Form 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2010


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: 001-34224

Brigham Exploration Company

(Exact name of registrant as specified in its charter)


Delaware (State of other jurisdiction of incorporation or organization)		75-2692967 (I.R.S. Employer Identification No.)

6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas (Address of principal executive offices)		78730 (Zip Code)

(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 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232 405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

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


Large Accelerated Filer o	Accelerated Filer þ	Non-Accelerated Filer o	Smaller Reporting Company o
		(Do not check if smaller reporting company)

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

Yes o No þ


Class		Outstanding
Common Stock, par value $.01 per share as of August 4, 2010		116,610,421

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)


	June 30,			December 31,
	2010			2009

ASSETS
Current assets:
Cash and cash equivalents	$	82,822		$	40,781
Accounts receivable		37,671			21,194
Short-term investments		250,354			80,093
Inventory		17,757			14,087
Other current assets		7,749			2,284

Total current assets		396,353			158,439

Oil and natural gas properties, using the full cost method including Proved, net of accumulated depletion of $388,954 and $365,496		365,249			254,424
Unproved		82,020			76,309

		447,269			330,733

Other property and equipment, net		8,284			3,025
Deferred loan fees		4,425			5,213
Other noncurrent assets		5,881			846

Total assets	$	862,212		$	498,256


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	44,825		$	19,251
Royalties payable		24,182			8,268
Accrued drilling costs		45,347			15,498
Participant advances received		4,415			6,949
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 December 31, 2009		—			10,101
Other current liabilities		5,719			7,706

Total current liabilities		124,488			67,773


Senior Notes		159,087			158,968

Other noncurrent liabilities		5,622			7,232

Commitments and contingencies (Note 4)

Stockholders’ equity:
Common stock, $.01 par value, 180 million shares authorized, 116,142,287 and 99,593,075 shares issued and 115,882,141 and 99,351,825 shares outstanding at June 30, 2010 and December 31, 2009, respectively		1,161			996
Additional paid-in capital		760,209			479,077
Treasury stock, at cost; 260,146 and 241,250 shares at June 30, 2010 and December 31, 2009, respectively		(2,405	)		(2,133	)
Accumulated other comprehensive income (loss)		(2,286	)		(205	)
Retained earnings (deficit)		(183,664	)		(213,452	)

Total stockholders’ equity		573,015			264,283

Total liabilities and stockholders’ equity	$	862,212		$	498,256

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

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

Revenues:
Oil and natural gas sales	$	40,564		$	13,209		$	69,494		$	27,018
Gain (loss) on derivatives, net		4,362			(2,727	)		7,996			1,916
Other revenue		4			32			13			66

		44,930			10,514			77,503			29,000

Costs and expenses:
Lease operating		4,371			3,573			8,720			7,372
Production taxes		3,900			831			6,408			1,645
General and administrative		2,711			2,264			5,797			4,386
Depletion of oil and natural gas properties		14,247			6,233			23,458			16,066
Impairment of oil and natural gas properties		—			—			—			114,781
Depreciation and amortization		261			167			494			316
Accretion of discount on asset retirement obligations		104			105			209			206
Loss on inventory valuation		—			128			—			2,167

		25,594			13,301			45,086			146,939

Operating income (loss)		19,336			(2,787	)		32,417			(117,939	)


Other income (expense):
Interest income		887			111			1,340			204
Interest expense, net		(2,931	)		(4,251	)		(5,835	)		(8,378	)
Other income (expense)		1,181			(33	)		1,866			82

		(863	)		(4,173	)		(2,629	)		(8,092	)

Income (loss) before income taxes		18,473			(6,960	)		29,788			(126,031	)

Income tax expense:
Current		—			—			—			—
Deferred		—			—			—			—

		—			—			—			—

Net income (loss)		18,473		$	(6,960	)	$	29,788		$	(126,031	)

Net income (loss) per share available to common stockholders:
Basic	$	0.16		$	(0.12	)	$	0.28		$	(2.39	)

Diluted	$	0.16		$	(0.12	)	$	0.27		$	(2.39	)


Weighted average shares outstanding:
Basic		113,426			59,687			106,473			52,745

Diluted		115,383			59,687			108,491			52,745

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

PART I — FINANCIAL INFORMATION

ITEM 1. 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, 2009		99,593	$	996	$	479,077		$	(2,133	)	$	(205	)	$	(213,452	)	$	264,283
Comprehensive income:
Net income		—		—		—			—			—			29,788			29,788
Unrealized gains (losses) on investments		—		—		—			—			(2,081	)		—			(2,081	)
Tax benefit (provisions)		—		—		—			—			—			—			—

Comprehensive income																		27,707
Issuance of common stock		16,100		161		277,386			—			—			—			277,547
Exercises of employee stock options		379		3		1,851			—			—			—			1,854
Vesting of restricted stock		70		1		(1	)		—			—			—			—
Stock based compensation		—		—		1,896			—			—			—			1,896
Repurchases of common stock		—		—		—			(272	)		—			—			(272	)


Balance, June 30, 2010		116,142	$	1,161	$	760,209		$	(2,405	)	$	(2,286	)	$	(183,664	)	$	573,015

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

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	29,788		$	(126,031	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion of oil and natural gas properties		23,458			16,066
Impairment of oil and natural gas properties		—			114,781
Depreciation and amortization		494			316
Stock based compensation		1,038			797
Amortization of deferred loan fees and debt issuance costs		1,014			626
Market value and other adjustments for derivative instruments		(9,260	)		6,891
Accretion of discount on asset retirement obligations		209			206
Other noncash items		(1	)		35
Changes in operating assets and liabilities:
Accounts receivable		(16,477	)		10,807
Other current assets		(2,210	)		36
Accounts payable		25,574			(4,301	)
Royalties payable		15,914			(2,291	)
Participant advances received		(2,534	)		(1,711	)
Other current liabilities		(56	)		(265	)
Other noncurrent assets and liabilities		(31	)		(15	)

Net cash provided by operating activities		66,920			15,947


Cash flows from investing activities:
Additions to oil and natural gas properties		(122,782	)		(39,703	)
Decrease (increase) in restricted cash		—			555
Changes to inventory		(3,806	)		—
Decrease (increase) in short term investments		(172,342	)		(5,268	)
Additions to other property and equipment		(5,752	)		(1,245	)
Proceeds from the sale of assets		12,544			—
Decrease (increase) in drilling advances paid		(1,654	)		163

Net cash provided (used) by investing activities		(293,792	)		(45,498	)


Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		277,547			93,523
Redemption of Series A mandatorily redeemable preferred stock		(10,101	)		—
Repayment of senior credit facility		—			(35,000	)
Deferred loan fees paid and equity costs		(115	)		(839	)
Proceeds from exercise of employee stock options		1,854			1
Repurchases of common stock		(272	)		(91	)

Net cash provided (used) by financing activities		268,913			57,594

Net increase (decrease) in cash and cash equivalents		42,041			28,043
Cash and cash equivalents, beginning of year		40,781			40,043

Cash and cash equivalents, end of period	$	82,822		$	68,086

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.” 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. Brigham’s exploration and development of oil and natural gas properties is currently focused in the Rocky Mountains, the Gulf Coast, the Anadarko Basin, and West Texas.

2. Basis of Presentation

The accompanying unaudited consolidated financial statements include the accounts of Brigham and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnership 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 (U.S. GAAP). The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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 2009 Annual Report on Form 10-K filed pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

3. Commitments and Contingencies

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

As of June 30, 2010, 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 and six months ended June 30, 2010 and 2009 are as follows (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009

Weighted average common shares outstanding — basic		113,426		59,687		106,473		52,745
Plus: Potential common shares
Stock options and restricted stock		1,957		—		2,018		—

Weighted average common shares outstanding — diluted		115,383		59,687		108,491		52,745


Stock options excluded from diluted EPS due to the anti-dilutive effect		1,087		4,915		1,078		4,915

5. Income Taxes

There was no federal or state income tax expense (benefit) for the six months ended June 30, 2010 and 2009.

Brigham has a net deferred tax asset at June 30, 2010, due to its net operating loss carryovers and ceiling test writedowns in the fourth quarter of 2008 and the first quarter of 2009. However, no net deferred tax asset was recorded on Brigham’s balance sheet at June 30, 2010, due to a valuation allowance required to be recorded in 2008 and 2009. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. After testing to determine if the deferred tax assets would meet the more likely than not criteria, Brigham determined that the valuation allowance should be $67.3 million at June 30, 2010.

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. Brigham has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, Brigham has recorded no uncertain tax liabilities in its consolidated balance sheet.

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 2009, 2008, 2007, and 2006. In addition, Brigham is open to examination for the years 1997 through 2005, resulting from net operating losses generated and available for carryforward.

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.

Natural Gas and Crude Oil Derivative Contracts

Brigham enters into contracts to hedge against the variability in cash flows associated with the forecasted sale of future oil and gas production. Brigham’s cash flow hedges have historically consisted of swaps, purchased put options, costless collars (purchased put options and written call options), and three-way collars (a standard collar plus a sold put below the floor price of the collar). The costless collars and three-way collars are used to establish floor and ceiling prices on anticipated future oil and natural gas production. There are no net premiums paid or received when Brigham enters into these option agreements. Brigham has elected not to designate any of its derivative contracts as cash flow hedges for accounting purposes under Financial Accounting Standards Board Accounting Standards Codification Topic 815 “Derivatives and Hedging” (FASB ASC 815). 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. See Note 7, “Fair Values”, for a discussion of the calculation of the fair values of natural gas and oil derivative contracts. 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.

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at June 30, 2010, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).


	Natural		Crude		Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
07/01/10 - 12/31/10		420,000			$	5.15	$	7.00
07/01/10 - 09/30/10		210,000			$	5.75	$	7.30
07/01/10 - 09/30/10		120,000			$	5.75	$	7.00
07/01/10 - 09/30/10		150,000			$	5.50	$	6.65
10/01/10 - 03/31/11		240,000			$	6.50	$	8.25
10/01/10 - 03/31/11		420,000			$	6.40	$	7.80
01/01/11 - 12/31/11		360,000			$	5.75	$	7.65
01/01/11 - 12/31/11		480,000			$	5.75	$	7.40
04/01/11 - 12/31/11		360,000			$	5.00	$	6.55
*Crude Oil Costless Collars*
07/01/10 - 08/31/10				6,000	$	70.00	$	99.00
07/01/10 - 09/30/10				9,000	$	60.00	$	91.40
07/01/10 - 12/31/10				60,000	$	48.70	$	80.00
07/01/10 - 12/31/10				18,000	$	60.00	$	86.50
07/01/10 - 12/31/10				30,000	$	60.00	$	88.80
07/01/10 - 12/31/10				24,000	$	70.00	$	101.75
07/01/10 - 12/31/10				18,000	$	70.00	$	91.50
07/01/10 - 12/31/10				12,000	$	60.00	$	100.00
07/01/10 - 12/31/10				18,000	$	60.00	$	96.00
07/01/10 - 11/30/10				15,000	$	70.00	$	95.50
07/01/10 - 12/31/10				48,000	$	57.50	$	82.15
07/01/10 - 09/30/10				6,000	$	70.00	$	87.25
07/01/10 - 12/31/10				30,000	$	65.00	$	94.25
07/01/10 - 12/31/10				12,000	$	65.00	$	107.70
07/01/10 - 07/31/10				10,000	$	75.00	$	100.50
07/01/10 - 12/31/10				30,000	$	75.00	$	101.00
08/01/10 - 10/31/10				15,000	$	75.00	$	101.00
08/01/10 - 07/31/12				365,500	$	65.00	$	97.20
08/01/10 - 07/31/12				365,500	$	65.00	$	98.55
08/01/10 - 07/31/12				365,500	$	65.00	$	100.40
08/01/10 - 07/31/12				365,500	$	65.00	$	100.00
10/01/10 - 12/31/10				3,000	$	70.00	$	88.50
01/01/11 - 02/28/11				10,000	$	70.00	$	92.00
01/01/11 - 02/28/11				8,000	$	75.00	$	103.50
01/01/11 - 03/31/11				9,000	$	75.00	$	93.50
01/01/11 - 06/30/11				18,000	$	65.00	$	97.50
01/01/11 - 06/30/11				24,000	$	70.00	$	92.50
01/01/11 - 07/31/11				21,000	$	70.00	$	94.80
01/01/11 - 12/31/11				84,000	$	65.00	$	88.25
01/01/11 - 12/31/11				60,000	$	60.00	$	97.25
01/01/11 - 12/31/11				60,000	$	65.00	$	108.00
01/01/11 - 12/31/11				48,000	$	70.00	$	106.80
01/01/11 - 12/31/11				48,000	$	75.00	$	102.60
01/01/11 - 12/31/11				36,000	$	65.00	$	100.00
01/01/11 - 12/31/11				36,000	$	75.00	$	104.30
03/01/11 - 04/30/11				16,000	$	75.00	$	104.50
07/01/11 - 09/30/11				9,000	$	70.00	$	95.00
07/01/11 - 12/31/11				12,000	$	75.00	$	103.00
07/01/11 - 12/31/11				12,000	$	75.00	$	95.15
10/01/11 - 12/31/11				6,000	$	70.00	$	96.35
01/01/12 - 06/30/12				60,000	$	75.00	$	106.90

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Natural

Crude

Purchased

Gas

Oil

Put

Settlement Period

(MMBTU)

(Barrels)

Nymex

Crude Oil Puts

01/01/11 - 06/30/12

273,500

65.00

01/01/11 - 06/30/12

273,500

65.00

The following table reflects commodity derivative contracts entered subsequent to June 30, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
Crude Oil Costless Collars
03/01/11 - 08/31/11		46,000	$	65.00	$	96.75
03/01/11 - 08/31/11		46,000	$	65.00	$	94.80
05/01/11 - 12/31/11		122,500	$	65.00	$	100.00
09/01/11 - 12/31/11		61,000	$	65.00	$	99.00
09/01/11 - 12/31/11		61,000	$	65.00	$	97.40
01/01/12 - 06/30/12		182,000	$	65.00	$	100.75
01/01/12 - 06/30/12		91,000	$	65.00	$	101.00
01/01/12 - 06/30/12		182,000	$	65.00	$	99.25
01/01/12 - 06/30/12		91,000	$	65.00	$	102.75
07/01/12 - 07/31/12		62,000	$	65.00	$	102.25
07/01/12 - 07/31/12		31,000	$	65.00	$	105.25
05/01/11 - 12/31/11		122,500	$	65.00	$	106.50
11/01/10 - 02/28/11		60,000	$	65.00	$	98.75

Additional Disclosures about Derivative Instruments and Hedging Activities

At June 30, 2010 and December 31, 2009, Brigham had derivative financial instruments under FASB ASC 815 recorded on the consolidated balance sheet as set forth below:


		June 30, 2010			Dec 31, 2009
		Estimated			Estimated
Type of Contract	Balance Sheet Location	Fair Value			Fair Value
		(in thousands)			(in thousands)
Derivatives Not Designated as Hedging Instruments

Derivative Assets:
Natural gas and crude oil contracts	Other current assets	$	4,263		$	1,152
Natural gas and crude oil contracts	Other non-current assets		3,602			186

Total Derivative Assets		$	7,865		$	1,338

Derivative Liabilities:
Natural gas and crude oil contracts	Other current liabilities	$	(474	)	$	(2,404	)
Natural gas and crude oil contracts	Other non-current liabilities		(106	)		(909	)

Total Derivative Liabilities		$	(580	)	$	(3,313	)

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

For the three and six months ended June 30, 2010 and 2009, the effect on income in the consolidated statement of operations for derivative financial instruments under FASB ASC 815 was as follows:


		Three Months			Three Months
		Ended			Ended
		June 30, 2010			June 30, 2009
	Statement of Operations	Amount of			Amount of
Type of Contract	Location of Gain (Loss)	Gain (Loss)			Gain (Loss)
		(in thousands)			(in thousands)
Derivatives Not Designated as Hedging Instruments

Natural gas contracts	Gain (loss) on derivatives, net	$	(594	)	$	529
Crude oil contracts	Gain (loss) on derivatives, net		4,956			(3,256	)

Total Derivative Gain (loss)		$	4,362		$	(2,727	)


		Six Months		Six Months
		Ended		Ended
		June 30, 2010		June 30, 2009
	Statement of Operations	Amount of		Amount of
Type of Contract	Location of Gain (Loss)	Gain (Loss)		Gain (Loss)
		(in thousands)		(in thousands)
Derivatives Not Designated as Hedging Instruments

Natural gas contracts	Gain (loss) on derivatives, net	$	2,661	$	5,397
Crude oil contracts	Gain (loss) on derivatives, net		5,335		(3,481	)

Total Derivative Gain (loss)		$	7,996	$	1,916

The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Brigham’s derivative contracts are with multiple counterparties within its credit facility bank group to minimize its exposure to any individual counterparty and Brigham has netting arrangements with all of its counterparties that provide for offsetting payables against receivables from separate derivative instruments with that counterparty.

7. Fair Values

Brigham adopted Financial Accounting Standards Board Accounting Standards Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820) on January 1, 2008, as it relates to financial assets and liabilities. Brigham adopted FASB ASC 820 on January 1, 2009, as it relates to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by FASB ASC 820 are as follows:

	•		Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

	•		Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

	•		Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

As such, effective January 1, 2008, the fair values of Brigham’s derivative financial instruments reflect Brigham’s estimate of the default risk of the parties in accordance with FASB ASC 820. The fair value of Brigham’s derivative financial instruments is determined based on counterparties’ valuation models that utilize market-corroborated inputs. The fair value of all derivative contracts is reflected on the balance sheet as detailed in the following schedule (in thousands). The current asset and liability amounts represent the fair values expected to be included in the results of operations for the subsequent year.


				Fair Value Measurements at June 30, 2010 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	June 30,			for Identical Assets		Inputs			Inputs
Description	2010			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(474	)	$	—	$	(474	)	$	—
Other non-current liabilities		(106	)		—		(106	)		—
Current derivative assets		4,263			—		4,263			—
Other non-current assets		3,602			—		3,602			—

	$	7,285		$	—	$	7,285		$	—


				Fair Value Measurements at December 31, 2009 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2009			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(2,404	)	$	—	$	(2,404	)	$	—
Other non-current liabilities		(909	)		—		(909	)		—
Current derivative assets		1,152			—		1,152			—
Other non-current assets		186			—		186			—

	$	(1,975	)	$	—	$	(1,975	)	$	—

Brigham’s assessment of the significance of a particular input to the fair value measurement requires judgment and may effect the valuation on the nonfinancial assets and liabilities and their placement in the fair value hierarchy levels. The fair value of Brigham’s asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. These inputs include salvage value, estimated life, working interest, a factor for inflation, and a discount factor. The fair value of the asset retirement obligations is reflected on the balance sheet as detailed below (in thousands).


				Fair Value Measurements at June 30, 2010 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	June 30,			for Identical Assets		Inputs		Inputs
Description	2010			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(5,516	)		—		—		(5,516	)

	$	(5,516	)	$	—	$	—	$	(5,516	)


				Fair Value Measurements at December 31, 2009 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	December 31,			for Identical Assets		Inputs		Inputs
Description	2009			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(6,323	)		—		—		(6,323	)

	$	(6,323	)	$	—	$	—	$	(6,323	)

See Note 13, “Asset Retirement Obligations” for a rollforward of the asset retirement obligation.

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Investments held by Brigham include certificates of deposit, corporate debt, and government securities. The fair value of the investments is reflected on the balance sheet as detailed below (in thousands).


			Fair Value Measurements at June 30, 2010 Using
			Quoted Prices in		Significant Other		Significant
			Active Markets		Observable		Unobservable
	June 30,		for Identical Assets		Inputs		Inputs
Description	2010		(Level 1)		(Level 2)		(Level 3)
Investments		250,354		250,354		—		—

	$	250,354	$	250,354	$	—	$	—


			Fair Value Measurements at December 31, 2009 Using
			Quoted Prices in		Significant Other		Significant
			Active Markets		Observable		Unobservable
	December 31,		for Identical Assets		Inputs		Inputs
Description	2009		(Level 1)		(Level 2)		(Level 3)
Investments		80,093		80,093		—		—

	$	80,093	$	80,093	$	—	$	—

The following table summarizes, by major security type, the fair value and any unrealized gain (loss) of Brigham’s investments (in thousands). The unrealized gain (loss) is recorded on the consolidated balance sheet as other comprehensive income (loss), a component of stockholders’ equity.


	Less Than 12 Months					12 Months or Greater					Total
			Unrealized					Unrealized					Unrealized
	Fair		Gains			Fair		Gains			Fair		Gains
Description of Securities	Value		(Losses)			Value		(Losses)			Value		(Losses)
Certificates of deposit	$	3,605	$	1		$	—	$	—		$	3,605	$	1
Corporate bonds and notes		124,888		(1,273	)		35,631		(654	)		160,519		(1,927	)
Government securities		50,221		(363	)		36,009		(1	)		86,230		(364	)

Total	$	178,714	$	(1,635	)	$	71,640	$	(655	)	$	250,354	$	(2,290	)

The cost basis of Brigham’s investments in certificates of deposit, corporate bonds and notes, and government securities (in thousands) is $3,600, $161,170, and $86,411, respectively.

Brigham’s other financial instruments include cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The carrying value of Brigham’s Senior Credit Facility approximates its fair market value since it bears interest at floating market interest rates. The following are estimated fair values and carrying values of our other financial instruments at each of these dates:


	June 30, 2010				December 31, 2009
	(in thousands)				(in thousands)
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior Notes	$	160,000	$	161,600	$	160,000	$	160,000
Series A Preferred Stock	$	—	$	—	$	10,101	$	10,166

The fair value of Brigham’s Senior Notes (as hereinafter defined) is based upon current market quotes and is the estimated amount required to purchase the Senior Notes on the open market.

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Oil and Gas Properties

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

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

The risk that Brigham will experience a ceiling test write-down increases when oil and gas prices are depressed or if Brigham has substantial downward revisions in its estimated proved reserves. Based on oil and gas prices in effect at the end of March 2009, the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit by $71.9 million, net of tax. As a result, Brigham was required to record a write-down of the net capitalized costs of its oil and gas properties in the amount of $114.8 million at March 31, 2009.

Based on the 12-month average oil and gas prices at June 30, 2010 ($4.10 per MMBtu for Henry Hub natural gas and $75.76 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of Brigham’s oil and gas properties did not exceed the ceiling limit. Therefore, Brigham was not required to writedown the net capitalized costs of its oil and gas properties at June 30, 2010.

During the second quarter 2010, Brigham sold a portion of its proved developed producing West Texas assets for $14 million with an effective date of January 1, 2010. The proceeds for the sale were applied to reduce the capitalized costs of oil and gas properties

9. Common Stock Offerings

In May 2009, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 36,292,117 shares of its common stock at a price of $2.75 per share and received net proceeds of $93.4 million after underwriting fees and offering expenses.

In October 2009, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 16,000,000 shares of its common stock at a price of $10.50 per share and received net proceeds of $159.9 million after underwriting fees and offering expenses. In November 2009, the underwriters elected to exercise a portion of the over-allotment option associated with this equity offering. Brigham issued 837,523 additional shares of common stock and received net proceeds of $8.4 million after underwriting fees and offering expenses.

In April 2010, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 16,100,000 shares of its common stock at a price of $18.00 per share and received net proceeds of approximately $277.5 million after deducting underwriting fees and offering expenses.

10. 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 and its wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. The guarantees are joint and several. Brigham does not have any independent assets or operations.

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

In April 2007, Brigham issued $35 million of 9 5/8% Senior Notes due 2014. The notes were issued as an add-on to the 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%. Upon completion of the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes due 2014 (collectively the “Senior Notes”).

The indenture contains various covenants, including among others restrictions on incurring other indebtedness, restrictions on liens, restrictions on the sale of assets, and restrictions on certain payments. In order to incur additional debt, the indenture requires Brigham to achieve a fixed charge coverage ratio (as defined) for the most recent four full fiscal quarters of at least 2.5 to 1. At June 30, 2010, Brigham was in compliance with all covenants under the indenture.

11. Senior Credit Facility

In May 2009, in conjunction with Brigham’s regularly scheduled semi-annual redetermination and Brigham’s common stock offering, the borrowing base was reset to $110 million. On July 24, 2009, Brigham amended and restated the Senior Credit Facility to extend the maturity of the agreement from June 2010 to July 2012. During October 2009, Brigham used a portion of the proceeds from the October stock offering to repay borrowings under the Senior Credit Facility of $110 million.

Borrowings under the Senior Credit Facility bear interest, at Brigham’s election, at a base rate (as the term is defined in the Senior Credit Facility) or Eurodollar rate, plus in each case an applicable margin that is reset quarterly (2.5% at June 30, 2010). The applicable interest rate margin varies from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term is defined in the Senior Credit Facility) and from 2.5% to 3.5% in the case of borrowings based on the Eurodollar rate, depending on percentage of the available borrowing base utilized. In addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base (0.50% at June 30, 2010). Borrowings under the Senior Credit Facility are collateralized by substantially all of Brigham’s oil and natural gas properties under first liens.

The Senior Credit Facility contains various covenants, including among other restrictions on liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on investments, and restrictions on hedging activity of a speculative nature or with counterparties having credit ratings below specified levels. The Senior Credit Facility requires Brigham to maintain a current ratio (as defined) of at least 1 to 1. The Senior Credit Facility also requires Brigham to maintain an interest coverage ratio for the four most recent quarters as of June 30, 2010 of at least 2.5 to 1. The Senior Credit Facility also requires Brigham to maintain a net leverage ratio for the quarters ending through September 30, 2010 not greater than 4.5 to 1, for the quarters ending December 31, 2010 and March 31, 2011 not greater than 4.25 to 1, and thereafter not greater than 4.0 to 1. At June 30, 2010, Brigham was in compliance with all covenants under the Senior Credit Facility.

12. Preferred Stock

In June 2010, Brigham exercised its option to redeem all of its Series A mandatorily redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC.

13. 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 Financial Accounting Standards Board Accounting Standards Codification Topic 410 “Asset Retirement and Environmental Obligations” (FASB ASC 410), 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 FASB ASC 410, 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 FASB ASC 410 during the six months ended June 30, 2010 and 2009 (in thousands):


	Six Months Ended
	June 30,
	2010			2009
Beginning asset retirement obligations	$	6,323		$	5,592
Liabilities incurred for new wells placed on production		257			275
Liabilities settled		(65	)		(15	)
Accretion of discount on asset retirement obligations		209			206
Revisions to estimates due to sale of oil and gas properties		(1,208	)		—

	$	5,516		$	6,058

14. Stock Based Compensation

Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic 718 “Compensation — Stock Compensation” (FASB ASC 718) to account for stock based compensation. The cost for all stock based awards is based on the grant date fair value estimated in accordance with the provisions of FASB ASC 718 and is amortized 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. The maximum contractual life of stock based awards is ten years.

The estimated fair value of the options granted during the six months ended June 30, 2010 and 2009 was calculated using a Black-Scholes Merton option pricing model (Black-Scholes). The following table summarizes the weighted average assumptions used in the Black-Scholes model for options granted during the six months ended June 30, 2010 and 2009:


	2010			2009
Risk-free interest rate		2.49	%		2.52	%
Expected life (in years)		5.0			5.0
Expected volatility		81	%		77	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	12.49		$	2.19

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.

Prior to the adoption of FASB ASC 718, 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. FASB ASC 718 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 record any excess tax benefits during the six months ended June 30, 2010 and 2009.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Pre-tax stock based compensation expense	$	1,133		$	816		$	1,896		$	1,466
Capitalized stock based compensation		(522	)		(372	)		(858	)		(669	)
Tax benefit		(214	)		(155	)		(363	)		(279	)

Stock based compensation expense, net	$	397		$	289		$	675		$	518

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Stock Based Plan Descriptions and Share Information

Brigham provides an incentive plan for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to provide incentive and reward key employees whose performance may have a significant impact on the success of Brigham. It is Brigham’s policy to use unissued shares of stock when stock options are exercised. As of June 30, 2010, the number of shares authorized under the plan was equal to the lesser of 9,966,033 or 12% of the total number of shares of common stock outstanding. At June 30, 2010, approximately 1,770,415 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 series of stock option grants, 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 maximum contractual life of ten 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 1,000,000 shares to non-employee directors and approximately 566,800 shares remain available for grant under the director stock option plan.

The following table summarizes option activity under the incentive plans for the six months ended June 30:


	2010					2009
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Options outstanding at the beginning of the year		4,170,137		$	5.14		3,128,651		$	7.00
Granted		931,500		$	19.04		1,150,000		$	2.21
Forfeited or cancelled		—		$	—		(10,000	)	$	3.73
Exercised		(379,412	)	$	4.80		—		$	—

Options outstanding at the end of the quarter		4,722,225		$	7.91		4,268,651		$	5.71

Options exercisable at the end of the quarter		548,550		$	5.46		1,976,451		$	7.21

The weighted-average grant-date fair value of share options granted during the six months ended June 30, 2010 and 2009 was $12.49 and $2.19, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2010 was $3.5 million. There were no options exercised during the six months ended June 30, 2009.

The following table summarizes information about stock options outstanding and exercisable at June 30, 2010:


	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average		Weighted-
	June 30,		Remaining	Average		June 30,		Remaining		Average
Exercise Price	2010		Contractual Life	Exercise Price		2010		Contractual Life		Exercise Price
$2.20 to $3.41		1,159,500	8.7 years	$	2.25		199,500	8.4 years		$	2.28
3.66 to 5.08		421,800	5.3 years	$	5.08		53,800	5.3 years		$	5.08
5.96 to 6.46		1,802,475	8.2 years	$	5.99		125,300	2.8 years		$	6.20
7.22 to 8.84		169,950	3.6 years	$	7.64		95,950	2.5 years		$	7.70
8.93 to 13.86		237,000	7.1 years	$	11.66		74,000	4.2 years		$	10.15
14.43 to 16.85		19,000	9.7 years	$	15.40		—		—	$	—
18.36 to 19.12		912,500	9.8 years	$	19.11		—		—	$	—

$2.21 to $19.12		4,722,225	8.2 years	$	7.91		548,550	4.9 years		$	5.46

The aggregate intrinsic value of options outstanding and exercisable at June 30, 2010 was $39 million and $5.5 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 June 30, 2010. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

As of June 30, 2010, there was approximately $17.3 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 4.9 years.

Restricted Stock

During the six months ended June 30, 2010 and 2009, Brigham issued 105,363 and 155,018, respectively, restricted shares of common stock as compensation to officers and employees of Brigham. The restricted shares generally vest over five years or cliff-vest at the end of five years. As of June 30, 2010, there was approximately $2.9 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 4.7 years. Brigham has assumed a 6% weighted average forfeiture rate for restricted stock. 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 six months ended June 30:


	2010					2009
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Restricted shares outstanding at the beginning of the year		556,990		$	7.04		593,260		$	7.58
Shares granted		105,363		$	14.45		155,018		$	2.62
Lapse of restrictions		(69,800	)	$	8.78		(101,734	)	$	5.10

Shares outstanding at the end of the quarter		592,553		$	8.16		646,544		$	6.78

15. Comprehensive Income

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009

Net income (loss)	$	18,473		$	(6,960	)	$	29,788		$	(126,031	)
Unrealized gains (losses) on investments		(1,817	)		—			(2,081	)		—

Other comprehensive income (loss), net	$	16,656		$	(6,960	)	$	27,707		$	(126,031	)

16. Subsequent Events

In July and August 2010, Brigham closed on four acreage acquisition transactions in the Williston Basin at a cost of approximately $54 million, which increased its acreage in the basin by approximately 44,800 net acres. Brigham also acquired an interest in three existing wells as a result of these transactions.

17. Related Party Transactions

During the six months ended June 30, 2010, Brigham incurred costs of approximately $4.9 million in fees for land acquisition services performed by Brigham Land Management, owned by a brother of Brigham’s Chairman, President and Chief Executive Officer and its Executive Vice President — Land and Administration. Other participants in Brigham’s 3-D seismic projects reimbursed Brigham for a portion of these amounts. At June 30, 2010, Brigham had a liability recorded in accounts payable of approximately $41,000, related to services performed by this company.

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 2009 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2010 and June 30, 2009. 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 2009 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 advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore crude oil and natural gas reserves. We focus our activities in provinces where we believe these technologies, including horizontal drilling, multi-stage isolated fracture stimulations and 3-D seismic imaging, can be used to effectively maximize our return on invested capital.

Commencing in late 2005 we began acquiring acreage within the Williston Basin in North Dakota and Montana. As of August 3, 2010, we have approximately 358,200 net leasehold acres in the Williston Basin. In late 2007, the majority of our drilling capital expenditures shifted from our historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West Texas to the Williston Basin, where we are currently targeting the Bakken, Three Forks and Red River objectives. Through the second quarter 2010, we had invested in excess of $350 million on drilling, land and seismic in this region.

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 can use technology to generate high rates of return on our invested capital. Key elements of our business strategy include:

•

Focus on Core Provinces;

•

Leverage Our Engineering and Operational Expertise;

•

Capitalize on Internally Generated Exploration Successes Through Disciplined Development Activities; and

•

Enhance Returns Through Operational Control.

Overview of Second Quarter 2010

In April 2010, we completed a public offering of common stock pursuant to a shelf registration statement. We sold 16.1 million shares at a price of $18.00 per share and received net proceeds of $277.5 million after underwriting fees and offering expenses.

In connection with the offering, we revised our 2010 exploration and development capital budget to approximately $293.9 million. We have begun an acceleration of our drilling program in the Williston Basin that targets both the Bakken and Three Forks objectives by adding a fifth operated drilling rig in May and plan to add additional operated rigs in October 2010, January 2011 and May 2011 such that we are running eight operated drilling rigs by May 2011. Additionally, we plan to fund the construction of production infrastructure and to acquire land and seismic in the Williston Basin. In August, we announced a further increase in our 2010 exploration and development capital budget by $110.1 million to approximately $404.0 million. The bulk of the incremental capital or $68.7 million will fund acreage acquisitions primarily in our Rough Rider and Eastern Montana project areas.

In the second quarter 2010, the average sales price that we received for crude oil, excluding realized and unrealized derivative hedging results, was $69.19 per barrel, which represents a 40% per barrel increase from the second quarter 2009. In the second quarter 2010, the average sales price that we received for natural gas, excluding realized and unrealized derivative hedging results, was $5.24 per Mcf, which represents a 50% per Mcf increase from that in the second quarter 2009.

Our second quarter 2010 production volumes were 7,756 barrels of equivalent per day, which represents a 71% increase from last year’s second quarter production volumes of 4,526 barrels of equivalent per day and a 43% increase from our first quarter 2010 production volumes of 5,420 barrels of oil equivalent per day. Crude oil represented 72% of our production volumes in the second quarter 2010 as compared to 40% of our production volumes in the second quarter 2009 and 66% of our first quarter 2010 production volumes. Both the increase in our production volumes and the increase in crude oil as a percent of total production volumes were as a result of our increased level of activity and successful drilling program in the Williston Basin targeting the Bakken and Three Forks objectives.

Our second quarter 2010 production volumes include approximately 5,089 barrels of crude oil added to inventory during the quarter. Adjusting our second quarter 2010 production volumes for our increased level of inventory resulted in sales volumes of 7,700 barrels of equivalent per day in the second quarter 2010 versus sales volumes of 4,526 barrel of equivalent per day in the second quarter 2009.

Our second quarter 2010 crude oil revenue, including hedge settlements but excluding unrealized hedging gains and losses, was up $26.4 million, or 335%, compared to the second quarter 2009. Crude oil revenue increased $16.5 million due to higher sales volumes, $9.8 million due to higher crude oil prices and $0.1 million due to higher hedge settlements.

Our second quarter 2010 natural gas revenue, including hedge settlements but excluding unrealized hedging gains and losses, increased $0.5 million from the second quarter 2009. Natural gas revenue increased $2.0 million due to higher natural gas prices, but was offset by lower sales volumes and lower hedge settlements during the second quarter 2010 compared to those in the prior year’s quarter, which lowered natural gas revenue by $1.0 million and $0.5 million, respectively.

Second quarter 2010 operating income was $19.3 million versus a $(2.8) million operating income (loss) in the second quarter last year. The increase in operating income was primarily attributable to the increases in crude oil sales volumes, crude oil sales prices and natural gas prices. These increases to operating income were partially offset by lower natural gas sales volumes and higher expenses, including higher depletion, production taxes, lease operating, and general and administrative.

As of June 30, 2010, we had $333.2 million in cash, cash equivalents and short term investments and $862.2 million in total assets.

Overview of Second Quarter 2010 Operational Results

Williston Basin

At the beginning of the second quarter 2010, we had four operated rigs running in the Williston Basin and added our fifth operated rig in May 2010 in conjunction with our April 2010 common stock offering. After adding our fifth rig, four of the rigs were primarily drilling wells in our Rough Rider project area in Williams and McKenzie Counties, North Dakota. The fifth operated rig drilled wells in our Ross project area in Mountrail County, North Dakota. The following table summarizes our completions in the Williston Basin since the end of the first quarter 2010.


						Frac		IP		30 Day
Well Name	County	Objective	~WI%			Stages		(Boe/d)		Average (Boe/d)**

Michael Owan 26-35 #1H	Williams	Bakken		87	%		33		2,931		NA
Sedlacek Trust 33-4 #1H	McKenzie	Bakken		48	%*		30		2,695		NA
Rogney 17-8 #1H	Roosevelt	Bakken		100	%		30		909		NA
Ross Alger 6-7 #1H	Mountrail	Bakken		47	%		32		3,070		1,465
Owan 29-32 #1H	Williams	Bakken		78	%		31		2,302		868
Abe 30-31 #1H	Williams	Bakken		97	%		31		1,847		731
Jack Cvancara 19-18 #1H	Mountrail	Bakken		83	%		36		5,035		1,800
Tjelde 29-32 #1H	McKenzie	Bakken		77	%		30		3,171		931
Abelmann State 21-16 #1H	McKenzie	Bakken		64	%		31		3,301		1,044
Mortenson 5-32 #1H	Williams	Bakken		77	%		23		2,314		584
Arnson 13-24 #1H	Williams	Bakken		93	%		30		1,339		480
Sorenson 29-32 #1H	Mountrail	Bakken		95	%		27		5,133		1,909
Jack Erickson 6-31 #1H	Williams	Bakken		21	%*		30		2,652		833
Averages									2,823		1,065


*		Rough Rider drilling participation agreement well where our working interest is anticipated to increase upon payout.

**		Excludes any days well was down for remediation.

Subsequent Events

Since April 2010, our ongoing organic leasing efforts plus four acreage acquisitions have added 52,800 net acres to our total Williston Basin acreage as of August 3, 2010. Largely as a result of these acreage acquisitions, we are increasing our exploration and development capital budget revised in April 2010 by $110.1 million to $404.0 million. The table below sets forth our 2010 capital budget revised in April 2010 in conjunction with our common stock offering and our 2010 capital budget revised in August 2010 to largely reflect the impact of our acreage acquisitions.


	2010 Budget		2010 Budget
	Revised April		Revised August
	2010		2010
	(In thousands)
Drilling	$	229.1	$	275.5
Field Level Infrastructure		37.8		32.8
Land and Seismic		27.0		41.8
Acreage Acquisitions		—		53.9

Exploration and Development Capital Budget	$	293.9	$	404.0

Results for the Three and Six Months Ended June 30, 2010

Comparison of the three month and six month periods ended June 30, 2010 and 2009.

Production volumes


	Three months ended June 30,							Six months ended June 30,
	2010		% Change			2009		2010		% Change			2009

Crude oil (MBbls)(1)		503		207	%		164		822		143	%		338
Natural gas (MMcf)		1,173		(20	%)		1,460		2,182		(34	%)		3,302
Total (MBoe)(2)		698		71	%		407		1,186		34	%		888
Average daily production (Boe/d)(3)		7,756		71	%		4,526		6,588		34	%		4,933


(1)		Includes approximately 5,089 barrels of crude oil produced in the Williston Basin during the second quarter 2010 and added to crude oil inventory during the second quarter 2010. Includes approximately 10,101 barrels of crude oil produced in the Williston Basin during the first half of 2010. Ending inventory as of the first and second quarters of 2009 was not material.

(2)		Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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

Crude oil represented 72% of our second quarter 2010 production volumes and 69% of our first six months 2010 production volumes, compared to 40% in the second quarter 2009 and 38% in the first six months 2009.

Sales Volumes (Production volumes less the Incremental Change in Inventory)


	Three months ended June 30,							Six months ended June 30,
	2010		% Change			2009		2010		% Change			2009

Crude oil (MBbls)(1)		497		203	%		164		812		140	%		338
Natural gas (MMcf)		1,173		(20	%)		1,460		2,182		(34	%)		3,302
Total (MBoe)(2)		693		70	%		407		1,176		32	%		888
Average daily production (Boe/d)(3)		7,700		70	%		4,526		6,532		32	%		4,933


(1)		Excludes approximately 5,089 barrels of crude oil produced in the Williston Basin during the second quarter 2010 and added to crude oil inventory at the end of the second quarter 2010. Excludes approximately 10,101 barrels of crude oil produced in the Williston Basin during the first half of 2010. Ending inventory as of the first and second quarters of 2009 was not material.

(2)		Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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

Crude oil represented 72% of our second quarter 2010 sales volumes and 69% of our first six months 2010 sales volumes, compared to 40% in the second quarter 2009 and 38% in the first six months 2009.

Revenues, Commodity Prices and Hedging

The following table sets forth our revenues, the average prices we received before hedging, the average prices we received including derivative settlement gains (losses) and the average prices including derivative settlements and unrealized gains (losses).


	Three months ended June 30,									Six months ended June 30,
	2010			% Change			2009			2010			% Change			2009

Crude oil revenue:
Crude oil revenue	$	34,423			325	%	$	8,105		$	57,293			308	%	$	14,055
Crude oil derivative settlement gains (losses)		(132	)		(41	%)		(222	)		(228	)	NM				860

Crude oil revenue including derivative settlements	$	34,291			335	%	$	7,883		$	57,065			283	%	$	14,915
Crude oil derivative unrealized gains (losses)		5,088		NM				(3,034	)		5,563		NM				(4,341	)

Crude oil revenue including derivative settlements and unrealized gains (losses)	$	39,379			712	%	$	4,849		$	62,628			492	%	$	10,574

Natural gas revenue:
Natural gas revenue	$	6,141			20	%	$	5,104		$	12,201			(6	%)	$	12,963
Natural gas derivative settlement gains (losses)		993			(34	%)		1,508			1,671			(79	%)		7,947

Natural gas revenue including derivative settlements	$	7,134			8	%	$	6,612		$	13,872			(34	%)	$	20,910
Natural gas derivative unrealized gains (losses)		(1,587	)		(62	%)		(979	)		990		NM				(2,550	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	5,547			(2	%)	$	5,633		$	14,862			(19	%)	$	18,360

Crude oil and natural gas revenue:
Crude oil and natural gas revenue	$	40,564			207	%	$	13,209		$	69,494			157	%	$	27,018
Crude oil and natural gas derivative settlement gains (losses)		861			(33	%)		1,286			1,443			(84	%)		8,807

Crude oil and natural gas revenue including derivative settlement gains (losses)		41,425			186	%		14,495			70,937			98	%		35,825
Crude oil and natural gas derivative unrealized gains (losses)		3,501		NM				(4,013	)		6,553		NM				(6,891	)

Crude oil and natural gas revenue including derivative settlements and unrealized gains (losses)		44,926			329	%		10,482			77,490			168	%		28,934
Other revenue		4			(88	%)		32			13			(80	%)		66

Total revenue	$	44,930			327	%	$	10,514		$	77,503			167	%	$	29,000


	Three months ended June 30,							Six months ended June 30,
	2010		% Change			2009		2010		% Change			2009

Average crude oil prices:
Crude oil price (per Bbl)	$	69.19		40	%	$	49.41	$	70.55		69	%	$	41.63
Crude oil price including derivative settlement gains (losses) (per Bbl)		68.93		43	%		48.06		70.27		59	%		44.18
Crude oil price including derivative settlements and unrealized gains (losses) (per Bbl)	$	79.16		168	%	$	29.56	$	77.12		146	%	$	31.32

Average natural gas prices:
Natural gas price (per Mcf)	$	5.24		50	%	$	3.50	$	5.59		42	%	$	3.93
Natural gas price including derivative settlement gains (losses) (per Mcf)		6.08		34	%		4.53		6.36		0	%		6.33
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	4.73		23	%	$	3.86	$	6.81		22	%	$	5.56

Average equivalent prices:
Crude oil equivalent price (per Boe)	$	58.53		81	%	$	32.40	$	59.09		94	%	$	30.42
Crude oil equivalent price including derivative settlement gains (losses) (per Boe)		59.78		68	%		35.58		60.32		50	%		40.32
Crude oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)	$	64.83		152	%	$	25.74	$	65.89		102	%	$	32.58


	For the three			For the six
	month periods			month periods
	ended June 30,			ended June 30,
	2010 and 2009			2010 and 2009

Change in revenue from the sale of crude oil
Volume variance impact	$	16,476		$	19,753
Price variance impact		9,842			23,485
Cash settlement of hedging contracts		90			(1,088	)
Unrealized hedge gain or loss		8,122			9,904

Total change	$	34,530		$	52,054


Change in revenue from the sale of natural gas
Volume variance impact	$	(999	)	$	(4,389	)
Price variance impact		2,036			3,627
Cash settlement of hedging contracts		(515	)		(6,276	)
Unrealized hedge gain or loss		(608	)		3,540

Total change	$	(86	)	$	(3,498	)


Change in revenue from the sale of crude oil and natural gas
Volume variance impact	$	15,477		$	15,364
Price variance impact		11,878			27,112
Cash settlement of hedging contracts		(425	)		(7,364	)
Unrealized hedge gain or loss		7,514			13,444

Total change	$	34,444		$	48,556

Second quarter 2010 crude oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) increased $34.5 million when compared to that in the second quarter 2009. The change in revenues was attributable to the following:

•

an increase in crude oil production resulting from our drilling activities in the Williston Basin, which was partially offset by a decrease in our natural gas volumes due to the natural decline of our wells, drove a $15.5 million increase in crude oil and natural gas revenues;

•

a 81% increase in pre-hedge per Boe sales prices resulted in a $11.9 million increase in revenues;

•

a $3.5 million unrealized derivative gain in second quarter 2010 versus a $4.0 million unrealized derivative loss in second quarter 2009 increased revenues by $7.5 million; and

•

a $0.9 million gain from the settlement of derivative contracts in the second quarter 2009 versus a $1.3 million gain from the settlement of derivative contracts in second quarter 2009 decreased revenues by $0.4 million.

First six months 2010 crude oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) increased $48.6 million when compared to that in the first six months 2009. The change in revenues was attributable to the following:

•

a 94% increase in pre-hedge per Boe sales prices resulted in a $27.1 million increase in revenues;

•

an increase in crude oil production resulting from our drilling activities in the Williston Basin, which was partially offset by a decrease in our natural gas volumes due to the natural decline of our wells, drove a $15.4 million increase in crude oil and natural gas revenues;

•

a $6.6 million unrealized derivative gain in first six months 2010 versus a $6.8 million unrealized derivative loss in first six months 2009 increased revenues by $13.4 million; and

•

a $1.4 million gain from the settlement of derivative contracts in the first six months 2010 versus a $8.8 million gain from the settlement of derivative contracts in first six months 2009 decreased revenues by $7.4 million.

Hedging. We utilize collars, three way costless collars, puts and swaps 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 the second quarter and first six months 2010 and 2009 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 June 30,									Six months ended June 30,
	2010			% Change			2009			2010			% Change			2009

Crude oil collars
Volumes (Bbls)		211,000			1,011	%		19,000			356,000			627	%		49,000
Average floor price ($ per Bbl)	$	61.55			3	%	$	59.63		$	60.03			(16	%)	$	71.58
Average ceiling price ($ per Bbl)	$	90.16			15	%	$	78.70		$	88.95			(8	%)	$	96.96
Gain (loss) upon settlement ($ in thousands)	$	(132	)	NM			$	45		$	(228	)	NM			$	1,127

Crude oil swaps
Volumes (Bbls)		—		NM				30,000			—		NM				30,000
Average swap price ($ per Bbl)	$	—		NM			$	50.75		$	—		NM			$	50.75
Gain (loss) upon settlement ($ in thousands)	$	—		NM			$	(267	)	$	—		NM			$	(267	)

Total crude oil
Gain (loss) upon settlement ($ in thousands)	$	(132	)		(40	%)	$	(222	)	$	(228	)	NM			$	860

Natural gas collars
Volumes (MMbtu)		690,000			176	%		250,000			1,500,000			23	%		1,220,000
Average floor price ($ per MMbtu)	$	5.51			(20	%)	$	6.89		$	5.87			(24	%)	$	7.74
Average ceiling price ($ per MMbtu)	$	7.02			(14	%)	$	8.19		$	7.43			(21	%)	$	9.42
Gain (loss) upon settlement ($ in thousands)	$	993			47	%	$	676		$	1,671			(76	%)	$	6,931

Natural gas swaps
Volumes (MMbtu)		—		NM				882,000			—		NM				1,062,000
Average swap price ($ per MMbtu)	$	—		NM			$	4.438		$	—		NM			$	4.572
Gain (loss) upon settlement ($ in thousands)	$	—		NM			$	832		$	—		NM			$	1,016

Total natural gas
Gain (loss) upon settlement ($ in thousands)	$	993			(34	%)	$	1,508		$	1,671			(79	%)	$	7,947

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 are the best way to evaluate our production costs. We use this information to internally evaluate our performance, as well as to evaluate our performance relative to our peers.


	Unit-of-Production							Amount
	(Per Boe)							(In thousands)
	Three months ended June 30,							Three months ended June 30,
	2010		% Change			2009		2010		% Change			2009

Production costs:
Operating & maintenance	$	4.06		(42	%)	$	7.02	$	2,821		(1	%)	$	2,853
Expensed workovers		1.88		74	%		1.08		1,300		192	%		445
Ad valorem taxes		0.36		(45	%)		0.66		250		(9	%)		275

Lease operating expenses	$	6.30		(28	%)	$	8.76	$	4,371		22	%	$	3,573

Production taxes		5.63		176	%		2.04		3,900		369	%		831

Production costs	$	11.93		10	%	$	10.80	$	8,271		88	%	$	4,404

Second quarter 2010 per unit of production costs increased $1.13 per Boe, or 10%, when compared to that in the second quarter last year mainly due to the following:

•

production taxes increased $3.59 per Boe, or 176%, due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to a 11.5% tax rate;

•

expensed workovers increased $0.80 per Boe, or 74%, with the majority of the increase due to several workovers of our conventional Gulf Coast and Anadarko Basin natural gas wells; and

•

operating and maintenance expenses decreased $2.96 per Boe, or 42%, primarily due to higher production volumes and lower compressor rental and saltwater disposal expenses.


	Unit-of-Production							Amount
	(Per Boe)							(In thousands)
	Six months ended June 30,							Six months ended June 30,
	2010		% Change			2009		2010		% Change			2009

Production costs:
Operating & maintenance	$	4.63		(28	%)	$	6.42	$	5,445		(4	%)	$	5,697
Expensed workovers		2.36		87	%		1.26		2,775		147	%		1,125
Ad valorem taxes		0.43		(28	%)		0.60		500		(9	%)		550

Lease operating expenses	$	7.42		(10	%)	$	8.28	$	8,720		18	%	$	7,372

Production taxes		5.45		193	%		1.86		6,408		290	%		1,645

Production costs	$	12.87		27	%	$	10.14	$	15,128		68	%	$	9,017

First six months 2010 per unit of production costs increased $2.73 per Boe, or 27%, when compared to the first six months last year mainly due to the following:

•

production taxes increased $3.59 per Boe, or 193%, due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to a 11.5% tax rate;

•

expensed workovers increased $1.10 per Boe, or 87%, with the majority of the increase due to several workovers of our conventional Gulf Coast and Anadarko Basin natural gas wells; and

•

operating and maintenance expenses decreased $1.79 per Boe, or 28%, primarily due to higher production volumes and lower saltwater disposal and equipment rental expenses.

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 June 30,									Six months ended June 30,
	2010			% Change			2009			2010			% Change			2009
	(In thousands, except per unit measurements)

General and administrative costs	$	5,332			30	%	$	4,087		$	11,247			45	%	$	7,759
Capitalized general and administrative costs		(2,621	)		44	%		(1,823	)		(5,450	)		62	%		(3,373	)

General and administrative expenses	$	2,711			20	%	$	2,264		$	5,797			32	%	$	4,386


General and administrative expense ($ per Boe)	$	3.91			(30	%)	$	5.58		$	4.93			0	%	$	4.92

Our general and administrative costs prior to capitalization for the second quarter and the first six months of 2010 increased primarily because of an increase in employee compensation costs, which is partially associated with increased levels of employee bonuses and bonus accruals as we re-instated our performance bonus plan in 2010 after suspending the plan in 2009.

Depletion of crude 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 June 30,							Six months ended June 30,
	2010		% Change			2009		2010		% Change			2009
	(In thousands, except per unit measurements)

Depletion of crude oil and natural gas properties	$	14,247		129	%	$	6,233	$	23,458		46	%	$	16,066
Depletion of crude oil and natural gas properties ($ per Boe)	$	20.56		34	%	$	15.30	$	19.95		10	%	$	18.12

Our depletion expense for the second quarter 2010 was $8.0 million higher than that in the second quarter 2009. Our higher sales volumes increased depletion expense by $4.4 million and our higher depletion rate increased depletion expense by $3.6 million.

Our depletion expense for the first six months 2010 was $7.4 million higher than that in the first six months 2009. Our higher sales volumes increased depletion expense by $5.2 million and our higher depletion rate increased depletion expense by $2.2 million.

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

Capitalized costs of crude oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved crude oil and natural gas reserves, based on the crude oil and natural gas prices in effect on the balance sheet date; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of crude oil and natural gas properties exceed this ceiling amount, we are subject to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings and reduces stockholders’ equity in the period of occurrence.

The downward trend in natural gas prices experienced in the second half of 2008 continued into the first quarter of 2009. On December 31, 2008, the Henry Hub natural gas cash price was $5.71 per MMbtu and on March 31, 2009 the natural gas cash price was $3.63 per MMbtu. Lower natural gas prices resulted in our capitalized costs, net of accumulated depreciation, of our crude oil and natural gas properties exceeding the discounted present value of our estimated proved reserves using a 10% discount rate. As such, we recorded a before tax ceiling test write-down of $114.8 million during the first six months of 2009.

Inventory Valuation. Our non-cash loss in the first six months 2009 was attributable to the $2.2 million lower of cost or market write-down of oil country tubular goods (OCTG). Market prices of OCTG experienced a substantial reduction in 2009 associated with lower steel costs, oversupply of OCTG and reduced levels of drilling activity.

Net interest expense. Interest on our Senior Notes, our Senior Credit Facility and dividends that we pay on our Series A mandatorily redeemable preferred stock represents the largest portion of our interest expense. Other costs include commitment fees that we pay on the unused portion of the borrowing base for our Senior Credit Facility. In addition, we typically pay loan and debt issuance costs when we enter into new lending agreements or amend existing agreements. When incurred, these costs are recorded as non-current assets and are then amortized over the life of the loan. We capitalize interest costs on borrowings associated with our major capital projects prior to their completion. Capitalized interest is added to the cost of the underlying assets and is amortized over the lives of the assets.


	Three months ended June 30,									Six months ended June 30,
	2010			% Change			2009			2010			% Change			2009
	(In thousands)

Interest on Senior Notes	$	3,850			0	%	$	3,850		$	7,700			0	%	$	7,700
Interest on Senior Credit Facility		—			(100	%)		1,021			—			(100	%)		2,026
Commitment fees		163			579	%		24			326			624	%		45
Dividend on mandatorily redeemable preferred stock		120			(21	%)		151			269			(10	%)		300
Amortization of deferred loan and debt issuance cost		481			57	%		306			963			66	%		581
Other general interest expense		101		NM				(1	)		101			531	%		16
Capitalized interest expense		(1,784	)		62	%		(1,100	)		(3,524	)		54	%		(2,290	)

Net interest expense	$	2,931			(31	%)	$	4,251		$	5,835			(30	%)	$	8,378


Weighted average debt outstanding	$	167,881			(44	%)	$	301,640		$	168,985			(45	%)	$	308,333
Average interest rate on outstanding indebtedness (a)		10.1	%					6.7	%		10.0	%					6.6	%


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

Second quarter 2010 interest expense was $1.3 million lower than the corresponding period last year primarily due to a $1.0 million decrease in interest expense associated with lower levels of outstanding debt on our Senior Credit Facility subsequent to its repayment in connection with our October 2009 common stock offering. Additionally, capitalized interest expense increased $0.7 million associated with our higher level of activity in the Williston Basin. This decrease was partially offset by a $0.2 million increase in deferred loan and debt issuance costs associated with the July 2009 amendment of our Senior Credit Facility.

First six months 2010 interest expense was $2.5 million lower than the corresponding period last year primarily due to a $2.0 million decrease in interest expense associated with lower levels of outstanding debt on our Senior Credit Facility subsequent to its repayment in connection with our October 2009 common stock offering. Additionally, capitalized interest expense increased $1.2 million associated with our higher level of activity in the Williston Basin. This decrease was partially offset by a $0.3 million increase in deferred loan and debt issuance costs associated with the July 2009 amendment of our Senior Credit Facility.

Other income (expense).

Other income (expense) included:


	Three months ended June 30,						Six months ended June 30,
	2010		% Change	2009			2010		% Change			2009
	(In thousands)
Other income (expense):
Total other income (expense)	$	1,181	NM	$	(33	)	$	1,866		2,176	%	$	82

Other income increased as a result of higher levels of drilling equipment rental income in the Williston Basin.

Income taxes. We recorded no current or deferred federal or state income tax expense (benefit) in the second quarter and the first six months of 2010, compared to no current or deferred federal or state income tax expense (benefit) in the second quarter and the first six months of 2009. For the first six months of 2010, our effective tax rate on book net income was 0%. This was lower than the statutory rate of 35% primarily due to (i) our ability to deduct depreciation, depletion, amortization and federal net operating losses to minimize current taxes, and (ii) our valuation allowances on federal net operating losses and our inability to deduct preferred stock dividends and certain portions or our non-cash stock compensation expense to minimize deferred taxes.

Capital Expenditures

The timing of most of our capital expenditures is discretionary because we operate the majority of our wells and 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 crude oil and natural gas wells;

•

cost of installing new production infrastructure;

•

cost of maintaining, repairing and enhancing existing crude 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 to our exploration professional staff.

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 re-evaluate this budget monthly. The primary factors that impact this value creation measure include forecasted commodity prices, drilling and completion costs, and a prospect’s risked reserve size and risked initial producing rate. Other factors that are also monitored throughout the year that influence the amount and timing of our planned expenditures include the level of production from our existing crude oil and natural gas properties, the availability of drilling and completion services, and the success and resulting production of our newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our exploration and development drilling schedule to ensure that we are optimizing our capital expenditure plan.

The final determination with respect to our 2010 budgeted expenditures will depend on a number of factors, including:

•

commodity prices;

•

production from our existing producing wells;

•

the results of our current exploration and development drilling efforts;

•

economic conditions at the time of drilling;

•

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

•

our liquidity and the availability of external sources of financing; and

•

the availability of more economically attractive prospects.

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

In April 2010, as a result of our common stock offering and improved operational results, we increased our activity level in the Williston Basin and concurrently increased our exploration and development capital budget to $293.9 million, which included $229.1 million in drilling, $27.0 million in land and seismic and $37.8 million in field level infrastructure expenditures.

Factors that could cause us to further increase our level of activity and capital budget in 2010 include a further reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, and a further improvement in commodity prices or well performance that exceeds our risked forecasts, all of which would positively impact our operating cash flow.

Factors that would cause us to reduce our capital budget in 2010 include, but are not limited to, increases in service and materials costs, reductions in commodity prices or underperformance of wells relative to our risked forecasts, all of which would negatively impact our operating cash flow.

The table below summarizes our 2010 exploration and development capital budget revised in August 2010, the amount spent through June 30, 2010 and the amount of our 2010 exploration and development capital budget that remains to be spent.


			Amount
	2010		Spent Through		Amount
	Budget (a)		June 30, 2010		Remaining (b)
	(In millions)
Drilling	$	275.5	$	114.9	$	160.6
Field level infrastructure		32.8		—		32.8
Land and seismic		41.8		29.5		12.3
Acreage acquisitions		53.9		—		53.9

Exploration and development capital budget	$	404.0	$	144.4	$	259.6


(a)		Capital budget announced August 2010.

(b)		Calculated based on the 2010 exploration and development capital budget less amounts spent through June 30, 2010.

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2010, we intend to fund our capital expenditure program and contractual commitments with cash, cash equivalents and short term investments on hand, cash flows from operations, reimbursements of prior land and seismic costs by third parties who participate in our projects, the sale of interests in projects and properties or alternative financing sources.

9 5/8% Senior Notes Due 2014

We have $160 million of Senior Notes outstanding, $125 million of which was issued in April 2006 and $35 million of which was issued in April 2007. The notes are fully and unconditionally guaranteed by us, and our wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. 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 and beginning in May 2007, we paid 9 5/8% 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 Facility.

The Indenture governing the Senior Notes 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 governing the Senior Notes contains customary restrictions and covenants which could potentially limit our flexibility to manage and fund our business. We were in compliance with all covenants associated with the Senior Notes as of June 30, 2010.

Senior Credit Facility

Our Senior Credit Facility provides for revolving credit borrowings up to $200 million. Our current borrowing base is $110 million. As of June 30, 2010 and as of the date of the filing of this report, we had no amounts outstanding.

Covenants under our Senior Notes preclude us from incurring additional debt under the Senior Credit Facility to the extent our total debt under the Senior Credit Facility exceeds the greater of $50 million plus 15% of a calculated proved PV10 value based on SEC prices used in our year-end reserve report, as defined in our Indenture, which is referred to as Adjusted Consolidated Net Tangible Assets, plus, in certain circumstances, an additional 10% of Adjusted Consolidated Net Tangible Assets.

Since the borrowing base for our Senior Credit Facility is redetermined at least semi-annually, the amount of borrowing capacity available to us under our Senior Credit Facility could fluctuate. 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 pay off the borrowing base deficiency and carry out our planned spending for exploration and development activities.

Borrowings under our Senior Credit Facility bear interest at a base rate or a Eurodollar rate, at our election, 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 Facility reaches certain percentages of the available borrowing base, as shown below:


Percent of	Eurodollar
Borrowing Base	Rate			Base Rate
Utilized	Advances			Advances(1)
< 25%		2.50	%		1.50	%
25% and < 50%		2.75	%		1.75	%
50% and < 75%		3.00	%		2.00	%
75% and < 90%		3.25	%		2.25	%
> 90%		3.50	%		2.50	%


(1)		Base rate is defined as for any day a fluctuating rate per annum equal to the highest of the following, in each case, to the extent determinable by the Administrative Agent: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of one month determined as of approximately 11:00 a.m. (London time) on such day plus 1.50% and (c) 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	Annual
Utilized	Commitment Fee
< 25%		0.500	%
25% and < 50%		0.500	%
50% and < 75%		0.500	%
75% and < 90%		0.500	%
> 90%		0.500	%

Our Senior Credit Facility 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 Facility, our current ratio must be at least 1.0 to 1. Our current ratio was 4.1 to 1 as of June 30, 2010. Pursuant to our Senior Credit Facility, our interest coverage ratio for the four most recent quarters as of June 30, 2010 must be at least 2.5 to 1. Our interest coverage ratio for the last twelve-month period ended June 30, 2010 was 6.0 to 1. Finally, the Senior Credit Facility also requires us to maintain a net leverage ratio for the quarters ending through September 30, 2010 not greater than 4.5 to 1, for the quarters ending December 31, 2010 through March 31, 2011 not greater than 4.25 to 1, and thereafter not greater than 4.0 to 1. Our net leverage ratio as of June 30, 2010 was (2.1) to 1. As of June 30, 2010, we were in compliance with all covenant requirements in connection with our Senior Credit Facility.

Mandatorily Redeemable Preferred Stock

In June 2010, we exercised our option to redeem all of our Series A mandatorily redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC.

Access to Capital Markets

We have two effective universal shelf registration statements covering the sale of our common stock, preferred stock, depositary shares, warrants, rights, units and debt securities. One of these registration statements has approximately $123 million remaining and expires in October 2012. The other registration statement is an automatic shelf registration statement with an unlimited amount and expires in April 2013. Our ability to raise additional capital using our shelf registration statements may be limited due to overall conditions of the stock market or the crude 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.


	Six months ended June 30,
	2010			%Change			2009
	(In thousands)

Net income (loss)	$	29,788		NM			$	(126,031	)
Non-cash items		16,952			(88	%)		139,718
Changes in working capital and other items		20,180			793	%		2,260

Cash flows provided by operating activities	$	66,920			320	%	$	15,947
Cash flows used by investing activities		(293,792	)		546	%		(45,498	)
Cash flows provided by financing activities		268,913			367	%		57,594

Net increase in cash and cash equivalents	$	42,041			50	%	$	28,043

Analysis of net cash provided by operating activities

Net cash provided by operating activities is a function of the amount of crude oil and natural gas that we produce, the prices that we receive from the sale of crude 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 crude 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 six months of 2010, cash flows provided by operating activities increased by 320% to $66.9 million from the same period last year. The increase in operating cash flow is primarily attributable to the increase in commodity prices, higher levels of crude oil sales volumes and cash provided by working capital. These increases to operating cash flow were partially offset by lower natural gas sales volumes and lower crude oil and natural gas hedge settlements and by higher production taxes, lease operating expense and general and administrative expense.

Analysis of changes in cash flows used in investing activities


	Six months ended June 30,
	2010			%Change			2009
	(In thousands)
Capital expenditures for crude oil and natural gas activities:
Drilling	$	114,930			334	%	$	26,492
Land and seismic		29,539		NM				(5,687	)
Capitalized cost		8,974			58	%		5,663
Capitalized asset retirement obligation		257			(7	%)		275

Total	$	153,700			475	%	$	26,743


Reconciling Items:
Asset sale proceeds including ARO liability reduction	$	(13,706	)	NM			$	—
Change in accrued drilling costs		(29,849	)	NM			$	13,906
Change in short term investments		172,342			3,171	%		5,268
Change in other property and equipment		5,375		NM				—
Change in inventory		3,806		NM				—
Other		2,124		NM				(419	)

Total Reconciling Items		140,092			647	%		18,755

Net cash used in investing activities	$	293,792			546	%	$	45,498

Net cash used by investing activities in the first six months 2010 increased by $248.3 million, or 546%, over the same period in 2009. The following were the reasons for the change:

•

drilling expenditures increased by $88.4 million;

•

land and seismic expenditures increased by $35.2 million;

•

capitalized costs increased by $3.3 million;

•

the sale of our West Texas assets reduced cash used in investing activities by $13.7 million;

•

the change in accrued drilling costs decreased cash used in investing activities by $43.8 million;

•

the change in short term investments increased cash used in investing activities by $167.1 million;

•

the change in other property and equipment increased cash used in investing activities by $5.4 million; and

•

the change in inventory increased cash used in investing activities by $3.8 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first six months of 2010 was 367% greater than the first six months of 2009. During the first six months 2010, we received net proceeds of $277.5 million from our April 2010 common stock offering. During the first six months 2009, we received net proceeds of $93.5 million related to our May 2009 common stock offering.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the six months ended June 30, 2010 and 2009.


	Shares Issued		Net Proceeds
			(In thousands)

2010 common stock transactions:
Common stock offering (April)		16,100,000	$	277,547
Exercise of employee stock options		379,412	$	1,854

2009 common stock transactions:
Common stock offering (May)		36,292,117	$	93,407
Exercise of employee stock options		500	$	1

Other Matters

Derivative Instruments

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

Effects of Inflation and Changes in Prices

Our results of operations and cash flows are affected by changing crude oil and natural gas prices. If the price of crude 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.

Environmental and Other Regulatory Matters

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

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 crude oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in crude oil and natural gas production, the number of wells we anticipate drilling during 2010 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 crude 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, 2009 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 DISCLOSURES 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. See Item 1. Condensed Consolidated Financial Statements — Notes 6 and 7 for more details.

Derivative Instruments and Hedging Activities

Our primary commodity market risk exposure is to changes in the prices that we receive for our crude oil and natural gas production. The market prices for crude 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 crude oil and natural gas production via 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 the first six months of 2009 and 2010, we were party to crude oil costless collars, crude oil swaps, crude oil puts, natural gas costless collars, natural gas three-way costless collars and natural gas swaps.

We use costless collars to establish floor (purchased put option) and ceiling prices (written call option) on our anticipated future crude oil and natural gas production. We do not pay or receive 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.

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.

We also use put options to establish floor prices (purchased put option) on our anticipated future crude oil production. We pay an initial premium when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us.

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. Crude 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 crude oil and natural gas contracts as of June 30, 2010, the associated volumes and the corresponding weighted average NYMEX floor and cap price.


	Crude		Purchased		Written
	oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Crude oil Costless Collars*
07/01/10 - 12/31/10		60,000	$	48.70	$	80.00
07/01/10 - 12/31/10		48,000	$	57.50	$	82.15
07/01/10 - 12/31/10		18,000	$	60.00	$	86.50
01/01/11 - 12/31/11		84,000	$	65.00	$	88.25
07/01/10 - 09/30/10		6,000	$	70.00	$	87.25
10/01/10 - 12/31/10		3,000	$	70.00	$	88.50
07/01/10 - 09/30/10		9,000	$	60.00	$	91.40
07/01/10 - 12/31/10		30,000	$	60.00	$	88.80
01/01/11 - 12/31/11		60,000	$	60.00	$	97.25
01/01/11 - 12/31/11		60,000	$	65.00	$	108.00
01/01/11 - 06/30/11		18,000	$	65.00	$	97.50
07/01/10 - 12/31/10		18,000	$	60.00	$	96.00
07/01/10 - 12/31/10		12,000	$	60.00	$	100.00
07/01/10 - 12/31/10		12,000	$	65.00	$	107.70
01/01/11 - 12/31/11		48,000	$	70.00	$	106.80
07/01/10 - 12/31/10		24,000	$	70.00	$	101.75
07/01/10 - 08/31/10		6,000	$	70.00	$	99.00
01/01/11 - 12/31/11		48,000	$	75.00	$	102.60
07/01/11 - 12/31/11		12,000	$	75.00	$	103.00
07/01/10 - 12/31/10		30,000	$	65.00	$	94.25
01/01/11 - 06/30/11		24,000	$	70.00	$	92.50
07/01/11 - 09/30/11		9,000	$	70.00	$	95.00
10/01/11 - 12/31/11		6,000	$	70.00	$	96.35
01/01/11 - 02/28/11		10,000	$	70.00	$	92.00
07/01/10 - 12/31/10		18,000	$	70.00	$	91.50
01/01/11 - 07/31/11		21,000	$	70.00	$	94.80
07/01/10 - 11/30/10		15,000	$	70.00	$	95.50
01/01/11 - 03/31/11		9,000	$	75.00	$	93.50
07/01/11 - 12/31/11		12,000	$	75.00	$	95.15
07/01/10 - 12/31/10		30,000	$	75.00	$	101.00
01/01/11 - 12/31/11		36,000	$	75.00	$	104.30
07/01/10 - 07/31/10		10,000	$	75.00	$	100.50
01/01/12 - 06/30/12		60,000	$	75.00	$	106.90
08/01/10 - 10/31/10		15,000	$	75.00	$	101.00
01/01/11 - 02/28/11		8,000	$	75.00	$	103.50
03/01/11 - 04/30/11		16,000	$	75.00	$	104.50
01/01/11 - 12/31/11		36,000	$	65.00	$	100.00
08/01/10 - 07/31/12		365,500	$	65.00	$	97.20
08/01/10 - 07/31/12		365,500	$	65.00	$	98.55
08/01/10 - 07/31/12		365,500	$	65.00	$	100.00
08/01/10 - 07/31/12		365,500	$	65.00	$	100.40


	Crude		Purchased
	oil		Put
Settlement Period	(Bbls)		(Nymex)
*Crude oil Floors*
01/01/11 - 06/30/12		273,500	$	65.00
01/01/11 - 06/30/12		273,500	$	65.00


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
07/01/10 - 09/30/10		210,000	$	5.75	$	7.30
10/01/10 - 03/31/11		240,000	$	6.50	$	8.25
07/01/10 - 09/30/10		120,000	$	5.75	$	7.00
07/01/10 - 12/31/10		420,000	$	5.15	$	7.00
07/01/10 - 09/30/10		150,000	$	5.50	$	6.65
10/01/10 - 03/31/11		420,000	$	6.40	$	7.80
01/01/11 - 12/31/11		360,000	$	5.75	$	7.65
01/01/11 - 12/31/11		480,000	$	5.75	$	7.40
04/01/11 - 12/31/11		360,000	$	5.00	$	6.55

The following table reflects commodity derivative contracts entered into subsequent to June 30, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.


	Crude		Purchased		Written
	oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Crude oil Costless Collars*
03/01/11 - 08/31/11		46,000	$	65.00	$	94.80
09/01/11 - 12/31/11		61,000	$	65.00	$	97.40
01/01/12 - 06/30/12		182,000	$	65.00	$	99.25
09/01/11 - 12/31/11		61,000	$	65.00	$	99.00
03/01/11 - 08/31/11		46,000	$	65.00	$	96.75
01/01/12 - 06/30/12		91,000	$	65.00	$	101.00
01/01/12 - 06/30/12		182,000	$	65.00	$	100.75
01/01/12 - 06/30/12		91,000	$	65.00	$	102.75
07/01/12 - 07/31/12		62,000	$	65.00	$	102.25
05/01/11 - 12/31/11		122,500	$	65.00	$	100.00
07/01/12 - 07/31/12		31,000	$	65.00	$	105.25
05/01/11 - 12/31/11		122,500	$	65.00	$	106.50
11/01/10 - 02/28/11		60,000	$	65.00	$	98.75

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 30, 2010, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our principal executive officer and our principal financial officer concluded that the design and operation of our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the second quarter of 2010 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 Statements, 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

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2009, other than the following:

We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect of these adoptions and interpretations may have on our business or financial condition.

Our business is subject to laws and regulations promulgated by federal, state and local authorities, including but not limited to the United States Congress, the Federal Energy Regulatory Commission, the Environmental Protection Agency (EPA), the Bureau of Land Management, the Texas Railroad Commission, the Texas Commission on Environmental Quality, the Oklahoma Corporation Commission, the Louisiana Department of Natural Resources, the Industrial Commission of North Dakota, the Wyoming Oil and Gas Conservation Commission and the Montana Board of Oil and Gas Conservation relating to the exploration for, and the development, production and marketing of, oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation.

Our operations are subject to complex federal, state and local environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, and the Clean Water Act. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm us. For example, on June 9, 2009, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2009 were introduced in the United States Senate and House of Representatives. These bills would repeal the exemption for hydraulic fracturing from the federal Safe Drinking Water Act, which would have the effect of allowing the EPA to promulgate regulations requiring permits and imposing new restrictions on hydraulic fracturing under the federal Safe Drinking Water Act. This could, in turn, require state regulatory agencies in states with programs delegated under the Safe Drinking Water Act to impose additional requirements on hydraulic fracturing operations. In addition, the bills would require persons using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas, of their fracturing fluids to a regulatory agency, which would make the information public via the internet, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. If this or similar legislation becomes law, it could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if the federal or state legislation is enacted into law. In addition, in March 2010, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Thus, even if the pending legislation is not adopted, the EPA study, depending on its results, could spur further initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which contains comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation contains significant derivatives regulation, including provisions requiring certain transactions to be cleared on exchanges and containing a requirement to post cash collateral (commonly referred to as “margin”) for such transactions as well as certain clearing and trade-execution requirements in connection with our derivative activities. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. However, we do not know the definitions that the CFTC will actually promulgate nor how these definitions will apply to us. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

Depending on the rules and definitions adopted by the CFTC, we could be required to post collateral with our dealer counterparties for our commodities hedging transactions. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity, thereby reducing our ability to use cash for investment or other corporate purposes, or would require us to increase our level of debt), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. In addition, a requirement for our counterparties to post collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

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

Issuer Purchases of Equity Securities

In the second quarter 2010, we elected to allow employees to deliver shares of vested restricted stock with a fair market value equal to their federal, state and local tax withholding amounts on the date of issue in lieu of cash payment.


	Total Number of		Average Price
Period	Shares Purchased		Paid per Share
May 2010		2,117	$	18.05
June 2010		2,082	$	14.44

TOTAL		4,199	$	16.26

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (REMOVED AND RESERVED)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



	3.1			Certificate of Incorporation (filed as Exhibit 3.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference)

	3.2			Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to Brigham’s Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated herein by reference)

	3.3			Bylaws, as amended through May 28, 2009 (incorporated by reference to Exhibit 3.5 to Brigham’s Current Report on Form 8-K filed May 28, 2009)

	3.4			Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated June 14, 2006 (filed as Exhibit 3.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference)

	3.5			Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated October 7, 2009 (filed as Exhibit 3.5 to Brigham’s Current Report on Form 8-K (dated October 13, 2009) and incorporated herein by reference)

	4.1			Form of Common Stock Certificate (filed as Exhibit 4.1 to Brigham’s Registration Statement on Form S-1 (Registration No. 333-22491) and incorporated herein by reference)

	4.2			Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference)

	4.3			Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001) and incorporated herein by reference)

	4.4			Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brigham’s Annual Report on Form 10-K for the year ended December 31, 2002 (filed March 31, 2003) and incorporated herein by reference)

	4.5			Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit 99.2 to Brigham’s Current Report on Form 8-K (filed July 20, 2004) and incorporated herein by reference)

	4.6			Indenture, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference)

	4.7			Notations of Guarantees, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference)



	4.8			Rule 144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference)

	4.9			Reg S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.4 to Brigham’s Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference)

	4.10			Notations of Guarantees dated as of April 9, 2007, among Brigham Exploration Company, the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.2 to Brigham’s Current Report on Form 8-K (filed April 13, 2007) and incorporated in by reference)

	4.11			Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brigham’s Current Report on Form 8-K (filed April 13, 2007) and incorporated in by reference)

	4.12			Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 to Brigham’s Current Report on Form 8-K (filed April 13, 2007) and incorporated herein by reference)

	4.13			Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)

	4.14			Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brigham’s Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference)

	4.15			Certificate of Elimination of Certificate of Designations of Series C Junior Preferred Stock of Brigham Exploration Company effective March 9, 2010 (filed as Exhibit 3.6 to Brigham’s Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)

	10.46			1997 Incentive Plan, as amended through March 9, 2010 (filed as Exhibit 10.46 to Brigham’s Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference)

	10.47			Sixth Amendment and Consent to the Fourth Amended and Restated Credit Agreement dated as of June 29, 2005 between the Company and the banks named therein (filed as Exhibit 10.47 to Brigham’s Current Report on Form 8-K (filed June 3, 2010) and incorporated herein by reference)

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

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

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

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


*		Management contract or compensatory plan.


	Page
PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets — June 30, 2010 and December 31, 2009		1

Consolidated Statements of Operations — Three and six months ended June 30, 2010 and 2009		2

Consolidated Statement of Stockholders’ Equity — Six months ended June 30, 2010		3

Consolidated Statements of Cash Flows — Six months ended June 30, 2010 and 2009		4

Notes to the Consolidated Financial Statements		5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		34

ITEM 4. CONTROLS AND PROCEDURES		37

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		38

ITEM 1A. RISK FACTORS		38

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		39

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		40

ITEM 4. (REMOVED AND RESERVED)		40

ITEM 5. OTHER INFORMATION		40

ITEM 6. EXHIBITS		40

SIGNATURES		42

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


	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