Form 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2009


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	1311	75-2692967
(State of other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

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

(512) 427-3300
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No 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 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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 November 3, 2009		99,014,801

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

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


	September 30,			December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	55,878		$	40,043
Restricted cash		10,019			555
Accounts receivable		15,219			24,558
Derivative assets		1,543			5,140
Investments		8,852			—
Inventory		8,046			6,070
Other current assets		1,203			2,154

Total current assets		100,760			78,520

Oil and natural gas properties, using the full cost method including
Proved, net		236,542			298,833
Unproved		72,858			106,006

		309,400			404,839

Other property and equipment, net		2,622			1,873
Deferred loan fees		5,660			3,122
Other noncurrent assets		374			702

Total assets	$	418,816		$	489,056


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	8,010		$	14,297
Royalties payable		5,586			6,859
Accrued drilling costs		10,430			19,768
Participant advances received		5,739			2,226
Other current liabilities		11,094			5,065

Total current liabilities		40,859			48,215


Senior Notes		158,908			158,730
Senior Credit Facility		110,000			145,000
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at September 30, 2009 and December 31, 2008		10,101			10,101
Deferred income taxes		444			149
Other noncurrent liabilities		6,644			5,592

Commitments and contingencies (Note 4)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 82,447,702 and 45,829,277 shares issued and 82,258,658 and 45,686,295 shares outstanding at September 30, 2009 and December 31, 2008, respectively		824			458
Additional paid-in capital		308,514			212,473
Treasury stock, at cost; 189,044 and 142,982 shares at September 30, 2009 and December 31, 2008, respectively		(1,478	)		(1,202	)
Accumulated deficit		(216,000	)		(90,460	)

Total stockholders’ equity		91,860			121,269

Total liabilities and stockholders’ equity	$	418,816		$	489,056

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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenues:
Oil and natural gas sales	$	18,747		$	31,731		$	45,765		$	101,112
Gain (loss) on derivatives, net		1,114			15,435			3,030			(3,928	)
Other revenue		6			25			72			104

		19,867			47,191			48,867			97,288

Costs and expenses:
Lease operating		3,279			3,092			10,651			8,626
Production taxes		1,551			1,383			3,196			4,107
General and administrative		2,082			2,502			6,468			7,691
Depletion of oil and natural gas properties		7,835			11,718			23,901			36,566
Impairment of oil and natural gas properties		—			—			114,781			—
Depreciation and amortization		234			159			550			464
Accretion of discount on asset retirement obligations		107			83			313			263
Loss on inventory valuation		29			—			2,196			—

		15,117			18,937			162,056			57,717

Operating income (loss)		4,750			28,254			(113,189	)		39,571


Other income (expense):
Interest income		157			49			361			163
Interest expense, net		(4,521	)		(3,762	)		(12,899	)		(10,663	)
Other income (expense)		400			16			482			419

		(3,964	)		(3,697	)		(12,056	)		(10,081	)

Income (loss) before income taxes		786			24,557			(125,245	)		29,490

Income tax expense:
Current		—			—			—			—
Deferred		(295	)		(9,297	)		(295	)		(11,186	)

		(295	)		(9,297	)		(295	)		(11,186	)

Net income (loss)	$	491		$	15,260		$	(125,540	)	$	18,304

Net income (loss) per share available to common stockholders:
Basic	$	0.01		$	0.34		$	(2.00	)	$	0.40

Diluted	$	0.01		$	0.33		$	(2.00	)	$	0.40


Weighted average shares outstanding:
Basic		82,085			45,481			62,633			45,358

Diluted		82,756			46,632			62,633			46,334

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)


	Nine Months Ended
	September 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(125,540	)	$	18,304
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion of oil and natural gas properties		23,901			36,566
Impairment of oil and natural gas properties		114,781			—
Depreciation and amortization		550			464
Stock based compensation		1,360			1,223
Amortization of deferred loan fees and debt issuance costs		1,127			810
Market value adjustment for derivative instruments		6,037			(1,645	)
Accretion of discount on asset retirement obligations		313			263
Deferred income taxes		295			11,186
Other noncash items		35			4
Changes in operating assets and liabilities:
Accounts receivable		9,339			(13,827	)
Other current assets		(1,123	)		(3,163	)
Accounts payable		(6,287	)		18,648
Royalties payable		(1,273	)		1,684
Participant advances received		3,513			(504	)
Other current liabilities		4,199			4,057
Other noncurrent assets and liabilities		(16	)		(432	)

Net cash provided (used) by operating activities		31,211			73,638


Cash flows from investing activities:
Additions to oil and natural gas properties		(51,113	)		(136,822	)
Decrease (increase) in restricted cash		(9,464	)		(2,562	)
Increase (decrease) in short term investments		(8,852	)		—
Additions to other property and equipment		(1,334	)		(806	)
Decrease (increase) in drilling advances paid		171			(3,061	)

Net cash provided (used) by investing activities		(70,592	)		(143,251	)


Cash flows from financing activities:
Proceeds from issuance of common stock, net of issuance costs		93,407			—
Increase in senior credit facility		—			62,900
Repayment of senior credit facility		(35,000	)		—
Deferred loan fees paid and equity costs		(3,389	)		(223	)
Proceeds from exercise of employee stock options		474			2,072
Repurchases of common stock		(276	)		(336	)

Net cash provided (used) by financing activities		55,216			64,413

Net increase (decrease) in cash and cash equivalents		15,835			(5,200	)
Cash and cash equivalents, beginning of year		40,043			13,863

Cash and cash equivalents, end of period	$	55,878		$	8,663

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 2008 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

3. Restricted Cash

Restricted cash at December 31, 2008 of $555,000 included deposits in an interest bearing escrow account under the terms of a turnkey drilling contract executed during the third quarter of 2008. Restricted cash at September 30, 2009 of $10 million included deposits required under the Senior Credit Facility.

4. Commitments and Contingencies

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

As of September 30, 2009, 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.

5. 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 nine months ended September 30, 2009 and 2008 are as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Weighted average common shares outstanding — basic		82,085		45,481		62,633		45,358
Plus: Potential common shares Stock options and restricted stock		671		1,151		—		976

Weighted average common shares outstanding — diluted		82,756		46,632		62,633		46,334


Stock options excluded from diluted EPS due to the anti-dilutive effect		2,688		64		4,779		341

6. Income Taxes

The income tax expense for the nine months ended September 30, 2009 and 2008 consists of the following (in thousands):


	September 30,		September 30,
	2009		2008
Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		—		10,269
State		295		917

	$	295	$	11,186

No deferred federal or state income tax benefit was recorded in the third quarter of 2009 because of ceiling test write-downs in the fourth quarter of 2008 and in the first quarter of 2009 resulting in increased valuation allowances on Brigham’s net deferred tax assets. A deferred state income tax expense of $295,000 was recorded in the third quarter of 2009 related to deferred tax liabilities in the state of North Dakota.

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. In 2006 and 2007, Brigham examined the tax positions taken in its tax returns and determined that the full values of the uncertain tax positions were reflected as part of its deferred tax liabilities and reclassified these liabilities to other tax liabilities on the consolidated balance sheet. In 2008, Brigham received approval from the Internal Revenue Service to change its method of accounting for certain geological and geophysical costs and no longer has a liability for uncertain tax positions. As a result, as of December 31, 2008, Brigham eliminated the other tax liabilities in its consolidated balance sheet.

The following table sets forth the reconciliation of unrecognized tax benefits for the nine months ended September 30:


	2009		2008
	(In thousands)		(In thousands)
Unrecognized tax benefits at beginning of the year	$	—	$	2,162
Increases (decreases) resulting from tax positions taken in the current period		—		(1,830	)

Unrecognized tax benefits at end of the quarter	$	—	$	332

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 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.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

7. 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 consist of swaps, 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 8, “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 September 30, 2009, the associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry Hub).


	Natural				Purchased		Written
	Gas		Oil		Put		Call
Settlement Period	(MMBTU)		(Barrels)		Nymex		Nymex
*Natural Gas Costless Collars*
10/01/09 - 03/31/10		420,000			$	5.75	$	7.05
11/01/09 - 12/31/10		980,000			$	5.15	$	7.00
04/01/10 - 09/30/10		420,000			$	5.75	$	7.30
04/01/10 - 09/30/10		240,000			$	5.75	$	7.00
04/01/10 - 09/30/10		300,000			$	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
*Oil Costless Collars*
10/01/09 - 12/31/09				30,000	$	60.00	$	81.00
10/01/09 - 03/31/10				18,000	$	60.00	$	91.75
10/01/09 - 05/31/10				80,000	$	57.50	$	75.95
10/01/09 - 12/31/09				30,000	$	49.00	$	70.00
10/01/09 - 12/31/09				11,000	$	62.50	$	76.75
01/01/10 - 03/31/10				6,000	$	65.00	$	87.50
01/01/10 - 12/31/10				120,000	$	48.70	$	80.00
01/01/10 - 12/31/10				54,000	$	60.00	$	86.50
01/01/10 - 12/31/10				60,000	$	60.00	$	88.80
04/01/10 - 09/30/10				18,000	$	60.00	$	91.40
06/01/10 - 12/31/10				56,000	$	57.50	$	82.15
07/01/10 - 09/30/10				6,000	$	70.00	$	87.25
10/01/10 - 12/31/10				3,000	$	70.00	$	88.50
01/01/11 - 12/31/11				84,000	$	65.00	$	88.25
01/01/11 - 12/31/11				60,000	$	60.00	$	97.25


	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMBTU)		Nymex		Nymex		Nymex
*Natural Gas Three Way Costless Collars*
10/01/09 - 03/31/10		420,000	$	8.00	$	10.00	$	5.50
10/01/09 - 03/31/10		360,000	$	5.75	$	7.00	$	3.50


	Natural				Written
	Gas		Oil		Swap
Settlement Period	(MMBTU)		(Barrels)		Nymex
*Natural Gas Swaps*
10/01/09 - 12/31/09		172,000			$	4.44
10/01/09 - 10/31/09		70,000			$	4.03
10/01/09 - 12/31/09		60,000			$	4.90
*Oil Swaps*
10/01/09 - 12/31/09				30,000	$	50.75

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects commodity derivative contracts entered subsequent to September 30, 2009, the associated volumes and the corresponding weighted average NYMEX reference price.


			Purchased		Written
	Oil		Put		Call
Settlement Period	(Barrels)		Nymex		Nymex
*Oil Collars*
01/01/10 - 06/30/10		30,000	$	60.00	$	103.75
01/01/11 - 12/31/11		60,000	$	65.00	$	108.00

Additional Disclosures about Derivative Instruments and Hedging Activities

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


		Estimated
Type of Contract	Balance Sheet Location	Fair Value
		(in thousands)
Derivatives Not Designated as Hedging Instruments

Derivative Assets:
Natural gas and oil contracts	Derivative assets — current	$	1,543
Natural gas and oil contracts	Other non-current assets		45

Total Derivative Assets		$	1,588

Derivative Liabilities:
Natural gas and oil contracts	Other current liabilities	$	(1,835	)
Natural gas and oil contracts	Other non-current liabilities		(453	)

Total Derivative Liabilities		$	(2,288	)

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

Three Months

Nine Months

Ended Sept 30,

Statement of Operations

Amount of

Type of Contract

Location of Gain (Loss)

Gain (Loss)

(in thousands)

Derivatives Not Designated as Hedging Instruments

Natural gas contracts

Gain (loss) on derivatives, net

374

5,770

Oil contracts

Gain (loss) on derivatives, net

740

(2,740

)

Total Derivative Gain (loss)

1,114

3,030

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 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.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. 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.

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. 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 September 30, 2009 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	September 30,			for Identical Assets		Inputs			Inputs
Description	2009			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(1,835	)	$	—	$	(1,835	)	$	—
Other non-current liabilities		(453	)		—		(453	)		—
Current derivative assets		1,543			—		1,543			—
Other non-current assets		45			—		45			—

	$	(700	)	$	—	$	(700	)	$	—


				Fair Value Measurements at December 31, 2008 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2008			(Level 1)		(Level 2)			(Level 3)
Other current liabilities	$	(5	)	$	—	$	(5	)	$	—
Other non-current liabilities		—			—		—			—
Current derivative assets		5,140			—		5,140			—
Other non-current assets		202			—		202			—

	$	5,337		$	—	$	5,337		$	—

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. The fair value of the asset retirement obligations is reflected on the balance sheet as detailed below.


				Fair Value Measurements at September 30, 2009 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	September 30,			for Identical Assets		Inputs		Inputs
Description	2009			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(6,193	)		—		—		(6,193	)

	$	(6,193	)	$	—	$	—	$	(6,193	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


				Fair Value Measurements at December 31, 2008 Using
				Quoted Prices in		Significant Other		Significant
				Active Markets		Observable		Unobservable
	December 31,			for Identical Assets		Inputs		Inputs
Description	2008			(Level 1)		(Level 2)		(Level 3)
Other non-current liabilities		(5,592	)		—		—		(5,592	)

	$	(5,592	)	$	—	$	—	$	(5,592	)

See Note 13 for a rollforward of the asset retirement obligation.

As of September 30, 2009, Brigham held $8.9 million of investments in certificates of deposit which have maturities of less than a year. There were no investments at December 31, 2008. The fair value of the investments is reflected on the balance sheet as detailed below.


			Fair Value Measurements at September 30, 2009 Using
			Quoted Prices in		Significant Other		Significant
			Active Markets		Observable		Unobservable
	September 30,		for Identical Assets		Inputs		Inputs
Description	2009		(Level 1)		(Level 2)		(Level 3)
Investments		8,852		8,852		—		—

	$	8,852	$	8,852	$	—	$	—

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:


	September 30, 2009				December 31, 2008
	(in millions)				(in millions)
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior Notes	$	160,000	$	144,800	$	160,000	$	84,000
Series A Preferred Stock	$	10,101	$	10,163	$	10,101	$	10,032

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

9. 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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for differentials), 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 oil and gas prices in effect on September 30, 2009 ($3.30 per MMBtu for Henry Hub natural gas and $70.61 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 September 30, 2009.

10. Common Stock Offering

In May 2009, Brigham completed a public offering of common stock pursuant to a shelf registration statement. Brigham sold 36,292,117 shares at a price of $2.75 and received net proceeds of $93.5 million after underwriting fees and offering expenses. Brigham used the net proceeds from the offering to repay $35 million of outstanding borrowings under its Senior Credit Facility. Brigham is using the remaining net proceeds to fund an expanded capital budget in 2009 and a portion of the 2010 capital budget. In October 2009, Brigham completed an additional public offering of common stock pursuant to a shelf registration. Refer to Note 16 for additional details.

11. 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.

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. The indenture requires Brigham to maintain a fixed charge coverage ratio (as defined) for the most recent four full fiscal quarters of at least 2.5 to 1. At September 30, 2009, Brigham was in compliance with all covenants under the indenture.

12. Senior Credit Facility

In November 2008, in conjunction with Brigham’s regularly scheduled semi-annual redetermination, the borrowing base was reset to $145 million. 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. As of September 30, 2009, Brigham had $110.0 million in borrowings outstanding under the Senior Credit Facility.

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 (3.5% at September 30, 2009). 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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 September 30, 2009). 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 others 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 September 30, 2009 of at least 2.5 to 1, for the quarters ending December 31, 2009 and March 31, 2010 of at least 2.0 to 1, and thereafter must be at least 2.5 to 1. The Senior Credit Facility also requires Brigham to maintain a net leverage ratio for the quarters ending September 30, 2009 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 September 30, 2009, Brigham was in compliance with all covenants under the Senior Credit Facility.

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.

The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410 during the nine months ended September 30, 2009 and 2008 (in thousands):


	Nine Months Ended
	September 30,
	2009			2008
Beginning asset retirement obligations	$	5,592		$	5,047
Liabilities incurred for new wells placed on production		303			267
Liabilities settled		(15	)		(102	)
Accretion of discount on asset retirement obligations		313			263

	$	6,193		$	5,475

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.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The estimated fair value of the options granted during the nine months ended September 30, 2009 and 2008 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 nine months ended September 30, 2009 and 2008:


	2009			2008
Risk-free interest rate		2.65	%		3.0	%
Expected life (in years)		5.0			5.0
Expected volatility		78	%		47	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	3.14		$	4.70

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 nine months ended September 30, 2009 and 2008.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Pre-tax stock based compensation expense	$	1,060		$	746		$	2,526		$	2,253
Capitalized stock based compensation		(497	)		(341	)		(1,166	)		(1,030	)
Tax benefit		(197	)		(142	)		(476	)		(428	)

Stock based compensation expense, net	$	366		$	263		$	884		$	795

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 September 30, 2009, the number of shares available under the plan was equal to the lesser of 6,962,648 or 15% of the total number of shares of common stock outstanding. At September 30, 2009, approximately 9,423 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 616,800 shares remain available for grant under the director stock option plan.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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


	2009					2008
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Options outstanding at the beginning of the year		3,128,651		$	7.00		3,046,166		$	7.14
Granted		2,686,975		$	4.35		18,000		$	10.56
Forfeited or cancelled		(1,549,675	)	$	8.30		(64,800	)	$	7.83
Exercised		(99,800	)	$	4.73		(385,715	)	$	5.36

Options outstanding at the end of the quarter		4,166,151		$	4.86		2,613,651		$	7.41

Options exercisable at the end of the quarter		694,876		$	5.95		1,685,951		$	7.04

The weighted-average grant-date fair value of share options granted during the nine months ended September 30, 2009 and 2008 was $3.14 and $4.70 respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2009 and 2008 was $477,000 and $2.4 million, respectively.

The following table summarizes information about stock options outstanding and exercisable at September 30, 2009:


	Options Outstanding					Options Exercisable
	Number		Weighted-			Number		Weighted-
	Outstanding at		Average	Weighted-		Exercisable at		Average	Weighted-
	September 30,		Remaining	Average		September 30,		Remaining	Average
Exercise Price	2009		Contractual Life	Exercise Price		2009		Contractual Life	Exercise Price
$2.21 to $3.41		1,227,000	9.3 years	$	2.27		27,000	1.0 years	$	3.41
3.66 to 5.08		718,200	4.1 years	$	4.78		258,200	0.6 years	$	4.24
5.96 to 6.73		1,949,851	8.5 years	$	6.01		256,576	3.1 years	$	6.27
7.22 to 8.84		189,100	3.8 years	$	7.71		97,100	2.7 years	$	7.94
8.93 to 11.74		82,000	2.8 years	$	10.31		56,000	2.7 years	$	10.13

$2.21 to $11.74		4,166,151	7.7 years	$	4.86		694,876	2.0 years	$	5.95

The aggregate intrinsic value of options outstanding and exercisable at September 30, 2009 was $12.9 million and $2.2 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 September 30, 2009. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of September 30, 2009 there was approximately $6.1 million of total unrecognized compensation expense related to unvested stock based compensation plans. This compensation expense is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining vesting period of approximately 4.8 years.

Brigham commenced an exchange offer on July 13, 2009 pursuant to which eligible employees were offered the opportunity to exchange outstanding stock options granted prior to April 21, 2009 for new stock options. On Monday, August 10, 2009, pursuant to the exchange offer, eligible optionholders tendered, and Brigham accepted for cancellation, 1,536,975 eligible stock options. After the cancellation of the options accepted by Brigham in the exchange offer, Brigham granted new stock options with an exercise price of $5.955 per share, which was the mean of the high and low sales price per share of Brigham shares as reported by The Nasdaq Global Select Market on August 10, 2009. The exchange of options resulted in incremental compensation expense of $1.3 million that will be recognized over the five year vesting period of the new options.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Restricted Stock

During the nine months ended September 30, 2009 and 2008, Brigham issued 247,074 and 109,000, 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 except for 162,074 restricted shares granted in 2009 that vest in the third and fourth quarter of 2009. As of September 30, 2009, there was approximately $2.4 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.3 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 nine months ended September 30:


	2009					2008
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Restricted shares outstanding at the beginning of the year		593,260		$	7.58		653,623		$	7.16
Shares granted		247,074		$	2.62		109,000		$	8.40
Lapse of restrictions		(226,008	)	$	4.27		(128,813	)	$	5.98
Forfeitures		(1,000	)	$	9.49		(29,940	)	$	6.58

Shares outstanding at the end of the quarter		613,326		$	6.80		603,870		$	7.67

15. Comprehensive Income

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009			2008
Net income (loss)	$	491	$	15,260	$	(125,540	)	$	18,304
Net (gains) losses included in net income		—		—		—			(177	)
Tax benefits (provisions) related to cash flow hedges		—		—		—			62

Other Comprehensive Income, net	$	491	$	15,260	$	(125,540	)	$	18,189

16. Subsequent Events

On October 7, 2009, the stockholders approved an amendment to Brigham’s Certificate of Incorporation to increase the number of shares of common stock which Brigham is authorized to issue from 90 million shares to 180 million shares. The amendment to the Certificate of Incorporation became effective on October 7, 2009. Additionally, stockholders approved an amendment to the 1997 Incentive Plan that increased the number of shares of common stock available for issuance under the 1997 Incentive Plan to the lesser of (i) 9,966,603 or (ii) 12% of the total number of shares of common stock outstanding at any time. At November 3, 2009 there were 3,012,778 shares of common stock available for issuance.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

On October 21, 2009, Brigham entered into an underwriting agreement with Credit Suisse Securities (USA) LLC and Jefferies & Company, Inc., as representatives for the several underwriters (“Underwriters”), to issue and sell to the Underwriters an aggregate of 16,000,000 shares of its common stock, $0.01 par value. Pursuant to the underwriting agreement, Brigham also granted the Underwriters a 30-day option to purchase up to an additional 2,400,000 shares of Common Stock. The stock offering was priced at $10.50 per share. On October 27, 2009, Brigham used a portion of the proceeds from the stock offering to repay borrowings under the Senior Credit Facility of $110 million.

On November 4, 2009, the Underwriters elected to exercise a portion of the over-allotment option associated with the October 2009 equity offering. This will result in the issuance of 837,523 additional shares from which Brigham will receive net proceeds of approximately $8.4 million when the transaction closes.

17. New Accounting Pronouncements and SEC Rulemaking

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Board Auditing Standard Codification Topic 820 “Fair Value Measurements and Disclosures” (FASB ASC 820), which provides expanded guidance for using fair value to measure assets and liabilities. FASB ASC 820 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of FASB ASC 820 was required on January 1, 2008 for financial assets and liabilities, as well as other assets and liabilities that are carried at fair value on a recurring basis in financial statements. The FASB Staff deferred implementation for other non-financial assets and liabilities for one year. Examples of non-financial assets and liabilities are asset retirement obligations and non-financial assets and liabilities initially measured at fair value in a business combination. The adoption of FASB ASC 820 did not have a material impact on the financial statements.

The Financial Accounting Standards Board revised Financial Accounting Standards Board Accounting Standard Codification Topic 805 “Business Combinations” (FASB ASC 805) in 2007. The revision broadens the application of the original pronouncement to cover all transactions and events in which an entity obtains control over one or more other businesses. This standard requires that transaction costs related to business combinations be expensed rather than be included in the acquisition cost. This standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The impact of this standard will be on the fair value recorded for future business combinations after adoption.

In March 2008, the Financial Accounting Standards Board revised certain provisions under Financial Accounting Standards Board Accounting Standard Topic 815 “Derivatives and Hedging” (FASB ASC 815) that require new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data; financial statement presentation of fair values on a gross basis, including those that currently qualify for netting; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. The revisions under FASB ASC 815 are effective for fiscal and interim periods beginning after November 15, 2008.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932 “Extractive Activities — Oil and Gas” (FASB ASC 932) provides guidance for oil and natural gas reserve related disclosures in the financial statements. Brigham is currently evaluating the impact that the adoption will have on the financial statements.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

In April 2009, the Financial Accounting Standards Board issued additional requirements under Financial Accounting Standards Board Accounting Standards Codification Topic 825 “Financial Instruments” (FASB ASC 825) which enhance consistency in financial reporting by increasing the frequency of fair value disclosures. The new requirements are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Adoption of the new requirements did not have a material impact on Brigham’s financial statements.

In May 2009, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 165 “Subsequent Events” (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 will apply with respect to interim or annual reporting periods ending after June 15, 2009. Brigham evaluated subsequent events through November 6, 2009, the date the financial statements were issued for the period ending September 30, 2009.

In June 2009, the Financial Accounting Standards Board issued Financial Accounting Standards Board Accounting Standards Codification Topic 105 “Generally Accepted Accounting Principles” (FASB ASC 105). FASB ASC 105 sets forth that the Financial Accounting Standards Board Accounting Standards Codification (ASC) is the exclusive authoritative reference for nongovernmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for SEC rules and interpretive releases, which also are authoritative GAAP for SEC registrants. The change was established by FASB Statement of Financial Accounting Standards No. 168 “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (FAS 168), which divides nongovernmental U.S. GAAP into the authoritative Codification and guidance that is nonauthoritative, doing away with the previous four-level hierarchy. FASB ASC 105 is effective for financial statements for interim or annual reporting periods ending after September 15, 2009. FASB ASC 105 was not intended to change or alter existing GAAP, and the Company’s adoption did not have any impact on its consolidated financial statements other than to modify certain existing disclosures. Upon adoption, the Company began to use the new guidelines and numbering system prescribed by the FASB ASC when referring to GAAP in the third quarter of fiscal 2009.


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 2008 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three and nine month periods ended September 30, 2009 and September 30, 2008. 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 2008 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 oil and natural gas reserves. We focus our activities in provinces where we believe these technologies, including horizontal drilling, multi-stage isolated fracture stimulation and 3-D seismic imaging, can be used to effectively maximize our return on invested capital.

Historically, our exploration and development activities have been focused in the Onshore Gulf Coast, the Anadarko Basin and West Texas. Beginning in late 2005, we began to acquire acreage within the Williston Basin in North Dakota and Montana, and through mid year 2009 have invested a total of $182 million on drilling, land and seismic in this region. 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 Bakken, Three Forks and Red River objectives.

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 attractive rates of return on our invested capital. Key elements of our business strategy include:

	•		Focus on Provinces;

	•		Leverage Our Engineering and Operational Expertise;

	•		Capitalize on Exploration Successes Through Disciplined Development Activities;

	•		Enhance Returns Through Operational Control; and

	•		Internally Generate an Inventory of High Quality Exploratory Prospects.

Overview of Third Quarter 2009 Financial Results

Third quarter 2009 oil and natural gas prices, excluding realized and unrealized derivative hedging results, decreased 47% and 66%, respectively, from that in the third quarter 2008. In the third quarter 2009, the average sales price that we received for oil, excluding realized and unrealized derivative hedging results, was $59.74 per barrel, which represents a $52.86 per barrel decrease from that in the third quarter 2008. In the third quarter 2009, the average sales price that we received for natural gas, excluding realized and unrealized derivative hedging results, was $3.38 per Mcf, which represents a $6.70 per Mcf decrease from that in the third quarter 2008.

Our third quarter 2009 production averaged 5,200 barrels of oil equivalent per day, which represents a 15% sequential increase from that in the second quarter 2009 and a 13% increase from that in the third quarter 2008. During the third quarter 2009, our oil volumes increased by 84% to approximately 2,606 barrels per day versus that in the third quarter 2008 as a result of our increased activity level in the Williston Basin. The natural production decline from our wells and our decreased level of drilling activity along the Texas Gulf Coast led to reduced natural gas production, which partially offset our higher oil production.

Our third quarter 2009 oil and natural gas revenues, including hedge settlements but excluding unrealized hedging gains and losses, were down $10.6 million, or 36%, compared to that in the third quarter 2008. Oil revenues in the third quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, increased $0.1 million from that in the third quarter 2008. Higher production volumes and hedge settlements increased oil revenues by $12.0 million and $0.5 million, respectively, while lower oil prices decreased oil revenues by $12.4 million. Natural gas revenues in the third quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, decreased $10.7 million

compared to that in the third quarter 2008. Lower natural gas prices and reduced production volumes decreased natural gas revenues $9.4 million and $3.2 million, respectively, while higher hedge settlements increased revenues by $1.9 million.

Third quarter 2009 operating income decreased $23.5 million from that in the third quarter last year. This decrease was attributable to the decline in commodity prices and lower natural gas volumes. These items were partially offset by higher oil volumes and lower depletion and general and administrative expenses.

As of September 30, 2009, we had $74.7 million in cash, cash equivalents and investments and $418.8 million in total assets.

Overview of Operational Results — July 1, 2009 to November 5, 2009

Rocky Mountain Province — Williston Basin

Recently Completed Wells and Drilling Participation Agreement

Strobeck 27-34 #1H. In July 2009, we successfully completed the Strobeck 27-34 #1H, which is a long lateral Three Forks well, with 18 isolated fracture stimulation stages. The Strobeck 27-34 #1H is located in Mountrail County, North Dakota in our Ross project area. The well produced approximately 2,021 barrels of oil equivalent during an early 24 hour flow back. Production from the well over the first 30 days averaged approximately 989 barrels of oil equivalent per day. We own an approximate 77% working interest and a 63% net revenue interest in the Strobeck 27-34 #1H.

Anderson 28-33 #1H. In August 2009, we successfully completed the Anderson 28-33 #1H, which is a long lateral Bakken well with 24 isolated fracture stimulation stages. The Anderson 28-33 #1H is also located in Mountrail County, North Dakota in our Ross project area. The well produced approximately 2,154 barrels of oil equivalent during an early 24 hour flow back. Production from the well over the first 30 days averaged approximately 1,346 barrels of oil equivalent per day. We have an approximate 66% working interest and 54% net revenue interest in the Anderson 28-33 #1H.

Figaro 29-32 #1H. In August 2009, we successfully completed the Figaro 29-32 #1H, which is a long lateral Bakken well, with 19 intervals and 35 pinpoint fracture stimulations. The Figaro 29-32 #1H is located in McKenzie County, North Dakota in our Rough Rider project area. The well produced approximately 1,895 barrels of oil equivalent during an early 24 hour flow back. Production from the well over the first 30 days averaged approximately 831 barrels of oil equivalent per day. We own an approximate 95% working interest and a 75% net revenue interest in the Figaro 29-32 #1H.

Brad Olson 9-16 #1H. In October 2009, we successfully completed the Brad Olson 9-16 #1H, which is a long lateral Bakken well, with 28 isolated fracture stimulation stages. The Brad Olson 9-16 #1H is located in Williams County, North Dakota in our Rough Rider project area. The well produced approximately 2,112 barrels of oil equivalent during an early 24 hour flow back. We have retained an initial approximate 33% working interest and 26% net revenue interest in the well, subject to our Rough Rider drilling participation agreement described below. The Brad Olson 9-16 #1H is the first well to be drilled under our Rough Rider drilling participation agreement.

BCD Farms 16-21 #1H. In November 2009, we successfully completed the BCD Farms 16-21 #1H, which is a long lateral Bakken well, with 28 isolated fracture stimulation stages. The BCD Farms 16-21 #1H is located in Williams County, North Dakota in our Rough Rider project area. The well produced approximately 1,776 barrels of oil equivalent during an early 24 hour flow back. We have retained an initial approximate 24% working interest in the well, subject to our Rough Rider drilling participation agreement described below.

Rough Rider Drilling Participation Agreement. In late August, we entered into a drilling participation agreement in our Rough Rider project area, which encompasses both Williams and McKenzie Counties, North Dakota, in order to accelerate operations and address near term state lease expirations. Initially, six wells are to be drilled under the agreement and our counterparty has the option to participate in an additional nine wells. In each of the initial six wells, we will retain 35% of our original working interest and will back in for 35% of our counterparty’s interest in the combined six well group after combined payout (defined as the point in time when the cumulative net receipts from the initial wells equals or exceeds all expenditures for such wells). In the optional nine wells, we may elect to retain 50% to 15% of our original working interest in the wells and back in after payout for a portion of our counterparty’s interest. We will have the option to keep up to 64% of our original working interest in all subsequent development wells in the 15 drilling units.

Subsequent Events

Universal Shelf Registration Statement Declared Effective

On October 5, 2009, our universal shelf registration statement covering the sale of $300 million of our common stock, preferred stock, depositary shares, warrants, rights, units and debt securities, or any combination of these securities became effective. Following the October equity offering and the exercise by the underwriters of their over-allotment in November, we have $123 million remaining under the shelf registration statement. This shelf registration statement expires in October 2012.

Amendment to Certificate of Incorporation

On October 7, 2009, our stockholders approved an amendment to our Certificate of Incorporation to increase the number of shares of common stock which we are authorized to issue from 90 million shares to 180 million shares. The amendment to the Certificate of Incorporation became effective on October 7, 2009.

October 2009 Equity Offering

In October 2009, we completed a public offering of common stock pursuant to our universal shelf registration statement. We sold 16,000,000 shares at a price of $10.50 per share and received net proceeds of $159.9 million, after underwriting fees and offering expenses. We intend to use the proceeds from this offering to fund a portion of our initial 2010 exploration and development budget, which consists primarily of our drilling programs in the Williston Basin that target both the Bakken and Three Forks objectives. Pending use of the net proceeds to fund our exploration and development budget, we used a portion of the net proceeds to repay the outstanding indebtedness under our Senior Credit Facility. We intend to re-borrow under our Senior Credit Facility in 2010 to fund exploration and development costs as they are incurred.

On November 4, 2009, underwriters elected to exercise a portion of the over-allotment option associated with the October 2009 equity offering. This will result in the issuance of 837,523 additional shares from which we will receive net proceeds of approximately $8.4 million when the transaction closes.

2009 and 2010 Capital Budgets

Subsequent to our October equity offering, our 2009 budget is anticipated to remain roughly in line with the budget announced in May 2009, as our lower working interest in wells as a result of our Rough Rider drilling participation agreement offsets the increased number of wells we will drill during the remainder of 2009. We anticipate setting our initial 2010 exploration and development budget at $175.8 million, which would include $169.4 million in drilling and $6.4 million in land capital. The increase in our drilling capital would be used to fund the drilling of 24 net horizontal wells in the Williston Basin. We currently anticipate the 24 net wells would be comprised of 21 net operated wells and three net non-operated wells. The majority of our drilling activity in 2010 would occur in our core developmental acreage positions in our Rough Rider and Ross project areas in Williams, McKenzie and Mountrail Counties, North Dakota. We also anticipate drilling a horizontal Bakken well in our Ghost Rider project area in Roosevelt County, Montana. Finally, our initial 2010 budget currently includes two net wells in our South Texas Vicksburg play in Brooks County, Texas.

Revenues, Commodity Prices and Hedging

The following table sets forth our production volumes, 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 September 30,									Nine months ended September 30,
	2009			%Change			2008			2009			%Change			2008
Oil revenue:
Oil revenue	$	14,010			(3	%)	$	14,381		$	28,065			(32	%)	$	41,178
Oil derivative settlement gains (losses)		(538	)		(49	%)		(1,050	)		322		NM				(3,237	)

Oil revenue including derivative settlements	$	13,472			1	%	$	13,331		$	28,387			(25	%)	$	37,941
Oil derivative unrealized gains (losses)		1,278			(75	%)		5,055			(3,063	)	NM				920

Oil revenue including derivative settlements and unrealized gains (losses)	$	14,750			(20	%)	$	18,386		$	25,324			(35	%)	$	38,861
Natural gas revenue:
Natural gas revenue	$	4,737			(73	%)	$	17,350		$	17,700			(70	%)	$	59,934
Natural gas derivative settlement gains (losses)		798		NM				(1,104	)		8,745		NM				(2,336	)

Natural gas revenue including derivative settlements	$	5,535			(66	%)	$	16,246		$	26,445			(54	%)	$	57,598
Natural gas derivative unrealized gains (losses)		(424	)	NM				12,534			(2,974	)	NM				725

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	5,111			(82	%)	$	28,780		$	23,471			(60	%)	$	58,323
Oil and natural gas revenue:
Oil and natural gas revenue	$	18,747			(41	%)	$	31,731		$	45,765			(55	%)	$	101,112
Oil and natural gas derivative settlement gains (losses)		260		NM				(2,154	)		9,067		NM				(5,573	)

Oil and natural gas revenue including derivative settlements		19,007			(36	%)		29,577			54,832			(43	%)		95,539
Oil and natural gas derivative unrealized gains (losses)		854			(95	%)		17,589			(6,037	)	NM				1,645

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		19,861			(58	%)		47,166			48,795			(50	%)		97,184
Other revenue		6			(76	%)		25			72			(31	%)		104

Total revenue	$	19,867			(58	%)	$	47,191		$	48,867			(50	%)	$	97,288


	Three months ended September 30,							Nine months ended September 30,
	2009		%Change			2008		2009		%Change			2008
Average oil prices:
Oil price (per Bo)	$	59.74		(47	%)	$	112.60	$	49.06		(56	%)	$	110.54
Oil price including derivative settlement gains (losses) (per Bo)		57.45		(45	%)		104.38		49.62		(51	%)		101.85
Oil price including derivative settlements and unrealized gains (losses) (per Bo)	$	62.90		(56	%)	$	143.96	$	44.27		(58	%)	$	104.32
Average natural gas prices:
Natural gas price (per Mcf)	$	3.38		(66	%)	$	10.08	$	3.76		(63	%)	$	10.23
Natural gas price including derivative settlement gains (losses) (per Mcf)		3.95		(58	%)		9.44		5.62		(43	%)		9.83
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	3.65		(78	%)	$	16.72	$	4.99		(50	%)	$	9.95
Average oil equivalent prices:
Oil equivalent price (per Boe)	$	40.06		(48	%)	$	76.46	$	33.75		(55	%)	$	74.95
Oil equivalent price including derivative settlement gains (losses) (per Boe)		40.61		(43	%)		71.27		40.44		(43	%)		70.82
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Boe)	$	42.44		(63	%)	$	113.65	$	35.98		(50	%)	$	72.04


	For the three			For the nine
	month periods			month periods
	ended September 30,			ended September
	2009 and 2008			30, 2009 and 2008
Change in revenue from the sale of oil
Volume variance impact	$	12,025		$	22,061
Price variance impact		(12,396	)		(35,174	)
Cash settlement of hedging contracts		512			3,559
Unrealized hedge gain or loss		(3,777	)		(3,983	)

Total change	$	(3,636	)	$	(13,537	)

Change in revenue from the sale of natural gas
Volume variance impact	$	(3,227	)	$	(11,818	)
Price variance impact		(9,386	)		(30,416	)
Cash settlement of hedging contracts		1,902			11,081
Unrealized hedge gain or loss		(12,958	)		(3,699	)

Total change	$	(23,669	)	$	(34,852	)

Change in revenue from the sale of oil and natural gas
Volume variance impact	$	8,798		$	10,242
Price variance impact		(21,782	)		(65,589	)
Cash settlement of hedging contracts		2,414			14,640
Unrealized hedge gain or loss		(16,735	)		(7,682	)

Total change	$	(27,305	)	$	(48,389	)

Third quarter 2009 oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), decreased $27.3 million when compared to that in the third quarter 2008. The change in revenues was attributable to the following:

•

a 48% decrease in pre-hedge sales prices per Boe resulted in a $21.8 million decrease in revenues;

•

a $0.9 million unrealized derivative gain in third quarter 2009 versus a $17.6 million unrealized derivative gain in third quarter 2008 decreased revenues by $16.7 million;

•

an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $8.8 million increase in oil and natural gas revenues; and

•

a $0.3 million gain from the settlement of derivative contracts in the third quarter 2009 versus a $2.1 million loss from the settlement of derivative contracts in third quarter 2008 increased revenues by $2.4 million.

First nine months 2009 oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), decreased $48.4 million when compared to that in the first nine months 2008. The change in revenues was attributable to the following:

•

a 55% decrease in pre-hedge sales prices per Boe resulted in a $65.6 million decrease in revenues;

•

a $6.1 million unrealized derivative loss in first nine months 2009 versus a $1.6 million unrealized derivative gain in first nine months 2008 decreased revenues by $7.7 million;

•

an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $10.2 million increase in oil and natural gas revenues; and

•

a $9.0 million gain from the settlement of derivative contracts in the first nine months 2009 versus a $5.6 million loss from the settlement of derivative contracts in first nine months 2008 increased revenues by $14.6 million.

Hedging. We utilize collars, three way costless collars 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 third quarter and first nine months 2009 and 2008 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 September 30,									Nine months ended September 30,
	2009			%Change			2008			2009			%Change			2008
Oil collars
Volumes (Bbls)		92,000			88	%		49,000			141,000			0	%		141,500
Average floor price ($ per Bo)	$	56.39			(25	%)	$	74.92		$	61.67			(10	%)	$	68.42
Average ceiling price ($ per Bo)	$	74.78			(25	%)	$	100.07		$	82.49			(11	%)	$	92.37
Gain (loss) upon settlement ($ in thousands)	$	(11	)		(99	%)	$	(1,050	)	$	1,115		NM			$	(3,237	)

Oil swaps
Volumes (Bbls)		30,000		NM				—			60,000		NM				—
Average swap price ($ per Bo)	$	50.75		NM			$	—		$	50.75		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	(527	)	NM			$	—		$	(793	)	NM			$	—

Total oil
Gain (loss) upon settlement ($ in thousands)	$	(538	)		(49	%)	$	(1,050	)	$	322		NM			$	(3,237	)

Natural gas collars
Volumes (MMbtu)		—		NM				1,130,000			1,000,000			(75	%)		4,020,000
Average floor price ($ per MMbtu)	$	—		NM			$	7.42		$	7.808			4	%	$	7.494
Average ceiling price ($ per MMbtu)	$	—		NM			$	9.95		$	9.321			(13	%)	$	10.751
Gain (loss) upon settlement ($ in thousands)	$	—		NM			$	(1,104	)	$	5,936		NM			$	(2,336	)

Natural gas three ways
Volumes (MMbtu)		—		NM				—			220,000		NM				—
Average floor price ($ per MMbtu)	$	—		NM			$	—		$	7.44		NM			$	—
Average ceiling price ($ per MMbtu)	$	—		NM			$	—		$	9.86		NM			$	—
Average price — written puts ($ per MMbtu)	$	—		NM			$	—		$	4.58		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	—		NM			$	—		$	996		NM			$	—

Natural gas swaps
Volumes (MMbtu)		1,126,000		NM				—			2,188,000		NM				—
Average swap price ($ per MMbtu)	$	4.138		NM			$	—		$	4.349		NM			$	—
Gain (loss) upon settlement ($ in thousands)	$	798		NM			$	—		$	1,813		NM			$	—

Total gas
Gain (loss) upon settlement ($ in thousands)	$	798		NM			$	(1,104	)	$	8,745		NM			$	(2,336	)

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 September 30,							Three months ended September 30,
	2009		%Change			2008		2009		%Change			2008
Production costs:
Operating & maintenance	$	5.59		(14	%)	$	6.47	$	2,616		(3	%)	$	2,684
Expensed workovers		0.75		241	%		0.22		351		282	%		92
Ad valorem taxes		0.67		(12	%)		0.76		312		(1	%)		316

Lease operating expenses	$	7.01		(6	%)	$	7.45	$	3,279		6	%	$	3,092

Production taxes		3.31		(1	%)		3.33		1,551		12	%		1,383

Production costs	$	10.32		(4	%)	$	10.78	$	4,830		8	%	$	4,475

Third quarter 2009 per unit of production costs decreased $0.46 per Boe, or 4%, when compared to that in the third quarter last year, mainly due to the following:

•

O&M expense decreased $0.88 per Boe, or 14%, due to a decrease in compressor rental and maintenance, salt water disposal, and well service and repair; and

•

workover expense increased $0.53 per Boe due to an increase in workover activity.


	Unit-of-Production							Amount
	(Per Boe)							(In thousands)
	Nine months ended September 30,							Nine months ended September 30,
	2009		%Change			2008		2009		%Change			2008
Production costs:
Operating & maintenance	$	6.13		26	%	$	4.85	$	8,313		27	%	$	6,542
Expensed workovers		1.09		11	%		0.98		1,476		12	%		1,316
Ad valorem taxes		0.64		12	%		0.57		862		12	%		768

Lease operating expenses	$	7.85		23	%	$	6.39	$	10,651		23	%	$	8,626

Production taxes		2.36		(22	%)		3.04		3,196		(22	%)		4,107

Production costs	$	10.21		8	%	$	9.43	$	13,847		9	%	$	12,733

First nine months 2009 per unit of production costs increased $0.78 per Boe, or 8%, when compared to the first nine months last year, mainly due to the following:

•

O&M expense increased $1.28 per Boe, or 26%, due to an increase in compressor rental and maintenance, electricity, and salt water disposal;

•

workover expense increased $0.11 per Boe due to an increase in workover activity; and

•

production taxes decreased $0.68 per Boe, or 22%, due to lower commodity prices.

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


	Three months ended September 30,									Nine months ended September 30,
	2009			%Change			2008			2009			%Change			2008
				(In thousands, except per unit measurements)
General and administrative costs	$	3,901			(16	%)	$	4,650		$	11,660			(19	%)	$	14,403
Capitalized general and administrative costs		(1,819	)		(15	%)		(2,148	)		(5,192	)		(23	%)		(6,712	)

General and administrative expenses	$	2,082			(17	%)	$	2,502		$	6,468			(16	%)	$	7,691


General and administrative expense ($ per Boe)	$	4.45			(26	%)	$	6.03		$	4.77			(16	%)	$	5.70

Our general and administrative costs for the third quarter 2009 decreased primarily because of a $0.6 million reduction in employee compensation costs associated with our cost cutting measures implemented earlier in the year.

General and administrative costs for the first nine months 2009 decreased primarily because of a $3.0 million reduction in employee compensation costs associated with our cost cutting measures implemented earlier in the year. Lower compensation costs were partially offset by $0.5 million in higher contract and professional fees.

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


	Three months ended September 30,							Nine months ended September 30,
	2009		%Change			2008		2009		%Change			2008
			(In thousands, except per unit measurements)
Depletion of oil and natural gas properties	$	7,835		(33	%)	$	11,718	$	23,901		(35	%)	$	36,566
Depletion of oil and natural gas properties ($ per Boe)	$	16.74		(41	%)	$	28.24	$	17.63		(35	%)	$	27.11

Our depletion expense for the third quarter 2009 was $3.9 million lower than that in the third quarter 2008. This decrease was due to a reduction in our depletion rate associated with our fourth quarter 2008 and first quarter 2009 ceiling test write-downs, which reduced depletion expense by $5.4 million. Higher production levels increased depletion expense by $1.5 million, which partially offset our higher depletion rate.

Our depletion expense for the first nine months 2009 was $12.7 million lower than that in the first nine months 2008. This decrease was due to the aforementioned ceiling test write-downs, which lowered our depletion rate and reduced depletion expense by $12.9 million; however, our higher production increased depletion expense by $0.2 million.

Impairment of oil and natural gas properties. We use 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; 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, 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 in the first quarter 2009 and was partially responsible for a first quarter 2009 before tax ceiling test write-down of $114.8 million. 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, combined with the impact from a deferred tax asset that was added to the full cost pool as a result of the year-end 2008 ceiling test write-down, resulted in our capitalized costs, net of accumulated depreciation, of our oil and gas properties to exceed the discounted present value of our estimated proved reserves using a 10% discount rate.

Based on oil and gas prices in effect on September 30, 2009 ($3.30 per MMBtu for Henry Hub natural gas and $70.61 per barrel for West Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas properties did not exceed the ceiling limit. Therefore, we were not required to writedown the net capitalized costs of its oil and gas properties at September 30, 2009.

Inventory Valuation. Our non-cash loss in the first nine 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 have experienced a substantial reduction 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 September 30,									Nine months ended September 30,
	2009			%Change			2008			2009			%Change			2008
	(In thousands)
Interest on Senior Notes	$	3,850			(0	%)	$	3,851		$	11,550			(0	%)	$	11,551
Interest on Senior Credit Facility		1,063			74	%		612			3,089			178	%		1,112
Commitment fees		26			(59	%)		64			71			(64	%)		198
Dividend on mandatorily redeemable preferred stock		153			0	%		153			453			(0	%)		455
Amortization of deferred loan and debt issuance cost		475			82	%		261			1,056			39	%		759
Other general interest expense		14		NM				—			30		NM				—
Capitalized interest expense		(1,060	)		(10	%)		(1,179	)		(3,350	)		(2	%)		(3,412	)

Net interest expense	$	4,521			20	%	$	3,762		$	12,899			21	%	$	10,663


Weighted average debt outstanding	$	280,101			21	%	$	231,399		$	298,819			45	%	$	206,676

Average interest rate on outstanding indebtedness (a)		7.2	%					8.0	%		6.8	%					8.6	%


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.

Third quarter 2009 interest expense was $0.8 million higher than the corresponding period last year primarily due to a $0.5 million increase in interest expense associated with higher levels of outstanding debt on our Senior Credit Facility and a $0.3 million increase in origination fees associated with our Senior Credit Facility. Similarly, the higher levels of debt outstanding under our Senior Credit Facility for the first nine months of 2009 increased interest expense under the Senior Credit Facility by $2.0 million.

Other income (expense).

Other income (expense) included:


	Three months ended September 30,							Nine months ended September 30,
	2009		%Change			2008		2009		%Change			2008
						(In thousands)
Other income (expense):
Total other income	$	400		2400	%	$	16	$	482		15	%	$	419

Third quarter 2009 other income (expense) includes a $0.3 million gain from the sale of pipe inventory and $0.1 million in rental income. First nine months 2009 other income (expense) includes the aforementioned gain and rental income plus $0.1 million in additional other income.

Income taxes. We recorded no deferred federal income tax expense and $0.3 million in deferred state income tax expense in the third quarter of this year, compared to deferred federal income tax expense of $0.8 million and deferred state income tax expense of $0.1 million in the third quarter last year. We recorded no deferred federal income tax expense and $0.3 million in deferred state income tax expense for the first nine months 2009, compared to deferred federal income tax expense of $10.3 million and deferred state income tax expense of $0.9 million for the first nine months 2008. The decreases were primarily due to ceiling test write-downs in the fourth quarter 2008 and in the first quarter 2009. For the first nine months 2009, our effective tax rate was 0%, which was lower than the statutory rate of 35% primarily due to increases in our valuation allowances on federal and state net operating losses and to our inability to deduct preferred stock dividends and certain portions of our non-cash stock compensation expense for federal tax purposes.

Capital Expenditures

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

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

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

	•		cost of installing new production infrastructure;

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

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

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

The table below summarizes our 2009 oil and gas capital expenditure budget, the amount spent through September 30, 2009 and the amount of our 2009 oil and gas capital expenditure budget that remains to be spent.


				Amount
	Revised 2009			Spent Through			Amount
	Budget			September 30, 2009			Remaining (a)
	(In millions)
Drilling	$	55.1		$	37.6		$	17.5
Net land and seismic (b)		(3.6	)		(3.2	)		(0.4	)
Capitalized costs (c)		11.4			8.5			2.9
Asset retirement obligation		0.4			0.3			0.1

Total oil and gas capital expenditures (d)	$	63.3		$	43.2		$	20.1


(a)		Calculated based on the revised 2009 capital expenditure budget announced in October 2009 in conjunction with our equity offering, less amounts spent through September 30, 2009.

(b)		Net land and seismic expenditures include $6 million in proceeds from the sale of our Mountrail County mineral interests and $0.5 million in reimbursements in connection with our G&G activity.

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

(d)		Excludes other property capital expenditures.

Determination of Capital Expenditure Budget

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

This value creation measure and the final determination with respect to our 2009 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 oil or natural gas.

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2009, we intend to fund our capital expenditure program and contractual commitments with cash on hand, cash flows from operations, reimbursements of prior land and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties or alternative financing sources.

9 5/8% Senior Notes Due 2014

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 September 30, 2009.

Senior Credit Facility

In May 2009, in conjunction with our regularly scheduled semi-annual redetermination and our common stock offering, the borrowing base was reset to $110 million. On July 24, 2009, our Senior Credit Facility was amended to extend the maturity date from June 2010 to July 24, 2012. As of September 30, 2009, we had $110.0 million outstanding under our Senior Credit Facility. Subsequent to completion of our October 2009 equity offering, we repaid the entire balance outstanding and as of the date of the filing of the document have no amounts outstanding under our Senior Credit Facility.

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. If our borrowing base is reduced, we may be required to repay amounts outstanding under our Senior Credit Facility.

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 25% of a calculated proved PV10 value based on prices used in our year-end reserve report, as defined in our Indenture, which is referred to as Adjusted Consolidated Net Tangible Assets. Because of the dramatic downturn in commodity prices during the second half of 2008 and because covenant calculations will rely on year-end 2008 prices for the above referenced calculation for the entirety of 2009, we elected to draw down our remaining unused capacity under our Senior Credit Facility before the lower year-end 2008 prices limited our access to this unused capacity and therefore negatively impacted our corporate liquidity.

Borrowings under our Senior Credit Facility bear interest, at our election, at a base rate or a Eurodollar rate, plus in each case an applicable margin. These margins are reset quarterly and are subject to increase if the total amount borrowed under our Senior Credit 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%	2.500%	1.500%
25% and < 50%	2.750%	1.750%
50% and < 75%	3.000%	2.000%
75% and < 90%	3.250%	2.250%
> 90%	3.500%	2.500%


(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		Quarterly
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 2.5 to 1 as of September 30, 2009. Pursuant to our Senior Credit Facility, our interest coverage ratio for the four most recent quarters as of June 30, 2009 and September 30, 2009 must be at least 2.5 to 1, as of December 31, 2009 and March 31, 2010 must be at least 2.0 to 1, and thereafter must be at least 2.5 to 1. Our interest coverage ratio for the last twelve-month period ended September 30, 2009 was 3.4 to 1. The Senior Credit Facility also requires us to maintain a net leverage ratio for the quarters ending September 30, 2009 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. Our net leverage ratio as of September 30, 2009 was 3.6 to 1. As of September 30, 2009, we were in compliance with all covenant requirements in connection with our Senior Credit Facility.

Mandatorily Redeemable Preferred Stock

As of September 30, 2009, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC. We are required to satisfy all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

Access to Capital Markets

On October 5, 2009, our universal shelf registration statement covering the sale of $300 million of our common stock, preferred stock, depositary shares, warrants, rights, units and debt securities, or any combination of these securities became effective. Following the October equity offering and the exercise by the underwriters of their over-allotment in November, we have approximately $123 million remaining under the shelf registration statement. This shelf registration statement expires in October 2012. Our ability to raise additional capital using our shelf registration statement may be limited due to overall conditions of the stock market or the oil and natural gas industry.

Off Balance Sheet Arrangements

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

Analysis of Changes in Cash and Cash Equivalents

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


	Nine months ended September 30,
	2009			%Change			2008
	(In thousands)
Net income (loss)	$	(125,540	)	NM			$	18,304
Non-cash items		148,399			204	%		48,871
Changes in working capital and other items		8,352			29	%		6,463

Cash flows provided by operating activities	$	31,211			(58	%)	$	73,638
Cash flows used by investing activities		(70,592	)		(51	%)		(143,251	)
Cash flows provided by financing activities		55,216			(14	%)		64,413

Net increase in cash and cash equivalents	$	15,835		NM			$	(5,200	)

Analysis of net cash provided by operating activities

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

For the first nine months of 2009, cash flows provided by operating activities decreased by 58% to $31.2 million from the same period last year. The decrease in operating cash flow is primarily attributable to the decreases in commodity prices.

Analysis of changes in cash flows used in investing activities


	Nine months ended September 30,
	2009			%Change			2008
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	37,610			(62	%)	$	99,433
Land and seismic		(3,212	)	NM				28,230
Capitalized cost		8,543			(16	%)		10,128
Capitalized asset retirement obligation		302			13	%		267

Total	$	43,243			(69	%)	$	138,058


Reconciling Items:
Change in accrued drilling costs	$	9,338		NM			$	59
Change in drilling advances paid		(171	)	NM				3,061
Change in restricted cash		9,464			269	%		2,562
Change in short term investments		8,852		NM				—
Other		(134	)		(73	%)		(489	)

Total Reconciling Items		27,349			427	%		5,193

Net cash used in investing activities	$	70,592			(51	%)	$	143,251

Net cash used by investing activities in the first nine months 2009 decreased by $72.7 million, or 51%, over the same period in 2008. The reduction was mainly due to the following:

	•		drilling expenditures decreased by $61.8 million;

	•		net land and seismic expenditures decreased by $31.4 million;

	•		capitalized costs decreased by $1.6 million;

	•		the change in accrued drilling costs increased cash used in investing activities by $9.3 million;

	•		the change in restricted cash increased cash used in investing activities by $6.9 million; and

	•		the change in short term investments increased cash used in investing activities by $8.9 million.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first nine months of 2009 was 14% less than the first nine months of 2008. During the first nine months 2009, we received net proceeds of $93.5 million from our common stock offering and used a portion of the proceeds to repay $35 million of our outstanding indebtedness under our Senior Credit Facility. In the first nine months 2008, we borrowed $63 million under our Senior Credit Facility to fund drilling activity.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the nine months ended September 30, 2009 and 2008.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
2009 common stock transactions:
Common stock offering		36,292,117	$	93,523
Exercise of employee stock options		100,300	$	474

2008 common stock transactions:
Exercise of employee stock options		385,715	$	2,072

Other Matters

Derivative Instruments

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

Effects of Inflation and Changes in Prices

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

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 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.

New Accounting Pronouncements and SEC Rulemaking

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932 “Extractive Activities – Oil and Gas” (FASB ASC 932) provides guidance for oil and natural gas reserve related disclosures in the financial statements. Brigham is currently evaluating the impact that the adoption will have on the financial statements.

Forward-looking Information

We or our representatives may make forward-looking statements, oral or written, including statements in this report, press releases and filings with the SEC, regarding estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and natural gas production, the number of wells we anticipate drilling during 2009 and thereafter and our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward-looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors set forth among the risk factors noted in our Form 10-K report for the year ended December 31, 2008, and our Form 10-Q reports for the quarters ended March 31, 2009 and June 30, 2009 and this Form 10-Q report for the quarter ended September 30, 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 7 and 8 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 oil and natural gas production. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future. As such, we employ established policies and procedures to manage our exposure to fluctuations in the sales prices we receive for our oil and natural gas production via 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 2008 and 2009 through September 30, we were party to natural gas costless collars, natural gas three-way costless collars, natural gas swaps, oil costless collars and oil swaps.

We use costless collars to establish floor (purchased put option) and ceiling prices (written call option) on our anticipated future oil and natural gas production. We receive no net premiums when we enter into these option arrangements. These contracts are settled monthly. When the settlement price for a period is above the ceiling price (written call option), we pay our counterparty. When the settlement price for a period is below the floor price (purchased put option), our counterparty is required to pay us.

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.

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

The following tables reflect our open natural gas and oil derivative contracts as of September 30, 2009, the associated volumes and the corresponding weighted average NYMEX floor and cap price.


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bo)		(Nymex)		(Nymex)
*Oil Costless Collars*
10/01/09 - 12/31/09		30,000	$	49.00	$	70.00
01/01/10 - 12/31/10		120,000	$	48.70	$	80.00
10/01/09 - 05/31/10		80,000	$	57.50	$	75.95
06/01/10 - 12/31/10		56,000	$	57.50	$	82.15
01/01/10 - 12/31/10		54,000	$	60.00	$	86.50
01/01/11 - 12/31/11		84,000	$	65.00	$	88.25
10/01/09 - 12/31/09		11,000	$	62.50	$	76.75
01/01/10 - 03/31/10		6,000	$	65.00	$	87.50
07/01/10 - 09/30/10		6,000	$	70.00	$	87.25
10/01/10 - 12/31/10		3,000	$	70.00	$	88.50
10/01/09 - 03/31/10		18,000	$	60.00	$	91.75
04/01/10 - 09/30/10		18,000	$	60.00	$	91.40
10/01/09 - 12/31/09		30,000	$	60.00	$	81.00
01/01/10 - 12/31/10		60,000	$	60.00	$	88.80
01/01/11 - 12/31/11		60,000	$	60.00	$	97.25


	Crude		Swap
	Oil		Price
Settlement Period	(Bo)		(Nymex)
*Oil Swaps*
10/01/09 - 12/31/09		30,000	$	50.75


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
10/01/09 - 03/31/10		420,000	$	5.75	$	7.05
04/01/10 - 09/30/10		420,000	$	5.75	$	7.30
10/01/10 - 03/31/11		240,000	$	6.50	$	8.25
04/01/10 - 09/30/10		240,000	$	5.75	$	7.00
11/01/09 - 12/31/10		980,000	$	5.15	$	7.00
04/01/10 - 09/30/10		300,000	$	5.50	$	6.65
10/01/10 - 03/31/11		420,000	$	6.40	$	7.80


	Natural		Purchased		Written		Written
	Gas		Put		Call		Put
Settlement Period	(MMbtu)		(Nymex)		(Nymex)		(Nymex)
*Natural Gas Three Way Costless Collars*
10/01/09 - 03/31/10		420,000	$	8.00	$	10.00	$	5.50
10/01/09 - 03/31/10		360,000	$	5.75	$	7.00	$	3.50


	Natural		Swap
	Gas		Price
Settlement Period	(MMbtu)		(Nymex)
*Natural Gas Swaps*
10/01/09 - 12/31/09		60,000	$	4.90
10/01/09 - 12/31/09		172,000	$	4.44
10/01/09 - 10/31/09		70,000	$	4.03

The following table reflects commodity derivative contracts entered into subsequent to September 30, 2009, the associated volumes and the corresponding weighted average NYMEX floor and cap price.


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bo)		(Nymex)		(Nymex)
*Oil Costless Collars*
01/01/10 - 06/30/10		30,000	$	60.00	$	103.75
01/01/11 - 12/31/11		60,000	$	65.00	$	108.00


ITEM 4.		CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2009, our management, including our principal executive officer and principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our principal executive officer and our principal financial officer concluded that the design and operation of our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the third quarter of 2009 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 4 of Notes to the Consolidated Financial Statements included in Part I. Financial Statements, we are 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, 2008 and our quarterly reports on Form 10-Q for the quarters ending March 31, 2009 and June 30, 2009, other than the following:

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended.

As of December 31, 2008, we had mineral leases on approximately 280,000 net acres in areas which we believe are prospective for the Bakken and/or Three Forks. A significant portion of the acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their primary terms or we obtain extensions of the leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

The results of our planned exploratory drilling in the Bakken and Three Forks objectives, an emerging play with limited drilling and production history, are subject to more uncertainties than our drilling program in the more established formations and may not meet our expectations for reserves or production.

We have recently begun drilling wells in the Bakken and Three Forks objectives. Part of our drilling strategy to maximize recoveries from the Bakken and Three Forks objectives involves the drilling of horizontal wells using completion techniques that have proven to be successful in other shale formations. Our experience with horizontal drilling of the Bakken and Three Forks objectives to date, as well as the industry’s drilling and production history in the formation, is limited. The ultimate success of these drilling and completion strategies and techniques in this formation will be better evaluated over time as more wells are drilled and longer term production profiles are established. In addition, based on reported decline rates in these formations in other areas and in other shale formations, we estimate the average monthly rates of production should decline by approximately 70% during the first twelve months of production. Actual decline rates may differ significantly. Accordingly, the results of our future drilling in the emerging Bakken and Three Forks objectives are more uncertain than drilling results in the other formations with established reserves and production histories.

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, 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 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 federal Environmental Protection Agency, commonly referred to as the EPA, to promulgate regulations requiring permits and implementing potential new requirements 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 person 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. If this or similar legislation becomes law, it could cause us to incur substantial compliance costs, and 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.


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

Issuer Purchases of Equity Securities

In the third quarter 2009, 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
September 2009		19,258	$	9.662

TOTAL		19,258	$	9.662


ITEM 3.		DEFAULTS UPON SENIOR SECURITIES

None.


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

None.


ITEM 5.		OTHER INFORMATION

None.


ITEM 6.		EXHIBITS


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)

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, as amended (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, as amended (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, as amended (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, as amended (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 on 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 on April 13, 2007 and incorporated in by reference)


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

10.1		Fifth Amendment to the Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.45 to Brigham’s Current Report on Form 8-K filed July 27, 2009)

10.2*		1997 Incentive Plan, as amended through August 19, 2009 (incorporated by reference to Exhibit 10.50 to Brigham’s Current Report on Form 8-K filed October 13, 2009)

10.3*		Form of Non-Qualified Stock Option Agreement Under the Brigham Exploration Company 1997 Director Stock Option Plan

10.4*		Form of Non-Qualified Stock Option Agreement

10.5*		Amendment to Non-Qualified Stock Option Agreements

10.6*		Amendment to Brigham Exploration Company 1997 Director Stock Option Plan

10.7*		Amendment to Non-Qualified Stock Option Agreements Under the Brigham Exploration Company 1997 Director Stock Option Plan

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.

EXHIBIT INDEX


Exhibit No.		Description

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)

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, as amended (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, as amended (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, as amended (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, as amended (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 on 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 on April 13, 2007 and incorporated in by reference)


Exhibit No.		Description

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

10.1		Fifth Amendment to the Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.45 to Brigham’s Current Report on Form 8-K filed July 27, 2009)

10.2*		1997 Incentive Plan, as amended through August 19, 2009 (incorporated by reference to Exhibit 10.50 to Brigham’s Current Report on Form 8-K filed October 13, 2009)

10.3*		Form of Non-Qualified Stock Option Agreement Under the Brigham Exploration Company 1997 Director Stock Option Plan

10.4*		Form of Non-Qualified Stock Option Agreement

10.5*		Amendment to Non-Qualified Stock Option Agreements

10.6*		Amendment to Brigham Exploration Company 1997 Director Stock Option Plan

10.7*		Amendment to Non-Qualified Stock Option Agreements Under the Brigham Exploration Company 1997 Director Stock Option Plan

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 — September 30, 2009 and December 31, 2008		1
Consolidated Statements of Operations — Three and nine months ended September 30, 2009 and 2008		2
Consolidated Statement of Stockholders’ Equity — Nine months ended September 30, 2009		3
Consolidated Statements of Cash Flows — Nine months ended September 30, 2009 and 2008		4
Notes to the Consolidated Financial Statements		5

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		19

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		37

ITEM 4. CONTROLS AND PROCEDURES		39


PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		40

ITEM 1.A. RISK FACTORS		40

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		41

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		41

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		41

ITEM 5. OTHER INFORMATION		41

ITEM 6. EXHIBITS		42

SIGNATURES		44
Exhibit 10.3
Exhibit 10.4
Exhibit 10.5
Exhibit 10.6
Exhibit 10.7
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


	Three months ended September 30,							Nine months ended September 30,
	2009		%Change			2008		2009%		Change			2008
Oil (MBo)		235		84	%		128		572		53	%		373
Natural gas (MMcf)		1,401		(19	%)		1,722		4,703		(20	%)		5,861
Total (MBoe)(1)		468		13	%		415		1,356		1	%		1,349
Average daily production (Boe/d)(2)		5,200		13	%		4,611		5,022		1	%		4,996
Average daily production (MMcfe/d)(2)		31.2		13	%		27.6		30.1		1	%		30.0


					Additional									Total
	Common Stock				Paid In			Treasury			Accumulated			Stockholders’
	Shares		Amounts		Capital			Stock			Deficit			Equity
Balance, December 31, 2008		45,829	$	458	$	212,473		$	(1,202	)	$	(90,460	)	$	121,269
Net income (loss)		—		—		—			—			(125,540	)		(125,540	)
Issuance of common stock		36,292		363		93,044			—			—			93,407
Exercises of employee stock options		101		1		473			—			—			474
Vesting of restricted stock		226		2		(2	)		—			—			—
Stock based compensation		—		—		2,526			—			—			2,526
Repurchases of common stock		—		—		—			(276	)		—			(276	)


Balance, September 30, 2009		82,448	$	824	$	308,514		$	(1,478	)	$	(216,000	)	$	91,860


(1)		MBoe is defined as one thousand barrels of oil equivalent, determined using the ratio of six MMcf of natural gas to one MBoe of crude oil, condensate or natural gas liquids.

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


	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