Brigham Exploration (BEXP) 10-Q 2006 Q1 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 March 31, 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 xNo ¨

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 x 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 x

At May 3, 2006, 45,478,308 shares of the Registrant’s Common Stock were outstanding.

Brigham Exploration Company

First Quarter 2006 Form 10-Q Report

TABLE OF CONTENTS

		Page
PART I - FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance Sheets - March 31, 2006 and December 31, 2005	1
	Consolidated Statements of Operations - Three months ended March 31, 2006 and 2005	2
	Consolidated Statement of Changes in Stockholders’ Equity - Three months ended March 31, 2006	3
	Consolidated Statements of Cash Flows - Three months ended March 31, 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	14
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
ITEM 4.	CONTROLS AND PROCEDURES	33
PART II - OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	33
ITEM 1A.	RISK FACTORS	33
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
ITEM 3.	DEFALTS UPON SENIOR SECURITIES	39
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	39
ITEM 5.	OTHER INFORMATION	39
ITEM 6.	EXHIBITS	39
SIGNATURES		41

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	March 31,			December 31,
	2006			2005
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	7,753		$	3,975
Accounts receivable		16,714			22,825
Deferred income taxes		—			482
Other current assets		3,792			1,043
Total current assets		28,259			28,325
Oil and natural gas properties, net (full cost method)		377,214			347,329
Other property and equipment, net		1,011			1,027
Deferred loan fees		2,055			2,174
Other noncurrent assets		1,445			1,572
Total assets	$	409,984		$	380,427
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	13,783		$	12,128
Royalties payable		5,984			6,886
Accrued drilling costs		18,458			12,218
Participant advances received		1,919			2,116
Deferred income taxes		746			—
Other current liabilities		2,474			4,119
Total current liabilities		43,364			37,467
Senior credit facility		44,300			33,100
Senior subordinated notes		30,000			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 March 31, 2006 December 31, 2005		10,101			10,101
Deferred income taxes		27,115			23,563
Other noncurrent liabilities		4,678			4,556
Commitments and contingencies (Note 3)
Stockholders' equity:
Common stock, $.01 par value, 50 million shares authorized, 45,006,968 and 44,917,768 shares issued and 44,989,000 and 44,917,768 shares outstanding at March 31, 2006 and December 31, 2005, respectively		450			449
Additional paid-in capital		200,592			202,127
Treasury stock, at cost; 17,968 shares at March 31, 2006		(211	)		—
Unearned stock compensation		—			(2,299	)
Accumulated other comprehensive income (loss)		1,931			(426	)
Retained earnings		47,664			41,789
Total stockholders’ equity		250,426			241,640
Total liabilities and stockholders' equity	$	409,984		$	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
	March 31,
	2006			2005
Revenues:
Oil and natural gas sales	$	25,796		$	16,703
Other revenue		(22	)		43
		25,774			16,746
Costs and expenses:
Lease operating		2,730			2,218
Production taxes		1,144			802
General and administrative		1,642			1,098
Depletion of oil and natural gas properties		10,256			6,453
Depreciation and amortization		242			182
Accretion of discount on asset retirement obligations		70			39
		16,084			10,792
Operating income		9,690			5,954
Other income (expense):
Interest income		106			39
Interest expense, net		(1,089	)		(741	)
Other income (expense)		679			(531	)
		(304	)		(1,233	)
Income before income taxes		9,386			4,721
Income tax expense:
Current		—			—
Deferred		(3,511	)		(1,673	)
		(3,511	)		(1,673	)
Net income	$	5,875		$	3,048
Net income per share available to common stockholders:
Basic	$	0.13		$	0.07
Diluted	$	0.13		$	0.07
Weighted average shares outstanding:
Basic		44,986			42,124
Diluted		45,579			43,166

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

2

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

(Unaudited)

	Common Stock
	Shares		Amounts		Additional Paid In Capital			Treasury Stock			Unearned Stock Compensation			Accumulated Other Comprehensive Income (Loss)			Retained Earnings		Total Stockholders' Equity
Balance, December 31, 2005		44,918	$	449	$	202,127		$	—		$	(2,299	)	$	(426	)	$	41,789	$	241,640
Comprehensive income:
Net income		—		—		—			—			—			—			5,875		5,875
Unrealized gain (losses) on cash flow hedges		—		—		—			—			—			4,461			—		4,461
Tax benefits (provisions) related to cash flow hedges		—		—		—			—			—			(1,269	)		—		(1,269	)
Reclassification adjust- ments for settled hedging positions		—		—		—			—			—			(835	)		—		(835	)
Comprehensive income																				8,232
Adoption of SFAS No. 123R		—		—		(2,299	)		—			2,299			—			—		—
Exercises of employee stock options		24		—		153			—			—			—			—		153
Vesting of restricted stock		65		1		(1	)		—			—			—			—		—
Stock based compensation		—		—		364			—			—			—			—		364
Repurchases of common stock		—		—		—			(211	)		—			—			—		(211	)
Amortization of unearned stock compensation		—		—		248			—			—			—			—		248
Balance, March 31, 2006		45,007	$	450	$	200,592		$	(211	)	$	—		$	1,931		$	47,664	$	250,426

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

3

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2006			2005
Cash flows from operating activities:
Net income	$	5,875		$	3,048
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		10,256			6,453
Depreciation and amortization		242			182
Interest paid through issuance of additional mandatorily redeemable preferred stock		—			188
Stock based compensation		364			—
Amortization of deferred loan fees and debt issuance costs		119			126
Market value adjustment for derivative instruments		(715	)		606
Accretion of discount on asset retirement obligations		70			39
Deferred income taxes		3,511			1,673
Other noncash items		42			12
Changes in assets and liabilities:
Accounts receivable		6,111			812
Other current assets		(336	)		85
Accounts payable		1,655			(4,616	)
Royalties payable		(902	)		(1,630	)
Participant advances received		(197	)		(949	)
Other current liabilities		147			226
Other noncurrent assets and liabilities		(54	)		(11	)
Net cash provided by operating activities		26,188			6,244
Cash flows from investing activities:
Additions to oil and natural gas properties		(33,674	)		(20,738	)
Additions to other property and equipment		(142	)		(65	)
(Increase) Decrease in drilling advances paid		324			159
Net cash used by investing activities		(33,492	)		(20,644	)
Cash flows from financing activities:
Increase in senior credit facility		14,500			17,100
Repayment of senior credit facility		(3,300	)		—
Deferred equity costs and loan fees paid		(60	)		(401	)
Proceeds from exercise of employee stock options		153			251
Repurchases of common stock		(211	)		(190	)
Net cash provided by financing activities		11,082			16,760
Net increase in cash and cash equivalents		3,778			2,360
Cash and cash equivalents, beginning of year		3,975			2,281
Cash and cash equivalents, end of period	$	7,753		$	4,641

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

4

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Nature of Operations

Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the “Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as “Brigham.” Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in the onshore 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 7. 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 March 31, 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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2006 and 2005 are as follows (in thousands):

	Three Months Ended March 31,
	2006		2005
Weighted average common shares outstanding - basic		44,986		42,124
Plus: Potential common shares
Stock options and restricted stock		593		1,042
Weighted average common shares outstanding - diluted		45,579		43,166
Stock options excluded from diluted EPS due to the anti-dilutive effect		1,246		718

5. 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.

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 month periods ended March 31, 2006 and 2005:

	Three Months Ended March 31,
	2006			2005
Natural Gas
Average price per Mcf as reported (including hedging results)	$	7.38		$	5.80
Average price per Mcf realized (excluding hedging results)	$	7.33		$	5.80
Increase (decrease) in revenue (in thousands)	$	131		$	(10	)
Oil
Average price per Bbl as reported (including hedging results)	$	61.03		$	43.74
Average price per Bbl realized (excluding hedging results)	$	61.46		$	48.33
Increase (decrease) in revenue (in thousands)	$	(50	)	$	(541	)

Ineffectiveness associated with Brigham's derivative commodity instruments designated as cash flow hedges is included in other income (expense). The following table provides a summary of the impact on earnings from ineffectiveness (in thousands):

	Three Months Ended March 31,
	2006		2005
Increase (decrease) in earnings due to ineffectiveness	$	835	$	(616	)

Natural Gas and Crude Oil Derivative Contracts

Cash-flow hedges

Brigham's cash-flow hedges consisted of costless collars (purchased put options and written call options). The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums received when Brigham entered into these option agreements.

6

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Derivative positions included written put options that are not designated as hedges and are reflected at fair value on the balance sheet. These positions were entered into in conjunction with a costless collar to offset the cost of other option positions that are designated as hedges. At each balance sheet date, the value of derivative contracts not designated as cash flow hedges is adjusted to reflect current fair value and any gains or losses are recognized as other income (expense). The following table provides a summary of the fair value of these derivatives included in other current liabilities (in thousands):

	March 31, 2006			December 31, 2005
Fair value of undesignated derivatives	$	(244	)	$	(125	)

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 (in thousands):

	Three Months Ended March 31,
	2006			2005
Increase (decrease) in earnings due to changes in fair value of undesignated derivatives	$	(120	)	$	10

The following table reflects open commodity derivative contracts at March 31, 2006, the associated volumes and the corresponding weighted average NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
04/01/06 - 06/30/06		Purchased put		Cash flow				16,500	$	54.80
		Written call		Cash flow				16,500		75.00
04/01/06 - 07/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				15.60
04/01/06 - 07/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				17.00
04/01/06 - 09/30/06		Purchased put		Cash flow				42,000	$	50.00
		Written call		Cash flow				42,000		75.60
04/01/06 - 10/30/06		Purchased put		Cash flow		490,000			$	8.00
		Written call		Cash flow		490,000				14.85
08/01/06 - 10/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				16.65
10/01/06 - 12/31/06		Purchased put		Cash flow				27,000	$	50.00
		Written call		Cash flow				27,000		77.50
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
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

7

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Three Way Costless Collars
04/01/06 - 06/30/06		Purchased put		Cash flow				7,500	$	63.00
		Written call		Cash flow				7,500		75.25
		Written put		Undesignated				7,500		48.00
04/01/06 - 10/31/06		Purchased put		Cash flow		420,000			$	7.50
		Written call		Cash flow		420,000				9.15
		Written put		Undesignated		420,000				6.25
04/01/06 - 10/31/06		Purchased put		Cash flow		490,000			$	8.50
		Written call		Cash flow		490,000				9.96
		Written put		Undesignated		490,000				7.00
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

The following table reflects commodity derivative contracts entered subsequent to March 31, 2006, the associated volumes and the corresponding weighted average NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		Gas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
04/01/07 - 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
10/01/07 - 03/31/08		Purchased put		Cash flow				18,000	$	56.00
		Written call		Cash flow				18,000		89.95

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 to fixed 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 with an investment grade credit rating 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 matures in March 2009. As of March 31, 2006 and 2005, approximately $847,000 and $481,000, respectively, of unrealized gains are included in accumulated other comprehensive income (loss) on the balance sheet which represents the fair value of the interest rate swap agreement as of that date. The fair value of the interest rate swap contract is based on quoted market prices and third-party provided calculations, which reflect the present values of the difference between estimated future variable-rate receipts and future fixed-rate payments. See Note 9 for a discussion of subsequent events.

8

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

	March 31, 2006			December 31, 2005
Other current liabilities	$	(200	)	$	(2,112	)
Other noncurrent liabilities		(61	)		(61	)
Other current assets		2,577			224
Other noncurrent assets		850			654
Net fair value of derivative contracts designated as cash-flow hedges	$	3,166		$	(1,295	)

6. 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 three months ended March 31, 2006 and 2005 (in thousands):

	Three Months Ended March 31,
	2006			2005
Beginning asset retirement obligations	$	4,389		$	2,896
Liabilities incurred for new wells placed on production		105			26
Liabilities settled		(44	)		—
Accretion of discount on asset retirement obligations		70			39
	$	4,520		$	2,961

7. 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.

9

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Brigham adopted SFAS 123R using the modified prospective method. Under this transition method, compensation cost recognized in the first quarter 2006 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). There were no options issued in the first quarter of 2005. The following table summarizes the assumptions used in the 2006 Black-Scholes model:

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

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

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

Prior to the adoption of SFAS 123R, Brigham presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Brigham did not have any excess tax benefits during the first quarter 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 (loss) and net income (loss) per share for the three month period ended March 31, 2005 would have been the pro forma amounts indicated below (in thousands, except per share amounts):

10

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Three Months Ended March 31,2005
Net income, as reported	$	3,048
Add back: Stock compensation expense previously included in net income		111
Effect of total employee stock-based compensation expense, determined under fair value method for all awards		(361	)
Pro forma	$	2,798
Net income per share:
Basic, as reported	$	0.07
Basic, pro forma		0.07
Diluted, as reported	$	0.07
Diluted, pro forma		0.06

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 March 31,
	2006			2005
Pre-tax stock based compensation expense	$	613		$	168
Capitalized stock based compensation		(305	)		(81	)
Tax benefit		(108	)		(30	)
Stock based compensation expense, net	$	200		$	57

The adoption of SFAS 123R did not impact basic and diluted net income per share for the three months ended March 31, 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. As amended by stockholder resolution, 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 March 31, 2006, approximately 900,000 shares remain available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one stock option grant, options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham’s common stock on the date of grant, vest over five years and have a contractual life of seven years.

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

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BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table summarizes option activity under the incentive plans for the three months ended March 31, 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		(111,067	)	$	2.46
Exercised		(24,200	)	$	6.30
Options outstanding at March 31, 2006		2,831,066		$	7.16		4.6 years	$	5,761
Options exercisable at March 31, 2006		970,933		$	5.64		3.8 years	$	3,041

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 first 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 March 31, 2006. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of March 31, 2006 there was approximately $5.6 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 4.6 years.

The total intrinsic value of options exercised during the three months ended March 31, 2006 and 2005, was $158,000 and $421,000, respectively.

Restricted Stock

During the three months ended March 31, 2006, Brigham issued 129,095 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 three months ended March 31, 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 three months ended March 31:

	Number of Shares			Weighted- Average Price
Restricted Stock Awards:
Restricted shares outstanding at the beginning of the year		397,650		$	7.22
Shares granted		129,095		$	10.85
Lapse of restrictions		(65,000	)	$	5.23
Forfeitures		(1,000	)	$	12.31
Restricted shares outstanding at March 31,2006		460,745		$	8.64

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BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8. Comprehensive Income

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

	Three Months Ended March 31,
	2006			2005
Net income	$	5,875		$	3,048
Unrealized gains (losses) on cash flow hedges		4,461			(609	)
Tax benefits (provisions) related to cash flow hedges		(1,269	)		(3	)
Reclassification adjustments for settled hedging positions		(835	)		616
Stock based compensation expense, net	$	8,232		$	3,052

9. Subsequent Events

During April 2006, Brigham sold $125 million of 9 5/8% Senior Notes due 2014 in a private placement. The Notes were priced at 98.629% of their face value to yield 9 7/8%. The Notes are fully and unconditionally guaranteed by certain of Brigham’s subsidiaries. Brigham used the net proceeds from the 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. The remaining funds will be used to fund exploration and development activities and for general corporate purposes. Subsequent to this repayment, Brigham terminated the subordinated credit agreement and the associated interest rate swap designated as a cash flow hedge.

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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 period ended March 31, 2006, and the comparable period 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.

Overview of First Quarter 2006

The price of natural gas during the first three months of 2006 remained relatively high compared to historical prices due to forecasts for continued U.S. production declines, seasonal weather, increasing natural gas demand and similarly high crude oil prices, which limit fuel-switching flexibility. The average sales price, excluding hedging results, that we received for our natural gas in the first three months of 2006 was $7.33 per Mcf. This represents an increase of 26% over the price we received in first quarter of 2005. Likewise, the average sales price that we received for oil in the first three months of 2006 was $61.46 and 27% higher than the price we received in the first quarter last year.

For the quarter ended March 31, 2006, we spent $40.1 million in net capital expenditures on oil and natural gas activities. Our production for the first quarter 2006 was 35.9 MMcfe/d compared to 30 MMcfe/d in the first quarter last year. This increase was primarily due to production from our new wells that came on line during the last three quarters of 2005 and the first quarter of 2006. This increase was partially offset by the natural decline in our production from wells that began producing prior to the second quarter of 2005.

Net income for the first quarter 2006 was $5.9 million, or $0.13 per diluted share, on total revenues of $25.8 million. This compares to reported net income of $3 million, or $0.07 per diluted share on revenue of $16.7 million in the first quarter last year. An increase in our production combined with an increase in the average realized price we received for our production were the primary reasons for the increase in our net income for the first quarter of 2006. These increases were partially offset by increases in our production costs, general and administrative expenses, depletion expense, net interest expense and deferred income tax expense.

For the first quarter 2006, net cash provided by operating activities funded approximately 78% of our cash used by investing activities and we borrowed an additional $11.2 million of debt, net of repayments, under our senior credit agreement. This compares to net cash provided by operating activities funding 30% of our cash used by investing activities and borrowing an additional $17.1 million of debt, net of repayments, under our senior credit agreement in first quarter last year.

At March 31, 2006, we had $7.8 million in cash, total assets of $410 million and a debt to book capitalization ratio of 25%.

Subsequent Events

In April 2006, we issued and sold $125 million of 9 5/8% Senior Notes due 2014. We used the net proceeds from this offering to repay $48.4 million in borrowings that were outstanding under our senior credit agreement and to repay $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. The remaining net proceeds will be used to fund our exploration and development activities and for general corporate purposes.

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Capital Commitments

Capital Expenditures

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

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

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

· cost of installing new production infrastructure;

· cost of 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 budgeted capital expenditures, the amount spent through March 31, 2006 and the amount of our 2006 budget that remains to be spent.

	2006 Budget		Amount Spent Through 03/31/2006		Amount Remaining (1)
	(In thousands)
Drilling	$	120,467	$	30,807	$	89,660
Net land and seismic		28,597		7,172		21,425
Capitalized costs (2)		7,259		2,162		5,097
Other assets		559		142		417
Total	$	156,882	$	40,283	$	116,599

____________

(1) Calculated as the amount budgeted for 2006 less amount spent through March 31, 2006.

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

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

For 2006, we currently plan to spend approximately $47 million, or 30% of our total planned capital expenditures to drill 21 exploratory wells with an average working interest of 61% and to drill and complete exploration wells that were in progress at December 31, 2005. We believe that we possess a multi-year inventory of exploratory drilling prospects, the majority of which have been internally generated by our staff. As a consequence and considering the results that we have achieved in recent years, we expect that we will continue to emphasize our prospect generation and drilling strategy as our primary means of creating value for our stockholders.

Due to our exploratory drilling success, over the last five years, a growing percentage of our capital expenditures have been allocated to the development of past field discoveries. For 2006, we currently plan to spend approximately $73.4 million, or 47% of our total planned capital expenditures on development drilling activities, which will include the drilling of 22 development wells with an average working interest of 56% and completing development wells that were in progress at December 31, 2005. We currently plan to allocate approximately $56.4 million of this capital to develop our reserves that were proved undeveloped at December 31, 2005.

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To support our prospect generation activities, we allocate a portion of our capital expenditures to land and seismic. For 2006, we expect to spend approximately $28.6 million or 18% of our planned capital expenditures on land and seismic activities.

Additionally, we currently plan to capitalize approximately $7.3 million of our forecasted general and administrative cost and interest expense in 2006.

The final determination with respect to our 2006 budgeted expenditures will depend on a number of factors, including:

· commodity prices;

· production from our existing producing wells;

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

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

· the availability of more economically attractive prospects.

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

9 5/8% Senior Notes due 2014

In April 2006, we issued and sold $125 million of 9 5/8% Senior Notes due 2014 (the “Notes”). The Notes were priced at 98.629% of their face value to yield 9 7/8%, and are fully and unconditionally guaranteed by us and our wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P.(the “Guarantors”). We entered into an Indenture (the “Indenture”), among us, the Guarantors and Wells Fargo Bank, N.A., as trustee (the “Trustee”) relating to the Notes.

The Notes were issued pursuant to the Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”). The Notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act, and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act. The initial purchasers purchased the Notes at a discount equal to 1.625% of the principal amount of the Notes.

We are obligated to pay the $125 million aggregate principal amount of the 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 Notes, payable semi-annually in arrears in May and November of each year.

After the Notes offering closed, we used $78.4 million of the net proceeds from the sale to repay all borrowings outstanding under our senior and subordinated credit agreements. Subsequent to this repayment, we terminated our subordinated credit agreement and the associated interest rate swap designated as a cash flow hedge.

The Notes are our unsecured senior obligations, and will:

· 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.

Except as set forth below, we will not be entitled to redeem the Notes prior to May 1, 2010. Starting in May 2010, we will be entitled to redeem all or a portion of the Notes at the redemption prices, plus accrued interest to the redemption date, if redeemed during the 12-month period commencing in May of the years set forth below:

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Period	Redemption Price
2010		104.813	%
20112011		102.406	%
2012 and thereafter		100.000	%

At any time prior to May 2009, we may use the net proceeds from one or more equity offerings to redeem up to an aggregate of 35% of the aggregate principal amount of the Notes issued under the Indenture (including the principal amount of any additional Notes issued under the Indenture) at a redemption price of 109.625% of the principal amount of the Notes plus any accrued and unpaid interest, if any, to the redemption date, subject to certain conditions.

If we experience a change of control, we will be required to make an offer to repurchase the Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase.

The Indenture contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the Notes may declare all outstanding Notes to be due and payable immediately. Additionally, the Indenture restricts our ability and the ability of our restricted subsidiaries to:

· incur additional debt;

· pay dividends on, or redeem or repurchase stock;

· create liens;

· make specified types of investments;

· apply net proceeds from certain asset sales;

· engage in transactions with our affiliates;

· engage in sale and leaseback transactions;

· restrict dividends or other payment from subsidiaries;

· merge or consolidate;

· sell equity interests of subsidiaries; and

· sell, assign, transfer, lease, convey or dispose of assets.

These covenants are subject to a number of important exceptions and qualifications.

Senior Credit Agreement

As of March 31, 2006, we had $44.3 million in borrowings outstanding under our senior credit agreement. Total borrowings under our senior credit agreement increased by $11.2 million during the first quarter of 2006. The total borrowing base available to us during the first quarter of this year was $90 million compared to $68.5 million during the first quarter last year. During the first quarter 2006, we utilized approximately 46% of our available borrowing base, compared to 47% in the first quarter last year.

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 March 31, 2006 and interest coverage ratio for the twelve-month period ended March 31, 2006, were 1.9 to 1 and 20.6 to 1, respectively. As of March 31, 2006, and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our senior credit agreement.

In April 2006, in connection with our sale of our 9 5/8% Senior Notes due 2014, we amended our senior credit agreement to reset the borrowing base to $50 million. We used the net proceeds from this offering to repay $48.4 million in borrowings that were outstanding under our senior credit agreement at the close of the Notes offering. At May 3, 2006, we had no borrowings outstanding under our senior credit agreement.

Senior Subordinated Notes

As of March 31, 2006, we had $30 million outstanding under our subordinated credit agreement. Pursuant to our subordinated credit agreement, we were 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 March 31, 2006 and interest coverage ratio for the twelve-month period ended March 31, 2006 were 1.9 to 1 and 20.6 to 1, respectively. At March 31, 2006 and for the twelve-month period then ended, we were in compliance with all covenant requirements in connection with our subordinated credit agreement.

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In April 2006, we used a portion of the net proceeds from our sale of our 9 5/8% Senior Notes due 2014 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 March 31, 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.

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.

Capital Resources

In 2006, we intend to fund our capital expenditure program and contractual commitments with cash flows from operations, the net proceeds remaining from the sale of our 9 5/8% Senior Notes due 2014 after repaying the borrowings outstanding under our senior and subordinated credit agreements, borrowings under our senior credit agreement, and if required, alternative financing sources. Our primary sources of cash during the first quarter of 2006 were funds generated by operations and borrowings under our senior credit agreement. We made aggregate cash payments of $1.2 million for interest in the first quarter of 2006.

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 derivative contracts, operating cost 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. Net cash provided by operating activities during the first quarter 2006 funded 78% of our net cash used by investing activities compared to 30% in the first quarter of 2005.

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. The amount that we can borrow under our senior credit agreement is limited by a borrowing base, which was reset to $50 million in connection with the Notes offering. Our senior credit agreement also permits letters of credit up to the lesser of $10 million or the unused committed borrowing base. Issuances of letters of credit reduce the amount of borrowings available to us under our senior credit agreement. As of March 31, 2006, we had $45.7 million of unused committed borrowing capacity available to us under our senior credit agreement.

In April 2006, $48.4 million of the net proceeds from the Notes offering was used to repay all outstanding borrowings under our senior credit agreement. As of May 3, 2006, we had $50 million of unused committed borrowing capacity available to us under our senior credit agreement.

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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.

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

As of March 31, 2006, we had $10 million of borrowing capacity available to us under our subordinated credit agreement. In April 2006, we used $30 million of the net proceeds from the Notes offering to repay all outstanding borrowings under our subordinated credit agreement, which was terminated thereafter.

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

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 has yet to be declared effective by the SEC.

Results of Operations

Comparison of the three-month periods ended March 31, 2006 and 2005.

Production volumes

	Three Months Ended March 31,
	2006		% Change		2005
Oil (MBbls)		115		(3%)		118
Natural gas (MMcf)		2,545		28%		1,994
Total (MMcfe)(1)		3,235		20%		2,700
Average daily production (MMcfe/d)		35.9				30.0

____________

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

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Our net equivalent production volumes for the first quarter of 2006 were 3.2 Bcfe (35.9 MMcfe/d) compared to 2.7 Bcfe (30 MMcfe/d) in the first quarter of 2005. This increase was primarily due to production from our new wells that came on line during the last three quarters of 2005 and the first quarter of 2006. This increase was partially offset by the natural decline in our production from wells that began producing prior to the second quarter of 2005.

Natural gas represented 79% of our first quarter 2006 production volumes compared to 74% in the first quarter of last year.

Hedging, commodity prices and revenues

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 March 31,
	2006			% Change		2005
Oil swaps
Volumes (Bbls)		—			0%		—
Average swap price ($ per Bbl)	$	—			0%	$	—
Gain /(loss) upon settlement ($ in thousands)	$	—			0%	$	—
Oil collars
Volumes (Bbls)		25,500			(7%)		27,450
Average floor price ($ per Bbl)	$	52.12			104%	$	25.56
Average ceiling price ($ per Bbl)	$	64.76			115%	$	30.18
Gain /(loss) upon settlement ($ in thousands)	$	(50	)		(91%)	$	(541	)
Total oil
Volumes (Bbls)		25,500			(7%)		27,450
Gain /(loss) upon settlement ($ in thousands)	$	(50	)		(91%)	$	(541	)
Natural gas swaps
Volumes (MMbtu)		—			0%		—
Average swap price ($ per MMbtu)	$	—			0%	$	—
Gain /(loss) upon settlement ($ in thousands)	$	—			0%	$	—
Natural gas collars
Volumes (MMbtu)		600,000			(18%)		727,500
Average floor price ($ per MMbtu)	$	8.49			65%	$	5.16
Average ceiling price ($ per MMbtu)	$	10.84			49%	$	7.26
Gain /(loss) upon settlement ($ in thousands)	$	131			NM	$	(10	)
Total natural gas
Volumes (MMbtu)		600,000			(18%)		727,500
Gain /(loss) upon settlement ($ in thousands)	$	131			NM	$	(10	)

Reported revenues from the sale of oil and natural gas are 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 effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans.

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

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

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Commodity prices and revenues

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

	Three months ended March 31,
	2006			% Change		2005
	(In thousands, except per unit measurements)
Revenue from the sale of oil and natural gas:
Oil sales	$	7,068			24%	$	5,689
Gain (loss) due to hedging		(50	)		(91%)		(541	)
Total revenue from the sale of oil	$	7,018			36%	$	5,148
Natural gas sales	$	18,647			61%	$	11,565
Gain (loss) due to hedging		131			NM		(10	)
Total revenue from the sale of natural gas	$	18,778			63%	$	11,555
Oil and natural gas sales	$	25,715			49%	$	17,254
Gain (loss) due to hedging		81			NM		(551	)
Total revenue from the sale of oil and natural gas	$	25,796			54%	$	16,703
Average prices:
Oil sales price (per Bbl)	$	61.46			27%	$	48.33
Gain (loss) due to hedging (per Bbl)		(0.43	)		(91%)		(4.59	)
Realized oil price (per Bbl)	$	61.03			40%	$	43.74
Natural gas sales price (per Mcf)	$	7.33			26%	$	5.80
Gain (loss) due to hedging (per Mcf)		0.05			NM		(0.00	)
Realized natural gas price (per Mcf)	$	7.38			27%	$	5.80
Natural gas equivalent sales price (per Mcfe)	$	7.95			24%	$	6.39
Gain (loss) due to hedging (per Mcfe)		0.02			NM		(0.20	)
Realized natural gas equivalent (per Mcfe)	$	7.97			29%	$	6.19

	2006 to 2005
Change in revenue from the sale of oil
Price variance impact	$	1,510
Volume variance impact		(131	)
Cash settlement of hedging contracts		491
Total change	$	1,870
Change in revenue from the sale of natural gas
Price variance impact	$	3,886
Volume variance impact		3,196
Cash settlement of hedging contracts		141
Total change	$	7,223

Our revenues from the sale of oil and natural gas for the first quarter of 2006 increased by 54% when compared to revenues in first quarter of 2005. The change in revenues was due to the following:

· An increase in production volumes for the quarter resulted in a $3.1 million increase in oil and natural gas sales;

· A 24% increase in the sales price we received for our oil and natural gas resulted in a $5.4 million increase in revenues from oil and natural gas sales; and,

· An $81,000 gain from the cash settlement of derivative contracts in the first quarter of 2006 versus a $551,000 loss last year led to $632,000 increase in our revenue from the sale of oil and natural gas in the first quarter 2006 when compared to 2005.

Other revenue. Other revenue relates to fees that we charge other parties who use our gas gathering systems that we own to move their production from the wellhead to third party gas pipeline systems. Other revenue for the first quarter of 2006 decreased by $65,000 when compared to the first quarter last year. The primary reason for the decrease in other income was due to the reprocessing of claims for our gas gathering systems in several wells in the Bayou Bengal project. This reprocessing had a negative impact on other income of approximately $59,000. Costs related to our gas gathering systems are recorded in lease operating expenses.

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Operating costs and expenses

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

	Three months ended March 31,
	2006		% Change		2005
	(In thousands, except per unit measurements)
Production cost:
Operating & maintenance	$	2,098		48%	$	1,422
Expensed workovers		125		(76%)		524
Ad valorem taxes		507		86%		272
Total lease operating expenses	$	2,730		23%	$	2,218
Production taxes		1,144		43%		802
Production costs	$	3,874		28%	$	3,020
Production cost ($ per Mcfe):
Operating & maintenance	$	0.65		23%	$	0.53
Expensed workovers		0.04		(79%)		0.19
Ad valorem taxes		0.15		50%		0.10
Total lease operating expenses	$	0.84		2%	$	0.82
Production taxes		0.35		17%		0.30
Production costs	$	1.19		6%	$	1.12

Our first quarter 2006 production costs increased by 28% when compared to production costs in the first quarter of 2005. One of the reasons for the overall increase in our period to period production costs has been due to an increase in our number of producing wells. In the future we anticipate that our production costs will continue to increase as we add new wells and production facilities and continue to maintain production from existing maturing properties. Changes in commodity prices will also have an affect on ad valorem taxes and production taxes.

Our operating and maintenance (O&M) expenses for first quarter 2006 were up 48% when compared to the same period of 2005. The following were the primary reasons for the increase in our first quarter 2006 O&M expenses versus those in the first quarter of 2005.

· O&M expenses include $442,000 of costs associated with new wells that began producing subsequent to the first quarter 2005.

· Actual O&M expenses recognized in the first quarter 2006 were $319,000 higher than were originally estimated for the fourth quarter at year end 2005 and represents 32% of the increase from the first quarter 2006 compared to first quarter 2005.

Our higher O&M expenses for the first quarter 2006 were offset by a 76% decline in workover cost during the quarter versus the first quarter of 2005.

Our ad valorem tax expense for the first quarter 2006 was up 86% when compared to the first quarter of 2005 due to an estimated increase in property valuations due to higher commodity prices.

Our production tax expenses for the first quarter 2006 were up 43% when compared to the first quarter last year. The following were the primary reasons for the increase in our first quarter 2006 production tax expense when compared to the first quarter last year.

· An increase in both production and commodity prices both resulted in higher production taxes.

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· This increase was partially offset by tax credits from 16 high cost gas wells in the first quarter 2006. Our effective production tax rate for the first quarter 2006 was 4.4% of our pre-hedge revenue from the sale of oil and natural gas, compared to 4.6% in 2005.

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

For the first quarter 2006, our unit production cost increased 6% when compared to the first quarter of last year. The following were the primary reasons for the increase in our first quarter 2006 production costs over the first quarter last year.

· Of the total $0.65 of per unit O&M expense for the first quarter 2006, approximately $0.14 per Mcfe was associated with new wells that began producing subsequent to the first quarter of 2005.

· Ad valorem taxes increased due to an increase in estimated property valuations for our oil and natural gas properties due to higher commodity prices.

· Production taxes were $0.05 higher per Mcfe due to higher commodity prices and the resulting higher pre-hedge revenue from the sale of oil and natural gas.

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

	Three months ended March 31,
	2006			% Change		2005
	(In thousands, except per unit measurements)
General and administrative cost	$	3,167			38%	$	2,303
Capitalized general and administrative cost		(1,525	)		27%		(1,205	)
General and administrative expense	$	1,642			50%	$	1,098
General and administrative expense ($ per Mcfe)	$	0.51			24%	$	0.41

For the first quarter of 2006, our general and administrative expenses increased by 50%.The following were the primary factors that led to the changes in to our first quarter 2006 general and administrative expenses:

· Increases in employee compensation and benefit costs represented approximately 69% of the increase in our general and administrative cost. Our employee compensation and benefit cost included a $364,000 non-cash charge associated with our adoption of FAS 123R during the first quarter of 2006.

· Increases in fees paid for contract and professional services, which include our audit and tax fees, represent approximately 23% of the increase in our general and administrative costs.

· These increases were partially offset by decreases in costs for employee training and continuing education, employee rental and maintenance and an increase in the amount of general and administrative cost that we capitalized.

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.

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	Three months ended March 31,
	2006		% Change		2005
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	10,256		59%	$	6,453
Depletion of oil and natural gas properties per Mcfe	$	3.17		33%	$	2.39

Our depletion expense for the first quarter 2006 was 59% higher than 2005. Approximately $2.5 million of the increase in our depletion expense was due to an increase in our depletion rate while the remaining $1.3 million was due to an increase in production volumes.

Net interest expense. The interest that we pay on outstanding borrowings under both our senior and subordinated credit agreements combined with dividends that we pay on our Series A mandatorily redeemable preferred stock represent the largest portion of our interest costs. Our interest costs also include the commitment fees that we pay on the unused portion of the borrowing base for our senior credit agreement and on the unused portion of our subordinated credit agreement. We typically pay loan and debt issuance costs when we enter into new lending agreements or amend existing agreements. When incurred, these costs are recorded as non-current assets and are then amortized over the life of the loan. We capitalize interest costs on borrowings associated with our major capital projects prior to their completion. This capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.

	Three months ended March 31,
	2006			% Change		2005
	(In thousands)
Interest on senior credit agreement	$	601			86%	$	323
Interest on senior subordinated notes (1)		578			53%		378
Commitment fees		48			26%		38
Dividend on mandatorily redeemable preferred stock		149			(21%)		188
Amortization of deferred loan and debt issuance cost		119			(6%)		126
Other general interest expense		3			0%		3
Capitalized interest expense		(409	)		30%		(315	)
Net interest expense	$	1,089			47%	$	741
Weighted average debt outstanding	$	81,594			33%	$	61,505
Average interest rate on outstanding indebtedness (2)		6.8	%				6.1	%

__________

(1) Includes the effects of interest rate swaps.

(2) 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.

Our net interest expense for the first quarter was 47% higher than the same period in 2005. The following were the primary reasons for the increase in our first quarter 2006 net interest expense when compared to the first three months of 2005.

· Interest expense and fees related to our senior credit agreement in the first quarter 2006 were 64% higher than in the first quarter 2005. During the first quarter 2006, we paid $278,000 more interest on amounts borrowed under our senior credit agreement than we did in the first three months of 2005. The primary reason for this was an increase in the Eurodollar rate combined with an increase in the weighted average amount we borrowed under our senior credit agreement during the first quarter 2006. This increase was partially offset by a decrease in the commitment fees we paid on the unused portion of the available borrowing base. Our weighted average debt outstanding under our senior credit agreement during the first three months of 2006 represented approximately 46% of our weighted average borrowing base available to us during the period, compared to 47% in the same period of 2005.

· Interest expense and fees related to our subordinated credit agreement in the first quarter 2006 were 48% higher than the first quarter of 2005. During the first three months of 2006, we paid $200,000 more interest on the amounts we borrowed under our subordinated credit agreement than we did in the first three months of 2005. The primary reason for this was an increase in the weighted average debt outstanding under our subordinated credit agreement during the first three months of 2006.

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· Dividends that we paid on our mandatorily redeemable preferred stock in the first quarter 2006 were 21% lower than the first quarter of 2005 due to a 2% decrease in our dividend rate. Our dividend rate for the first quarter of 2006 was 6% compared to 8% in the last year’s first quarter.

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

Other income (expense) included:

	Three months ended March 31,
	2006			% Change		2005
	(In thousands)
Non-cash gain (loss) due to change in fair market value of derivative contracts not designated as cash flow hedges	$	(120	)		NM	$	10
Non-cash gain (loss) for ineffective portion of cash flow hedges		835			NM		(616	)
Gain (loss) on settlement of derivative contracts not designated as cash flow hedges		(108	)		NM		—
Gain (loss) on disposal of assets		(42	)		250%		(12	)
Other		114			31%		87
Other income (loss)	$	679			NM	$	(531	)

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 March 31,
	2006			% Change		2005
Written puts
Oil
Volumes (MMbtu)		18,000			NM		—
Average price ($ per MMbtu)	$	38.00			NM	$	—
Gain /(loss) upon settlement ($ in thousands)	$	—			NM	$	—
Natural Gas
Volumes (MMbtu)		600,000			186%		210,000
Average price ($ per MMbtu)	$	7.05			28%	$	5.50
Gain /(loss) upon settlement ($ in thousands)	$	(108	)		NM	$	—

Income taxes. A deferred tax liability or asset is recognized for the estimated future tax effects attributable to (i) NOLs and (ii) existing temporary differences between book and taxable income. Realization of net deferred tax assets is dependent upon generating sufficient taxable income within the carryforward period available under tax law.

In the first three months of 2006, we recognized a current period net deferred tax liability of $4.8 million due to reversals of our existing temporary differences between book and taxable income resulting mainly from our capital expenditures. The $4.8 million consisted of $3.5 million in deferred income tax expense and a $1.3 million tax effect of unrealized hedging gains. The primary reason for the difference between our effective tax rate of 37.4% and the federal statutory rate of 35% was due to the effects of nondeductible preferred stock dividends and compensation expense associated with unexercised incentive stock options.

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Analysis of Changes In Cash and Cash Equivalents

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

	Three months ended March 31,
	2006			% Change		2005
	(In thousands)
Net income	$	5,875			93%	$	3,048
Non-cash items		13,889			50%		9,279
Changes in working capital and other items		6,424			NM		(6,083	)
Cash flows provided by operating activities		26,188			319%		6,244
Cash flows used by investing activities		(33,492	)		62%		(20,644	)
Cash flows provided by financing activities		11,082			(34%)		16,760
Net increase in cash and cash equivalents	$	3,778			60%	$	2,360

Analysis of net cash provided by operating activities

Cash flows provided by operating activities for the first quarter of 2006 were 319% higher than net cash provided by operating activities in the same period of 2005. The following were the primary factors that led to the changes to our cash flows provided by operating activities during the first three months of 2006.

· Our total revenues for the first three months of 2006 increased $9.1 million due to an increase in the prices we received for our oil and natural gas, an increase in our production volumes for the first quarter 2006 and a decrease in losses associated with our derivative contracts.

· The collection of accounts receivable in excess of the payment of accounts payable during the first three months of 2006 increased our cash flows provided by operating activities by $11.6 million.

· These increases were partially offset by higher production costs and higher cash interest expense that reduced our first quarter 2006 cash provided by operating activities by $854,000 and $543,000, respectively.

Working Capital

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

At March 31, 2006, we had a working capital deficit of $15.1 million compared to a working capital deficit of $9.1 million at December 31, 2005. Our working capital deficit at March 31, 2006, included a net asset of $2.1 million related to the fair value of our derivative contracts compared to a net liability of $2 million at December 31, 2005.

Analysis of changes in cash flows used in investing activities

Net cash used by investing activities in the first quarter of 2006 was 62% higher than the first quarter of 2005. The following were the primary reasons for the $12.8 million increase in our net cash used by investing activities for the first quarter 2006 when compared to the first quarter of last year.

· Our additions to oil and natural gas properties for the first three months of 2006 were up 62% when compared to the same period of 2005. The primary reasons for this increase were $13.3 million increase in our drilling capital expenditures net of changes in accrued drilling costs, a $2.4 million increase in our capital expenditures for land and seismic activities and a $414,000 increase in the amount of interest and general and administrative costs we capitalized. The primary reason for these increases was an increase in our budgeted capital expenditures for oil and natural gas activities in 2006.

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· Our capital expenditures for other assets in the first quarter of 2006 were $77,000 higher than the same period in 2005.

· Our prepaid drilling cost at March 31, 2006, which is reported as an asset on our balance sheet was $81,000 compared to $218,000 at March 31, 2005.

Our capital expenditures for oil and natural gas activities for the first quarter of 2006 and 2005 were:

	Three months ended March 31,
	2006		%Change		2005
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	30,807		76%	$	17,458
Land and seismic		7,172		49%		4,815
Capitalized cost (1)		2,057		28%		1,601
Asset retirement obligation		105		304%		26
Total	$	40,141		68%	$	23,900

____________

(1) For 2006, includes $1.5 million in capitalized general and administrative cost, $409,000 in capitalized interest cost and $122,000 of capitalized stock compensation expense. For 2005, includes $1.2 million in capitalized general and administrative cost, $315,000 in capitalized interest cost and $81,000 of capitalized stock compensation expense.

Analysis of changes in cash flows from financing activities

Senior Credit Agreement

During first three months of 2006, we borrowed an additional $14.5 million under our senior credit agreement and repaid $3.3 million of the amount borrowed under our senior credit agreement. This compares to our borrowing an additional $17.1 million and paying $371,000 in fees to amend and restate our senior credit agreement during the first three months of 2005.

Senior Subordinated Notes

During the first three months of 2006, we did not borrow any additional amount under our subordinated credit agreement. We paid no cash fees during the first quarter 2006 compared to cash fees of $30,000 to amend our subordinated credit agreement during the first quarter 2005.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the first quarter of 2006 and 2005.

	Shares Issued		Net Proceeds
	(In thousands except share data)
2006 common stock transactions:
Exercise of employee stock options		24,200	$	153
2005 common stock transactions:
Exercise of employee stock options		76,700	$	251

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.

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Effects of Inflation and Changes in Prices

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

Environmental and Other Regulatory Matters

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

New Accounting Pronouncement

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 in the first quarter 2006 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. 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 first quarter 2006.

Total compensation cost related to nonvested awards not yet recognized is approximately $5.6 million with a weighted average period over which it is expected to be recognized. We expect this cost to be recognized over 4.6 years.

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 including, but not limited to, the Risk Factors identified in Item 1A. of such report. 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 March 31, 2006, the associated volumes and the corresponding weighted average NYMEX reference price.

					Notional Amount
Settlement Period	Derivative Instrument		Hedge Strategy		NaturalGas (MMBTU)		Oil (Barrels)		Nymex Reference Price
Costless Collars
04/01/06 - 06/30/06		Purchased put		Cash flow				16,500	$	54.80
		Written call		Cash flow				16,500		75.00
04/01/06 - 07/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				15.60
04/01/06 - 07/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				17.00
04/01/06 - 09/30/06		Purchased put		Cash flow				42,000	$	50.00
		Written call		Cash flow				42,000		75.60
04/01/06 - 10/30/06		Purchased put		Cash flow		490,000			$	8.00
		Written call		Cash flow		490,000				14.85
08/01/06 - 10/31/06		Purchased put		Cash flow		360,000			$	8.00
		Written call		Cash flow		360,000				16.65
10/01/06 - 12/31/06		Purchased put		Cash flow				27,000	$	50.00
		Written call		Cash flow				27,000		77.50
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
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
Three Way Costless Collars
04/01/06 - 06/30/06		Purchased put		Cash flow				7,500	$	63.00
		Written call		Cash flow				7,500		75.25
		Written put		Undesignated				7,500		48.00
04/01/06 - 10/31/06		Purchased put		Cash flow		420,000			$	7.50
		Written call		Cash flow		420,000				9.15
		Written put		Undesignated		420,000				6.25
04/01/06 - 10/31/06		Purchased put		Cash flow		490,000			$	8.50
		Written call		Cash flow		490,000				9.96
		Written put		Undesignated		490,000				7.00
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

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The following table reflects commodity derivative contracts entered subsequent to March 31, 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
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
10/01/07 - 03/31/08		Purchased put		Cash flow				18,000	$	56.00
		Written call		Cash flow				18,000		89.95

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 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 first 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 following related to the offering of our 9 5/8% Senior Notes due 2014 which was completed April 20, 2006.  The information presented below updates and should be read in conjunction with the risk factors and information disclosed in our 2005 Annual Report on Form 10-K.  

Risks Relating to the Notes and Our Indebtedness

Our level of indebtedness may adversely affect our cashavailable for operations, which would limit our growth, ourability to make interest and principal payments on ourindebtedness as they become due and our flexibility to respondto market changes.

At March 31, 2006, we had indebtedness of $44.3 million outstanding under our senior credit agreement and $30 million outstanding under our subordinated credit agreement. After we used the net proceeds from the Notes offering to repay the amounts outstanding under our senior and subordinated credit agreements, we had $125 million in outstanding indebtedness, as well as $50 million of borrowing capacity available to us for borrowing under our $200 million senior credit agreement. Our level of indebtedness has several important effects on our operations, including those listed below.

· It may make it more difficult for us to satisfy our obligations with respect to the Notes.

· We have dedicated a portion of our cash flow from operations to the payment of interest on our indebtedness and to the payment of our other current obligations and we no longer have these cash flows available for other purposes.

· Our senior credit agreement and the indenture governing the Notes may limit our ability to borrow additional funds or dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions.

· Our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired.

· We may be more vulnerable to economic downturns and our ability to withstand sustained declines in oil and natural gas prices may be impaired.

· Our flexibility in planning for or reacting to changes in market conditions may be limited.

· It may place us at a competitive disadvantage compared to our competitors that have less debt.

We may incur additional debt in order to fund our exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, oil and natural gas prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.

In addition, under the terms of our senior credit agreement, the borrowing base is subject to at least semi-annual redeterminations based in part on prevailing oil and natural gas prices. In the event the amount that we have borrowed under our senior credit agreement exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make such payments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell assets at unfavorable prices.

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Despite current indebtedness levels, we and our subsidiariesmay still be able to incur substantially more debt, includingsecured debt. This could further exacerbate the risks associatedwith our substantial leverage.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture governing the Notes and our senior credit agreement do not, prohibit us or our subsidiaries from doing so. In addition to the liens granted under our senior credit agreement, the indenture governing the Notes allows us to grant liens on all of our other assets to secure indebtedness outstanding under the senior secured credit agreement and certain additional other debt without ratably securing the Notes. Our senior credit agreement provides for total revolving credit borrowings up to $200 million (which borrowings are limited by a borrowing base that is subject to re-determination at least semi-annually and that was reset to $50 million in connection with the Notes offering) and all of those borrowings would be effectively senior to the Notes and to the subsidiary guarantees thereof to the extent of the value of the assets securing such indebtedness. If new indebtedness is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify and we may not be able to meet all our debt obligations, including the repayment of the Notes, in whole or in part.

To service our indebtedness, we will require a significantamount of cash. Our ability to generate cash depends on manyfactors beyond our control.

Our ability to make payments on and to refinance our indebtedness, including the Notes, and to fund planned capital expenditures and development efforts will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our senior credit agreement or otherwise in an amount sufficient to enable us to pay our indebtedness, including the Notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Notes, on or before the maturity thereof. Any future borrowings under our senior credit agreement will mature in June 2010. As a result, we may be required to refinance any indebtedness then outstanding under our senior credit agreement prior to the maturity of the Notes. We may not be able to obtain such financing on commercially reasonable terms or at all. If we are unable to generate sufficiently material cash flow to refinance our debt obligations, including the Notes, on favorable terms, it could have a significant adverse effect on our financial condition and on our ability to pay principal and interest on the Notes.

In addition, if for any reason we are unable to meet our debt service obligations, we would be in default under the terms of our agreements governing our outstanding debt. If such a default were to occur, the lenders under our senior credit agreement could elect to declare all amounts then outstanding under the senior credit agreement immediately due and payable, and the lenders would not be obligated to continue to advance funds under our senior credit agreement. In addition, if such a default were to occur, the Notes would become immediately due and payable. If the amounts outstanding under these debt agreements are accelerated, we cannot assure you that our assets will be sufficient to repay in full the money owed to the banks or to our debt holders, including holders of Notes.

A noteholder’s right to receive payments on the Notes is effectivelysubordinated to the rights of our and the guarantors’ existingand future secured creditors.

Holders of our secured indebtedness and the secured indebtedness of the guarantors have claims that are prior to a noteholder’s claims as a holder of the Notes to the extent of the value of the assets securing that other indebtedness. Notably, we and the guarantors are parties to our senior credit agreement, which is secured by liens on substantially all of our assets and the assets of the guarantors. The Notes are effectively subordinated to any secured indebtedness incurred under the senior credit agreement. In the event of any distribution or payment of our or any guarantor’s assets in any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of secured indebtedness will have prior claim to those of our or the guarantor’s assets that constitute their collateral. Holders of Notes will participate ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as such Notes, and potentially with all of our or any guarantor’s other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the Notes. As a result, holders of Notes may receive less, ratably, than holders of secured indebtedness.

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Upon completion of the Notes offering, up to $50 million of secured indebtedness is available for borrowing under the borrowing base of our $200 million senior credit agreement. In addition, we are permitted to borrow secured indebtedness in the future under the terms of the indenture.

The Notes are effectively subordinated to the debt of ournon-guarantor subsidiaries, if any.

The Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing operating subsidiaries, as well as all of our future domestic subsidiaries. However, they are not guaranteed by any of our future subsidiaries outside the United States unless, subject to certain limited exceptions, these subsidiaries guarantee our other domestic indebtedness. In addition, on the issue date of the Notes, two of our wholly owned subsidiaries (referred to herein as the “limited partners”), which together own approximately 99% limited partnership interests in Brigham Oil & Gas, L.P., our primary operating subsidiary, were not guarantors of the Notes. As of the issee date of the notes, the limited partners did not conduct any business or operations and held no properties other than the limited partnership interests in Brigham Oil & Gas, L.P. and other minor miscellaneous assets. Under the indenture governing the Notes, the limited partners are required to guarantee the Notes if they ever (i) hold properties in excess of $1 million, (ii) incur debt in excess of $1 million, or (iii) guarantee any of our or our subsidiaries’ indebtedness. The indenture also provides that the Notes may not be guaranteed by certain subsidiaries with minimal net worth. The Notes are effectively subordinated to all debt and other liabilities, including trade payables of any subsidiaries that do not guarantee the Notes.

If we default on our obligations to pay our otherindebtedness, we may not be able to make payments on the Notes.

Any default under the agreements governing our indebtedness, including a default under our senior credit agreement that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal, premium, if any, and interest on the Notes and substantially decrease the market value of the Notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including our senior credit agreement), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our senior credit agreement could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our senior credit agreement to avoid being in default. If we breach our covenants under our senior credit agreement and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our senior credit agreement, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. See “Management Discussion and Analysis — Capital Resources — Senior Credit Agreement.”

35

The indenture governing the Notes and our senior credit agreement impose significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.

The indenture governing the Notes and our senior credit agreement contain, customary restrictions on our activities, including covenants that restrict our and our subsidiaries’ ability to:

· incur additional debt;

· pay dividends on, or redeem or repurchase stock;

· create liens;

· make specified types of investments;

· apply net proceeds from certain asset sales;

· engage in transactions with our affiliates;

· engage in sale and leaseback transactions;

· merge or consolidate;

· restrict dividends or other payments from subsidiaries;

· sell equity interests of subsidiaries; and

· sell, assign, transfer, lease, convey or dispose of assets.

Our senior credit agreement also requires us to meet a minimum current ratio and a minimum interest coverage ratio. We may not be able to maintain these ratios, and if we fail to be in compliance with these tests, we will not be able to borrow funds under our senior credit agreement which would make it difficult for us to operate our business.

The restrictions in the indenture governing the Notes and our senior credit agreement may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We cannot assure that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.

The breach of any of these covenants and restrictions could result in a default under the indenture governing the Notes or under our senior credit agreement. An event of default under our debt agreements would permit some of our lenders to declare all amounts borrowed from them to be due and payable. If we are unable to repay debt, lenders having secured obligations, such as the lenders under our senior credit agreement, could proceed against the collateral securing the debt. Because the indenture governing the Notes and our senior credit agreement have customary cross-default provisions, if the indebtedness under the Notes or under our senior credit agreements or any of our other facilities is accelerated, we may be unable to repay or finance the amounts due.

We may not have the ability to raise the funds necessary tofinance the change of control offer required by the indenturegoverning the Notes.

Upon the occurrence of certain kinds of change of control events, we will be required to offer to repurchase all outstanding Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the date of repurchase, unless all Notes have been previously called for redemption. The holders of other debt securities that we may issue in the future, which rank equally in right of payment with the Notes, may also have this right. Our failure to purchase tendered Notes would constitute an event of default under the indenture governing the Notes, which in turn, would constitute a default under our senior credit agreement. In addition, the occurrence of a change of control would also constitute an event of default under our senior credit agreement. A default under our senior credit agreement would result in a default under the indenture if the lenders accelerate the debt under our senior credit agreement.

36

Therefore, it is possible that we may not have sufficient funds at the time of the change of control to make the required repurchase of Notes. Moreover, our senior credit agreement restricts, and any future indebtedness we incur may restrict, our ability to repurchase the Notes, including following a change of control event. As a result, following a change of control event, we would not be able to repurchase Notes unless we first repay all indebtedness outstanding under our senior credit agreement and any of our other indebtedness that contains similar provisions, or obtain a waiver from the holders of such indebtedness to permit us to repurchase the Notes. We may be unable to repay all of that indebtedness or obtain a waiver of that type. Any requirement to offer to repurchase outstanding Notes may therefore require us to refinance our other outstanding debt, which we may not be able to do on commercially reasonable terms, if at all. These repurchase requirements may also delay or make it more difficult for others to obtain control of us.

In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “Change of Control” under the Indenture.

There are restrictions on a noteholder’s ability to transfer or resellthe Notes.

The Notes were issued and sold pursuant to an exemption from registration under the Securities Act and applicable state securities laws. Accordingly, a noteholder may transfer or resell the Notes only in a transaction registered under, or exempt from, the registration requirements of the Securities Act and applicable state securities laws, and the noteholder may be required to bear the risk of the investment for an indefinite period of time.

We intend to file a registration statement with the SEC and seek to cause the registration statement to become effective with respect to the exchange notes. The SEC has broad discretion to declare any registration statement effective and may delay or deny the effectiveness of any registration statement for a variety of reasons.

If issued under an effective registration statement, the exchange notes generally may be resold or otherwise transferred with no need for further registration. However,

· the exchange notes will constitute a new issue of securities with no established trading market; and

· the offer to exchange the Notes for the exchange notes will not depend upon the amount of notes tendered for exchange.

A noteholder’s ability to transfer the Notes may be limited by theabsence of an active trading market and there is no assurancethat any active trading market will develop for the Notes.

The Notes are a new issue of securities for which there is no established public market. The Notes are not listed on a national securities exchange or included on any automated dealer quotation system, although they are eligible for trading in The PORTAL Market.

The initial purchasers are not obligated to make a market in the Notes or the exchange notes, and they may discontinue their market-making activities at any time without notice. Therefore, we cannot assure you that an active market for the Notes or exchange notes will develop or, if developed, that it will continue. Credit Suisse Securities (USA) LLC (“Credit Suisse”), one of the initial purchasers of the notes, is an affiliate of DLJ Merchant Banking Partners III, L.P. and its affiliated funds, that are investors in our company. Accordingly, Credit Suisse is required to deliver a current “market maker” prospectus and otherwise comply with the registration requirements of the Securities Act in connection with any secondary market sale of the Notes, which may affect its ability to continue market making activities. We have agreed to make a “market maker” prospectus generally available to Credit Suisse to permit it to engage in market making transactions. However, the registration rights agreement also provides that we may, for valid business reasons, allow the market maker prospectus to cease to be effective and usable for a period of time set forth in the registration rights agreement or as otherwise acceptable to the market maker. As a result, the liquidity of the secondary market for the Notes may be materially adversely affected by the unavailability of a current “market maker” prospectus.

37

Even if a trading market for the Notes does develop, a noteholder may not be able to sell the Notes at a particular time, if at all, or a noteholder may not be able to obtain the price desired for the Notes. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the Notes. We cannot assure you that the market, if any, for the Notes or exchange notes will be free from similar disruptions or that any such disruptions may not adversely affect the prices at which a noteholder may sell the Notes. In addition, the Notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, our ability to effect the exchange offer, the market for similar notes, our credit rating, the interest of securities dealers in making a market for the Notes, the price of any other securities we may issue, our performance, prospects, operating results, financial condition and other factors.

Federal and state statutes allow courts, under specificcircumstances, to void the guarantees and require noteholders toreturn payments received from the guarantors.

Creditors are protected by fraudulent conveyance laws which differ among various jurisdictions, and these laws may apply to the issuance of the guarantees by our subsidiary guarantors. Under federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee may be voided by a court, or subordinated to the claims of other creditors, if, among other things:

· the indebtedness evidenced by such guarantee was incurred by a subsidiary guarantor with actual intent to hinder, delay or defraud any present or future creditor of such subsidiary guarantor; or

· such subsidiary guarantor did not receive fair consideration or reasonably equivalent value for issuing the guarantee, and the applicable subsidiary guarantor

· was insolvent, or were rendered insolvent by reason of issuing the applicable guarantee;

· was engaged or about to engage in a business or transaction for which the remaining assets of the applicable subsidiary guarantor constituted unreasonably small capital; or

· intended to incur, or believed that we or it would incur, indebtedness beyond our or its ability to pay such debts as they matured.

In addition, any payment by such subsidiary guarantor pursuant to any guarantee could be voided and required to be returned to such subsidiary guarantor, or to a fund for the benefit of creditors of such subsidiary guarantor. A legal challenge to a guarantee on fraudulent conveyance grounds may focus on the benefits, if any, realized by us or the subsidiary guarantors as a result of our issuance of the guarantees. To the extent a subsidiary’s guarantee of the Notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, a noteholder would cease to have any claim in respect of that guarantee and would be creditors solely of ours.

Because all of our significant assets are held by our guarantor subsidiaries, the stake of a guarantee being voided under fraudulent transfer laws is higher. In addition, any future guarantees provided under the indenture governing the Notes have a greater risk of being voided. Moreover, the borrower under our senior credit agreement is Brigham Oil & Gas, L.P., our primary operating subsidiary and guarantor of the Notes. In the event Brigham Oil & Gas, L.P.’s guarantee of the Notes is avoided or held unenforceable, the Notes would be effectively subordinated to any then outstanding borrowings under our senior credit agreement, which would be paid in full prior to amounts due on the Notes in the event of any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding with respect to Brigham Oil & Gas, L.P.

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The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:

· the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets; or

· the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

· it could not pay its debts as they become due.

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

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased		Average Price Paid per Share
January 1, 2006 - January 31, 2006		17,968	$	11.74

No purchases were made under a publicly announced plan.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

39

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

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

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

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SIGNATURES

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