Brigham Exploration 10Q 2007 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2007


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

For the transition period from to

Commission File Number: 000-22433

Brigham Exploration Company

(Exact name of registrant as specified in its charter)


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

Yesþ Noo

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 Filero		Accelerated Filerþ		Non-Accelerated Filero

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

Yeso Noþ


Class		Outstanding
Common Stock, par value $.01 per share as of May 7, 2007		45,617,160

Brigham Exploration Company

First Quarter 2007 Form 10-Q Report

TABLE OF CONTENTS


		Page
PART I — FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS

	Consolidated Balance Sheets -- March 31, 2007 and December 31, 2006		1

	Consolidated Statements of Operations -- Three months ended March 31, 2007 and 2006		2

	Consolidated Statement of Stockholders’ Equity -- Three months ended March 31, 2007		3

	Consolidated Statements of Cash Flows -- Three months ended March 31, 2007 and 2006		4

	Notes to the Consolidated Financial Statements		5

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		15

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		31

ITEM 4.	CONTROLS AND PROCEDURES		34

PART II — OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS		34

ITEM 1.A.	RISK FACTORS		34

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		34

ITEM 3.	DEFALTS UPON SENIOR SECURITIES		34

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		34

ITEM 5.	OTHER INFORMATION		34

ITEM 6.	EXHIBITS		34

SIGNATURES			35

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)


		March 31,			December 31,
		2007			2006
ASSETS
Current assets:
Cash and cash equivalents		$	7,151		$	4,300
Accounts receivable			18,567			18,352
Derivative assets	��		1,018			5,676
Other current assets			1,964			2,390
Property held for sale			500			500

Total current assets			29,200			31,218

Oil and natural gas properties, using the full cost method including
Proved, net			435,281			410,474
Unproved			70,913			75,051

			506,194			485,525

Other property and equipment, net			1,184			936
Deferred loan fees			3,260			3,420
Other noncurrent assets			871			1,488

Total assets		$	540,709		$	522,587


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable		$	11,385		$	19,464
Royalties payable			5,188			5,012
Accrued drilling costs			9,777			23,310
Participant advances received			1,603			3,990
Other current liabilities			7,305			5,677

Total current liabilities			35,258			57,453


Senior Notes			123,488			123,434
Senior credit facility			61,500			25,900
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at March 31, 2007 and December 31, 2006			10,101			10,101
Deferred income taxes			34,853			34,609
Other taxes payable			2,139			—
Other noncurrent liabilities			5,534			5,075

Commitments and contingencies (Note 3)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,150,398 and 45,090,398 shares issued and 45,053,399 and 44,011,362 shares outstanding at March 31, 2007 and December 31, 2006, respectively			452			451
Additional paid-in capital			204,435			203,643
Treasury stock, at cost; 96,999 and 79,036 shares at March 31, 2007 and December 31, 2006, respectively			(796	)		(662	)
Accumulated other comprehensive income (loss)			295			1,006
Retained earnings			63,450			61,577

Total stockholders’ equity			267,836			266,015

Total liabilities and stockholders’ equity		$	540,709		$	522,587

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

BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)


	Three Months Ended
	March 31,
	2007			2006
Revenues:
Oil and natural gas sales	$	28,486		$	25,796
Gain (loss) on derivatives, net		(3,492	)		(228	)
Other revenue		27			(22	)

		25,021			25,546

Costs and expenses:
Lease operating		2,569			2,730
Production taxes		71			1,144
General and administrative		2,178			1,769
Depletion of oil and natural gas properties		13,959			10,256
Depreciation and amortization		163			115
Accretion of discount on asset retirement obligations		117			70

		19,057			16,084

Operating income		5,964			9,462

Other income (expense):
Interest income		131			106
Interest expense, net		(3,417	)		(1,089	)
Other income (expense)		190			907

		(3,096	)		(76	)

Income before income taxes		2,868			9,386

Income tax expense:
Current		—			—
Deferred		(995	)		(3,511	)

		(995	)		(3,511	)


Net income	$	1,873		$	5,875


Net income per share available to common stockholders:
Basic	$	0.04		$	0.13

Diluted	$	0.04		$	0.13


Weighted average shares outstanding:
Basic		45,051			44,986

Diluted		45,430			45,579

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

BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In thousands)
(Unaudited)


											Accumulated
					Additional						Other					Total
	Common Stock				Paid In			Treasury			Comprehensive			Retained		Stockholders’
	Shares		Amounts		Capital			Stock			Income (Loss)			Earnings		Equity
Balance, December 31, 2006		45,090	$	451	$	203,643		$	(662	)	$	1,006		$	61,577	$	266,015
Comprehensive income:
Net income		—		—		—			—			—			1,873		1,873
Net (gains) losses included in net income		—		—		—			—			(1,094	)		—		(1,094	)
Tax benefit (provision) related to hedges		—		—		—			—			383			—		383

Comprehensive income																	1,162
Exercises of employee stock options		5		—		23			—			—			—		23
Vesting of restricted stock		55		1		(1	)		—			—			—		—
Stock based compensation		—		—		770			—			—			—		770
Repurchases of common stock		—		—		—			(134	)		—			—		(134	)

Balance, March 31, 2007		45,150	$	452	$	204,435		$	(796	)	$	295		$	63,450	$	267,836

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

BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)


	Three Months Ended
	March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	1,873		$	5,875
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		13,959			10,256
Depreciation and amortization		163			115
Stock based compensation		421			491
Amortization of deferred loan fees and debt issuance costs		214			119
Market value adjustment for derivative instruments		4,916			(715	)
Accretion of discount on asset retirement obligations		117			70
Deferred income taxes		995			3,511
Other noncash items		—			42
Changes in operating assets and liabilities:
Accounts receivable		(215	)		6,111
Other current assets		426			(336	)
Accounts payable		(8,079	)		1,655
Royalties payable		176			(902	)
Participant advances received		(2,387	)		(197	)
Other current liabilities		2,999			147
Other noncurrent assets and liabilities		6			(54	)

Net cash provided by operating activities		15,584			26,188


Cash flows from investing activities:
Additions to oil and natural gas properties		(47,605	)		(33,674	)
Additions to other property and equipment		(411	)		(142	)
Decrease (increase) in drilling advances paid		(206	)		324

Net cash used by investing activities		(48,222	)		(33,492	)


Cash flows from financing activities:
Increase in senior credit facility		35,600			14,500
Repayment of senior credit facility		—			(3,300	)
Repayment of senior subordinated notes		—			—
Deferred loan fees paid and equity costs		—			(60	)
Proceeds from issuance of stock, net of issuance costs		—			153
Proceeds from exercise of employee stock options		23			—
Repurchases of common stock		(134	)		(211	)

Net cash provided by financing activities		35,489			11,082

Net increase (decrease) in cash and cash equivalents		2,851			3,778
Cash and cash equivalents, beginning of year		4,300			3,975

Cash and cash equivalents, end of period	$	7,151		$	7,753

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Organization and Nature of Operations

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

2. Basis of Presentation

The accompanying unaudited consolidated financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries, has a participating interest. All significant intercompany accounts and transactions have been eliminated.

The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham’s 2006 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

See Note 9 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, 2007, there are no known environmental or other regulatory matters related to Brigham’s operations that are reasonably expected to result in a material liability to Brigham. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on Brigham’s financial position, results of operations or cash flows.

4. Net Income Available Per Common Share

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

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, 2007 and 2006 are as follows (in thousands):


	Three Months Ended
	March 31,
	2007		2006
Weighted average common shares outstanding — basic		45,051		44,986
Plus: Potential common shares Stock options and restricted stock		379		593


Weighted average common shares outstanding — diluted		45,430		45,579


Stock options excluded from diluted EPS due to the anti-dilutive effect		2,550		1,246

5. Income Taxes

The income tax expense (benefit) for the three months ended March 31, 2007 and 2006 consist of the following (in thousands):


	March 31,			March 31,
	2007			2006
Current income taxes:
Federal	$	—		$	—
State		—			—
Deferred income taxes:
Federal		1,179			3,511
State		(184	)		—

	$	995		$	3,511

In May 2006, the State of Texas enacted legislation establishing a new franchise tax (referred to as the “Margin Tax”), that is based on modified gross revenue. Within the context of generally accepted accounting principles in the United States, the Margin Tax is based on a measure of income and is thus accounted for in accordance with Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (SFAS 109). The provisions of SFAS 109 require recognition of the effects of the tax law change in the period of enactment. As a result, Brigham began recognizing deferred state income taxes in the second quarter of 2006. As of December 31, 2006, Brigham recorded a deferred state tax liability in the amount of $1.2 million consisting primarily of the estimated impact of the adoption of the Margin Tax in 2006. During the first quarter of 2007, Brigham recorded a deferred state tax benefit in the amount of $184,000, consisting primarily of the Margin Tax.

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48), which provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” of being sustained if the position were to be challenged by a taxing authority. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is greater than 50% likely of being recognized upon ultimate settlement with the taxing authority is recorded. Brigham has examined the tax positions taken in its tax returns or expected to be taken in its future tax returns and has determined that the full values of the uncertain tax positions have been recorded as part of the deferred tax liabilities. Therefore, no additional liabilities should be created and no incremental current or deferred income tax expenses should be recognized. However, consistent with the view of the FASB, Brigham has reclassified the liability for unrecognized tax benefits related to these uncertain tax positions from deferred tax liabilities to other tax liabilities on the consolidated balance sheet.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


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


Unrecognized tax benefits at 03/31/2007	$	2,139

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

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

6. Derivative Instruments and Hedging Activities

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

Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. On October 1, 2006, Brigham de-designated all derivates that were previously classified as cash flow hedges and, in addition, Brigham has elected not to designate any additional derivative contracts as accounting hedges under SFAS No. 133. Beginning on October 1, 2006, all derivative positions are carried at their fair value on the consolidated balance sheet and are marked-to-market at the end of each period. As such, the realized and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the consolidated statement of operations rather than as a component of other comprehensive income. The following table sets forth Brigham’s oil and natural gas prices including and excluding the realized and unrealized hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three months ended March 31, 2007 and 2006:


	Three Months Ended
	March 31,
	2007			2006
*Natural Gas*
Average price per Mcf realized excluding gas hedging results	$	7.32		$	7.33
Average price per Mcf including gas hedging settlement results	$	7.76		$	7.34
Increase (decrease) in revenue, in thousands	$	1,311		$	23
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	6.23		$	7.28
Increase (decrease) in revenue, in thousands	$	(3,251	)	$	(120	)

*Oil*
Average price per Bbl realized excluding oil hedging results	$	54.75		$	61.40
Average price per Bbl including oil hedging settlement results	$	55.68		$	60.97
Increase (decrease) in revenue, in thousands	$	113		$	(50	)
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	52.78		$	61.17
Increase (decrease) in revenue, in thousands	$	(240	)	$	(27	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Ineffectiveness associated with Brigham’s derivative commodity instruments designated as cash flow hedges is included in other income (expense). Effective October 1, 2006, Brigham de-designated all existing cash flow hedges. Subsequent derivative contracts are undesignated for accounting purposes. Brigham continues to designate derivative contracts as cash flow hedges for tax purposes:


	Three Months Ended
	March 31,
	2007		2006
Increase (decrease) in earnings due to ineffectiveness	$	—	$	835

Natural Gas and Crude Oil Derivative Contracts

Cash-flow hedges

Prior to October 1, 2006, all derivative positions that qualified for hedge accounting were designated on the date Brigham entered into the contract as a hedge against the variability in cash flows associated with the forecasted sale of future oil and gas production. Brigham’s cash flow hedges consisted of costless collars (purchased put options and written call options). The costless collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There were no net premiums paid or received when Brigham entered into these option agreements. The cash flow hedges were valued at the end of each period and adjustments to the fair value of the contract prior to settlement were recorded on the consolidated statement of stockholders’ equity as other comprehensive income. Upon settlement, the gain (loss) on the cash flow hedge was recorded as an increase or decrease in revenue on the consolidated statement of operations. Additionally, any unrealized gains (losses) relating to the ineffective portion of the cash flow hedges was recorded as an increase or decrease in other income (expense).

On October 1, 2006, Brigham de-designated all derivates that were previously classified as cash flow hedges and, in addition, Brigham has elected not to designate any additional derivative contracts as accounting hedges under SFAS No. 133. As such, all derivative positions are carried at their fair value on the consolidated balance sheet and are marked-to-market at the end of each period. Any realized and unrealized gains or losses are recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the consolidated statement of operations rather than as a component of other comprehensive income or as other income (expense).

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


	March 31,
	2007		2006
Fair value of undesignated written put options	$	—	$	(244	)

The following table provides a summary of the impact on earnings from non-cash gains (losses) related to changes in the fair values of these derivative contracts for the three months ended March 31 (in thousands):


	March 31,
	2007		2006
Increase (decrease) in earnings due to changes in fair value of written put options	$	—	$	(120	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at March 31, 2007, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
04/01/07 - 08/31/07		520,000			$	7.00	$	8.00
04/01/07 - 10/31/07		280,000			$	7.00	$	15.45
04/01/07 - 10/31/07		280,000			$	7.25	$	15.25
04/01/07 - 10/31/07		280,000			$	7.00	$	14.85
04/01/07 - 10/31/07		700,000			$	7.50	$	11.00
04/01/07 - 10/31/07		350,000			$	7.00	$	11.60
04/01/07 - 10/31/07		350,000			$	7.00	$	9.10
04/01/07 - 10/31/07		350,000			$	7.25	$	9.60
04/01/07 - 08/31/07		200,000			$	7.00	$	10.00
05/01/07 - 10/31/07		600,000			$	7.00	$	9.55
09/01/07 - 10/31/07		70,000			$	7.00	$	9.35
11/01/07 - 03/31/08		250,000			$	8.00	$	13.40
11/01/07 - 03/31/08		300,000			$	8.85	$	15.00
11/01/07 - 03/31/08		300,000			$	9.30	$	15.00
11/01/07 - 03/31/08		500,000			$	7.50	$	13.30
11/01/07 - 03/31/08		150,000			$	8.00	$	10.20
11/01/07 - 03/31/08		250,000			$	8.00	$	12.65
04/01/08 - 09/30/08		420,000			$	6.75	$	9.75
04/01/08 - 09/30/08		540,000			$	7.00	$	9.68

*Oil Costless Collars*
04/01/07 - 06/30/07				12,000	$	59.00	$	90.00
04/01/07 - 04/30/08				27,000	$	60.00	$	74.75
04/01/07 - 12/31/07				9,000	$	55.00	$	79.00
04/01/07 - 09/30/07				30,000	$	50.00	$	81.50
04/01/07 - 09/30/07				12,000	$	56.00	$	92.50
04/01/07 - 12/31/07				23,000	$	60.00	$	76.00
04/01/07 - 12/31/07				33,000	$	55.00	$	80.30
06/01/07 - 08/31/07				6,000	$	65.00	$	80.00
07/01/07 - 10/31/07				10,000	$	58.00	$	90.50
10/01/07 - 12/31/07				9,000	$	59.20	$	90.00
10/01/07 - 03/31/08				18,000	$	56.00	$	89.95
10/01/07 - 03/31/08				6,000	$	65.00	$	80.25
11/01/07 - 03/31/08				10,000	$	68.40	$	90.00
01/01/08 - 03/31/08				7,500	$	57.60	$	90.00
01/01/08 - 12/31/08				24,000	$	57.50	$	75.50
04/01/08 - 10/31/08				21,000	$	65.70	$	90.00
04/01/08 - 12/31/08				18,000	$	57.50	$	76.00

The following table reflects commodity derivative contracts entered subsequent to March 31, 2007, the associated volumes and the corresponding weighted average NYMEX reference price (Henry Hub).


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMBTU)		Nymex		Nymex
*Natural Gas Costless Collars*
04/01/07 - 08/31/07		750,000	$	7.00	$	10.20
04/01/08 - 10/31/08		350,000	$	7.25	$	10.40

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Interest rate swap

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

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

Fair values

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


	March 31,			December 31,
	2007			2006
	(In thousands)
Other current liabilities	$	(405	)	$	(5	)
Other noncurrent liabilities		(129	)		—
Other current assets		1,018			5,676
Other noncurrent assets		81			904

	$	565		$	6,575

7. Senior Notes

In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the “Senior Notes”). The Senior Notes were priced at 98.629% of their face value to yield 9 7/8% and are fully and unconditionally guaranteed by Brigham Exploration and its wholly-owned subsidiaries, Brigham Inc. and Brigham Oil & Gas, L.P. (the “Guarantors”). The guarantees are joint and several. Brigham Exploration does not have any independent assets or operations and the aggregate assets and revenues of the subsidiaries not guaranteeing are less than 3% of the Company’s consolidated assets and revenues. During April 2007, Brigham sold $35 million of Senior Notes in a private placement add-on. See Note 12 — Subsequent Events for a discussion of the sale of additional Senior Notes.

8. Asset Retirement Obligations

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the three months ended March 31, 2007 and 2006 (in thousands):


	Three Months Ended
	March 31,
	2007		2006
Beginning asset retirement obligations	$	5,002	$	4,389
Liabilities incurred for new wells placed on production		208		105
Liabilities settled		10		(44	)
Accretion of discount on asset retirement obligations		117		70

	$	5,337	$	4,520

9. Stock Based Compensation

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

The estimated fair value of the options granted during the first quarter of 2006 was calculated using a Black-Scholes Merton option pricing model (Black-Scholes). There were no options granted during the first quarter of 2007. The following table summarizes the weighted average assumptions used in the Black-Scholes model for options granted during the first quarter of 2006:


	2006
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 FASB issued FASB Staff Position No. FAS 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” Brigham elected to adopt the alternative transition method provided in the FASB Staff Position for calculating the tax effects of stock based compensation pursuant to SFAS 123R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (APIC pool) related to the tax effects of employee stock based compensation, and to determine the subsequent impact on the APIC pool and Consolidated Statements of Cash Flows of the tax effects of employee stock based compensation awards that are outstanding upon adoption of SFAS 123R.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Prior to the adoption of SFAS 123R, Brigham presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Brigham did not have any excess tax benefits during the three months ended March 31, 2007 and 2006.

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


	Three Months Ended
	March 31,
	2007			2006
Pre-tax stock based compensation expense	$	770		$	613
Capitalized stock based compensation		(349	)		(305	)
Tax benefit		(147	)		(108	)

Stock based compensation expense, net	$	274		$	200

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. 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, 2007, approximately 943,180 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 36,300 remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for the three months ended March 31:


	2007					2006
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Options outstanding at the beginning of the year		3,243,566		$	7.08		2,946,333		$	6.96
Granted		—		$	—		20,000		$	9.73
Forfeited or cancelled		(86,600	)	$	8.14		(111,067	)	$	2.46
Exercised		(5,000	)	$	4.59		(24,200	)	$	6.30

Options outstanding at the end of the quarter		3,151,966		$	7.05		2,831,066		$	7.16

Options exercisable at the end of the quarter		1,468,266		$	6.20		970,933		$	5.64

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

As noted on the previous page, there were no options granted during the three months ended March 31, 2007. The weighted-average grant-date fair value of share options granted during the three months ended March 31, 2006 was $6.54. The total intrinsic value of options exercised during the three months ended March 31, 2007 and 2006 was $6,112 and $158,000, respectively.

The following table summarizes information about stock options outstanding and exercisable at March 31, 2007:


	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average	Weighted-
	March 31,		Remaining	Average		March 31,		Remaining	Average
Exercise Price	2007		Contractual Life	Exercise Price		2007		Contractual Life	Exercise Price
$3.05 to $3.41		230,166	1.7 years	$	3.35		214,866	1.6 years	$	3.34
3.66 to 5.08		486,900	2.3 years	$	4.22		399,700	1.9 years	$	3.70
6.14 to 6.73		1,237,000	4.6 years	$	6.51		473,000	3.5 years	$	6.69
7.09 to 8.84		808,900	4.7 years	$	8.51		283,700	4.4 years	$	8.69
8.93 to 12.31		389,000	5.4 years	$	11.48		97,000	5.3 years	$	11.11

$3.05 to $12.31		3,151,966	4.1 years	$	7.05		1,468,266	3.0 years	$	6.20

The aggregate intrinsic value of options outstanding and exercisable at March 31, 2007 was $1.3 million and $1.1 million, respectively. The aggregate intrinsic value represents the total pre-tax value (the difference between Brigham’s closing stock price on the last trading day of the quarter and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on March 31, 2007. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of March 31, 2007 there was approximately $5.3 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.8 years.

Restricted Stock

During the three months ended March 31, 2007 and 2006, Brigham issued 75,000 and 129,095, respectively, restricted shares of common stock as compensation to officers and employees of Brigham. The restricted shares vest over five years or cliff-vest at the end of five years. As of March 31, 2007, there was approximately $2.6 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.8 years. During 2006, stock compensation expense related to unvested restricted stock was adjusted to recognize actual forfeitures during the year as they occurred. Brigham has assumed a 6% weighted average forfeiture rate for restricted stock to be used prospectively at December 31, 2006. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods.

The following table reflects the outstanding restricted stock awards and activity related thereto for the three months ended March 31:


	2007					2006
				Weighted-						Weighted-
				Average						Average
				Exercise						Exercise
	Shares			Price		Shares			��	Price
Restricted shares outstanding at the beginning of the year		391,367		$	8.60		397,650			$	7.22
Shares granted		75,000		$	7.43		129,095			$	10.85
Lapse of restrictions		(55,000	)	$	5.23		(65,000	)		$	5.23
Forfeitures		(25,160	)	$	8.09		(1,000	)		$	12.31

Shares outstanding at the end of the quarter		386,207		$	8.89		460,745			$	8.64

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

10. Comprehensive Income

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


	Three Months Ended
	March 31,
	2007			2006
Net income	$	1,873		$	5,875
Unrealized gains (losses) on cash flow hedges		—			4,461
Net gains (losses) included in net income		(1,094	)		—
Tax benefits (provisions) related to cash flow hedges		383			(1,269	)
Reclassification adjustments for settled hedging positions		—			(835	)

Other comprehensive income, net	$	1,162		$	8,232

11. New Accounting Pronouncements

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

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

12. Subsequent Events

On April 9, 2007, Brigham issued $35 million in Senior Notes, which were issued as an add-on to the existing $125 million of Senior Notes under the indenture dated April 20, 2006. The add-on Senior Notes were priced at 99.50% of face value to yield 9.721% and were issued under a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”). Brigham is in the process of completing an offering to exchange the unregistered notes for registered notes. The unregistered notes may not be offered or sold in the United States without registration or an applicable exemption from the registration requirements of the Securities Act. The add-on Senior Notes are fully and unconditionally guaranteed by the Guarantors. Brigham used the proceeds from the add-on offering to repay amounts outstanding under the existing senior credit agreement and for general corporate purposes. Upon completion of the add-on, Brigham had outstanding $160 million in Senior Notes.

At March 31, 2007, Brigham had $500,000 of property held for sale recorded on the consolidated balance sheet. During April 2007, Brigham sold the property held for sale for $600,000 to a third party

ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following updates information as to our financial condition provided in our 2006 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month periods ended March 31, 2007 and March 31, 2006. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the “Glossary of Oil and Gas Terms” provided in our 2006 Annual Report on Form 10-K. Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes hereto.

General Overview

We are an independent exploration, development and production company that utilizes 3-D seismic imaging and other advanced technologies to systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our exploration and development activities in provinces where we believe technology and the knowledge of our technical staff can be effectively used to maximize our return on invested capital by reducing drilling risk and enhancing our ability to grow reserves and production volumes. Our exploration and development activities are currently concentrated in four provinces: the Onshore Gulf Coast, the Anadarko Basin, the Rocky Mountains and West Texas.

We regularly evaluate opportunities to expand our activities to other areas that may offer attractive exploration and development potential, with a particular interest in those areas with plays that complement our current exploration, development and production activities. As a result of this strategy, since late 2005 we have accumulated significant acreage positions in the Powder River Basin of Wyoming and the Williston Basin of North Dakota and Montana. In April 2007, we announced that we had added to our Williston Basin acreage by entering into joint ventures that encompass acreage in Mountrail County, North Dakota and Sheridan County, Montana. Operations within the Powder River and Williston Basins are included in and constitute the bulk of our activity in our Rocky Mountains province. We also entered into two joint ventures in Southern Louisiana in 2006. We consider these joint ventures to be logical extensions of our prospect generating activities in the Onshore Gulf Coast.

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

	•		Focus on Core Provinces and Trends;

	•		Internally Generate Inventory of High Quality Exploratory Prospects;

	•		Leverage Our Operational Expertise;

	•		Evaluate and Selectively Pursue New Potential Plays;

	•		Capitalize on Exploration Successes Through Development of Our Field Discoveries;

	•		Continue to Actively Drill Our Multi-Year Prospect Inventory; and

	•		Enhance Returns Through Operational Control.

Overview of First Quarter 2007 Financial Results

First quarter 2007 natural gas prices decreased slightly from the comparable quarter last year, but remain high relative to long-term historical averages. Excluding realized and unrealized derivative hedging results, the average sales price that we received for natural gas in the first quarter 2007 was $7.32, which represents a $0.01 decrease from the first quarter 2006. Excluding realized and unrealized derivative hedging results, the average sales price that we received for oil in the first quarter 2007 was $54.75 per Bbl, which represents an 11% decrease from the first quarter 2006.

Our production for the first quarter 2007 averaged 41.2 MMcfe per day, up 15% from the first quarter 2006 and up 6% sequentially from the fourth quarter 2006. This increase was primarily attributable to production from new Vicksburg and Southern Louisiana wells that came on line subsequent to the first quarter 2006 and was partially offset by the natural decline in wells that began producing in prior periods.

First quarter 2007 operating income decreased 37% to $6.0 million from the first quarter last year. This decrease was attributable to unrealized derivative hedging losses, lower commodity prices, increases in depletion expense and higher general and administrative expense. Higher production volumes and lower production taxes partially offset these decreases.

For the three months ended March 31, 2007, we spent $34.6 million on oil and gas capital expenditures, which represents a decrease of 14% from the first quarter 2006 and a 24% decrease from the fourth quarter 2006. For the first three months 2007, net cash provided by operating activities funded approximately 32% of cash used by investing.

As of March 31, 2007, we had $7.2 million in cash and $540.7 million in total assets. Our net debt to book capitalization ratio was 42%, which is calculated as debt plus preferred stock divided by book equity plus debt plus preferred stock.

Overview of First Quarter 2007 Operational Results

Onshore Gulf Coast

Vicksburg

In January, we announced production commenced from our Floyd Fault Block Sullivan C-33 from the shallowest pay intervals at an initial rate of 9.5 MMcfe per day. Subsequently, the deeper pay intervals were added to the production stream and the production rate increased to 10.6 MMcfe per day. We retained a 100% working interest in the well, subject to a 33% back-in after payout.

In March, the Dawson #1S, an offset to our high rate Sullivan F-33, commenced production from the Dawson Sand at an initial rate of 2.7 MMcfe per day. We are in the process of commingling the shallower Loma Blanca Sand into the production stream.

Also in March, we commenced drilling the first of three Vicksburg development wells that have the potential to add meaningful development drilling locations. The first well, the Triple Crown Field Sullivan C-35, was successfully drilled and found apparent pay in the Brigham, 9,800’, Loma Blanca and Dawson Sands. Casing has been set and completion is underway with the well expected to commence producing to sales by the end of May. The successful completion of the C-35 likely sets up additional upper Vicksburg development drilling locations.

We are currently commencing the Triple Crown Sullivan #14, which will test upper and lower Vicksburg intervals. With success, the Sullivan #14 also establishes additional development drilling locations. In June, we anticipate spudding the last well in the three well line, the Home Run Sullivan #15. This well will be located structurally high at various lower Vicksburg intervals and could prove up additional development drilling in the Home Run Field.

Southern Louisiana

In late-January, we announced that our first Bayou Postillion development well, the Cotten Land #3, encountered 30 feet of pay in the primary objective and an additional 50 feet of unexpected shallower pay. In March, the Cotten Land #3 commenced production to sales and is currently producing 28 MMcfe per day. We maintain a 47% working interest in the well.

Also in March, we announced that our second Bayou Postillion development well, the Marie Snyder #1, commenced production and is currently producing 17 MMcfe per day. The Marie Snyder #1 extends the gas water contact, indicating that reserves are potentially larger than originally anticipated in this fault block. We maintain a 13% working interest in the well.

In May, we spud the first of two additional development wells in Bayou Postillion, the Cotten Land #2. This well is in a fault block adjacent to our Cotten Land #1, which is currently producing 15 MMcfe per day, and provides the potential for booking additional reserves if successful. Following the Cotten Land #2, in June we anticipate spudding the Cotten Land #4, which should encounter an Oligocene objective structurally flat to the Cotten Land #1.

In early January, we announced that our first well in the Mystic Bayou complex, the Williams Land #1, did not encounter reservoir quality sands and was plugged and abandoned.

Anadarko Basin

In March, we announced that the Mills Ranch 96#1 commenced production at an initial rate of 4.5 MMcf of natural gas per day from the lower, middle and upper Hunton intervals despite the fact that production tubing had yet to be installed. Subsequent to initiating production from the Hunton, a production log of the well determined that only seven of the 100 perforations were open and producing. Operations are currently underway to reperforate and stimulate the remaining Hunton intervals, install production tubing and commingle the Viola pay section. The deeper Viola pay interval was producing 3 MMcf of natural gas per day prior to being shut in. We maintain a 75% working interest in the Mills Ranch 96#1.

Also in March, we indicated that the Mills Ranch 98#2 remediation operation was unsuccessful and the well was temporarily abandoned. We are currently evaluating a sidetrack of the well and anticipate drilling the sidetrack later in 2007 or in the first half of 2008.

Rocky Mountains

Powder River Basin

The Werner #1-14H was spud in March 2007 and drilling was completed in early May after reaching a total depth of 10,235 feet. Approximately 3,100 feet of lateral hole was drilled in the Mowry and we encountered significant fracturing and strong oil shows during drilling of the well. We plan to install a pre-perforated liner and commence production testing of the entire length of the lateral upon completion. Following the Werner well, we plan on commencing drilling the State #1-16H in May.

We are currently continuing completion operations on our two 2006 wells drilled in the region, the Krejci Federal #3-29H and the Mill Trust 1-12H. The Krecji is currently producing 55 to 65 barrels of oil per day. Given that the rate is lower than the previously tested cased and open hole intervals, we believe it is likely that there is an obstruction limiting hydrocarbon entry and plan to commence operations to clean out the borehole. We are testing the outer 415 feet of open hole on the Mill Trust, which is currently producing 10 to 20 barrels of oil per day. Late in the second quarter or early in the third quarter 2007, we anticipate fracture stimulating the approximate 885 feet of cased lateral, which experienced strong shows during drilling.

Williston Basin

Our first well in McKenzie County, North Dakota, the Field 18-19 #1H, is currently producing between 40 and 60 barrels of oil and 30 to 50 Mcf or natural gas per day. Our second well in the county, the Erickson, is currently producing between 80 and 100 barrels of oil and 70 to 90 Mcf of natural gas per day. We plan to fracture stimulate our third well, the Mracheck 15-22 1-H by the end of May. Currently, the Mracheck is on rod pump and is producing between 20 and 30 barrels of oil and 10 to 20 Mcf of natural gas per day.

On April 23, 2007, we announced the formation of joint ventures in the Williston Basin in Mountrail County, North Dakota and Sheridan County, Montana. The joint ventures provide for participation in a total of approximately 30,300 gross and 24,350 net acres. The Mountrail County joint venture, which totals approximately 5,120 gross and 3,000 net acres, is proximate to high rate producing wells where the pace of drilling activity is rapidly accelerating. The other joint venture is located in Sheridan County, Montana, a portion of which underlies an 85 square mile proprietary 3-D shoot that we previously acquired. We expect to drill four wells in 2007, two in Mountrail County and two in Sheridan County. Subsequent to the implementation of the joint ventures, we have over 150,000 net acres in the Williston Basin.

Subsequent Events

On April 9, 2007, we issued $35 million in 9 5/8% senior notes due 2014. The notes were issued as an add-on to our existing $125 million of 9 5/8% senior notes due 2014 under the indenture dated April 20, 2006. The add-on notes were priced at 99.50% of face value to yield 9.721% and were issued under a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”). We are in the process of completing an offering to exchange the unregistered notes for registered notes. The unregistered notes may not be offered or sold in the United States without registration or an applicable exemption from the registration requirements of the Securities Act. We used the proceeds from the add-on offering to repay amounts outstanding under our existing senior credit agreement and for general corporate purposes. Upon completion of the add-on, we had outstanding $160 million in 9 5/8% senior notes due 2014 (collectively the “Senior Notes”). We do not anticipate expanding our previously announced capital expenditure budget as a result of the add-on transaction. For a further description of the Senior Notes, see Liquidity and Capital Resources — Sources of Capital — 9 5/8% Senior Notes Due 2014.

At March 31, 2007, we had $500,000 of property held for sale recorded on our consolidated balance sheet. During April 2007, we sold the property held for sale to a third party for $600,000.

First Quarter 2007 Results

Comparison of the three-month periods ended March 31, 2007 and 2006.

Production volumes


	Three Months Ended March 31,
	2007		% Change			2006
Oil (MBbls)		122		6	%		115
Natural gas (MMcf)		2,982		17	%		2,545
Total (MMcfe)(1)		3,712		15	%		3,235
Average daily production (MMcfe/d) (2)		41.2					35.9


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

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

Natural gas represented 80% of our first quarter 2007 production volumes, compared to 79% in the first quarter of last year.

Revenues, Commodity Prices and Hedging

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


	Three Months Ended March 31,
	2007			% Change			2006
	(In thousands)
Oil revenue:
Oil revenue	$	6,663			(6	%)	$	7,068
Oil derivative settlement gains (losses)		113			NM			(50	)

Oil revenue including oil derivative settlements	$	6,776			(3	%)	$	7,018
Oil derivative unrealized gains (losses)		(353	)		NM			23

Oil revenue including derivative settlements and unrealized gains (losses)	$	6,423			(9	%)		7,041
Natural gas revenue:
Natural gas revenue	$	21,823			17	%	$	18,647
Natural gas derivative settlement gains (losses)		1,311			5600	%		23


	Three Months Ended March 31,
	2007			% Change			2006
	(In thousands)
Natural gas revenue including derivative settlements	$	23,134			24	%	$	18,670
Natural gas derivative unrealized gains (losses)		(4,563	)		3091	%		(143	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	18,571			0	%		18,527
Oil and natural gas revenue:
Oil and natural gas revenue	$	28,486			11	%	$	25,715
Oil and natural gas derivative settlement gains (losses)		1,424			NM			(27	)

Oil and natural gas revenue including derivative settlement gains (losses)		29,910			16	%		25,688
Oil and natural gas derivative unrealized gains (losses)		(4,916	)		3997	%		(120	)

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		24,994			(2	%)		25,568
Other revenue		27			NM			(22	)

Total revenue	$	25,021			(2	%)	$	25,546

Average oil prices:
Oil price (per Bbl)	$	54.75			(11	%)	$	61.40
Oil price including derivative settlement gains (losses) (per Bbl)		55.68			(9	%)		60.97
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)		52.78			(14	%)		61.17
Average natural gas prices:
Natural gas price (per Mcf)	$	7.32			0	%	$	7.33
Natural gas price including derivative settlement gains (losses) (per Mcf)		7.76			6	%		7.34
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	6.23			(14	%)	$	7.28
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	7.67			(4	%)	$	7.95
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		8.05			1	%		7.94
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	6.73			(15	%)	$	7.90


	For the three
	month periods
	ended March 31,
	2007 and 2006
	(In thousands)
Change in revenue from the sale of oil:
Price variance impact	$	(809	)
Volume variance impact		404
Cash settlement of derivative hedging contracts		163
Unrealized gains (losses) due to a derivative hedging contracts		(376	)

Total change	$	(618	)

Change in revenue from the sale of natural gas:
Price variance impact	$	(36	)
Volume variance impact		3,212
Cash settlement of derivative hedging contracts		1,288
Unrealized gains (losses) due to a derivative hedging contracts		(4,420	)

Total change	$	44


Change in revenue from the sale of oil and natural gas:
Price variance impact	$	(846	)
Volume variance impact		3,617
Cash settlement of derivative hedging contracts		1,451
Unrealized gains (losses) due to a derivative hedging contracts		(4,796	)

Total change	$	(574	)

First quarter 2007 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses), decreased $0.6 million, or 2%, when compared to the first quarter 2006. The change in revenues was attributable to the following:

•		a $4.9 million unrealized derivative loss in first quarter 2007 versus a $0.1 million unrealized derivative loss in first quarter 2006 decreased revenues by $4.8 million. In October 2006, we de-designated all derivatives that were previously classified as cash flow hedges and as such began using mark-to-market accounting for these derivatives. Subsequent to September 30, 2006, all newly executed derivatives are undesignated and therefore subject to mark-to-market accounting. Mark-to-market accounting requires that we record both derivative settlements and unrealized gains (losses) to the consolidated statement of operations within a single income statement line item. On October 1, 2006, we began including both derivative settlements and unrealized gains (losses) within revenue. As such, amounts that were previously recorded in other comprehensive income or other income (expense) are instead incorporated within revenue.

•		a 4% decrease in the sales price we received for our oil and natural gas resulted in a $0.8 million decrease in revenues from oil and natural gas sales;

•		a 15% increase in production volumes for the quarter resulted in a $3.6 million increase in oil and natural gas sales; and

•		a $1.4 million gain from the settlement of derivative contracts in the first quarter 2007 versus no gain (loss) in first quarter 2006 increased revenue by $1.4 million.

Hedging.We utilize collars and three way costless collars 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 following table details derivative contracts that settled during first quarter 2007 and 2006 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon settlement.


	Three months ended March 31,
	2007		% Change			2006
*Oil collars*
Volumes (Bbls)		76,000		198	%		25,500
Average floor price ($ per Bbl)	$	55.76		7	%	$	52.12
Average ceiling price ($ per Bbl)	$	79.05		22	%	$	64.76
Gain (loss) upon settlement ($ in thousands)	$	113		NM		$	(50	)

*Oil written puts*
Volumes (Bbl)		—		NM			18,000
Average price ($ per Bbl)	$	—		NM		$	38.00
Gain (loss) upon settlement ($ in thousands)	$	—		NM		$	—

*Total oil*
Gain (loss) upon settlement ($ in thousands)	$	113		NM		$	(50	)

*Natural gas collars*
Volumes (MMbtu)		1,805,000		201	%		600,000
Average floor price ($ per MMbtu)	$	7.58		(11	%)	$	8.49
Average ceiling price ($ per MMbtu)	$	16.15		49	%	$	10.84
Gain (loss) upon settlement ($ in thousands)	$	1,311		901	%	$	131

*Natural gas written puts*
Volumes (MMbtu)		—		NM			600,000
Average price ($ per MMbtu)	$	—		NM		$	7.05
Gain (loss) upon settlement ($ in thousands)	$	—		NM		$	(108	)

*Total gas*
Gain (loss) upon settlement ($ in thousands)	$	1,311		5600	%		23

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

Operating costs and expenses

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


	Unit-of-Production								Amount
	(Per Mcfe)								(In thousands)
	Three months ended March 31,								Three months ended March 31,
	2007			% Change			2006		2007			% Change			2006
Production costs:
Operating & maintenance	$	0.62			(5	%)	$	0.65	$	2,304			10	%	$	2,098
Expensed workovers		(0.04	)		NM			0.04		(142	)		NM			125
Ad valorem taxes		0.11			(27	%)		0.15		407			(20	%)		507

Lease operating expenses	$	0.69			(18	%)	$	0.84	$	2,569			(6	%)	$	2,730

Production taxes		0.02			(94	%)		0.35		71			(94	%)		1,144

Production costs	$	0.71			(40	%)	$	1.19	$	2,640			(32	%)	$	3,874

First quarter 2007 per unit of production costs decreased 40% when compared to the first quarter last year because of the following:

•		production taxes decreased $0.33 per Mcfe, or 94%, due to production tax refunds received on the D.J. Sullivan C-31, the Dawson State #3, Hobart 60 #4, and the Dawson State #4;

•		ad valorem taxes decreased $0.04 per Mcfe, or 27%, due to a decrease in estimated property valuations for our oil and natural gas properties;

•		O&M expense decreased $0.03 per Mcfe, or 5%, due to lower saltwater disposal and chemical treating costs; and

•		expense workovers decreased $0.08 per Mcfe as we reversed over-accrued workover expense booked in the fourth quarter 2006.

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


	Three months ended March 31,
	2007			% Change			2006
	(In thousands, except per unit measurements)
General and administrative costs	$	4,229			28	%	$	3,294
Capitalized general and administrative costs		(2,051	)		34	%		(1,525	)

General and administrative expenses	$	2,178			23	%	$	1,769


General and administrative expense ($ per Mcfe)	$	0.59			9	%	$	0.54

Our general and administrative expenses in the first quarter 2007 were $0.05 per Mcfe higher than the first quarter 2006. General and administrative costs before capitalization increased $0.9 million because of increased employee compensation expense, of which $0.3 million was attributable to non-cash stock option expense under FAS 123R.

Depletion of oil and natural gas properties. Our depletion expense is driven by many factors including certain costs spent in the exploration for and development of producing reserves, production levels, and estimates of proved reserve quantities and future developmental costs at the end of the year.


	Three months ended March 31,
	2007		% Change			2006
	(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	13,959		36	%	$	10,256
Depletion of oil and natural gas properties ($ per Mcfe)	$	3.76		19	%	$	3.17

Our depletion expense for the first quarter 2007 was $3.7 million higher than the first quarter 2006. Approximately 59% of the increase was due to an increase in our depletion rate while the remaining 41% of the increase was due to an increase in our production volumes. The increase in our depletion rate for the quarter 2007 was primarily a result of an increase in the cost of reserve additions.

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


	Three months ended March 31,
	2007			% Change			2006
	(In thousands)
Interest on Senior Notes	$	3,008			NM		$	—
Interest on senior credit facility	$	763			27	%		601
Interest on senior subordinated notes (a)		—			NM			578
Commitment fees		48			0	%		48
Dividend on mandatorily redeemable preferred stock		149			0	%		149
Amortization of deferred loan and debt issuance cost		205			72	%		119
Other general interest expense		1			(67	%)		3
Capitalized interest expense		(757	)		85	%		(409	)

Net interest expense	$	3,417			214	%	$	1,089


Weighted average debt outstanding	$	171,733			110	%	$	81,594
Average interest rate on outstanding indebtedness (b)		9.4	%					6.8	%


a)		Includes the effects of interest rate swaps.

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

First quarter 2007 interest expense was $2.3 million higher primarily due to a 110% increase in the weighted average debt outstanding and a higher weighted average cost of debt attributable to our April 2006 issuance of Senior Notes.

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

Other income (expense) included:


	Three months ended March 31,
	2007		% Change			2006
	(In thousands)
Other income (expense):
Non-cash gain (loss) for ineffective portion of cash flow hedges	$	—		(100	%)	$	835
Non-cash gain (loss)		40		NM			(42	)
Cash income (expense)		150		32	%		114

Total other income (loss)	$	190		(79	%)	$	907

Other non-cash income decreased in the first quarter 2007 versus the comparable period last year because, as described above, we de-designated all derivatives. All de-designated derivatives are marked-to market and the resulting gain (loss) is recorded to revenue rather than other income (expense).

Income taxes.We recorded deferred federal income tax expense of $1.2 million in the first quarter of this year, compared to deferred federal income tax expense of $3.5 million in the first quarter last year. The decrease in our deferred federal income taxes was primarily due to lower first quarter 2007 income before income taxes.

In May 2006, the State of Texas enacted legislation establishing a new franchise tax (referred to as the “Margin Tax”) based on modified gross income. As a result, we began recognizing deferred state income taxes in the second quarter 2006. As of December 31, 2006, we recognized deferred state tax expenses of $1.2 million consisting mainly of the Margin Tax. We recorded a deferred state tax benefit of $0.2 million in the first quarter of this year, consisting mainly of the Margin Tax.

For the first three months of 2007, the following table reconciles the difference between the statutory tax rate of 35% and the effective tax rate of 34.67%:


	Three months ended
	March 31, 2007			Tax Rate
	(In thousands)
*Reconciliation to effective tax rate:*
Tax at the statutory rate	$	1,004			35.00	%
Add the effect of:
Non-deductible expenses		1			0.01	%
Preferred stock dividends		52			1.82	%
Incentive stock options not exercised		68			2.37	%
Margin Tax and other state taxes (after-tax)		(120	)		(4.17	%)
Other		(10	)		(0.36	%)

Total	$	995			34.67	%

Capital Expenditures

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

	•		Cost of acquiring and maintaining our lease acreage position and our seismic resources;

	•		Cost of drilling and completing new oil and natural gas wells;

	•		Cost of installing new production infrastructure;

	•		Cost of maintaining, repairing and enhancing existing oil and natural gas wells;

	•		Cost related to plugging and abandoning unproductive or uneconomic wells; and

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

The table below summarizes our 2007 oil and gas capital expenditure budget, the amount spent through March 31, 2007 and the amount of our 2007 oil and gas capital expenditure budget that remains to be spent.


			Amount
			Spent Through		Amount
	2007 Budget		March 31, 2007		Remaining (a)
	(In millions)
Drilling	$	91.2	$	28.7	$	62.5
Net land and seismic		11.2		2.9		8.3
Capitalized costs (b)		11.5		2.8		8.7
Asset retirement obligation		1.0		0.2		0.8

Total oil and gas capital expenditures (c)	$	114.9	$	34.6	$	80.3


(a)		Calculated based on the 2007 capital expenditure budget announced in February 2007 less amount spent through March 31, 2007.

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

(c)		Excludes other property capital expenditures.

Determination of Capital Expenditure Budget

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

This value creation measure and the final determination with respect to our 2007 budgeted expenditures will depend on a number of factors, including:

	•		Changes in commodity prices;

	•		Variances in forecasted production and the resulting production of our newly drilled wells;

	•		Variances in our production levels from our existing oil and gas properties;

	•		Variances in a prospect’s risked reserve size;

	•		Variances in drilling and completion costs, service costs and the availability of drilling equipment;

	•		Variances in the availability and timing of drilling and completion services;

	•		Economic and industry conditions at the time of drilling; and

	•		The availability of more economically attractive prospects.

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

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2007, we intend to fund our capital expenditure program and contractual commitments with cash flows from operations, borrowings under our Senior Notes and senior credit agreement, reimbursements of prior land and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties or alternative financing sources.

9 5/8% Senior Notes Due 2014

On April 9, 2007, we issued $35 million in Senior Notes. The Senior Notes were issued as an add-on to our existing $125 million of Senior Notes under the indenture dated April 20, 2006. The add-on notes were priced at 99.50% of face value to yield 9.721% and were issued under a transaction exempt from the registration requirements of the Securities Act of 1933 (the “Securities Act”). We are in the process of completing an offering to exchange the unregistered notes for registered notes. The unregistered notes may not be offered or sold in the United States without registration or an applicable exemption from the registration requirements of the Securities Act. We used the proceeds from the add-on offering to repay amounts outstanding under our existing senior credit agreement and for general corporate purposes. Upon completion of the add-on, we had outstanding $160 million in Senior Notes.

In April 2006, we issued $125 million of Senior Notes. The notes were priced at 98.629% of their face value to yield 9.875%. We entered into the Indenture, among us, the Guarantors and Wells Fargo Bank, N.A., as trustee, relating to the Senior Notes. The April 2006 Senior Notes were originally issued in a transaction exempt from the registration requirements of the Securities Act of 1933. We have since completed an exchange offer to exchange all of the unregistered April 2006 Senior Notes for registered Senior Notes.

The notes are fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P.(the “Guarantors”). We are obligated to pay the $160 million of Senior Notes in cash upon maturity in May 2014. Beginning November 2006, we paid 9 5/8% interest on the $125 million outstanding. Beginning in May 2007, we paid interest on the $160 million outstanding. Future interest payments are due semi-annually in arrears in November and May of each year.

The Senior Notes are our unsecured senior obligations, and:

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

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

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

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

Additionally, the Indenture contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the Senior Notes as of March 31, 2007.

Senior Credit Agreement

In June 2005, we amended and restated our $100 million senior credit agreement to provide for revolving credit borrowings up to $200 million and to extend the maturity of the agreement from March 2009 to June 2010. In April 2006, in conjunction with the issuance of our Senior Notes, the borrowing base was reset to $50 million. In November 2006, we concluded our semi-annual redetermination process, which is described in further detail below, and at that time the borrowing base was reset to $110 million. In April 2007, in conjunction with the issuance of our Senior Notes add-on, the borrowing base was reset to $101 million.

As of March 31, 2007, we had $61.5 million outstanding and $48.5 million of unused committed borrowing capacity available under our senior credit agreement. In April 2007, proceeds from the Senior Notes add-on were used to repay amounts outstanding under the senior credit agreement. As of April 30, 2007, we had $33.1 million of borrowings outstanding under the senior credit agreement. We strive to manage the amounts we borrow under our senior credit agreement in order to maintain excess borrowing capacity.

Since the borrowing base for our senior credit agreement is re-determined at least semi-annually, the amount of borrowing capacity available to us under our senior credit agreement could fluctuate. While we do not expect the amount that we have borrowed under our senior credit agreement to exceed the borrowing base, in the event that the borrowing base is adjusted below the amount that we have borrowed, our access to further borrowings will be reduced, and we may not have the resources necessary to carry out our planned spending for exploration and development activities. The next semi-annual borrowing base redetermination is anticipated to be concluded in May 2007.

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


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


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

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


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

Our senior credit agreement also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at March 31, 2007 and interest coverage ratio for the twelve-month period ended March 31, 2007 were 2.20 to 1 and 7.52 to 1, respectively. As of March 31, 2007, we were in compliance with all covenant requirements in connection with our senior credit agreement.

Access to the committed and undrawn portion of our borrowing base could be limited based on the covenants that are part of the indenture governing the Senior Notes. 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.

Mandatorily Redeemable Preferred Stock

As of March 31, 2007, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC. We are required to satisfy all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

Access to Capital Markets

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

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

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

Off Balance Sheet Arrangements

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

Analysis of Changes In Cash and Cash Equivalents

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


	Three months ended March 31,
	2007			%Change			2006
	(In thousands)
Net income	$	1,873			(68	%)	$	5,875
Non-cash items		20,785			50	%		13,889
Changes in working capital and other items		(7,074	)		NM			6,424

Cash flows provided by operating activities	$	15,584			(40	%)		26,188
Cash flows used by investing activities		(48,222	)		44	%		(33,492	)
Cash flows provided by financing activities		35,489			220	%		11,082

Net increase in cash and cash equivalents	$	2,851			(25	%)	$	3,778

Analysis of net cash provided by operating activities

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

For the first three months of 2007, cash flows provided by operating activities decreased by 40% to $15.6 million from the same period last year. The decrease in operating cash flow is attributable to a decrease in accounts payable in the current period while accounts receivable decreased in the first quarter 2006.

Analysis of changes in cash flows used in investing activities


	Three months ended March 31,
	2007		%Change			2006
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	28,677		(7	%)	$	30,807
Land and seismic		2,936		(59	%)		7,172
Capitalized cost		2,808		37	%		2,057
Capitalized asset retirement obligation		207		97	%		105

Total	$	34,628		(14	%)	$	40,141


Reconciling Items:
Change in accrued drilling costs	$	13,533		NM		$	(6,240	)
Other		61		NM			(409	)

Total Reconciling Items		13,594		NM			(6,649	)

Net cash used in investing activities	$	48,222		44	%	$	33,492

Net cash used by investing activities in the first quarter 2007 increased by $14.7 million, or 44%, over the same period in 2006. The following were the reasons for the change:

	•		a decrease in accrued drilling cost changed cash used by investing activities by $19.8 million;

	•		capitalized costs increased by $0.8 million;

	•		drilling capital expenditures decreased by $2.1 million; and

	•		land and seismic expenditures decreased by $4.2 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first quarter 2007 was 220% higher than the first quarter 2006. During first three months of 2007, we borrowed $35.6 million under our senior credit agreement compared to $11.2 million of borrowings during the first quarter 2006.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the three months ended March 31, 2007 and 2006.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
*2007 common stock transactions:*
Exercise of employee stock options		5,000	$	23

*2006 common stock transactions:*
Exercise of employee stock options		24,200	$	153

Other Matters

Derivative Instruments

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

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

Effects of Inflation and Changes in Prices

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

Environmental and Other Regulatory Matters

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

New Accounting Pronouncements

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

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

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

Forward Looking Information

We or our representatives may make forward looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and natural gas production, the number of wells we anticipate drilling during 2007 and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in our Form 10-K report for the year ended December 31, 2006 including, but not limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and written forward looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

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

Derivative Instruments and Hedging Activities

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

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

During 2006, we were party to natural gas costless collars, natural gas three-way costless collars, natural gas basis swaps, oil costless collars, oil three-way costless collars and interest rate swaps.

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

A three-way costless collar consists of a costless collar (purchased put option and written call option) plus a put (written put) sold by us with a price below the floor price (purchased put option) of the costless collar. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. The written put requires us to make a payment to our counterparty if the settlement price for a period is below the written put price. Combining the costless collar (purchased put option and written call option) with the written put results in us being entitled to a net payment equal to the difference between the floor price (purchased put option) of the costless collar and the written put price if the settlement price is equal to or less than the written put price. If the settlement price is greater than the written put price, the result is the same as it would have been with a costless collar. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while offsetting the associated cost with the sale of the written put. Prior to October 1, 2006, the costless collar portion of the three-way costless collar was designated as a cash flow hedge while the written put was undesignated.

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

The following tables reflect our open natural gas and oil derivative contracts as of March 31, 2007, the associated volumes and the corresponding weighted average NYMEX floor and cap price.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
04/01/07 - 04/30/07		150,000	$	7.00	$	8.00
04/01/07 - 04/30/07		60,000	$	7.00	$	10.00
04/01/07 - 10/31/07		280,000	$	7.00	$	15.45
04/01/07 - 10/31/07		280,000	$	7.25	$	15.25
04/01/07 - 10/31/07		280,000	$	7.00	$	14.85
04/01/07 - 10/31/07		700,000	$	7.50	$	11.00
04/01/07 - 10/31/07		350,000	$	7.00	$	11.60
04/01/07 - 10/31/07		350,000	$	7.00	$	9.10
04/01/07 - 10/31/07		350,000	$	7.25	$	9.60
05/01/07 - 05/31/07		50,000	$	7.00	$	10.00
06/01/07 - 06/30/07		40,000	$	7.00	$	10.00
05/01/07 - 05/31/07		130,000	$	7.00	$	8.00
05/01/07 - 10/31/07		600,000	$	7.00	$	9.55
06/01/07 - 06/30/07		100,000	$	7.00	$	8.00
07/01/07 - 07/31/07		30,000	$	7.00	$	10.00
08/01/07 - 08/31/07		20,000	$	7.00	$	10.00
07/01/07 - 07/31/07		80,000	$	7.00	$	8.00
08/01/07 - 08/31/07		60,000	$	7.00	$	8.00
09/01/07 - 09/30/07		40,000	$	7.00	$	9.35
10/01/07 - 10/31/07		30,000	$	7.00	$	9.35
11/01/07 - 11/30/07		50,000	$	8.00	$	10.20
11/01/07 - 03/31/08		250,000	$	8.00	$	13.40
11/01/07 - 03/31/08		300,000	$	8.85	$	15.00
11/01/07 - 03/31/08		300,000	$	9.30	$	15.00
11/01/07 - 03/31/08		500,000	$	7.50	$	13.30
11/01/07 - 03/31/08		250,000	$	8.00	$	12.65
12/01/07 - 12/31/07		40,000	$	8.00	$	10.20
01/01/08 - 01/31/08		30,000	$	8.00	$	10.20
02/01/08 - 02/29/08		20,000	$	8.00	$	10.20
03/01/08 - 03/31/08		10,000	$	8.00	$	10.20
04/01/08 - 09/30/08		420,000	$	6.75	$	9.75
04/01/08 - 09/30/08		540,000	$	7.00	$	9.68


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars*
04/01/07 - 06/30/07		12,000	$	59.00	$	90.00
04/01/07 - 12/31/07		9,000	$	55.00	$	79.00
04/01/07 - 04/30/07		3,000	$	60.00	$	74.75
04/01/07 - 04/30/07		5,000	$	60.00	$	76.00
04/01/07 - 05/31/07		12,000	$	55.00	$	80.30
04/01/07 - 09/30/07		30,000	$	50.00	$	81.50
04/01/07 - 09/30/07		12,000	$	56.00	$	92.50
05/01/07 - 05/31/07		4,000	$	60.00	$	76.00
05/01/07 - 04/30/08		24,000	$	60.00	$	74.75
06/01/07 - 06/30/07		3,000	$	60.00	$	76.00
06/01/07 - 07/31/07		8,000	$	55.00	$	80.30
06/01/07 - 08/31/07		6,000	$	65.00	$	80.00
07/01/07 - 08/31/07		4,000	$	60.00	$	76.00


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
07/01/07 - 10/31/07		10,000	$	58.00	$	90.50
08/01/07 - 10/31/07		9,000	$	55.00	$	80.30
09/01/07 - 09/30/07		3,000	$	60.00	$	76.00
10/01/07 - 10/31/07		2,000	$	60.00	$	76.00
10/01/07 - 12/31/07		9,000	$	59.20	$	90.00
10/01/07 - 03/31/08		18,000	$	56.00	$	89.95
10/01/07 - 03/31/08		6,000	$	65.00	$	80.25
11/01/07 - 12/31/07		4,000	$	55.00	$	80.30
11/01/07 - 12/31/07		2,000	$	60.00	$	76.00
11/01/07 - 03/31/08		10,000	$	68.40	$	90.00
01/01/08 - 03/31/08		7,500	$	57.60	$	90.00
01/01/08 - 12/31/08		24,000	$	57.50	$	75.50
04/01/08 - 10/31/08		21,000	$	65.70	$	90.00
04/01/08 - 12/31/08		18,000	$	57.50	$	76.00

The following table reflects commodity derivative contracts entered into subsequent to March 31, 2007, the associated volumes and the corresponding weighted average NYMEX floor and cap prices.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
06/01/07 - 10/31/07		750,000	$	7.00	$	10.20
04/01/08 - 10/31/08		350,000	$	7.25	$	10.40

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 2007, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our principal executive officer and our principal financial officer concluded that the design and operation of our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the first quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

None.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

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

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

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 3, 2007.


	BRIGHAM EXPLORATION COMPANY
	By:	/s/ BEN M. BRIGHAM
		Ben M. Brigham
		Chief Executive Officer, President and Chairman of the Board


	By:	/s/ EUGENE B. SHEPHERD, JR.
		Eugene B. Shepherd, Jr.
		Executive Vice President and Chief Financial Officer

EXHIBIT INDEX


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

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

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

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Brigham Exploration (BEXP) Inactive 10-Q2007 Q1 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents