Brigham Exploration (BEXP) 10-Q 2006 Q2 Quarterly report

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 June 30, 2006

OR

¨  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 August 7, 2006	45,513,508

Brigham Exploration Company

Second Quarter 2006 Form 10-Q Report

TABLE OF CONTENTS

		Page
PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance Sheets - June 30, 2006 and December 31, 2005	1
	Consolidated Statements of Operations - Three and six months ended June 30, 2006 and 2005	2
	Consolidated Statement of Stockholders’ Equity - Six months ended June 30, 2006	3
	Consolidated Statements of Cash Flows - Six months ended June 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	16
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32
ITEM 4.	CONTROLS AND PROCEDURES	35
PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	35
ITEM 1.A.	RISK FACTORS	35
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	36
ITEM 3.	DEFALTS UPON SENIOR SECURITIES	36
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS	36
ITEM 5.	OTHER INFORMATION	37
ITEM 6.	EXHIBITS	37
SIGNATURES		37

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	June 30,			December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	8,048		$	3,975
Accounts receivable		17,194			22,825
Investments		37,600			-
Deferred income taxes		-			482
Other current assets		5,338			1,043
Total current assets		68,180			28,325
Oil and natural gas properties, net (full cost method)		410,274			347,329
Other property and equipment, net		1,020			1,027
Deferred loan fees		3,563			2,174
Other noncurrent assets		1,156			1,572
Total assets	$	484,193		$	380,427
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	23,304		$	12,128
Royalties payable		6,672			6,886
Accrued drilling costs		20,525			12,218
Participant advances received		3,543			2,116
Other current liabilities		6,280			4,119
Total current liabilities		60,324			37,467
Senior Notes		123,328			-
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 June 30, 2006 and December 31, 2005		10,101			10,101
Deferred income taxes		30,275			23,563
Other noncurrent liabilities		5,016			4,556
Commitments and contingencies (Note 3)
Stockholders' equity:
Common stock, $.01 par value, 90 million shares authorized, 45,031,368 and 44,917,768 shares issued and 45,013,400 and 44,917,768 shares outstanding at June 30, 2006 and December 31, 2005, respectively		450			449
Additional paid-in capital		201,659			202,127
Treasury stock, at cost; 17,968 shares at June 30, 2006		(211	)		-
Unearned stock compensation		-			(2,299	)
Accumulated other comprehensive income (loss)		1,921			(426	)
Retained earnings		51,330			41,789
Total stockholders’ equity		255,149			241,640
Total liabilities and stockholders' equity	$	484,193		$	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						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Revenues:
Oil and natural gas sales	$	26,134		$	18,434		$	51,930		$	35,137
Other revenue		52			56			30			99
		26,186			18,490			51,960			35,236
Costs and expenses:
Lease operating		2,536			1,390			5,266			3,608
Production taxes		1,052			366			2,196			1,168
General and administrative		2,182			1,304			3,951			2,402
Depletion of oil and natural gas properties		11,106			7,206			21,362			13,659
Depreciation and amortization		121			178			236			360
Accretion of discount on asset retirement obligations		79			43			149			82
		17,076			10,487			33,160			21,279
Operating income		9,110			8,003			18,800			13,957
Other income (expense):
Interest income		448			52			554			91
Interest expense, net		(3,141	)		(766	)		(4,230	)		(1,507	)
Gain (loss) on derivatives, net		(316	)		140			291			(466	)
Other income (expense)		938			37			1,010			112
		(2,071	)		(537	)		(2,375	)		(1,770	)
Income before income taxes		7,039			7,466			16,425			12,187
Income tax expense:
Current		-			-			-			-
Deferred		(3,373	)		(2,656	)		(6,884	)		(4,329	)
		(3,373	)		(2,656	)		(6,884	)		(4,329	)
Net income	$	3,666		$	4,810		$	9,541		$	7,858
Net income per share available to common stockholders:
Basic	$	0.08		$	0.11		$	0.21		$	0.19
Diluted	$	0.08		$	0.11		$	0.21		$	0.18
Weighted average shares outstanding:
Basic		44,992			42,189			44,989			42,144
Diluted		45,361			43,206			45,501			43,162

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		—		—		—			—			—			—			9,541		9,541
Unrealized gain (losses) on cash flow hedges		—		—		—			—			—			4,488			—		4,488
Tax provisions related to cash flow hedges		—		—		—			—			—			(1,264	)		—		(1,264	)
Net (gains) losses included in net income		—		—		—			—			—			(877	)		—		(877	)
Comprehensive income																				11,888
Adoption of SFAS No. 123R		—		—		(2,299	)		—			2,299			—			—		—
Issuance of common stock		—		—		37			—			—			—			—		37
Exercises of employee stock options		48				239			—			—			—			—		239
Vesting of restricted stock		65		1		(1	)		—			—			—			—		—
Stock based compensation		—		—		1,556			—			—			—			—		1,556
Repurchases of common stock		—		—		—			(211	)		—			—			—		(211	)
Balance, June 30, 2006		45,031	$	450	$	201,659		$	(211	)	$	-		$	1,921		$	51,330	$	255,149

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

3

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2006			2005
Cash flows from operating activities:
Net income	$	9,541		$	7,858
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		21,362			13,659
Depreciation and amortization		236			360
Stock based compensation		843			-
Write-off of deferred loan costs		965			-
Interest paid through issuance of additional mandatorily redeemable preferred stock		-			381
Amortization of deferred loan fees and debt issuance costs		303			253
Market value adjustment for derivative instruments		(490	)		466
Accretion of discount on asset retirement obligations		149			82
Deferred income taxes		6,884			4,329
Other noncash items		64			59
Changes in operating assets and liabilities:
Accounts receivable		5,631			4,030
Other current assets		(750	)		241
Accounts payable		11,176			466
Royalties payable		(214	)		(1,070	)
Participant advances received		1,427			(2,946	)
Other current liabilities		2,548			47
Other noncurrent assets and liabilities		(221	)		(14	)
Net cash provided by operating activities		59,454			28,201
Cash flows from investing activities:
Additions to oil and natural gas properties		(74,929	)		(56,938	)
Purchases of short term investments		(45,150	)		-
Sales and redemptions of short term investments		7,550			-
Additions to other property and equipment		(293	)		(86	)
Decrease (increase) in drilling advances paid		(45	)		211
Net cash used by investing activities		(112,867	)		(56,813	)
Cash flows from financing activities:
Proceeds from senior notes offering		123,286			-
Increase in senior credit facility		24,200			31,600
Repayment of senior credit facility		(57,300	)		(8,200	)
Increase in senior subordinated notes		-			10,000
Repayment of senior subordinated notes		(30,000	)		-
Deferred loan fees paid and equity costs		(2,765	)		(888	)
Proceeds from issuance of stock, net of issuance costs		37			-
Proceeds from exercise of employee stock options		239			434
Repurchases of common stock		(211	)		(190	)
Net cash provided by financing activities		57,486			32,756
Net increase (decrease) in cash and cash equivalents		4,073			4,144
Cash and cash equivalents, beginning of year		3,975			2,281
Cash and cash equivalents, end of period	$	8,048		$	6,425

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

4

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

3. Commitments and Contingencies

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

As of June 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. Earnings Per Common Share

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

5

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Weighted average common shares outstanding - basic		44,992		42,189		44,989		42,144
Plus: Potential common shares
Stock options and restricted stock		369		1,017		512		1,018
Weighted average common shares outstanding - diluted		45,361		43,206		45,501		43,162
Stock options excluded from diluted EPS due to the anti-dilutive effect		1,426		700		1,246		700

5. Income Taxes

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

	June 30, 2006
Current income taxes:
Federal	$	-
State		-
Deferred income taxes:
Federal		5,543
State		1,341
	$	6,884

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. Senior Notes

In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due 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.

6

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 June 30, 2006 is shown below (in thousands):

	Cost		Unrealized Holding Gains / (Losses)		Fair Value
Available-for-Sale Securities:
State and municipal securities	$	37,600	$	-	$	37,600

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 six month periods ended June 30, 2006 and 2005:

	Three Months Ended June 30,					Six Months Ended June 30,
	2006		2005			2006			2005
Natural Gas
Average price per Mcf as reported (including hedging results)	$	7.07	$	6.62		$	7.22		$	6.21
Average price per Mcf realized (excluding hedging results)	$	6.56	$	6.73		$	6.94		$	6.27
Increase (decrease) in revenue (in thousands)	$	1,359	$	(231	)	$	1,490		$	(241	)
Oil
Average price per Bbl as reported (including hedging results)	$	68.88	$	47.83		$	64.83		$	45.65
Average price per Bbl realized (excluding hedging results)	$	68.88	$	51.56		$	65.05		$	49.84
Increase (decrease) in revenue (in thousands)	$	-	$	(385	)	$	(50	)	$	(926	)

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 six months ended June 30 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Increase (decrease) in earnings due to ineffectiveness	$	42	$	203	$	877	$	(413	)

7

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):

	June 30, 2006			December 31, 2005
Fair value of undesignated derivatives	$	(408	)	$	(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 six months ended June 30 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006		��	2005
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives	$	(163	)	$	(63	)	$	(283	)	$	(53	)

The following table reflects open commodity derivative contracts at June 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
07/01/06 - 07/31/06		Purchased put		Cash flow		90,000			$	8.00
		Written call		Cash flow		90,000				17.00
07/01/06 - 07/31/06		Purchased put		Cash flow		90,000			$	8.00
		Written call		Cash flow		90,000				15.60
07/01/06 - 09/30/06		Purchased put		Cash flow				21,000	$	50.00
		Written call		Cash flow				21,000		75.60
07/01/06 - 10/31/06		Purchased put		Cash flow		280,000			$	8.00
		Written call		Cash flow		280,000				14.85
10/01/06 - 12/31/06		Purchased put		Cash flow				27,000	$	50.00
		Written call		Cash flow				27,000		77.50
08/01/06 - 10/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				16.65
08/01/06 - 10/31/06		Purchased put		Cash flow		300,000			$	5.50
		Written call		Cash flow		300,000				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

8

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
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

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Three Way Costless Collars
07/01/06 - 09/30/06		Purchased put		Cash flow				15,000	$	63.00
		Written call		Cash flow				15,000		75.65
		Written put		Undesignated				15,000		48.00
07/01/06 - 10/31/06		Purchased put		Cash flow		240,000			$	7.50
		Written call		Cash flow		240,000				9.15
		Written put		Undesignated		240,000				6.25
07/01/06 - 10/31/06		Purchased put		Cash flow		280,000			$	8.50
		Written call		Cash flow		280,000				9.96
		Written put		Undesignated		280,000				7.00

9

The following table reflects commodity derivative contracts entered subsequent to June 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
09/01/06 - 10/31/06		Purchased put		Cash flow				17,000	$	70.00
		Written call		Cash flow				17,000		85.20
11/01/06 - 11/30/06		Purchased put		Cash flow				4,000	$	70.00
		Written call		Cash flow				4,000		85.20
12/01/06 - 02/28/07		Purchased put		Cash flow				7,500	$	70.00
		Written call		Cash flow				7,500		85.20
11/01/07 - 03/31/08		Purchased out		Cash Flow		300,000			$	8.85
		Written call		Cash Flow		300,000				15.00

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):

	June 30, 2006			December 31, 2005
Fair value of undesignated derivatives	$	(104	)	$	-

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2006			2005		2006			2005
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives	$	(104	)	$	-	$	(104	)	$	-

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

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Natural Gas (MMBTU)		Oil (Barrels)	Discount To NYMEX
Basis Swaps
NGPL STX
08/01/06 - 10/31/06		Purchased Put		Undesignated		600,000		$	0.603
HSC
08/01/06 - 10/31/06		Purchased Put		Undesignated		240,000		$	0.510
ANR OK
08/01/06 - 10/31/06		Purchased Put		Undesignated		420,000		$	1.110

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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.

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.

	June 30, 2006			December 31, 2005
	(In thousands)
Other current liabilities	$	(383	)	$	(2,112	)
Other noncurrent liabilities		(235	)		(61	)
Other current assets		3,619			224
Other noncurrent assets		192			654
	$	3,193		$	(1,295	)

9. Asset Retirement Obligations

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

Brigham has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes Brigham's asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the six months ended June 30, 2006 and 2005 (in thousands):

	Six Months Ended June 30,
	2006			2005
Beginning asset retirement obligations	$	4,389		$	2,896
Liabilities incurred for new wells placed on production		358			160
Liabilities settled		(196	)		(6	)
Accretion of discount on asset retirement obligations		149			82
	$	4,700		$	3,132

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10. Stock Based Compensation

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 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.

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.

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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 six 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 six month periods ended June 30, 2005 would have been the pro forma amounts indicated below (in thousands, except per share amounts):

	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
Net income, as reported	$	4,810		$	7,858
Add back: Stock compensation expense previously included in net income		111			222
Effect of total employee stock-based compensation expense, determined under fair value method for all awards		(321	)		(682	)
Pro forma	$	4,600		$	7,398
Net income per share:
Basic, as reported	$	0.11		$	0.19
Basic, pro forma		0.11			0.18
Diluted, as reported	$	0.11		$	0.18
Diluted, pro forma		0.11			0.17

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 June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Pre-tax stock based compensation expense	$	943		$	166		$	1,556		$	334
Capitalized stock based compensation		(408	)		(80	)		(713	)		(161	)
Tax benefit		(187	)		(30	)		(295	)		(60	)
Stock based compensation expense, net	$	348		$	56		$	548		$	113

The adoption of SFAS 123R did not impact basic and diluted net income per share for the three and six months ended June 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 June 30, 2006, approximately 1,407,222 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.

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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 six months ended June 30, 2006:

	Shares			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term		Aggregate Intrinsic Value (in thousands)
Options outstanding at the beginning of the year		2,946,333		$	6.96
Granted		20,000		$	9.73
Forfeited or cancelled		(194,067	)	$	4.84
Exercised		(48,600	)	$	5.99
Options outstanding at June 30, 2006		2,723,666		$	7.15		4.4 years	$	4,127,489
Options exercisable at June 30, 2006		1,021,733		$	5.58		3.6 years	$	2,513,637

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 second 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 June 30, 2006. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of June 30, 2006 there was approximately $5 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, in approximately 4.7 years.

The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005, was $224,000 and $672,000, respectively.

Restricted Stock

During the six months ended June 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. For the six months ended June 30, 2006, Brigham recognized approximately $1.4 million of unearned stock compensation and will amortize this amount to compensation expense over the vesting period of the restricted stock. 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 six months ended June 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		(27,500	)	$	8.05
Restricted shares outstanding at June 30, 2006		434,745		$	8.68

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11. Comprehensive Income

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Net income	$	3,666		$	4,810		$	9,541		$	7,858
Unrealized gains (losses) on cash flow hedges		27			1,000			4,488			391
Tax benefits (provisions) related to cash flow hedges		5			(279	)		(1,264	)		(282	)
Net (gains) losses included in net income		(42	)		(202	)		(877	)		414
Other Comprehensive Income, net	$	3,656		$	5,329		$	11,888		$	8,381

12. New Accounting Pronouncements

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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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 six month periods ended June 30, 2006, and the comparable periods of 2005. For definitions of commonly used gas and oil terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 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, we have acquired approximately 80,000 net acres in the Bakken play in North Dakota and Montana since November 2005. Furthermore, 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.

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 Second Quarter and First Six Months 2006 Results

Although natural gas prices declined during the second quarter 2006, they continue to remain relatively high compared to long-term historical averages due to forecasts for continued U.S. production declines, increasing natural gas demand and high crude oil prices, which encourages fuel switching. The average sales price, excluding hedging results, that we received for our natural gas in the second quarter and first six months of 2006 was $6.56 and $6.94 per Mcf, respectively. This represents a decrease of 3% over the price we received in the second quarter 2005 and an 11% increase from that in the first six months of 2005. The average sales price that we received for oil, excluding hedging results, in the second quarter and first six months of 2006 was $68.88 and $65.05 per Bbl, respectively. Oil prices increased by 34% from the second quarter last year and by 31% from the first six months of 2005.

Our average production for the second quarter 2006 increased 24% to 36.5 MMcfe/d from the second quarter 2005. Average production for the first six months of 2006 increased 22% to 36.2 Mmcfe/d from the first six months of 2005. These increases were primarily attributable to production from new wells that came on line during the second half of 2005 and the first half of 2006 and were partially offset by the natural decline in wells that began producing prior to the third quarter 2005.

16

Second quarter operating income increased 14% to $9.1 million from last year’s second quarter. First half 2006 operating income increased 35% to $18.8 million from the comparable period last year. Production increases combined with an increase in our average realized prices for natural gas and oil led to an increase in our operating income. These increases were partially offset by increases in production taxes, general and administrative expense and depletion expense.

For the quarter ended June 30, 2006, we spent $36.8 million on drilling capital expenditures, which represents an increase of 33% over that in the second quarter 2005 and a 19% increase over that in the first quarter 2006. Through June 30, 2006, we spent $67.6 million on drilling capital expenditures and $84.3 million on oil and gas capital expenditures. Second quarter and first half 2006 net cash provided by operating activities funded approximately 75% and 71%, respectively, of our oil and gas capital expenditures. In April 2006, we issued $125 million of 9 5/8% senior notes due 2014 (the “Senior Notes”) to refinance existing indebtedness and to fund the balance of investing activities for these periods and for the remainder of 2006.

As of June 30, 2006, we had $8.0 million in cash, $37.6 million in short-term investments, $484.2 million in total assets and a net debt to book capitalization ratio of 34%.

Overview of Operations

Through early August, we have spud 26 wells, retaining an average working interest of approximately 61%. Seventeen of these wells have been or are in the process of being completed, three have been plugged and six are currently drilling.  Our gross and net completion rate thus far in 2006 is 85% and 86%, respectively.

Vicksburg Trend

We have successfully completed 4 wells in the Vicksburg trend during 2006. Most recently, we are drilling the Sullivan F-33, which encountered 62 feet of apparent net pay in the upper Vicksburg 9800’ sands. We expect to commence production testing on the well by late August. We also completed the Dawson #4 well from the 9800' sands at an initial rate of 2.8 MMcf of gas and 27 barrels of condensate (3.0 MMcfe) per day. Approximately 70 feet of gross "Brigham" sand remains behind pipe and will likely be added to the production stream. In August we will commence the Sullivan C-33, offsetting a previously drilled Floyd Fault Block field well, the Sullivan #10. The Sullivan #10 produced at rates as high as approximately 15 MMcfe per day, and has produced approximately 7 Bcfe to date. Earlier in the year, we completed the Palmer #11 and Dawson #3, which produced at initial rates of 5.3 MMcfe per day and 4.7 MMcfe per day, respectively.

Frio Trend

We are currently completing the State Tract 109 #1, which encountered 60 feet of apparent Lower Frio pay, with an additional 73 feet of potential pay that will likely be tested. We expect to commence production testing the well in mid-August. In late September, we expect to spud our high potential Green Ranch #1 well, with results expected in November. Earlier in the year, we completed with Trull B #3, which flowed at 1.8 MMcfe per day. In the first quarter, we completed the Sartwelle #4, which flowed at 2.6 MMcfe per day.

Gulf Coast Louisiana Miocene Trend

We entered into two joint ventures to develop prospects in Iberia and St. Martin Parishes. Our first well, the Cotten Land Corp. #1, tested at an initial rate of 10.1 MMcfe per day. We expect to complete the pipeline hook-up and begin producing to sales in mid to late September. By late August, we expect to commence drilling of our high potential Williams Land Company #1 well. This well will test the Lower Planulina objective structurally high to two wells that have produced a combined 57 Bcfe to date. We retain a 59% working interest in the well.

Anadarko Basin

In early June, we commenced production of the Mills Ranch #1-99S in the Hunton. The well initially produced at rates as high as 6.0 MMcfe per day, and is currently producing approximately 1.5 MMcfe per day. Though the Mills Ranch #1-99S’s production has declined, it will take more time to determine the well's long-term productivity. In June it became apparent that the Mills Ranch 98-2 Hunton well had developed a tubing leak. On July 1st we commenced operations to pull the tubing and remediate the well, but became stuck at a depth of approximately 12,000 feet. We are currently above the stuck point and are attempting to fish the remaining tubing from the well. Prior to the apparent tubing leak, the Mills Ranch 98-2 was producing approximately 3.3 MMcfe per day. Currently, we are drilling the Mill Ranch 96 #1, which targets the Hunton objective at 24,500 feet. We expect results from this well in September.

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Rockies Plays

Through July 2006, our company has acquired 80,000 net acres in the Bakken Play of North Dakota and Montana in the Williston Basin, and is the process of acquiring additional acreage. We have successfully drilled our first well, the Field 18-19 1-H, which initially produced at 200 barrels of oil per day and is currently producing at 105 barrels of oil per day. We anticipate installing tubing and a rod pump, which should increase the production rate for the well. Our second well, the Erickson 8-17 1-H, is in the process of drilling and should reach total depth by the end of August.

In August, we commenced the first of four Powder River Basin wells. Our first well, the Krejci #1, is targeting the Mowry shale via a 1,600 foot horizontal lateral that will reach a total depth of 7,375 feet. We expect to reach total depth in late August.

Second Quarter and First Six Months 2006 Results

Comparison of the three-month and six month periods ended June 30, 2006 and 2005.

Production volumes

	Three months ended June 30,							Six months ended June 30,
	2006		% Change			2005		2006		% Change			2005
Oil (MBbls)		109		6	%		103		225		2	%		221
Natural gas (MMcf)		2,629		29	%		2,041		5,174		28	%		4,035
Total (MMcfe)(1)		3,286		24	%		2,659		6,521		22	%		5,359
Average daily production (MMcfe/d)		36.5					29.5		36.2					29.8

____________

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

Production volumes increased due to new wells that came on line during the last two quarters of 2005 and first two quarters of 2006. Production from these new wells was offset by the natural decline in our production from existing wells.

Natural gas represented 80% of our second quarter 2006 production volumes compared to 77% in the second quarter of last year. For the first six months of 2006, natural gas represented 79% of our production versus 75% during the first half 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 June 30,								Six months ended June 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		42	%	$	5,313		$	14,609			33	%	$	11,002
Gain (loss) due to hedging		—		(100	%)		(385	)		(50	)		(95	%)		(926	)
Total revenue from the sale of oil	$	7,541		53	%	$	4,928		$	14,559			44	%	$	10,076
Natural gas sales	$	17,234		25	%	$	13,737		$	35,881			42	%	$	25,302
Gain (loss) due to hedging		1,359		NM			(231	)		1,490			NM			(241	)
Total revenue from the sale of natural gas	$	18,593		38	%	$	13,506		$	37,371			49	%	$	25,061
Oil and natural gas sales	$	24,775		30	%	$	19,050		$	50,490			39	%	$	36,304
Gain (loss) due to hedging		1,359		NM			(616	)		1,440			NM			(1,167	)
Total revenue from the sale of oil and natural gas	$	26,134		42	%	$	18,434		$	51,930			48	%	$	35,137
Average prices:
Oil sales price (per Bbl)	$	68.88		34	%	$	51.56		$	65.05			31	%	$	49.84
Gain (loss) due to hedging (per Bbl)		—		(100	%)		(3.73	)		(0.22	)		(95	%)		(4.19	)
Realized oil price (per Bbl)	$	68.88		44	%	$	47.83		$	64.83			42	%	$	45.65
Natural gas sales price (per Mcf)	$	6.56		(3	)%	$	6.73		$	6.94			11	%	$	6.27
Gain (loss) due to hedging (per Mcf)		0.51		NM			(0.11	)		0.28			NM			(0.06	)
Realized natural gas price (per Mcf)	$	7.07		7	%	$	6.62		$	7.22			16	%	$	6.21
Natural gas equivalent sales price (per Mcfe)	$	7.54		5	%	$	7.16		$	7.74			14	%	$	6.77
Gain (loss) due to hedging (per Mcfe)		0.41		NM			(0.23	)		0.22			NM			(0.21	)
Realized natural gas equivalent (per Mcfe)	$	7.95		15	%	$	6.93		$	7.96			21	%	$	6.56

18

	For the three month periods ended June 30, 2006 and 2005			For the six month periods ended June 30,2006 and 2005
Change in revenue from the sale of oil
Price variance impact	$	1,896		$	3,415
Volume variance impact		332			192
Cash settlement of hedging contracts		385			876
Total change	$	2,613		$	4,483
Change in revenue from the sale of natural gas
Price variance impact	$	(457	)	$	3,443
Volume variance impact		3,954			7,136
Cash settlement of hedging contracts		1,590			1,731
Total change	$	5,087		$	12,310

Our total revenue from the sale of oil and natural gas for the second quarter 2006 increased by 42% when compared to revenue for the second quarter 2005. The change in total revenue was due to the following:

· A 24% increase in production volumes generated a $4.3 million increase in revenue;

· A 5% increase in prices, excluding the impact of hedges, resulted in a $1.4 million increase in revenue; and

· A $1.4 million gain from the cash settlement of derivative contracts in the second quarter 2006 versus a $0.6 million loss for the same period last year led to $2.0 million increase in revenue.

Our total revenue from the sale of oil and natural gas for the first six months of 2006 increased by 48% when compared to revenue for the first six months of 2005. The following factors led to the change:

· A 22% increase in production volumes generated a $7.3 million increase in revenue;

· A 14% increase in prices, excluding the impact of hedges, resulted in a $6.9 million increase in revenue; and

· A $1.4 million gain from the cash settlement of derivative contracts in the first half of 2006 versus a $1.2 million loss last year led to $2.6 million increase in revenue.

19

The following table shows our derivative contracts designated as cash flow hedges, 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 June 30,								Six months ended June 30,
	2006		% Change			2005			2006			% Change			2005
Oil collars
Volumes (Bbls)		45,000		83	%		24,655			70,500			35	%		52,105
Average floor price ($ per Bbl)	$	53.93		69	%	$	31.96		$	53.27			86	%	$	28.59
Average ceiling price ($ per Bbl)	$	75.32		91	%	$	39.37		$	71.50			107	%	$	34.53
Gain /(loss) upon settlement ($ in thousands)	$	—		(100	%)	$	(385	)	$	(50	)		(95	%)	$	(926	)
Natural gas collars
Volumes (MMbtu)		1,140,000		80	%		635,000			1,740,000			28	%		1,362,500
Average floor price ($ per MMbtu)	$	8.01		62	%	$	4.93		$	8.18			62	%	$	5.06
Average ceiling price ($ per MMbtu)	$	13.74		94	%	$	7.08		$	12.74			78	%	$	7.17
Gain /(loss) upon settlement ($ in thousands)	$	1,359		NM		$	(231	)	$	1,490			NM		$	(241	)

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 on our income statement as gain / (loss) on derivatives, net.

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.

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 June 30,								Three months ended June 30,
	2006		% Change			2005			2006		% Change			2005
Production costs:
Operating & maintenance	$	0.59		13	%	$	0.52		$	1,953		41	%	$	1,389
Expensed workovers		0.05		NM			(0.08	)		152		NM			(213	)
Ad valorem taxes		0.13		63	%		0.08			431		101	%		214
Lease operating expenses	$	0.77		48	%	$	0.52		$	2,536		82	%	$	1,390
Production taxes		0.32		129	%		0.14			1,052		187	%		366
Production costs	$	1.09		65	%	$	0.66		$	3,588		104	%	$	1,756

20

Second quarter per unit of production costs increased 65% when compared to the second quarter last year because of the following:

· O&M expense increased 13%, or $0.07 per Mcfe. The increase in our per unit O&M expense from that in the prior year’s quarter was due to small increases in several different expense categories, with chemical treating accounting for 43% of the per unit increase.

· Ad valorem taxes increased 63% or $0.05 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 129% or $0.18 per Mcfe due to higher production volumes, higher commodity prices and a lack of severance tax refunds in the current period as compared to the $540,000 in refunds on six wells during the second quarter 2005.

· Workover expense increased by $0.13 per Mcfe due principally to a reclassification of costs related to workovers performed and reported as workover expense in the first quarter 2005 to capital cost in the second quarter 2005 and to insurance reimbursements in the second quarter 2005

	Unit-of-Production (Per Mcfe)							Amount (In thousands)
	Six months ended June 30,							Six months ended June 30,
	2006		% Change			2005		2006		% Change			2005
Production cost:
Operating & maintenance	$	0.62		19	%	$	0.52	$	4,051		44	%	$	2,811
Expensed workovers		0.04		(33	%)		0.06		277		(11	%)		311
Ad valorem taxes		0.15		67	%		0.09		938		93	%		486
Lease operating expenses	$	0.81		21	%	$	0.67	$	5,266		46	%	$	3,608
Production taxes		0.34		55	%		0.22		2,196		88	%		1,168
Production costs	$	1.15		29	%	$	0.89	$	7,462		56	%	$	4,776

Per unit of production costs for the first six months of 2006 increased by 29% compared to the last year’s first half because of the following:

· O&M expense increased 19% or $0.10 per Mcfe. The increase in our per unit O&M expense from that in the prior year’s first six months was due to small increases in several different expense categories, with chemical treating and saltwater disposal accounting for 44% of the per unit change.

· Ad valorem taxes increased 67% 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.

· Production taxes increased 55% or $0.12 per Mcfe due to higher production volumes, higher commodity prices and a lack of severance tax refunds in the current period as compared to the $540,000 in refunds on six wells during the first six months 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.

21

	Three months ended June 30,									Six months ended June 30,
	2006			% Change			2005			2006			% Change			2005
	(In thousands, except per unit measurements)
General and administrative costs	$	3,882			55	%	$	2,501		$	7,176			49	%	$	4,804
Capitalized general and administrative costs		(1,700	)		42	%		(1,197	)		(3,225	)		34	%		(2,402	)
General and administrative expenses	$	2,182			67	%	$	1,304		$	3,951			64	%	$	2,402
General and administrative expense ($ per Mcfe)	$	0.66			35	%	$	0.49		$	0.61			36	%	$	0.45

Our general and administrative expense for the second quarter 2006 was 67% higher when compared to that in the second quarter of last year due primarily to a $1.3 million increase in employee compensation expense and, to a lesser extent, an increase in financial reporting and stock listing expense. Roughly 27% of the increase in employee compensation expense was non-cash expense resulting from our 2006 adoption of FAS 123(R), dealing with a change in accounting methodology for employee stock option expense. Due to these higher costs, general and administrative expense on a per unit basis increased 35% in the quarter to $0.66 per Mcfe.

General and administrative expense for the first six months of 2006 was 64% higher than the first six months of last year. G&A expenses increased primarily because of $2.0 million of increased employee compensation expense and, to a lesser extent, because of increased audit, tax and financial reporting costs. Roughly 42% of the increase in employee compensation expense was non-cash expense resulting from our 2006 adoption of FAS 123(R), dealing with a change in accounting methodology for employee stock option expense. These 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 June 30,							Six months ended June 30,
	2006		% Change			2005		2006		% Change			2005
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	11,106		54	%	$	7,206	$	21,362		56	%	$	13,659
Depletion of oil and natural gas properties ($ per Mcfe)	$	3.38		25	%	$	2.71	$	3.28		29	%	$	2.55

Our depletion expense for the second quarter 2006 was $3.9 million higher than 2005. Approximately 56% of the increase was due to an increase in our depletion rate while the remaining 44% of the increase was due to an increase in our production volumes. Our depletion expense for the first half 2006 was $7.7 million higher than 2005. Approximately 61% of the increase was due to an increase in our depletion rate while the remaining 39% of the increase was due to an increase in our production volumes.

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

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

	Three months ended June 30,									Six months ended June 30,
	2006			% Change			2005			2006			% Change			2005
	(In thousands)
Interest on Senior Notes	$	2,339			NM		$	—		$	2,339			NM		$	—
Interest on senior credit facility		142			(74	%)		547			743			(15	%)		870
Interest on senior subordinated notes (a)		121			(68	%)		381			699			(8	%)		759
Commitment fees		35			94	%		18			83			48	%		56
Dividend on mandatorily redeemable preferred stock		151			(22	%)		193			300			(21	%)		381
Amortization of deferred loan and debt issuance cost		1,149			805	%		127			1,268			401	%		253
Other general interest expense		2			(33	%)		3			5			(17	%)		6
Capitalized interest expense		(798	)		59	%		(503	)		(1,207	)		48	%		(818	)
Net interest expense	$	3,141			310	%	$	766		$	4,230			181	%	$	1,507
Weighted average debt outstanding	$	124,918			67	%	$	74,899		$	103,376			51	%	$	68,239
Average interest rate on outstanding indebtedness (b)		9.1	%					6.1	%		8.1	%					6.1	%

22

__________

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.

Second quarter 2006 interest expense was $2.4 million higher because of a higher weighted average debt balance and a higher weighted average cost of debt attributed to the April 2006 issuance of Senior Notes. In addition, we wrote-off approximately $1 million in subordinated note issuance costs associated with the termination of the subordinated credit facility.

First half 2006 interest expense was $2.7 million higher than the comparable period in 2005 because of the issuance of Senior Notes and the write-off or our subordinated note issuance costs.

We made aggregate cash payments of $0.9 million for interest in the second quarter 2006 and $1.8 million in the first six months 2006.

Other Income(expense). Gain (loss) on derivatives 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 June 30,									Six months ended June 30,
	2006			% Change			2005			2006			% Change			2005
Derivative:	(In thousands)
Non-cash gain (loss) due to change in fair market value of derivative contracts not designated as cash flow hedges	$	(267	)		324	%	$	(63	)	$	(387	)		630	%	$	(53	)
Non-cash gain (loss) for ineffective portion of cash flow hedges		42			(79	%)		203			877			NM			(413	)
Cash settlement		(91	)		NM			—			(199	)		NM			—
Gain (loss) on derivatives, net	$	(316	)		NM		$	140		$	291			NM		$	(466	)
Other:
Non-cash gain (loss)	$	(22	)		(57	%)	$	(51	)	$	(64	)		8	%	$	(59	)
Cash income (expense)		960			991	%		88			1,074			528	%		171
Miscellaneous other income (loss)	$	938			2435	%	$	37		$	1,010			802	%	$	112
Total other income	$	622			251	%	$	177		$	1,301			NM		$	(354	)

Other cash income increased in the second quarter 2006 when compared to the second quarter 2005 primarily because of $838,000 in income associated with the termination of the subordinated credit facility interest rate swap. Similarly, first half 2006 other income increased because of the previously mentioned interest rate swap.

23

The following table shows the volumes and the weighted average NYMEX reference price for those derivative contracts that we did not designate as cash flow hedges under SFAS 133 for the periods indicated.

	Three months ended June 30,								Six months ended June 30,
	2006			% Change			2005		2006			% Change			2005
Written puts
Oil
Volumes (Bbl)		7,500			25	%		6,000		25,500			325	%		6,000
Average price ($ per Bbl)	$	48.00			26	%	$	38.00	$	40.94			8	%		38.00
Gain /(loss) upon settlement ($ in thousands)	$	—			—		$	—	$	—			—		$	—
Natural gas
Volumes (MMbtu)		390,000			NM			—		990,000			371	%		210,000
Average price ($ per MMbtu)	$	6.65			NM		$	—	$	6.89			25	%	$	5.50
Gain /(loss) upon settlement ($ in thousands)	$	(91	)		NM		$	—	$	(199	)		NM		$	—

Income taxes. 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 operating margin. 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 $3.4 million in the second quarter of this year, compared to deferred income tax expenses of $2.7 million in the second quarter last year. The increase in our deferred income taxes was primarily due to our second quarter adoption of the Margin Tax, 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 in the second quarter 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.

We recorded deferred income tax expenses of $6.9 million in the first six months of this year, compared to deferred income tax expenses of $4.3 million in the first six months of last year. The increase in our deferred income taxes was primarily due to higher income before income taxes and the aforementioned second quarter adoption of the Margin Tax.

For the first six months of 2006, the following table reconciles the difference between the statutory tax rate of 35% and the effective tax rate of 41.9%:

	Six months endedJune 30, 2006		Tax Rate
Reconciliation to effective tax rate:
Tax at the statutory rate	$	5,749		35.00	%
Add the effect of:
Non-deductible expenses		2		0.02	%
Preferred stock dividends		105		0.64	%
Incentive stock options not exercised		124		0.76	%
Deferred Margin Tax (after-tax)		848		5.16	%
Other		56		0.34	%
Total	$	6,884		41.92	%

24

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 2006 budgeted oil and gas capital expenditures, the amount spent through June 30, 2006 and the amount of our budget that remains to be spent.

	2006 Budget		Amount Spent Through 06/30/2006		Amount Remaining (1)
	(In thousands)
Drilling	$	120,467	$	67,617	$	52,850
Net land and seismic		28,597		11,554		17,043
Capitalized costs (2)		7,259		4,781		2,478
Asset Retirement Obligations		559		358		201
Total (3)	$	156,882	$	84,310	$	72,572

____________

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

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

(3) Excludes other property capital expenditures.

The capital that funds our drilling activities is allocated to individual prospects based on the value potential of a prospect, as measured by a risked net present value analysis. We start each year with a budget and reevaluate this budget monthly. The primary factors that impact this value creation measure include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of all our budgeted expenditures include the level of production from our existing oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. 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.

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 second quarter 2006 were funds generated by operations and proceeds from our Senior Notes.

25

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, 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 issued pursuant to an indenture (the"Indenture") in a transaction exempt from the registration requirements of the Securities Act of 1933. We have filed a registration statement and are in the process of completing an exchange offer to exchange the existing unregistered Senior Notes for registered Senior Notes.

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

· be 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 June 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 June 30, 2006, we had no amounts outstanding and therefore had $50 million of unused committed borrowing capacity available. As of June 30, 2005, we had $44.5 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 June 30, 2006 and interest coverage ratio for the twelve-month period ended June 30, 2006, were 4.0 to 1 and 14.2 to 1, respectively. As of June 30, 2006, we were in compliance with all covenant requirements in connection with our senior credit agreement.

26

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.

Senior Subordinated Notes

In April 2006, we used a portion of the net proceeds from our sale of our Senior Notes issuance to repay the $30 million in borrowings that were outstanding under our subordinated credit agreement. Subsequent to this repayment, we terminated our subordinated credit agreement and the associated interest rate swap designated as a cash flow hedge.

Mandatorily Redeemable Preferred Stock

As of June 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.

Access to Capital Markets

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

In February 2006, we filed a new universal shelf registration statement allowing us to issue common stock, preferred stock, depositary shares, warrants, senior debt and subordinated debt up to an aggregate amount of $300 million. Our new universal shelf registration statement was declared effective by the SEC in June 2006. 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.

27

Analysis of Changes In Cash and Cash Equivalents

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

	Six months ended June 30,
	2006			%Change			2005
	(In thousands)
Net income	$	9,541			21	%	$	7,858
Non-cash items		30,316			55	%		19,589
Changes in working capital and other items		19,597			2499	%		754
Cash flows provided by operating activities	$	59,454			111	%		28,201
Cash flows used by investing activities		(112,867	)		99	%		(56,813	)
Cash flows provided by financing activities		57,486			75	%		32,756
Net increase in cash and cash equivalents	$	4,073			(2	%)	$	4,144

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.

First half 2006 cash flows provided by operating activities increased by 111% to $59.5 million from the same period last year. The increase in operating cash flow is attributable to improved net income associated with higher production volumes and prices. Additionally, cash flows were also increased by the $7.7 million increase in non-cash depletion expense.  Finally, accounts receivable decreases and accounts payable increases improved our cash flow provided by operating activities. Cash flows provided by operating activities funded 71% of our oil and gas capital expenditures during the first half of 2006. This compares with 48% during the first half of 2005.

Analysis of changes in cash flows used in investing activities

	Six months ended June 30,
	2006			%Change			2005
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	67,617			49	%	$	45,238
Land and seismic		11,554			13	%		10,246
Capitalized cost		4,781			41	%		3,381
Asset retirement obligation		358			124	%		160
Total	$	84,310			43	%	$	59,025
Reconciling Items:
Change in accrued drilling costs	$	(8,307	)		370	%	$	(1,766	)
Change short-term investments		37,600			NM			—
Other		(736	)		65	%		(446	)
Total reconciling items		28,556			NM			(2,212	)
Net cash used in investing activities	$	112,867			99	%	$	56,813

Net cash used by investing activities in the first half of 2006 was 99% higher than the similar period for 2005. The following were the primary reasons for the increase:

· Drilling capital expenditures increased by $22.4 million due to our increased level of exploratory and developmental drilling activities. Increased drilling expenditures were partially offset by an $8.3 million change in our drilling accrual.

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· Capitalized costs increased by $1.4 million associated with our increased levels of general and administrative expense, capitalized stock expense and capitalized interest expense during the period.

· We invested $37.6 million of our Senior Notes proceeds in short-term investments.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first half of 2006 was 75% higher than the first half 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 $120.8 million.

· Our Senior Notes issuance was partially offset by $78 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 six months ended 2006 and 2005.

	Shares Issued		Net Proceeds
	(In thousands except share data)
2006 common stock transactions:
Exercise of employee stock options		48,600	$	238
2005 common stock transactions:
Exercise of employee stock options		125,500	$	434

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.

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New Accounting Pronouncements

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.

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.

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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 second quarter 2006.

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 report for the period ended March 31, 2006 including, but not limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

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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 consists 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 June 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
07/01/06 - 07/31/06		Purchased put		Cash flow		90,000			$	8.00
		Written call		Cash flow		90,000				17.00
07/01/06 - 07/31/06		Purchased put		Cash flow		90,000			$	8.00
		Written call		Cash flow		90,000				15.60
07/01/06 - 09/30/06		Purchased put		Cash flow				21,000	$	50.00
		Written call		Cash flow				21,000		75.60
07/01/06 - 10/31/06		Purchased put		Cash flow		280,000			$	8.00
		Written call		Cash flow		280,000				14.85
10/01/06 - 12/31/06		Purchased put		Cash flow				27,000	$	50.00
		Written call		Cash flow				27,000		77.50
08/01/06 - 10/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				16.65
08/01/06 - 10/31/06		Purchased put		Cash flow		300,000			$	5.50
		Written call		Cash flow		300,000				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

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					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Natural Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
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
Three Way Costless Collars
07/01/06 - 09/30/06		Purchased put		Cash flow				15,000	$	63.00
		Written call		Cash flow				15,000		75.65
		Written put		Undesignated				15,000		48.00
07/01/06 - 10/31/06		Purchased put		Cash flow		240,000			$	7.50
		Written call		Cash flow		240,000				9.15
		Written put		Undesignated		240,000				6.25
07/01/06 - 10/31/06		Purchased put		Cash flow		280,000			$	8.50
		Written call		Cash flow		280,000				9.96
		Written put		Undesignated		280,000				7.00

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 gain (loss) on derivatives, net,  on our consolidated statement of operations.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Natural Gas (MMBTU)		Oil (Barrels)	Discount To Nymex
Basis Swaps
NGPL STX
08/01/06 - 10/31/06		Purchased Put		Undesignated		600,000		$	0.603
HSC
08/01/06 - 10/31/06		Purchased Put		Undesignated		240,000		$	0.510
ANR OK
08/01/06 - 10/31/06		Purchased Put		Undesignated		420,000		$	1.110

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The following table reflects commodity derivative contracts entered subsequent to June 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
09/01/06 - 10/31/06		Purchased put		Cash flow				17,000	$	70.00
		Written call		Cash flow				17,000		85.20
11/01/06 - 11/30/06		Purchased put		Cash flow				4,000	$	70.00
		Written call		Cash flow				4,000		85.20
12/01/06 - 02/28/07		Purchased put		Cash flow				7,500	$	70.00
		Written call		Cash flow				7,500		85.20
11/01/07 - 03/31/08		Purchased put		Cash flow		300,000			$	8.85
		Written call		Cash flow		300,000				15.00

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 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 second quarter of 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

Our 2005 Annual Report on Form 10-K includes a detailed discussion of our risk factors.  There have been no material changes to the risk factors previously disclosed in our 2005 Annual Report on Form 10-K, except for the risk factors related to the offering of our 9 5/8%Senior Notes due 2014 which was completed April 20, 2006 and included in the first quarter 2006 10-Q.   The information presented below updates and should be read in conjunction with the risk factors and the information disclosed in our 2005 Annual Report on Form 10-K.

Holders of outstanding notes who fail to properly tender them may be unable to resell them.

If you do not tender your outstanding notes or if we do not accept your outstanding notes because you did not tender your outstanding notes properly, then, after we consummate the exchange offer, you may continue to hold outstanding notes that are subject to the existing transfer restrictions. We will only issue exchange notes in exchange for outstanding notes that are timely received by the exchange agent, together with all required documents, including a properly completed and signed letter of transmittal. Therefore, you should allow sufficient time to ensure timely delivery of the outstanding notes and you should carefully follow the instructions on how to tender your outstanding notes. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of the outstanding notes. In addition, if you tender your outstanding notes for the purpose of participation in a distribution of the exchange notes, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange notes. If you are a broker-dealer that receives exchange notes for your own account in exchange for outstanding notes that you acquired as a result of market-making activities or any other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes. After the exchange offer is consummated, if you continue to hold any outstanding notes, you may have difficulty selling them because there will be less outstanding notes outstanding. In addition, if a large amount of outstanding notes are not tendered or are tendered improperly, the limited amount of exchange notes that would be issued and outstanding after we consummate the exchange offer could lower the market price of such exchange notes.

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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

(a) We held our Annual Stockholders meeting on Thursday, June 1, 2006, in Austin, Texas at 10:00 a.m. local time.

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

(c) Out of the total 45,474,608 shares of our common stock outstanding and entitled to vote, 39,928,466 shares were present in person or by proxy, representing approximately 88%. The only matters voted on by our stockholders, as fully described in the definitive proxy materials for the annual meeting, are set forth below. The results were as follows:

1. To elect eight directors to serve until the Annual Meeting of Stockholders in 2006.

Nominee	Number of shares voting for election as director		Number of shares voting against election as director		Number of shares withholding authority to vote for election as director
Ben M. “Bud” Brigham		29,922,190		—		10,006,276
David T. Brigham		29,801,404		—		10,127,062
Harold D. Carter		27,685,503		—		12,242,963
Stephen C. Hurley		38,986,035		—		942,431
Stephen P. Reynolds		38,162,107		—		1,766,359
Hobart A. Smith		38,985,706		—		942,760
Steven A. Webster		29,297,365		—		10,631,101
R. Graham Whaling		38,985,930		—		942,536

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2. To approve the appointment of PricewaterhouseCoopers LLP for the year ending December 31, 2006.

For	39,547,818
Against	367,248
Abstained	13,400

Subsequently, the Audit Committee engaged KPMG LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 and dismissed PricewaterhouseCoopers LLP, our previous independent registered public accounting firm.

3. To approve the amendment to our Certificate of Incorporation to increase the number of authorized shares of our common stock from 50,000,000 to 90,000,000.

For	37,380,671
Against	2,468,743
Abstained	79,050

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

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

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

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

SIGNATURES

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