EPS due to the anti-dilutive effect		2,633		—		1,700		10

5. Income Taxes

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

	September 30, 2006
Current income taxes:
Federal	$	-
State		-
Deferred income taxes:
Federal		8,630
State		1,341
	$	9,971

In May 2006, the state of Texas enacted legislation that replaces the taxable capital and earned surplus components of its franchise tax with a new franchise tax that is based on modified gross revenue. The new franchise tax (referred to as the “Margin Tax”) becomes effective beginning with the 2007 tax year. The current franchise tax remains in effect through the end of 2006.

Within the context of generally accepted accounting principals in the United States, the Margin Tax is based on a measure of income and is thus accounted for in accordance with Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects of the tax law change in the period of enactment. The Company has recorded a deferred tax liability in the amount of $1.3 million to reflect the estimated impact of the adoption of the Margin Tax in 2006.

The Margin Tax legislation contains significant inconsistencies in language describing the computation of the tax, which combined with unclear legislative intent preclude reliable interpretation of the law. The Texas Comptroller of public accounts (responsible for administering Texas tax laws) has issued guidance on calculating the Margin Tax that the Company has followed in determining the effects of the Margin Tax, even though the comptroller’s guidance differs in several respects from the text of the enacted law.

6

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

6. Senior Notes

In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the “Senior Notes”). The Senior Notes were priced at 98.629% of their face value to yield 9 7/8% and are fully and unconditionally guaranteed by Brigham Exploration and its wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P. (the “Guarantors”). The guarantees are joint and several. Brigham Exploration does not have any independent assets or operations and the aggregate assets and revenues of the subsidiaries not guaranteeing are less than 3% of the Company’s consolidated assets and revenues.

7. Short-term Investments

The Company classifies all of its short-term investments as available-for-sale securities. Such short-term investments consist of state and municipal securities, which are stated at market value, with unrealized gains and losses on such securities reflected, net of tax, as other comprehensive income in stockholders’ equity. Any realized gains and losses on short-term investments are included in earnings and are derived using the specific identification method for determining the cost of securities. Dividend and interest income are recognized when earned. It is the Company’s intent to maintain a liquid portfolio to take advantage of investment opportunities and, therefore, all securities are considered to be available-for-sale and are classified as current assets. The carrying amount of the Company’s investments at September 30, 2006 is shown below (in thousands):

	Cost		Unrealized Holding Gains / (Losses)		Fair Value
Available-for-Sale Securities:
State and municipal securities	$	1,004	$	-	$	1,004

There were no investments at September 30, 2005.

8. Derivative Instruments and Hedging Activities

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

Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham's 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, 2006 and 2005:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
Natural Gas
Average price per Mcf as reported (including hedging results)	$	7.07	$	8.45		$	7.17	$	7.01
Average price per Mcf realized (excluding hedging results)	$	6.48	$	8.71		$	6.78	$	7.14
Increase (decrease) in revenue (in thousands)	$	1,549	$	(590	)	$	3,039	$	(831	)
Oil
Average price per Bbl as reported (including hedging results)	$	72.36	$	58.51		$	67.22	$	49.87
Average price per Bbl realized (excluding hedging results)	$	71.86	$	60.44		$	67.22	$	53.32
Increase (decrease) in revenue (in thousands)	$	52	$	(208	)	$	2	$	(1,134	)

7

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges is included in gain (loss) on derivatives, net. 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,
	2006		2005			2006		2005
Increase (decrease) in earnings due to ineffectiveness	$	2,336	$	(477	)	$	3,213	$	(890	)

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 or paid when Brigham entered into these option agreements.

Derivative positions including written put options that are not designated as hedges 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 gain (loss) on derivatives, net.

The following table provides a summary of the fair value of these derivatives included in other current liabilities (in thousands):

	September 30, 2006			December 31, 2005
Fair value of undesignated derivatives	$	(293	)	$	(125	)

The following table provides a summary of the impact on earnings from the changes in the fair values of these derivative contracts as recognized as gain (loss) on derivatives, net, for the three and nine months ended September 30 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006			2005
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives	$	115	$	(52	)	$	(168	)	$	(105	)

The following table reflects open commodity derivative contracts at September 30, 2006, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).

			Notional Amount
Settlement Period	Derivative Instrument	Hedge Strategy	Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
10/01/06 - 10/31/06	Purchased put	Cash flow		70,000			$	8.00
	Written call	Cash flow		70,000				14.85
10/01/06 - 12/31/06	Purchased put	Cash flow				27,000	$	50.00
	Written call	Cash flow				27,000		77.50
10/01/06 - 10/31/06	Purchased put	Cash flow		120,000			$	8.00
	Written call	Cash flow		120,000				16.65

8

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

			Notional Amount
Settlement Period	Derivative Instrument	Hedge Strategy	Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
10/01/06 - 10/31/06	Purchased put	Cash flow		100,000			$	5.50
	Written call	Cash flow		100,000				11.75
11/01/06 - 01/31/07	Purchased put	Cash flow		540,000			$	8.00
	Written call	Cash flow		540,000				23.25
11/01/06 - 03/31/07	Purchased put	Cash flow		450,000			$	8.00
	Written call	Cash flow		450,000				21.20
11/01/06 - 03/31/07	Purchased put	Cash flow		375,000			$	8.00
	Written call	Cash flow		375,000				15.75
11/01/06 - 06/30/07	Purchased put	Cash flow				32,000	$	59.00
	Written call	Cash flow				32,000		90.00
01/01/07 - 03/31/07	Purchased put	Cash flow				24,000	$	50.00
	Written call	Cash flow				24,000		78.25
02/01/07 - 03/31/07	Purchased put	Cash flow		300,000			$	8.00
	Written call	Cash flow		300,000				25.75
04/01/07 - 09/30/07	Purchased put	Cash flow				30,000	$	50.00
	Written call	Cash flow				30,000		81.50
04/01/07 - 09/30/07	Purchased put	Cash flow				12,000	$	56.00
	Written call	Cash flow				12,000		92.50
04/01/07 - 10/31/07	Purchased put	Cash flow		280,000			$	7.00
	Written call	Cash flow		280,000				15.45
04/01/07 - 10/31/07	Purchased put	Cash flow		280,000			$	7.25
	Written call	Cash flow		280,000				15.25
04/01/07 - 10/31/07	Purchased put	Cash flow		280,000			$	7.00
	Written call	Cash flow		280,000				14.85
04/01/07 - 10/31/07	Purchased put	Cash flow		700,000			$	7.50
	Written call	Cash flow		700,000				11.00
04/01/07 - 10/31/07	Purchased put	Cash flow		350,000			$	7.00
	Written call	Cash flow		350,000				11.60
07/01/07 - 10/31/07	Purchased put	Cash flow				10,000	$	58.00
	Written call	Cash flow				10,000		90.50
10/01/07 - 12/31/07	Purchased put	Cash flow				9,000	$	59.20
	Written call	Cash flow				9,000		90.00
10/01/07 - 03/31/08	Purchased put	Cash flow				18,000	$	56.00
	Written call	Cash flow				18,000		89.95
11/01/07 - 03/31/08	Purchased put	Cash flow		250,000			$	8.00
	Written call	Cash flow		250,000				13.40
01/01/08 - 03/31/08	Purchased put	Cash flow				7,500	$	57.60
	Written call	Cash flow				7,500		90.00
04/01/07 - 08/31/07	Purchased put	Cash flow		60,000			$	7.00
	Written call	Cash flow		60,000				10.00
11/01/07 - 03/31/08	Purchased put	Cash flow		300,000			$	8.85
	Written call	Cash flow		300,000				15.00
11/01/07 - 03/31/08	Purchased put	Cash flow		300,000			$	9.30
	Written call	Cash flow		300,000				15.00
10/01/06 - 02/28/07	Purchased put	Cash flow				20,000	$	70.00
	Written call	Cash flow				20,000		85.20
11/01/07 - 03/31/08	Purchased put	Cash flow				10,000	$	68.40
	Written call	Cash flow				10,000		90.00
04/01/08 - 10/31/08	Purchased put	Cash flow				21,000	$	65.70
	Written call	Cash flow				21,000		90.00
06/01/07 - 09/30/07	Purchased put	Cash flow				6,000	$	65.00
	Written call	Cash flow				6,000		80.00

9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

			Notional Amount
Settlement Period	Derivative Instrument	Hedge Strategy	Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
10/01/07 - 03/31/08	Purchased put	Cash flow				6,000	$	65.00
	Written call	Cash flow				6,000		80.25
Three Way Costless Collars
10/01/06 - 10/31/06	Purchased put	Cash flow		60,000			$	7.50
	Written call	Cash flow		60,000				9.15
	Written put	Undesignated		60,000				6.25
10/01/06 - 10/31/06	Purchased put	Cash flow		70,000			$	8.50
	Written call	Cash flow		70,000				9.96
	Written put	Undesignated		70,000				7.00

The following table reflects commodity derivative contracts entered subsequent to September 30, 2006, the associated volumes and the corresponding weighted average NYMEX reference price.

			Notional Amount
Settlement Period	Derivative Instrument	Hedge Strategy	Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
01/01/07 - 12/31/07	Purchased put	Cash flow				12,000	$	55.00
	Written call	Cash flow				12,000		79.00
01/01/07 - 03/31/07	Purchased put	Cash flow		90,000			$	7.50
	Written call	Cash flow		90,000				10.00
01/01/07 - 03/31/07	Purchased put	Cash flow		150,000			$	7.25
	Written call	Cash flow		150,000				9.65
04/01/07 - 10/31/07	Purchased put	Cash flow		350,000			$	7.00
	Written call	Cash flow		350,000				9.10

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

Basis Swaps

Derivative positions including basis swaps that are not designated as hedges are reflected at fair value on the balance sheet date. These arrangements are designed to manage our exposure to the basis risk associated with the fluctuations between the price received at NYMEX and the actual delivery point of our oil and natural gas volumes during the period beginning August 1, 2006 through October 31, 2006. These derivatives will be marked-to-market at the end of each period to reflect current fair value and the realized and unrealized gains or losses will be recorded as gain (loss) on derivatives, net, on our consolidated statement of operations. The following table provides a summary of the fair value of these derivatives included in other current liabilities (in thousands):

	September 30, 2006			December 31, 2005
Fair value of undesignated derivatives	$	(119	)	$	-

10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table provides a summary of the impact on earnings from non-cash gains (losses) included in gain (loss) on derivatives, net, 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,
	2006			2005		2006			2005
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives	$	(15	)	$	-	$	(119	)	$	-

The following table reflects open basis swap contracts at September 30, 2006, the associated volumes and the corresponding discount to the NYMEX reference price.

							Notional Amount
Basis Swaps	Settlement Period		Derivative Instrument		Hedge Strategy		Natural Gas (MMBTU)		Oil (Barrels)	Discount To NYMEX
NGPL STX		10/01/06 - 10/31/06		Purchased Put		Undesignated		200,000		$	0.603
HSC		10/01/06 - 10/31/06		Purchased Put		Undesignated		80,000		$	0.510
ANR OK		10/01/06 - 10/31/06		Purchased Put		Undesignated		140,000		$	1.110

Interest rate swap

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

At March 31, 2006, Brigham had an interest rate swap contract to pay a fixed-rate of interest of 7.6% on $20.0 million notional amount of senior subordinated notes. The $20.0 million notional amount of the outstanding contract was to mature in March 2009. Brigham used the net proceeds from the Senior Notes offering to repay all amounts currently outstanding under its senior and subordinated credit agreements which totaled $78.4 million at the time the offering closed. Subsequent to this repayment, Brigham terminated the subordinated credit agreement and the associated interest rate swap. Upon termination of the interest rate swap, Brigham received $838,000 for the fair market value of the swap, as recognized as gain (loss) on derivatives, net.

11

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Fair values

The fair value of derivative contracts designated as cash flow hedges is reflected on the balance sheet as detailed in the following schedule. The current asset and liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.

	September 30, 2006			December 31, 2005
	(In thousands)
Other current liabilities	$	(45	)	$	(2,112	)
Other noncurrent liabilities		0			(61	)
Other current assets		5,630			224
Other noncurrent assets		1,135			654
	$	6,720		$	(1,295	)

9. Oil and Gas Properties

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

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

The risk that the Company will experience a ceiling test writedown increases when oil and gas prices are depressed or if the Company has substantial downward revisions in its estimated proved reserves. Based on oil and gas prices in effect on September 29, 2006 ($4.18 per MMBtu for Henry Hub gas and $62.91 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of the Company's oil and gas properties exceeded the ceiling limit by $87 million, net of tax. Had the impact of derivatives qualifying as hedges been excluded from the calculation, the ceiling limit would have decreased by approximately $16.7 million. However, subsequent to the end of the quarter, oil and natural gas prices increased and, on November 1, 2006, reached $7.09 per MMBtu for natural gas and $58.72 per barrel for oil. Utilizing these prices, the Company’s net capitalized costs of oil and natural gas properties would not have exceeded the ceiling limit. As a result of the increase in the ceiling limit using subsequent prices, the Company was not required to writedown the net capitalized costs of its oil and gas properties.

10. 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.

12

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2006 and 2005 (in thousands):

	Nine Months Ended September 30,
	2006			2005
Beginning asset retirement obligations	$	4,389		$	2,896
Liabilities incurred for new wells placed on production		395			244
Liabilities settled		(218	)		(10	)
Accretion of discount on asset retirement obligations		229			126
	$	4,795		$	3,256

11. Stock Based Compensation

Effective January 1, 2006, Brigham adopted the provisions of SFAS 123R “Share Based Payment” for its stock based compensation plans. Brigham previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” (APB 25) and related interpretations and disclosure requirements established by SFAS 123, “Accounting for Stock-Based Compensation.”

Under APB 25, Brigham recognized stock based compensation using the intrinsic value method and, thus, generally no compensation expense was recognized for stock options as they were generally granted at the market value on the date of grant. The pro forma effects on net income due to stock based compensation were disclosed in the notes to the consolidated financial statements. SFAS 123R eliminates the use of APB 25 and the intrinsic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards, in the financial statements over the requisite service period.

Brigham adopted SFAS 123R using the modified prospective method. Under this transition method, compensation cost recognized includes the cost for all stock based compensation granted prior to, but not yet vested, as of January 1, 2006. This cost was based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. The cost for all stock based awards granted subsequent to January 1, 2006, was based on the grant date fair value that was estimated in accordance with the provisions of SFAS 123R. The maximum contractual life of stock based awards is seven years and the historical forfeiture rate used to estimate forfeitures prospectively is 14.5%. At adoption of SFAS 123R, Brigham elected to amortize newly issued and existing graded awards on a straight-line basis over the requisite service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods. Unearned stock compensation recorded under APB 25 of $2.3 million was eliminated and additional paid-in capital was reduced by a like amount on the consolidated balance sheet and consolidated statements of stockholders’ equity, in accordance with SFAS 123R. Results for prior periods have not been restated.

13

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The estimated fair value of the options granted during 2006 and prior periods was calculated using a Black-Scholes Merton option pricing model (Black-Scholes). The following table summarizes the assumptions used in the 2006 Black-Scholes model:

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

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

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

Prior to the adoption of SFAS 123R, Brigham presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Brigham did not have any excess tax benefits during the first nine months of 2006.

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 would have been the pro forma amounts indicated below (in thousands, except per share amounts):

	Three Months Ended Sept 30, 2005			Nine Months Ended Sept 30, 2005
Net income, as reported	$	7,678		$	15,536
Add back: Stock compensation expense previously included in net income		111			333
Effect of total employee stock-based compensation expense, determined under fair value method for all awards		(355	)		(1,036	)
Pro forma	$	7,434		$	14,833
Net income per share:
Basic, as reported	$	0.18		$	0.37
Basic, pro forma		0.18			0.35
Diluted, as reported	$	0.18		$	0.36
Diluted, pro forma		0.17			0.34

14

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Prior to January 1, 2006, Brigham’s stock compensation expense largely consisted of the amortization of unearned stock compensation due to unvested (restricted) stock, in accordance with APB 25. The following table summarizes the components of stock based compensation included in general and administrative expense (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Pre-tax stock based compensation expense	$	516		$	167		$	2,072		$	501
Capitalized stock based compensation		(225	)		(80	)		(938	)		(241	)
Tax benefit		(102	)		(31	)		(397	)		(91	)
Stock based compensation expense, net	$	189		$	56		$	737		$	169

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

Stock Based Plan Descriptions and Share Information

Brigham provides an incentive plan for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to provide incentive and reward key employees whose performance may have a significant impact on the success of Brigham. It is Brigham’s policy to use unissued shares of stock when stock options are exercised. The number of shares available under the plan is equal to the lesser of 5,915,414 or 15% of the total number of shares of common stock outstanding. At September 30, 2006, approximately 1,035,470 shares remain available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one stock option grant, options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham’s common stock on the date of grant, vest over five years and have a contractual life of seven years.

Brigham also maintains a director stock option plan under which stock options are awarded to non-employee directors. Options granted under this plan have an exercise price equal to the fair market value of Brigham common stock on the date of grant and vest over five years. Stockholders have authorized the issuance of 430,000 shares to non-employee directors and approximately 62,300 remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for the nine months ended September 30, 2006:

	Shares			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term		Aggregate Intrinsic Value
Options outstanding at the beginning of the year		2,946,333		$	6.96
Granted		430,000		$	6.47
Forfeited or cancelled		(200,467	)	$	4.93
Exercised		(77,100	)	$	5.08
Options outstanding at September 30, 2006		3,098,766		$	7.07		4.5 years	$	2,417,000
Options exercisable at September 30, 2006		1,201,566		$	1.94		3.4 years	$	1,773,000

15

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The aggregate intrinsic value in the above table represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the third quarter of 2006 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on September 30, 2006. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of September 30, 2006 there was approximately $5.8 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.9 years.

The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005, was $317,000 and $1,218,000, respectively.

Restricted Stock

During the nine months ended September 30, 2006, Brigham issued 129,595 restricted (unvested) shares of common stock as compensation to officers and employees of Brigham. Restricted shares vest over five years or cliff-vest at the end of five years. As of September 30, 2006, there was approximately $2.4 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.5 years. Brigham has assumed a zero percent forfeiture rate for restricted stock.

The following table reflects the outstanding restricted stock awards and activity related thereto for the nine months ended September 30, 2006:

	Number of Shares			Weighted- Average Price
Restricted Stock Awards:
Restricted shares outstanding at the beginning of the year		397,650		$	7.37
Shares granted		129,595		$	10.84
Lapse of restrictions		(65,000	)	$	5.23
Forfeitures		(58,348	)	$	8.16
Restricted shares outstanding at September 30, 2006		403,897		$	8.72

12. Comprehensive Income

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Net income	$	5,246		$	7,678		$	14,787		$	15,536
Unrealized gains (losses) on cash flow hedges		3,527			(6,129	)		8,015			(5,738	)
Tax benefits (provisions) related to cash flow hedges		(417	)		1,978			(1,681	)		1,696
Net (gains) losses on derivatives included in net income		(2,336	)		476			(3,213	)		890
Other Comprehensive Income, net	$	6,020		$	4,003		$	17,908		$	12,384

16

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

13. New Accounting Pronouncements

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

In September 2006 the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157), which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 is required on January 1, 2008. The Company is currently evaluating the impact of adopting SFAS 157 on the financial statements.

On September 29, 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(r)” (SFAS 158). The Statement requires the recognition of the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability on the balance sheet and the recognition of the changes of the funded status in the year in which the changes occur through comprehensive income. Implementation of SFAS 158 is required as of the end of the fiscal year ending after December 15, 2006. The adoption of SFAS 158 will not have an impact on the Company’s financial statements because the Company does not currently have any defined benefit pension or other postretirement benefit plans.

On September 13, 2006 the Securities Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (SAB 108), which establishes an approach that requires quantification of financial statement errors based on the effects of the error on each of the company's financial statements and the related disclosures. SAB 108 requires the use of a balance sheet and an income statement approach to evaluate whether either of these approaches results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

17

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 2005 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month and nine month periods ended September 30, 2006, and the comparable periods of 2005. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2005 Annual Report on Form 10-K.

General Overview

We are an independent exploration, development and production company that utilizes 3−D seismic imaging and other advanced technologies to systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our exploration and development activities in provinces where we believe technology and the knowledge of our technical staff can be used effectively to maximize our return on invested capital by reducing drilling risk and enhancing our ability to grow reserves and production volumes.

Since our inception in 1990, we have evolved from a pioneering, 3−D seismic-driven exploration company to a balanced exploration and development company with technical and operational expertise and a strong production base. We have generated a multi-year inventory of exploration prospects, which due to our field discoveries, are complemented by a multi-year inventory of development locations.

Our 3−D seismic exploration and development activities are currently concentrated in three provinces: the Onshore Gulf Coast, the Anadarko Basin in northwest Oklahoma and the Texas Panhandle and West Texas. We also regularly evaluate opportunities to expand our activities to other areas that may offer attractive exploration and development potential, with a particular interest in those areas with plays that complement our current exploration, development and production activities. As a result, since November, we have acquired approximately 100,000 net acres in the Bakken play of North Dakota and Montana. In early 2006, we entered into two new joint ventures with two operators in Southern Louisiana, which we consider to be a logical extension of our onshore Texas Gulf Coast activities. Furthermore, since March 2006, we have acquired 53,000 net acres in the Mowry and Muddy plays of the Powder River Basin of Wyoming.

Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we believe our operations will likely result in a high return on our invested capital. Key elements of our business strategy include:

· Focus on Core Provinces and Trends.

· Internally Generate and Add to Our Inventory of High Quality Exploratory Prospects.

· Evaluate and Selectively Pursue New Potential Plays.

· Capitalize on Exploration Successes Through Development of Our Field Discoveries.

· Continue to Actively Drill Our Multi-Year Prospect Inventory.

· Enhance Returns Through Operational Control.

Overview of Third Quarter and First Nine Months 2006 Results

Although third quarter 2006 natural gas prices declined from the comparable quarter last year, natural gas prices continue to remain higher than long-term historical averages. Excluding hedging results, the average sales price that we received for our natural gas in the third quarter and first nine months of 2006 was $6.48 and $6.78 per Mcf, respectively. This represents a decrease of 26% over the price we received in the third quarter 2005 and a 5% decrease from that in the first nine months of 2005. Excluding hedging results, the average sales price that we received for oil in the third quarter and first nine months of 2006 was $71.86 and $67.22 per Bbl, respectively. Oil prices increased by 19% from the third quarter last year and by 26% from that in the first nine months of 2005.

Our average production for the third quarter 2006 increased 13% to 36.1 MMcfe per day from that in the third quarter 2005. Average production for the first nine months of 2006 increased 19% to 36.2 MMcfe per day from that in the first nine months of 2005. These increases were primarily attributable to production from new wells that came on line subsequent to the third quarter 2005 and were partially offset by the natural decline in wells that began producing in prior periods.

18

Third quarter operating income decreased 40% to $8.1 million from that in last year’s third quarter. First nine months 2006 operating income decreased by 2% from the comparable period last year to $26.9 million. Increases in lease operating, general and administrative and depletion expense were partially offset by increased revenue generated by higher natural gas production, higher oil prices, and increased revenue from our hedging activities.

For the quarter ended September 30, 2006, we spent $39.3 million on drilling capital expenditures, which represents an increase of 88% over that in the third quarter 2005 and a 7% increase over that in the second quarter 2006. For the nine months ended September 30, 2006, we spent $106.9 million on drilling capital expenditures. For the third quarter and first nine months 2006, net cash provided by operating activities funded approximately 27% and 54%, respectively, of our oil and gas capital expenditures. Remaining capital expenditures were funded by the cash proceeds resulting from our $125 million 9 5/8% Senior Notes offering (the “Senior Notes”) completed in April 2006.

As of September 30, 2006, we had $9.6 million in cash, $1.0 million in short-term investments, and $492.6 million in total assets. Our net debt to book capitalization ratio was 34% which is calculated as debt plus preferred stock divided by book equity plus debt plus preferred stock.

Third Quarter 2006 Operations Update

Through early November 2006, we have spud 41 wells, retaining an average working interest of approximately 55%. Thirty of these wells have been or are in the process of being completed, five are currently drilling and six have been plugged. Our gross and net completion rate thus far in 2006 is 83% and 86%, respectively.

Vicksburg Trend

In September, we successfully completed our fifth 2006 Vicksburg development well, the Triple Crown Field Sullivan F-33, which came on-line at 9.5 MMcfe per day and is currently producing 6.2 MMcfe per day. We encountered four pay zones and are currently producing only out of the deepest zone, the Dawson sand. Our plans are to commingle the remaining three zones after flowing pressures from the Dawson sand subside. The remaining 63 feet of pay includes, from shallowest to deepest, the Brigham, 9800’ and the Loma Blanca sands. Production from the Dawson sand represents a new source of reserves for our company as this is the first well to be completed to sales from this zone. We are preparing to commence a sidetrack of the Dawson #1 to offset the F-33 and further develop the Dawson sand. In addition to the Dawson sand, we expect the Dawson #1 sidetrack to encounter the Brigham, 9800’ and Loma Blanca sands, all of which produce in the area.

In September, we commenced drilling the Sullivan C-33, an offset to the Floyd Fault Block Field Sullivan #10. The well is being completed after encountering strong drilling shows and apparent sand sections comparable and structurally approximately flat to the Sullivan #10. The Sullivan #10 produced at rates as high as 15 MMcfe per day and was recently producing approximately 8.8 MMcfe per day. Completion to sales is expected later this month.

Frio Trend

We are currently completing the State Tract 109 #1, which encountered 36 feet of apparent Lower Frio pay. The well was initially tested at 2.5MMcfe per day; however, sand was produced during the test. We are in the process of completing a frac pac to limit sand production and possibly enhance the level of production. An additional 21 feet of production remains behind pipe for future completion.

In mid-November, we expect to spud the high potential Green Ranch #1 well and expect results by year end.

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Gulf Coast Louisiana Miocene Trend

In September, we brought on line our first South Louisiana well, the Cotten Land Corp. #1. The well was brought on line at 10.4 MMcfe per day. Subsequently, the choke was increased and the well is now producing at 14.3 MMcfe per day.

We reached total depth on the Marie Snyder #1, which is an important downdip discovery to the Cotten Land Corp. #1. Apparent pay was encountered approximately 450 feet structurally low to the Cotten Land Corp. #1.

We are currently drilling the high reserve potential Williams Land Company #1 and expect results in late December. This well is expected to test the Lower Planulina objective structurally high to two wells that have produced a combined 57 Bcfe to date from the same interval.

Anadarko Basin

In October, we reached total depth on our Mills Ranch 96 #1 well. The well is currently being production tested after encountering approximately 300 feet of apparent net pay in the Hunton and Viola. Early testing has confirmed that the Hunton is gas productive, and we expect to commingle all the zones and be fully on line and producing to sales by late November.

Although the tubing leak on the Mills Ranch 98 #2 was successfully repaired, we have experienced additional operational problems, including a potential casing problem, delaying the well’s completion to sales. Over the next several weeks, we expect to determine whether the well will require a sidetracking operation to reestablish production.

Resource Plays

Completion operations are continuing on our second and third horizontal Bakken wells, the Mracheck 15-22 1-H and the Erickson 8-17 1-H. Both wells are scheduled to be fracture stimulated by mid-November.

In the Wyoming Powder River Basin, we are continuing completion operations on our first horizontal Mowry shale test, the Krejci #3. We are conducting varied and extensive production tests to evaluate completion techniques for the targeted reservoir. Brigham is currently testing the last 219 feet of the approximately 1,600 feet lateral section. The remaining section will be perforated and stimulated at a later date. To date, the early results have been encouraging, though extended and stabilized rates have not been measured. In the same area, we are currently drilling our second horizontal Mowry test, the Mills Trust #1-12. The Mills Trust #1-12 has been drilled to a depth of approximately 7,834 feet and we are preparing to commence the planned 1,600 foot lateral leg. Results for this well are expected later in the fourth quarter.

Third quarter and First Nine months 2006 Results

Comparison of the three-month and nine month periods ended September 30, 2006 and 2005.

Production volumes

	Three months ended September 30,						Nine months ended September 30,
	2006		% Change		2005		2006		% Change		2005
Oil (MBbls)		105		(3%)		108		330		0%		329
Natural gas (MMcf)		2,616		17%		2,233		7,789		24%		6,268
Total (MMcfe)(1)		3,245		13%		2,881		9,766		19%		8,240
Average daily production ( MMcfe/d)		36.1				32.0		36.2				30.5

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

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Natural gas represented 81% of our third quarter 2006 production volumes, compared to 78% in the third quarter of last year. For the first nine months of 2006, natural gas represented 80% of our production versus 76% during the first nine months of 2005.

Revenues, Commodity Prices and Hedging

The following table shows our revenue from the sale of oil and natural gas for the periods indicated. Also included are average prices for the periods indicated.

	Three months ended September 30,							Nine months ended September 30,
	2006		% Change		2005			2006		% Change		2005
	(In thousands, except per unit measurements)
Revenue from the sale of oil and natural gas:
Oil sales	$	7,541		16%	$	6,529		$	22,150		26%	$	17,531
Gain (loss) due to hedging		52		NM		(208	)		2		NM		(1,134	)
Total revenue from the sale of oil	$	7,593		20%	$	6,321		$	22,152		35%	$	16,397
Natural gas sales	$	16,946		(13%)	$	19,458		$	52,827		18%	$	44,760
Gain (loss) due to hedging		1,549		NM		(590	)		3,039		NM		(831	)
Total revenue from the sale of natural gas	$	18,495		(2%)	$	18,868		$	55,866		27%	$	43,929
Oil and natural gas sales	$	24,487		(6%)	$	25,987		$	74,977		20%	$	62,291
Gain (loss) due to hedging		1,601		NM		(798	)		3,041		NM		(1,965	)
Total revenue from the sale of oil and natural gas	$	26,088		4%	$	25,189		$	78,018		29%	$	60,326
Average prices:
Oil sales price (per Bbl)	$	71.86		19%	$	60.44		$	67.22		26%	$	53.32
Gain (loss) due to hedging (per Bbl)		0.50		NM		(1.93	)		—		100%		(3.45	)
Realized oil price (per Bbl)	$	72.36		24%	$	58.51		$	67.22		35%	$	49.87
Natural gas sales price (per Mcf)	$	6.48		(26%)	$	8.71		$	6.78		(5%)	$	7.14
Gain (loss) due to hedging (per Mcf)		0.59		NM		(0.26	)		0.39		NM		(0.13	)
Realized natural gas price (per Mcf)	$	7.07		(16%)	$	8.45		$	7.17		2%	$	7.01
Natural gas equivalent sales price (per Mcfe)	$	7.55		(16%)	$	9.02		$	7.68		2%	$	7.56
Gain (loss) due to hedging (per Mcfe)		0.49		NM		(0.28	)		0.31		NM		(0.24	)
Realized natural gas equivalent (per Mcfe)	$	8.04		(8%)	$	8.74		$	7.99		9%	$	7.32

	For the three month periods ended September 30, 2006 and 2005			For the nine month periods ended September 30, 2006 and 2005
Change in revenue from the sale of oil
Volume variance impact		(186	)		39
Price variance impact	$	1,198		$	4,580
Cash settlement of hedging contracts		260			1,136
Total change	$	1,272		$	5,755
Change in revenue from the sale of natural gas
Volume variance impact		3,325			10,855
Price variance impact	$	(5,837	)	$	(2,788	)
Cash settlement of hedging contracts		2,139			3,870
Total change	$	(373	)	$	11,937

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Our total revenue from the sale of oil and natural gas for the third quarter 2006 increased by 4% when compared to revenue for the third quarter 2005. The change in total revenue was due to the following:

· A 13% increase in production volumes generated a $3.1 million increase in revenue;

· A 16% decrease in prices, excluding the impact of hedges, resulted in a $4.6 million decrease in revenue; and

· A $1.6 million gain from the cash settlement of derivative contracts in the third quarter 2006 versus a $800,000 loss for the same period last year led to $2.4 million increase in revenue.

Our total revenue from the sale of oil and natural gas for the first nine months of 2006 increased by 29% when compared to revenue for the first nine months of 2005. The following factors led to the change:

· A 19% increase in production volumes generated a $10.9 million increase in revenue;

· A 2% increase in prices, excluding the impact of hedges, resulted in a $1.8 million increase in revenue; and

· A $3.0 million gain from the cash settlement of derivative contracts in the first nine months of 2006 versus a $2.0 million loss last year led to $5.0 million increase in revenue.

The following table shows our derivative contracts designated as cash flow hedges that settled during the representative periods. Included in the table is the type of derivative contracts, the volumes, the weighted average NYMEX reference price for those volumes, and the associated gain/ (loss) upon settlement of those contracts.

	Three months ended September 30,							Nine months ended September 30,
	2006		% Change		2005			2006		% Change		2005
Oil collars
Volumes (Bbls)		44,500		35%		33,000			115,000		35%		85,105
Average floor price ($ per Bbl)	$	58.20		31%	$	44.36		$	55.18		59%	$	34.71
Average ceiling price ($ per Bbl)	$	77.45		35%	$	57.20		$	73.80		70%	$	43.32
Gain /(loss) upon settlement ($ in thousands)	$	52		NM	$	(208	)	$	2		NM	$	(1,134	)
Natural gas collars
Volumes (MMbtu)		1,220,000		85%		660,000			2,960,000		46%		2,022,500
Average floor price ($ per MMbtu)	$	7.60		24%	$	6.12		$	7.94		47%	$	5.40
Average ceiling price ($ per MMbtu)	$	13.23		75%	$	7.57		$	12.94		77%	$	7.30
Gain /(loss) upon settlement ($ in thousands)	$	1,549		NM	$	(590	)	$	3,039		NM	$	(831	)

Reported revenue from the sale of oil and natural gas is based on the market price we received adjusted for marketing charges and the results from the settlement of our derivative contracts that qualify for cash flow hedge accounting treatment under SFAS 133. We utilize swap, collar, three way costless collar and floor contracts to (i) reduce the effects of volatility in price changes on the oil and natural gas 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 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 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 contracts that do not qualify for cash flow hedge accounting treatment under SFAS 133 are reported in other income (expense).

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.

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Operating costs and expenses

Production costs. We believe that per unit of production measures are the best way to evaluate our production costs. We use this information to internally evaluate our performance, as well as to evaluate our performance relative to our peers.

	Unit-of-Production (Per Mcfe)							Amount (In thousands)
	Three months ended September 30,							Three months ended September 30,
	2006		% Change		2005			2006		% Change		2005
Production costs:
Operating & maintenance	$	0.64		31%	$	0.49		$	2,076		47%	$	1,410
Expensed workovers		0.04		NM		(0.03	)		134		NM		(73	)
Ad valorem taxes		0.14		100%		0.07			462		126%		204
Lease operating expenses	$	0.82		55%	$	0.53		$	2,672		73%	$	1,541
Production taxes		0.39		50%		0.26			1,259		70%		741
Production costs	$	1.21		53%	$	0.79		$	3,931		72%	$	2,282

Third quarter per unit of production costs increased 53% when compared to the third quarter last year because of the following:

· O&M expense increased 31%, or $0.15 per Mcfe. Increases in equipment rental, chemical treating, and saltwater disposal accounted for 62% of the per unit change.

· Ad valorem taxes increased 100% or $0.07 per Mcfe due to an increase in estimated property valuations for our oil and natural gas properties because of higher commodity prices.

· Production taxes increased 50% or $0.13 per Mcfe due to $400,000 less in severance tax refunds in the third quarter 2006 compared to third quarter 2005.

	Unit-of-Production (Per Mcfe)						Amount (In thousands)
	Nine months ended September 30,						Nine months ended September 30,
	2006		% Change		2005		2006		% Change		2005
Production cost:
Operating & maintenance	$	0.63		24%	$	0.51	$	6,127		45%	$	4,221
Expensed workovers		0.04		33%		0.03		411		73%		238
Ad valorem taxes		0.14		75%		0.08		1,400		103%		690
Lease operating expenses	$	0.81		31%	$	0.62	$	7,938		54%	$	5,149
Production taxes		0.35		52%		0.23		3,455		81%		1,909
Production costs	$	1.16		36%	$	0.85	$	11,393		61%	$	7,058

Per unit of production costs for the first nine months of 2006 increased by 36% compared to the last year’s first nine months because of the following:

· O&M expense increased 24% or $0.12 per Mcfe. Increases in chemical treating, equipment rental, saltwater disposal, and well service and repair accounted for 60% of the per unit increase.

· Ad valorem taxes increased 75% or $0.06 per Mcfe due to an increase in estimated property valuations for our oil and natural gas properties because of higher commodity prices.

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· Production taxes increased 52% or $0.12 per Mcfe due to higher commodity prices and $1.0 million less in severance tax refunds in the nine months ended September 2006 versus the nine months ended September 2005.

General and administrative expenses. We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on capital projects and a portion of our associated technical organization costs such as supervision, telephone and postage.

	Three months ended September 30,								Nine months ended September 30,
	2006			% Change		2005			2006			% Change		2005
	(In thousands, except per unit measurements)
General and administrative costs	$	3,702			45%	$	2,551		$	10,878			48%	$	7,355
Capitalized general and administrative costs		(1,717	)		39%		(1,234	)		(4,942	)		36%		(3,636	)
General and administrative expenses	$	1,985			51%	$	1,317		$	5,936			60%	$	3,719
General and administrative expense ($ per Mcfe)	$	0.61			33%	$	0.46		$	0.61			36%	$	0.45

Our general and administrative expense for the third quarter 2006 was 51% higher when compared to that in the third quarter of last year. G&A expense increased primarily because of $575,000 in non-cash employee compensation associated with our 2006 adoption of SFAS 123R dealing with a change in accounting methodology for employee stock option expense. Due to higher costs, general and administrative expense on a per unit basis increased 33% in the quarter to $0.61 per Mcfe.

General and administrative expense for the first nine months of 2006 was 60% higher than the first nine months of last year. G&A expenses increased primarily because of the $1.2 million of increased non-cash employee compensation associated with our 2006 adoption of SFAS 123R. Increased costs resulted in our general and administrative expense increasing on a per unit basis by 36% to $0.61 per Mcfe.

Depletion of oil and natural gas properties. Our 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 future developmental costs at the end of the year.

	Three months ended September 30,						Nine months ended September 30,
	2006		% Change		2005		2006		% Change		2005
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	11,910		50%	$	7,953	$	33,272		54%	$	21,612
Depletion of oil and natural gas properties ($ per Mcfe)	$	3.67		33%	$	2.76	$	3.41		30%	$	2.62

Our depletion expense for the third quarter 2006 was $4.0 million higher than the third quarter 2005. Approximately 75% of the increase was due to an increase in our depletion rate while the remaining 25% of the increase was due to an increase in our production volumes. Our depletion expense for the first nine months 2006 was $11.7 million higher than 2005. Approximately 66% of the increase was due to an increase in our depletion rate while the remaining 34% of the increase was due to an increase in our production volumes.

The increase in our depletion rates for both the third quarter and first nine months of 2006 was primarily a result of an increase in the cost of reserve additions.

Net interest expense. Interest on borrowings under our Senior Notes, our senior credit agreement and dividends on our Series A mandatorily redeemable preferred stock represents the largest portion of our interest costs. Other costs include commitment fees that we pay on the unused portion of the borrowing base and amortization of debt issuance costs. We capitalize a portion of our interest costs associated with major capital projects.

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	Three months ended September 30,								Nine months ended September 30,
	2006			% Change		2005			2006			% Change		2005
	(In thousands)
Interest on Senior Notes	$	3,008			NM	$	—		$	5,347			NM	$	—
Interest on senior credit facility		—			(100%)		668			743			(52%)		1,538
Interest on senior subordinated notes (a)		—			(100%)		574			699			(48%)		1,333
Commitment fees		41			14%		36			124			35%		92
Dividend on mandatorily redeemable preferred stock		153			(24%)		200			453			(22%)		581
Amortization of deferred loan and debt issuance cost		197			64%		120			1,465			293%		373
Other general interest expense		1			0%		1			6			(14%)		7
Capitalized interest expense		(731	)		59%		(461	)		(1,938	)		52%		(1,279	)
Net interest expense	$	2,669			135%	$	1,138		$	6,899			161%	$	2,645
Weighted average debt outstanding	$	135,101			47%	$	91,985		$	114,067			50%	$	76,241
Average interest rate on outstanding indebtedness (b)		9.5	%				6.4	%		8.6	%				6.2	%

a) Includes the effects of interest rate swaps.

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

Third quarter 2006 interest expense was $1.5 million higher primarily due to a 47% increase in the weighted average debt outstanding and a higher weighted average cost of debt attributed to the April 2006 issuance of Senior Notes. The interest expense that we paid on the Senior Notes during the third quarter 2006 was 142% higher than the interest paid on the senior credit facility and the senior subordinated notes during the comparable period of 2005.

First nine months 2006 interest expense was $4.3 million higher than the comparable period in 2005 because of a higher weighted average debt balance attributed to the issuance of our Senior Notes, and the write-off of our subordinated note issuance costs.

We made no cash payments for interest during the third quarter 2006. For the first nine months of 2006, we made $1.8 million in aggregate cash payments for interest.

Other income (expense). Other income (expense) primarily includes non-cash gains (losses) resulting from the change in fair market value of oil and natural gas derivative contracts that did not qualify as cash flow hedges under SFAS 133, non-cash gains (losses) related to charges for the ineffective portions of cash flow hedges under SFAS 133, and cash gains (losses) on the settlement of these contracts.

Other income (expense) included:

	Three months ended September 30,								Nine months ended September 30,
	2006			% Change		2005			2006			% Change		2005
Derivative:	(In thousands)
Non-cash gain (loss) due to change in fair market value of undesignated hedges	$	100			NM	$	(52	)	$	(287	)		174%	$	(105	)
Non-cash gain (loss) for ineffective portion of cash flow hedges		2,336			NM		(477	)		3,213			NM		(890	)
Cash settlement of undesignated hedges		(222	)		NM		—			(421	)		NM		—
Derivative other income (loss)	$	2,214			NM	$	(529	)	$	2,505			NM	$	(995	)
Other:
Non-cash gain (loss)	$	—			(100%)	$	(44	)	$	(64	)		(38%)	$	(103	)
Cash income (expense)		171			125%		76			1,245			404%		247
Miscellaneous other income (loss)	$	171			434%	$	32		$	1,181			720%	$	144
Total other income	$	2,385			NM	$	(497	)	$	3,686			NM	$	(851	)

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Other cash income increased in the nine months ended September 30, 2006 versus the comparable period last year because of $838,000 in income associated with the termination of the subordinated credit facility interest rate swap.

The following table shows the volumes, the weighted average NYMEX reference price, and the gain/ (loss) upon settlement for those derivative contracts that were undesignated under SFAS 133 for the periods indicated.

	Three months ended September 30,							Nine months ended September 30,
	2006			% Change		2005		2006			% Change		2005
Oil
Written puts
Volumes (Bbl)		15,000			(55%)		33,000		40,500			4%		39,000
Average price ($ per Bbl)	$	48.00			40%	$	34.36	$	43.56			25%		34.92
Gain /(loss) upon settlement ($ in thousands)	$	—			NM	$	—	$	—			NM	$	—
Total oil
Gain /(loss) upon settlement ($ in thousands)	$	—			NM	$	—	$	—			NM	$	—
Natural gas
Basis swaps
Volumes (MMbtu)		840,000			NM		—		840,000			NM		—
Average discount to NYMEX ($ per MMbtu)	$	(0.754	)		NM	$	—	$	(0.754	)		NM		—
Gain /(loss) upon settlement ($ in thousands)	$	(107	)		NM	$	—	$	(107	)		NM	$	—
Written puts
Volumes (MMbtu)		390,000			(19%)		480,000		1,380,000			100%		690,000
Average price ($ per MMbtu)	$	6.65			26%	$	5.28	$	6.83			28%	$	5.35
Gain /(loss) upon settlement ($ in thousands)	$	(115	)		NM	$	—	$	(314	)		NM	$	—
Total natural gas
Gain /(loss) upon settlement ($ in thousands)	$	(222	)		NM	$	—	$	(421	)		NM	$	—

Income taxes. We recorded deferred income tax expenses of $3.1 million in the third quarter of this year, compared to deferred income tax expenses of $4.2 million in the third quarter last year. The decrease in our deferred income taxes was primarily due to lower third quarter 2006 income before income taxes than the third quarter 2005.

In May 2006, the state of Texas enacted legislation that replaces the taxable capital and earned surplus components of its franchise tax with a new franchise tax that is based on modified gross revenue. The new franchise tax (referred to as the “Margin Tax”) becomes effective beginning with the 2007 tax year. The current franchise tax remains in effect through the end of 2006.

Within the context of generally accepted accounting principals in the United States, the Margin Tax is based on a measure of income and is thus accounted for in accordance with Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects of the tax law change in the period of enactment.

We recorded deferred income tax expenses of $10.0 million in the first nine months of this year, compared to deferred income tax expenses of $8.5 million in the first nine months of last year. The increase in our deferred income taxes was primarily due to our adoption of the Margin Tax in 2006, which applies a 1% tax on operating margin beginning in 2007 and payable in 2008. In order to implement the Margin Tax, we booked $1.3 million of deferred Margin Tax ($872,000 after-tax) in June 2006 to account for the cumulative differences between book and tax accounting for periods prior to and including December 31, 2006.

Beginning in 2007, due to our ability to deduct intangible drilling costs, we anticipate that the bulk of the associated Margin Tax should be deferred.

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For the first nine months of 2006, the following table reconciles the difference between the statutory tax rate of 35% and the effective tax rate of 40.3%:

	Nine months ended September 30, 2006		Tax Rate
Reconciliation to effective tax rate:
Tax at the statutory rate	$	8,665		35.00	%
Add the effect of:
Non-deductible expenses		2		0.01	%
Preferred stock dividends		159		0.64	%
Incentive stock options not exercised		184		0.75	%
Adoption of Margin Tax (after-tax)		872		3.52	%
Other		89		0.35	%
Total	$	9,971		40.27	%

Capital Expenditures

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

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

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

· cost of installing new production infrastructure;

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

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

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

The table below summarizes our revised 2006 oil and gas capital expenditures, the amount spent through September 30, 2006 and the amount of our budget that remains to be spent.

	Revised 2006 Budget		Amount Spent Through 09/30/2006		Amount Remaining (1)
	(In thousands)
Drilling	$	137,255	$	106,931	$	30,324
Net land and seismic		28,060		24,244		3,816
Capitalized costs (2)		9,970		7,273		2,697
Asset retirement obligation		533		395		138
Total oil and gas capital expenditures (3)	$	175,818	$	138,843	$	36,975

(1) Calculated based on the 2006 capital expenditure budget announced in September 2006 less amount spent through September 30, 2006.

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

(3) Excludes other property capital expenditures.

2006 Capital Spending Plan

As part of our revised budget we now plan to spend $175.8 million to drill 43 wells with an average working interest of 59% consisting of 20 wells in the Gulf Coast, 12 in the Anadarko Basin, 3 in the Williston Basin, and 8 in other areas. This compares to spending $156.9 million to drill 43 wells with an average working interest of 58% in our original budget. 71% of the increase in our revised budget resulted principally from a $13.4 million increase in drilling capital due to our ability to increase our working interest in the 2006 Vicksburg development wells.

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Approximately $51.8 million of the drilling capital in our revised budget will be allocated to drill 24 exploration wells with an average working interest of 56%. The drilling capital allocated to exploration drilling in our revised budget represents an increase of 10% over the amount in our original budget where we planned to spend $47 million to drill 21 wells with an average working interest of 61%.

The remaining $85.5 million of drilling capital in our revised budget will be allocated to drill 19 development wells with an average working interest of 63% and for other development activities. The drilling capital allocated to development activities in our revised budget represents an increase of 16% over the amount in our original budget, where we planned to spend $73.4 million to drill 22 development wells with an average working interest of 56% and for other development activities. In our revised 2006 budget, we now plan to spend $68.3 million to develop our proved undeveloped reserves compared to $56.4 million in our original budget.

Determination of Capital Expenditure Budget

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

This value creation measure and the final determination with respect to our 2006 budgeted expenditures will depend on a number of factors, including:

· changes in commodity prices;

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

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

· variances in a prospect’s risked reserve size;

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

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

· economic and industry conditions at the time of drilling; and

· the availability of more economically attractive prospects.

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

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2006, we intend to fund our capital expenditure program and contractual commitments with cash flows from operations, the net proceeds that remain from the sale of our Senior Notes, borrowings under our senior credit agreement, and if required, alternative financing sources. Our primary sources of cash during the third quarter 2006 were funds generated by operations and proceeds from our Senior Notes.

9 5/8% Senior Notes due 2014

In April 2006, we issued $125 million of Senior Notes. The Senior Notes were priced at 98.629% of their face value to yield 9 7/8% and are fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P.(the “Guarantors”). We entered into an indenture (the “Indenture”), among us, the Guarantors and Wells Fargo Bank, N.A., as trustee, relating to the Senior Notes. The Senior Notes are fully and unconditionally guaranteed by the Guarantors.

The Senior Notes were originally issued pursuant to the Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933. We have completed an exchange offer to exchange all of the unregistered Senior Notes for registered Senior Notes.

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We are obligated to pay the $125 million aggregate principal amount of the Senior Notes in cash upon maturity in May 2014. Starting in November 2006, we will pay 9 5/8% interest per annum on the principal amount of the Senior Notes, payable semi-annually in arrears in May and November of each year.

The Senior Notes are our unsecured senior obligations, and:

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

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

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

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

Additionally, the Indenture contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the Senior Notes as of September 30, 2006.

Senior Credit Agreement

In June 2005, we amended and restated our $100 million senior credit agreement to provide for revolving credit borrowings up to $200 million and to extend the maturity of the agreement from March 2009 to June 2010. In conjunction with the issuance of our Senior Notes, the borrowing base was reset to $50 million.

In April 2006, proceeds from the Senior Notes issuance were used to repay the $48.4 million balance outstanding. As of September 30, 2006, we had no amounts outstanding and therefore had $50 million of unused committed borrowing capacity available. As of September 30, 2005, we had $50 million in borrowings outstanding.

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

Our senior credit agreement also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at September 30, 2006 and interest coverage ratio for the twelve-month period ended September 30, 2006, were 1.3 to 1 and 11.6 to 1, respectively. As of September 30, 2006, we were in compliance with all covenant requirements in connection with our senior credit agreement.

The future amounts of debt that we borrow under our senior credit agreement will depend primarily on net cash provided by operating activities, proceeds from other financing activities, reimbursements of prior land and seismic costs by third party participants in our projects and proceeds generated from asset dispositions.

We strive to manage the amounts we borrow under our senior credit agreement in order to maintain excess borrowing capacity.

Mandatorily Redeemable Preferred Stock

As of September 30, 2006, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC. Our option to pay the dividends on our Series A preferred stock in kind expired in October 2005 and we are now required to satisfy all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

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Access to Capital Markets

We currently have two effective universal shelf registration statements covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. In July 2004, we sold 2,598,500 shares of our common stock and in November and December 2005, we sold 8,625,000 total shares of our common stock under one of these registration statements. We have $73.4 million remaining available under this shelf registration statement.

In February 2006, we filed a new universal shelf registration statement allowing us to issue common stock. Our other universal shelf registration statement has not been utilized to date and has $300 million available.

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

Off Balance Sheet Arrangements

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

Analysis of Changes In Cash and Cash Equivalents

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

	Nine months ended September 30,
	2006			%Change		2005
	(In thousands)
Net income	$	14,787			(5%)	$	15,536
Non-cash items		43,593			33%		32,858
Changes in working capital and other items		15,915			NM		(8,332	)
Cash flows provided by operating activities	$	74,295			85%		40,062
Cash flows used by investing activities		(126,139	)		51%		(83,285	)
Cash flows provided by financing activities		57,483			23%		46,815
Net increase in cash and cash equivalents	$	5,639			57%	$	3,592

Analysis of net cash provided by operating activities

Net cash provided by operating activities is a function of the amount of oil and natural gas that we produce, the prices that we receive from the sale of oil and natural gas, which are inherently volatile and unpredictable, gains or losses related to the settlement of our derivative contracts, operating costs and our cost of capital. Our asset base, as with other extractive industries, is a depleting one in which each barrel of oil or Mcf of natural gas produced must be replaced or our ability to generate cash flow, and thus sustain our exploration and development activities, will diminish.

For the first nine months of 2006, cash flows provided by operating activities increased by 85% to $74.3 million from the same period last year. The increase in operating cash flow is attributed to increases in revenue due principally to higher natural gas production volumes, higher oil prices, and increases in revenue due to our hedging activities. Finally, accounts receivable decreases and accounts payable increases improved our working capital position and further enhanced our operating cash flow. For the first nine months 2006, net cash provided by operating activities funded approximately 54% of our oil and gas capital expenditures. This compares with 48% during the first nine months of 2005.

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Analysis of changes in cash flows used in investing activities

	Nine months ended September 30,
	2006			%Change		2005
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	106,931			62%	$	66,172
Land and seismic		24,244			90%		12,754
Capitalized cost		7,273			41%		5,156
Capitalized asset retirement obligation		395			62%		244
Total	$	138,843			65%	$	84,326
Reconciling Items:
Change in accrued drilling costs	$	(12,453	)		2228%	$	(535	)
Change short-term investments		1,004			NM		—
Other		(1,255	)		148%		(506	)
Total Reconciling Items		(12,704	)		1120%		(1,041	)
Net cash used in investing activities	$	126,139			51%	$	83,285

Net cash used by investing activities in the first nine months of 2006 was 51% higher than the similar period for 2005. The following were the primary reasons for the increase:

· Drilling capital expenditures increased by $40.8 million due to our increased level of exploratory and developmental drilling activities.

· Land and seismic expenditures increased by $11.5 million due principally to our 180 square mile 3-D shoot in Wheeler County, Texas and land expenditures related to our resource plays.

· Capitalized costs increased by $2.1 million associated with our increased levels of general and administrative expense, capitalized stock expense and capitalized interest expense during the period.

· As of September 30, 2006, $1.0 million of our Senior Notes proceeds were invested in short-term investments.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first nine months of 2006 was 23% higher than the first nine months 2005. The following were the primary reasons for the increase:

· In April 2006, we issued $125 million of Senior Notes, generating net proceeds after the discount, fees and expenses of $120.7 million.

· Our Senior Notes issuance was partially offset by $78.4 million in repayments on our senior credit agreement and senior subordinated notes.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the nine months ended 2006 and 2005.

	Shares Issued		Net Proceeds
	(In thousands except share data)
2006 common stock transactions:
Exercise of employee stock options		77,100	$	392
2005 common stock transactions:
Exercise of employee stock options		218,300	$	805

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Other Matters

Derivative Instruments

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

Effects of Inflation and Changes in Prices

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

Environmental and Other Regulatory Matters

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

New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157), which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 is required on January 1, 2008. The Company is currently evaluating the impact of adopting SFAS 157 on the financial statements.

On September 29, 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(r)” (SFAS 158). The Statement requires the recognition of the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability on the balance sheet and the recognition of the changes of the funded status in the year in which the changes occur through comprehensive income. Implementation of SFAS 158 is required as of the end of the fiscal year ending after December 15, 2006. The adoption of SFAS 158 will not have an impact on the Company’s financial statements because the Company does not currently have any defined benefit pension or other postretirement benefit plans.

On September 13, 2006 the Securities Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (“SAB 108”), which establishes an approach that requires quantification of financial statement errors based on the effects of the error on each of the company's financial statements and the related disclosures. SAB 108 requires the use of a balance sheet and an income statement approach to evaluate whether either of these approaches results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

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

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Effective January 1, 2006, Brigham adopted the provisions of SFAS 123R for its stock based compensation plans. Brigham previously accounted for these plans under the recognition and measurement principles of APB 25 and related interpretations and disclosure requirements established by SFAS 123.

Under APB 25, Brigham recognized stock based compensation using the intrinsic value method. The pro forma effects on net income due to stock based compensation were disclosed in the notes to the consolidated financial statements. SFAS 123R eliminates the use of APB 25 and the intrinsic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards, in the financial statements over the requisite service period.

We adopted SFAS 123R using the modified prospective method. Under this transition method, compensation cost recognized includes the cost for all stock based compensation granted prior to, but not yet vested, as of January 1, 2006. This cost was based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. The cost for all stock based awards granted subsequent to January 1, 2006, was based on the grant date fair value that was estimated in accordance with the provisions of SFAS 123R. The maximum contractual life of stock based awards is seven years and the historical forfeiture rate used to estimate forfeitures prospectively is 14.5%. At adoption of SFAS 123R, Brigham elected to amortize newly issued and existing graded awards on a straight-line basis over the requisite service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods. Unearned stock compensation recorded under APB 25 of $2.3 million was eliminated and additional paid-in capital was reduced by a like amount on the consolidated balance sheet and consolidated statements of stockholders’ equity, in accordance with SFAS 123R. Results for prior periods have not been restated.

The estimated fair value of the options granted during 2006 and prior periods was calculated using a Black Scholes option pricing model. The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free rate of interest for periods within the contractual life of the option is based on a zero-coupon U.S. government instrument over the contractual term of the equity instrument. Expected volatility is based on the historical volatility of Brigham’s stock for an equal period of the expected term. The expected life is determined using the contractual life and vesting term in accordance with the guidance in Staff Accounting Bulletin No. 107 for using the “simplified” method for “plain vanilla” options.

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

Prior to the adoption of SFAS 123R, we presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. We did not have any excess tax benefits during the third quarter 2006.

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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 natural gas production, the number of wells we anticipate drilling during 2006 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in our Form 10-K report for the year ended December 31, 2005 and the 10-Q reports for the periods ended March 31, 2006, June 30, 2006, and September 30, 2006 including, but not limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

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

Derivative Instruments and Hedging Activities

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

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

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

Cash Flow Hedges

Our derivative contracts accounted for as cash flow hedges consist of fixed-price swaps, costless collars (purchased put options and written call options) and the costless collar portion of a three-way costless collar (purchased put option, written put and written call options).

We use fixed-price swap contracts to fix the sales price for our anticipated future oil and natural gas production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us. We designate these contracts as cash flow hedges designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility.

We use costless collars to establish floor (purchased put option) and ceiling price (written call option) on our anticipated future oil and natural gas production. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is above the ceiling price (written call option), we pay our counterparty. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us. We designate these collar arrangements as cash flow hedges designed to achieve a more predictable cash flow, as well as reduce our exposure to price volatility.

A three-way costless collar consists of a costless collar (purchased put option and written call option) plus a put (written put) sold by us with a price below the floor price (purchased put option) of the costless collar. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. The written put requires us to make a payment to our counterparty if the settlement price for a period is below the written put price. Combining the costless collar (purchased put option and written call option) with the written put results in us being entitled to a net payment equal to the difference between the floor price (purchased put option) of the costless collar and the written put price if the settlement price is equal to or less than the written put price. If the settlement price is greater than the written put price, the result is the same as it would have been with a costless collar. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while offsetting the associated cost with the sale of the written put. The put that we sell is not designated as a cash flow hedge.

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Derivatives Not Designated as Hedges

Our derivative positions that are not designated as cash flow hedges include written put options and are reported at fair value on our balance sheet. These contracts are entered into in conjunction with a costless collar to offset the cost of other option positions that are designated as hedges.

The following table reflects our open derivative contracts at September 30, 2006, the associated volumes and the corresponding weighted average NYMEX reference price.

Settlement Period	Hedge Strategy	Natural Gas (MMBTU)		Purchased Put (Nymex)		Written Call (Nymex)
Natural Gas Costless Collars
10/01/06 - 10/31/06	Cash flow		70,000	$	8.00	$	14.85
10/01/06 - 10/31/06	Cash flow		120,000	$	8.00	$	16.65
10/01/06 - 10/31/06	Cash flow		100,000	$	5.50	$	11.75
11/01/06 - 01/31/07	Cash flow		540,000	$	8.00	$	23.25
11/01/06 - 03/31/07	Cash flow		450,000	$	8.00	$	21.20
11/01/06 - 03/31/07	Cash flow		375,000	$	8.00	$	15.75
02/01/07 - 03/31/07	Cash flow		300,000	$	8.00	$	25.75
04/01/07 - 10/31/07	Cash flow		280,000	$	7.00	$	15.45
04/01/07 - 10/31/07	Cash flow		280,000	$	7.25	$	15.25
04/01/07 - 10/31/07	Cash flow		280,000	$	7.00	$	14.85
04/01/07 - 10/31/07	Cash flow		700,000	$	7.50	$	11.00
04/01/07 - 10/31/07	Cash flow		350,000	$	7.00	$	11.60
04/01/07 - 04/30/07	Cash flow		60,000	$	7.00	$	10.00
05/01/07 - 05/31/07	Cash flow		50,000	$	7.00	$	10.00
06/01/07 - 06/30/07	Cash flow		40,000	$	7.00	$	10.00
07/01/07 - 07/31/07	Cash flow		30,000	$	7.00	$	10.00
08/01/07 - 08/31/07	Cash flow		20,000	$	7.00	$	10.00
11/01/07 - 03/31/08	Cash flow		250,000	$	8.00	$	13.40
11/01/07 - 03/31/08	Cash flow		300,000	$	8.85	$	15.00
11/01/07 - 03/31/08	Cash flow		300,000	$	9.30	$	15.00

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Settlement Period	Hedge Strategy	Crude Oil (Barrels)		Purchased Put (Nymex)		Written Call (Nymex)		Written Put (Nymex)
Natural Gas Three-Way Costless Collars
10/01/06 - 10/31/06	Cash flow/Undesignated		60,000	$	7.50	$	9.15	$	6.25
10/01/06 - 10/31/06	Cash flow/Undesignated		70,000	$	8.50	$	9.96	$	7.00

Settlement Period	Hedge Strategy	Crude Oil (Barrels)		Purchased Put (Nymex)		Written Call (Nymex)
Oil Costless Collars
10/01/06 - 10/31/06	Cash flow		8,500	$	70.00	$	85.20
10/01/06 - 12/31/06	Cash flow		27,000	$	50.00	$	77.50
11/01/06 - 11/30/06	Cash flow		4,000	$	70.00	$	85.20
11/01/06 - 06/30/07	Cash flow		32,000	$	59.00	$	90.00
12/01/06 - 02/28/07	Cash flow		7,500	$	70.00	$	85.20
01/01/07 - 03/31/07	Cash flow		24,000	$	50.00	$	78.25
04/01/07 - 09/30/07	Cash flow		30,000	$	50.00	$	81.50
04/01/07 - 09/30/07	Cash flow		12,000	$	56.00	$	92.50
07/01/07 - 10/31/07	Cash flow		10,000	$	58.00	$	90.50
10/01/07 - 12/31/07	Cash flow		9,000	$	59.20	$	90.00
10/01/07 - 03/31/08	Cash flow		18,000	$	56.00	$	89.95
10/01/07 - 03/31/08	Cash flow		6,000	$	65.00	$	80.25
06/01/07 - 08/31/07	Cash flow		6,000	$	65.00	$	80.00
04/01/08 - 10/31/08	Cash flow		21,000	$	65.70	$	90.00

During the second quarter of 2006, we entered into basis swap agreements with respect to amounts previously hedged against the NYMEX. These arrangements are designed to manage our exposure to the basis risk associated with the fluctuations between the price received at NYMEX and the actual delivery point of our oil and natural gas volumes. The basis swap hedges are designed to effectively exchange existing obligations to deliver volumes based on floating prices for obligations to deliver volumes based on fixed NYMEX prices at a slight discount. At the end of each period, the realized gain or loss for outstanding derivative contracts, and unrealized gain or loss for the settled derivative contract, will be recorded as market-to-market gains and losses within other income on our consolidated statement of operations.

Settlement Period	Hedge Strategy	Natural Gas (MMBTU)		Purchased Put (Discount to Nymex)
Basis Swaps
NGPL STX
10/01/06 - 10/31/06	Undesignated		200,000	$	0.603
HSC
10/01/06 - 10/31/06	Undesignated		80,000	$	0.510
ANR OK
10/01/06 - 10/31/06	Undesignated		140,000	$	1.110

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The following table reflects commodity derivative contracts entered subsequent to September 30, 2006, the associated volumes and the corresponding weighted average NYMEX reference price.

Settlement Period	Hedge Strategy	Natural Gas (MMBTU)		Purchased Put (Nymex)		Written Call (Nymex)
Natural Gas Costless Collars
01/01/07 - 03/31/07	Cash flow		90,000	$	7.50	$	10.00
01/01/07 - 03/31/07	Cash flow		150,000	$	7.25	$	9.65
04/01/07 - 10/31/07	Cash flow		350,000	$	7.00	$	9.10

Settlement Period	Hedge Strategy	Crude Oil (Barrels)		Purchased Put (Nymex)		Written Call (Nymex)
Oil Costless Collars
01/01/07 - 12/31/07	Cash flow		12,000	$	55.00	$	79.00

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2006, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our principal executive officer and our principal financial officer concluded that the design and operation of our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the third quarter of 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

None.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

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

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

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

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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 8, 2006.

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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