Filed by Bowne Pure Compliance

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, 2008


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

For the transition period from to

Commission File Number: 000-22433

Brigham Exploration Company

(Exact name of registrant as specified in its charter)


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


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, 2008		46,510,925

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)
(Unaudited)


	September 30,			December 31,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	8,663		$	13,863
Restricted cash		2,562			—
Accounts receivable		28,436			14,609
Derivative assets		1,876			1,416
Other current assets		6,006			2,617

Total current assets		47,543			32,505

Oil and natural gas properties, using the full cost method including
Proved, net		506,507			448,663
Unproved		105,194			61,544

		611,701			510,207

Other property and equipment, net		968			1,034
Land		404			—
Deferred loan fees, net		3,278			3,687
Other noncurrent assets		4,367			995

Total assets	$	668,261		$	548,428


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	30,949		$	12,301
Royalties payable		7,662			5,978
Accrued drilling costs		14,782			14,841
Participant advances received		1,591			2,095
Derivative liabilities		1,041			1,812
Other current liabilities		8,748			4,691

Total current liabilities		64,773			41,718


Senior Notes		158,670			158,492
Senior credit facility		72,900			10,000
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, 2008 and December 31, 2007		10,101			10,101
Deferred income taxes		54,827			41,625
Other taxes payable		332			2,162
Other noncurrent liabilities		5,475			5,303

Commitments and contingencies (Note 4)

Stockholders’ equity:
Common stock, $.01 par value, 90 million shares authorized, 45,818,667 and 45,304,139 shares issued and 45,678,105 and 45,197,303 shares outstanding at September 30, 2008 and December 31, 2007, respectively		458			453
Additional paid-in capital		211,824			207,526
Treasury stock, at cost; 140,562 and 106,836 shares at September 30, 2008 and December 31, 2007, respectively		(1,190	)		(854	)
Accumulated other comprehensive income (loss)		—			115
Retained earnings		90,091			71,787

Total stockholders’ equity		301,183			279,027

Total liabilities and stockholders’ equity	$	668,261		$	548,428

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,
	2008			2007			2008			2007

Revenues:
Oil and natural gas sales	$	31,731		$	29,481		$	101,112		$	92,250
Gain (loss) on derivatives, net		15,435			1,648			(3,928	)		420
Other revenue		25			17			104			73

		47,191			31,146			97,288			92,743


Costs and expenses:
Lease operating		3,092			2,564			8,626			8,458
Production taxes		1,383			951			4,107			1,573
General and administrative		2,502			2,514			7,691			6,973
Depletion of oil and natural gas properties		11,718			14,776			36,566			45,347
Impairment of oil and natural gas properties		—			—			—			6,505
Depreciation and amortization		159			147			464			468
Accretion of discount on asset retirement obligations		83			87			263			298

		18,937			21,039			57,717			69,622

Operating income		28,254			10,107			39,571			23,121


Other income (expense):
Interest income		49			271			163			536
Interest expense, net		(3,762	)		(3,976	)		(10,663	)		(11,071	)
Other income (expense)		16			105			419			1,007

		(3,697	)		(3,600	)		(10,081	)		(9,528	)

Income before income taxes		24,557			6,507			29,490			13,593


Income tax expense:
Current		—			—			—			—
Deferred		(9,297	)		(2,324	)		(11,186	)		(5,227	)

		(9,297	)		(2,324	)		(11,186	)		(5,227	)

Net income	$	15,260		$	4,183		$	18,304		$	8,366


Net income per share available to common stockholders:
Basic	$	0.34		$	0.09		$	0.40		$	0.19

Diluted	$	0.33		$	0.09		$	0.40		$	0.18


Weighted average shares outstanding:
Basic		45,481			45,123			45,358			45,085

Diluted		46,632			45,477			46,334			45,490

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

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BRIGHAM EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands)
(Unaudited)


											Accumulated
					Additional						Other					Total
	Common Stock				Paid In			Treasury			Comprehensive			Retained		Stockholders’
	Shares		Amounts		Capital			Stock			Income (Loss)			Earnings		Equity
Balance, December 31, 2007		45,304	$	453	$	207,526		$	(854	)	$	115		$	71,787	$	279,027
Comprehensive income:
Net income		—		—		—			—			—			18,304		18,304
Net (gains) losses included in net income		—		—		—			—			(177	)		—		(177	)
Tax benefit (provision) related to hedges		—		—		—			—			62			—		62

Comprehensive income																	18,189
Exercises of employee stock options		386		4		2,046			—			—			—		2,050
Vesting of restricted stock		129		1		(1	)		—			—			—		—
Stock based compensation		—		—		2,253			—			—			—		2,253
Repurchases of common stock		—		—		—			(336	)		—			—		(336	)


Balance, September 30, 2008		45,819	$	458	$	211,824		$	(1,190	)	$	—		$	90,091	$	301,183

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,
	2008			2007

Cash flows from operating activities:
Net income	$	18,304		$	8,366
Adjustments to reconcile net income to cash provided by operating activities:
Depletion of oil and natural gas properties		36,566			45,347
Impairment of oil and natural gas properties		—			6,505
Depreciation and amortization		464			468
Stock based compensation		1,223			1,455
Amortization of deferred loan fees and debt issuance costs		810			713
Market value adjustment for derivative instruments		(1,645	)		2,985
Accretion of discount on asset retirement obligations		263			298
Deferred income taxes		11,186			5,227
Other noncash items		4			(4	)
Changes in operating assets and liabilities:
Accounts receivable		(13,827	)		361
Other current assets		(3,163	)		77
Accounts payable		18,648			(2,807	)
Royalties payable		1,684			1,688
Participant advances received		(504	)		(3,320	)
Other current liabilities		4,057			5,593
Other noncurrent assets		(330	)		514
Other noncurrent liabilities		(102	)		(114	)

Net cash provided by operating activities		73,638			73,352


Cash flows from investing activities:
Additions to oil and natural gas properties		(136,822	)		(108,453	)
Additions to restricted cash		(2,562	)		—
Proceeds from the sale of oil and natural gas properties		—			35,435
Additions to other property and equipment		(402	)		(600	)
Additions to land		(404	)		—
Decrease (increase) in drilling advances paid		(3,061	)		(1,545	)

Net cash used by investing activities		(143,251	)		(75,163	)


Cash flows from financing activities:
Proceeds from senior notes offering		—			34,825
Increase in senior credit facility		62,900			46,400
Repayment of senior credit facility		—			(72,300	)
Deferred loan fees paid and equity costs		(223	)		(974	)
Proceeds from exercise of employee stock options		2,072			230
Repurchases of common stock		(336	)		(174	)

Net cash provided by financing activities		64,413			8,007


Net increase (decrease) in cash and cash equivalents		(5,200	)		6,196
Cash and cash equivalents, beginning of year		13,863			4,300

Cash and cash equivalents, end of period	$	8,663		$	10,496

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

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Nature of Operations

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

2. Basis of Presentation

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

The accompanying consolidated financial statements are unaudited, and in the opinion of management, reflect all adjustments that are necessary for a fair presentation of the financial position and results of operations for the periods presented. All such adjustments are of a normal and recurring nature. The unaudited consolidated financial statements are presented in accordance with the requirements of Form 10-Q and do not include all disclosures normally required by accounting principles generally accepted in the United States of America. The results of operations for the periods presented are not necessarily indicative of the results to be expected for the entire year. The unaudited consolidated financial statements should be read in conjunction with Brigham’s 2007 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

See Note 8 for a discussion of the accounting policy pertaining to the adoption of Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements” (SFAS 157) effective January 1, 2008.

3. Restricted Cash

Restricted cash at September 30, 2008 includes deposits in an interest bearing escrow account under the terms of a turnkey drilling contract executed during the third quarter of 2008

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, 2008, 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, 2008 and 2007 are as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Weighted average common shares outstanding — basic		45,481		45,123		45,358		45,085
Plus: Potential common shares
Stock options and restricted stock		1,151		354		976		405

Weighted average common shares outstanding — diluted		46,632		45,477		46,334		45,490


Stock options excluded from diluted EPS due to the anti-dilutive effect		64		2,595		341		2,525

6. Income Taxes

The income tax expense (benefit) for the nine months ended September 30, 2008 and 2007 consists of the following (in thousands):


	September 30,		September 30,
	2008		2007
Current income taxes:
Federal	$	—	$	—
State		—		—
Deferred income taxes:
Federal		10,269		4,926
State		917		301

	$	11,186	$	5,227

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement 109” (FIN 48), which provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” of being sustained if the position were to be challenged by a taxing authority. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is greater than 50% likely of being recognized upon ultimate settlement with the taxing authority is recorded. Brigham adopted the provisions of FIN 48 on January 1, 2007. Brigham has examined the tax positions taken in its tax returns or expected to be taken in its future tax returns and has determined that the full values of the uncertain tax positions have been recorded as part of the deferred tax liabilities. Therefore, no additional liabilities should be created and no incremental current or deferred income tax expenses should be recognized. However, consistent with the view of the FASB, Brigham has reclassified the liability for unrecognized tax benefits related to these uncertain tax positions from deferred tax liabilities to other tax liabilities on the consolidated balance sheet.

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


	(In thousands)
Unrecognized tax benefits at December 31, 2007	$	2,162
Increases (decreases) resulting from tax positions taken in the current period		(1,830	)
Decreases relating to settlements with taxing authorities		—
Reductions resulting from the lapse of applicable statutes of limitations		—

Unrecognized tax benefits at September 30, 2008	$	332

The decrease was the result of approval by the Internal Revenue Service in August 2008, of a change in method for recording geological and geophysical costs for tax purposes. None of the above unrecognized benefits would affect Brigham’s effective tax rate. Brigham classifies interest on uncertain tax positions as interest expense. Penalties are included in general administrative expense on the consolidated statement of operations. There are no interest and penalties recognized in the consolidated statement of operations or in the consolidated balance sheet because of the existence of Brigham’s net operating loss carryovers.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The tax years that remain subject to examination by Federal and major state tax jurisdictions are the years ended December 31, 2007, 2006, and 2005.

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

Cash flow hedges

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

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

Brigham reports average oil and natural gas prices and revenues including the net results of hedging activities. The following table sets forth Brigham’s oil and natural gas prices including and excluding the realized and unrealized hedging gains and losses and the increase or decrease in oil and natural gas revenues as a result of the hedging activities for the three and nine months ended September 30, 2008 and 2007:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
*Natural Gas*
Average price per Mcf realized excluding gas hedging results	$	10.08		$	6.71		$	10.23		$	7.23
Average price per Mcf including gas hedging settlement results	$	9.44		$	7.31		$	9.83		$	7.56
Increase (decrease) in revenue, in thousands	$	(1,104	)	$	1,996		$	(2,336	)	$	3,313
Average price per Mcf including gas hedging settlement results and any unrealized gains (losses)	$	16.72		$	7.31		$	9.95		$	7.34
Increase (decrease) in revenue, in thousands	$	11,430		$	1,967		$	(1,611	)	$	1,121
*Oil*
Average price per Bbl realized excluding oil hedging results	$	112.60		$	73.65		$	110.54		$	66.95
Average price per Bbl including oil hedging settlement results	$	104.38		$	73.43		$	101.85		$	67.26
Increase (decrease) in revenue, in thousands	$	(1,050	)	$	(21	)	$	(3,237	)	$	92
Average price per Bbl including oil hedging settlement results and any unrealized gains (losses)	$	143.96		$	70.35		$	104.32		$	64.60
Increase (decrease) in revenue, in thousands	$	4,005		$	(319	)	$	(2,317	)	$	(701	)

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects open commodity derivative contracts at September 30, 2008, 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*
10/01/08 – 10/31/08		50,000			$	7.25	$	10.40
10/01/08 – 12/31/08		240,000			$	9.75	$	11.50
04/01/09 – 09/30/09		120,000			$	7.25	$	9.80
10/01/08 – 03/31/09		180,000			$	8.00	$	10.20
10/01/08 – 03/31/09		300,000			$	8.00	$	11.20
10/01/08 – 03/31/09		300,000			$	7.75	$	9.82
01/01/09 – 03/31/09		220,000			$	10.25	$	12.25
04/01/09 – 09/30/09		420,000			$	8.00	$	10.70
04/01/09 – 09/30/09		300,000			$	7.00	$	9.73
*Oil Costless Collars*
10/01/08 – 10/31/08				3,000	$	65.70	$	90.00
10/01/08 – 12/31/08				6,000	$	57.50	$	75.50
10/01/08 – 12/31/08				6,000	$	85.00	$	117.00
10/01/08 – 12/31/08				6,000	$	57.50	$	76.00
10/01/08 – 10/31/08				6,000	$	90.00	$	120.00
11/01/08 – 12/31/08				8,000	$	87.75	$	120.00
11/01/08 – 06/30/09				24,000	$	62.00	$	81.75
01/01/09 – 03/31/09				21,000	$	86.50	$	120.00

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMBTU)

Nymex

Natural Gas Three Way Costless Collars

10/01/08 – 03/31/09

300,000

8.00

10.35

5.50

The following table reflects commodity derivative contracts entered subsequent to September 30, 2008, the associated volumes and the corresponding weighted average NYMEX reference price.

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMBTU)

Nymex

Natural Gas Collars

10/01/09 – 03/31/10

420,000

8.00

10.00

5.50

8. Fair Values

Effective January 1, 2008, the fair values of Brigham’s derivative financial instruments also reflect Brigham’s estimate of the default risk of the parties in accordance with Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157). Under SFAS 157, the fair value of a derivative asset would reflect an estimate of the counterparties’ default risk and the fair value of a derivative liability would reflect an estimate of Brigham’s default risk. 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, 2008 Using
				Quoted Prices in		Significant Other			Significant
				Active Markets		Observable			Unobservable
	December 31,			for Identical Assets		Inputs			Inputs
Description	2007			(Level 1)		(Level 2)			(Level 3)
Current derivative liabilities	$	(1,812	)	$	—	$	(1,041	)	$	—
Other non-current liabilities		(256	)		—		—			—
Current derivative assets		1,416			—		1,876			—
Other non-current assets		25			—		6			—

	$	(627	)	$	—	$	841		$	—

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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 interest capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Capitalized costs of oil and natural gas properties, net of accumulated amortization, are limited to the present value (10% per annum discount rate) of estimated future net cash flow from proved oil and natural gas reserves, based on the oil and natural gas prices in effect on the balance sheet date including the impact of qualifying cash flow hedging instruments; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. If net capitalized costs of oil and gas properties exceed this ceiling amount, Brigham is subject to a ceiling test writedown to the extent of such excess. A ceiling test writedown 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 writedown increases when oil and gas prices are depressed or if Brigham has substantial downward revisions in its estimated proved reserves. Based on oil and natural gas prices in effect at the end of the second quarter 2007, the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit and Brigham was required to record a writedown of its oil and gas properties in the amount of $4.1 million, net of tax.

Based on oil and natural gas prices in effect at the end of the third quarter 2007, the unamortized cost of Brigham’s oil and gas properties exceeded the ceiling limit by $13.5 million, net of tax. However, subsequent to the end of the quarter, oil and natural gas prices increased and, utilizing these prices, Brigham’s net capitalized costs of oil and natural gas properties would not have exceeded the ceiling limit. As a result of the increase in the ceiling limit using subsequent prices, Brigham was not required to writedown the net capitalized costs of its oil and gas properties.

Based on oil and gas prices in effect on September 30, 2008 ($7.12 per MMBtu for Henry Hub natural gas and $100.64 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, 2008.

During the third quarter 2007, Brigham sold its Anadarko Basin Granite Wash oil and gas properties for net proceeds of $35.4 million with an effective date of September 1, 2007.

10. Senior Notes

In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the “Senior Notes”). The Senior Notes were priced at 98.629% of their face value to yield 9 7/8% and are fully and unconditionally guaranteed by Brigham and its wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. (the “Guarantors”). The guarantees are joint and several. Brigham does not have any independent assets or operations and the aggregate assets and revenues of the subsidiaries not guaranteeing are less than 3% of the Brigham’s consolidated assets and revenues.

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, 2008, Brigham was in compliance with all covenants under the indenture.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. Asset Retirement Obligations

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

The following table summarizes Brigham’s asset retirement obligation transactions recorded in accordance with the provisions of SFAS 143 during the nine months ended September 30, 2008 and 2007 (in thousands):


	Nine Months Ended
	September 30,
	2008			2007

Beginning asset retirement obligations	$	5,047		$	5,002
Liabilities incurred for new wells placed on production		267			325
Liabilities settled		(102	)		(41	)
Revisions to estimates due to sale of oil and gas properties		—			(615	)
Accretion of discount on asset retirement obligations		263			298

	$	5,475		$	4,969

11. Stock Based Compensation

Brigham adopted SFAS 123R using the modified prospective method. Under this transition method, compensation cost recognized includes the cost for all stock based compensation granted prior to, but not yet vested, as of January 1, 2006. This cost was based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. The cost for all stock based awards granted subsequent to January 1, 2006, was based on the grant date fair value that was estimated in accordance with the provisions of SFAS 123R. The maximum contractual life of stock based awards is seven years. Additionally, during 2007, stock compensation expense related to unvested stock based awards was adjusted to recognize actual forfeitures during the year. Brigham has assumed a 4% weighted average forfeiture rate for stock based awards to be used prospectively at September 30, 2007. At adoption of SFAS 123R, Brigham elected to amortize newly issued and existing granted awards on a straight-line basis over the requisite service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods. Unearned stock compensation recorded under APB 25 of $2.3 million was eliminated and additional paid-in capital was reduced by a like amount on the consolidated balance sheet and consolidated statements of stockholders’ equity, in accordance with SFAS 123R. Results for prior periods have not been restated.

The estimated fair value of the options granted during the nine months ended September 30, 2008 and 2007 were 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, 2008 and 2007:


	2008			2007
Risk-free interest rate		3.0	%		4.6	%
Expected life (in years)		5.0			5.0
Expected volatility		47	%		49	%
Expected dividend yield		—			—
Weighted average fair value per share of stock compensation	$	4.70		$	2.97

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free rate of interest for periods within the contractual life of the option is based on a zero-coupon U.S. government instrument over the contractual term of the equity instrument. Expected volatility is based on the historical volatility of Brigham’s stock for an equal period of the expected term. The expected life is based on the historical exercise data of Brigham’s option grants with the guidance of Staff Accounting Bulletin No. 107 and Staff Accounting Bulletin No. 110 for “plain vanilla” options.

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

Prior to the adoption of SFAS 123R, Brigham presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires the cash flow resulting from the tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. Brigham did not have any excess tax benefits during the nine months ended September 30, 2008 and 2007.

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,
	2008			2007			2008			2007

Pre-tax stock based compensation expense	$	746		$	1,100		$	2,253		$	2,628
Capitalized stock based compensation		(341	)		(481	)		(1,030	)		(1,171	)
Tax benefit		(142	)		(217	)		(428	)		(510	)

Stock based compensation expense, net	$	263		$	402		$	795		$	947

Stock Based Plan Descriptions and Share Information

Brigham provides an incentive plan for the issuance of stock options, stock appreciation rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this plan is to provide incentive and reward key employees whose performance may have a significant impact on the success of Brigham. It is Brigham’s policy to use unissued shares of stock when stock options are exercised. The number of shares available under the plan is equal to the lesser of 5,915,414 or 15% of the total number of shares of common stock outstanding. At September 30, 2008, approximately 611,563 shares remain available for grant under the current incentive plan. The Compensation Committee of the Board of Directors determines the type of awards made to each participant and the terms, conditions and limitations applicable to each award. Except for one stock option grant, options granted subsequent to March 4, 1997 have an exercise price equal to the fair market value of Brigham’s common stock on the date of grant, vest over five years and have a contractual life of seven years.

Brigham also maintains a director stock option plan under which stock options are awarded to non-employee directors. Options granted under this plan have an exercise price equal to the fair market value of Brigham common stock on the date of grant and vest over five years. Stockholders have authorized the issuance of 1,000,000 shares to non-employee directors and approximately 592,300 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:


	2008					2007
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Options outstanding at the beginning of the year		3,046,166		$	7.14		3,243,566		$	7.08
Granted		18,000		$	10.56		35,000		$	6.18
Forfeited or cancelled		(64,800	)	$	7.83		(145,300	)	$	8.06
Exercised		(385,715	)	$	5.36		(57,000	)	$	4.05

Options outstanding at the end of the quarter		2,613,651		$	7.41		3,076,266		$	7.08

Options exercisable at the end of the quarter		1,685,951		$	7.04		1,645,366		$	6.34

The weighted-average grant-date fair value of share options granted during the nine months ended September 30, 2008 and 2007 was $4.70 and $2.97, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2008 and 2007 was $2.4 million and $122,313, respectively.

The following table summarizes information about stock options outstanding and exercisable at September 30, 2008:


	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	2008		Contractual Life	Exercise Price		2008		Contractual Life	Exercise Price
$3.05 to $3.41		44,000	1.0 years	$	3.40		44,000	1.0 years	$	3.40
3.66 to 5.08		339,200	1.0 years	$	4.29		339,200	1.0 years	$	4.29
6.10 to 6.73		1,134,576	3.1 years	$	6.49		683,376	2.6 years	$	6.59
7.22 to 8.84		736,875	3.6 years	$	8.45		473,375	3.1 years	$	8.65
8.93 to 12.31		359,000	4.1 years	$	11.64		146,000	4.0 years	$	11.48

$3.05 to $12.31		2,613,651	3.1 years	$	7.41		1,685,951	2.5 years	$	7.04

The aggregate intrinsic value of options outstanding and exercisable at September 30, 2008 was $9.7 million and $6.8 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, 2008. The amount of aggregate intrinsic value will change based on the fair market value of Brigham’s stock.

As of September 30, 2008 there was approximately $2.7 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 4.7 years.

Restricted Stock

During the nine months ended September 30, 2008 and 2007, Brigham issued 109,000 and 379,550, respectively, restricted shares of common stock as compensation to officers and employees of Brigham. The restricted shares vest over five years or cliff-vest at the end of five years. As of September 30, 2008, there was approximately $3.2 million of total unrecognized compensation expense related to unvested restricted stock. This compensation expense is expected to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.7 years. Brigham has assumed a 6% weighted average forfeiture rate for restricted stock. If actual forfeitures differ from the estimates, additional adjustments to compensation expense may be required in future periods.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

The following table reflects the outstanding restricted stock awards and activity related thereto for the nine months ended September 30:


	2008					2007
				Weighted-					Weighted-
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price

Restricted shares outstanding at the beginning of the year		653,623		$	7.16		391,367		$	8.60
Shares granted		109,000		$	8.40		379,550		$	5.78
Lapse of restrictions		(128,813	)	$	5.98		(78,131	)	$	6.46
Forfeitures		(29,940	)	$	6.58		(27,053	)	$	8.35

Shares outstanding at the end of the quarter		603,870		$	7.67		665,733		$	7.25

12. 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,
	2008		2007			2008			2007

Net income	$	15,260	$	4,183		$	18,304		$	8,366
Net (gains) losses included in net income		—		(68	)		(177	)		(1,231	)
Tax benefits (provisions) related to cash flow hedges		—		24			62			431

Other Comprehensive Income, net	$	15,260	$	4,139		$	18,189		$	7,566

13. New Accounting Pronouncements

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for the fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on the Brigham’s financial statements.

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (SFAS 157), which provides expanded guidance for using fair value to measure assets and liabilities. SFAS 157 establishes a hierarchy for data used to value assets and liabilities, and requires additional disclosures about the extent to which a company measures assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. Implementation of SFAS 157 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. FASB Financial Staff Position No. FAS 157-2 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 SFAS 157 did not have a material impact on the financial statements.

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement 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. An entity may not apply it before that date. Brigham is currently evaluating the impact on the financial statements.

BRIGHAM EXPLORATION COMPANY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

In February 2007, the Financial Accounting Standards Board issued Statement No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. Companies are required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. It does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. Brigham has not elected the fair value option for any eligible items.

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements — an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. Brigham is currently evaluating the impact on the financial statements.

In March 2008, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 161 “Disclosures about Derivative Instruments and Hedging Activities — An Amendment of FASB Statement No. 133” (SFAS 161), that requires 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 under FASB Interpretation No. 39; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008.

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 2007 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three month and nine month periods ended September 30, 2008 and September 30, 2007. 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 2007 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 3-D seismic imaging and drilling and completion technologies to systematically explore for and develop domestic onshore oil and natural gas reserves. We focus our exploration and development activities in provinces where we believe technology and the knowledge of our technical staff can be effectively used to maximize our return on invested capital by reducing drilling risk and enhancing our ability to cost effectively grow reserves and production volumes. Our exploration and development activities are currently concentrated in four provinces: the Rocky Mountains, the onshore Gulf Coast, the Anadarko Basin and West Texas.

We regularly evaluate opportunities to expand our activities to other areas that may offer attractive exploration and development potential, with a particular interest in those areas with plays that complement our current exploration, development and production activities. As a result of this strategy, since late 2005 we have been accumulating significant acreage positions in the Williston and Powder River Basins. Operations within these two basins are included in and constitute the bulk of our activity in our Rocky Mountains province. We have also entered into four joint ventures in Southern Louisiana over the last two years. We consider these joint ventures to be logical extensions of our prospect generating activities along the onshore Texas Gulf Coast.

Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we can use technology to generate high rates of return on our invested capital. Key elements of our business strategy include:

	•		Focus on Core Provinces and Trends;

	•		Internally Generate Inventory of High Quality Exploratory Prospects;

	•		Leverage Our Operational Expertise;

	•		Evaluate and Selectively Pursue New Potential Plays;

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

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

	•		Enhance Returns Through Operational Control.

Overview of Third Quarter and First Nine Months 2008 Financial Results

During the third quarter 2008, Henry Hub natural gas futures prices were highly volatile and front month prices ranged from a high of $13.58 per Mcfe to a low of $7.22 per Mcfe. In particular, prices rapidly decreased after July 4^th due to production increases seen in the onshore U.S. and concerns about the long-term pricing of natural gas given the numerous shale resource plays under development. Pricing conditions are likely to remain highly volatile as natural gas storage levels will likely approach last year’s pre-heating season level. Pricing during the fourth quarter 2008 and first quarter 2009 is expected to be highly dependent on weather conditions experienced during the upcoming winter. In particular, volatility can be expected each Thursday with the Energy Information Administration’s (EIA) weekly update on natural gas storage levels. Excluding realized and unrealized derivative hedging results, the average sales price that we received for natural gas in the third quarter and first nine months of 2008 was $10.08 and $10.23 per Mcfe, respectively, which represents a 50% increase from the third quarter 2007 and a 41% increase from the first nine months 2007.

Crude oil futures prices were also highly volatile during the quarter. Front month Cushing, Oklahoma futures prices ranged from a high of $145.29 to a low of $91.15 per barrel. In particular, prices rapidly decreased after July 14^th on concerns of demand destruction associated with high oil prices experienced during the first half of 2008, as well as concerns associated with the turmoil in the global credit markets and the potential impact on the U.S. and global economies. Excluding realized and unrealized derivative hedging results, the average sales price that we received for crude oil in the third quarter and first nine months of 2008 was $112.60 and $110.54 per barrel, respectively, which represents a 53% increase from the third quarter 2007 and a 65% increase from the first nine months 2007.

Daily production volumes for the third quarter 2008 averaged 27.6 MMcfe, down 36% from the third quarter 2007. Daily production for the first nine months 2008 averaged 30.0 MMcfe per day, which represents a 31% decrease from the first nine months 2007. These decreases were attributable to the impact of hurricanes Gustav and Ike, which caused delays in hooking up our new Southern Louisiana wells to sales, as well as shut in production along the Texas Gulf Coast and South Texas. Production also decreased due to the natural declines experienced in our Southern Louisiana and South Texas producing areas. These decreases were partially offset by increasing production in the Williston Basin where we are spending the majority of our capital to fund horizontal drilling targeting the Bakken and Three Forks formations.

Third quarter operating income increased 180% to $28.3 million from last year’s third quarter. The primary drivers behind the increase in our operating income were higher unrealized hedging gains and commodity price increases. Operating income also increased because of lower depletion expense. These factors were partially offset by lower production volumes, lower realized hedging settlements and increases in both our lease operating expense and production taxes. First nine months 2008 operating income increased 71% to $39.6 million from the comparable period last year. The drivers behind the increase in operating income were largely consistent with that experienced during the third quarter 2008; however, operating income in the first nine months of 2008 did benefit from the lack of a full cost ceiling test impairment, as we recorded a $6.5 million ($4.1 million after-tax) non-cash expense impairment charge in the second quarter 2007.

For the quarter ended September 30, 2008, we spent $49.4 million on oil and gas capital expenditures, which represents an 87% increase from the third quarter 2007 and a 15% increase from the second quarter 2008.

As of September 30, 2008, we had $8.7 million in cash and $668.3 million in total assets. Our net debt to book capitalization ratio was 45%, which is calculated as debt plus preferred stock divided by book equity plus debt plus preferred stock.

Overview of Third Quarter 2008 Operational Results

Rocky Mountain Province

Williston Basin

In July, we announced the successful completion of our first well in the North Stanley area of Mountrail County, North Dakota, the Johnson 33 #1H, at an early peak flowing rate of 618 barrels of oil equivalent per day. Prior to July 11th, the Johnson 33 #1H flowed oil intermittently as production was apparently hampered by numerous sand plugs in the well bore. Subsequent to a portion of the lateral being cleaned out, the well flowed at an early peak rate of approximately 568 barrels of oil and 300 Mcf of natural gas per day and over a three day period the well flowed at an average rate of approximately 515 barrels of oil and 267 Mcf of natural gas per day.

In late July, we announced the successful completion of the Carkuff 22 #1H, which flowed approximately 1,110 barrels of oil and an estimated 400 to 500 Mcf of natural gas up 7.5 inch casing over 24 hours. The Carkuff 22 #1H was completed with approximately 12 fracture stimulation stages across the horizontal well bore. The increased number of fracture stimulation stages relative to our wells drilled in late 2007 and early 2008, which were completed with approximately 7 stages, appears to be generating improved operational results.

In October, we announced the successful completion of our first Three Forks test, the Adix 25 #1H. The Adix 25 #1H flowed at an initial 24 hour rate of approximately 765 barrels of oil and 760 Mcf of natural gas per day up 7 inch casing. The Adix represents our fifth consecutive completion in the Ross Area. The four prior completions were in the Bakken formation, the most recent of which was the Carkuff 22 #1H.

We are currently operating two drilling rigs in North Dakota, both of which are currently operating west of the Nesson Anticline. We are currently drilling the Olson 10-15 #1H in Williams County, North Dakota and the Figaro 29-32 #1H in McKenzie County, North Dakota. We plan to drill these wells across two sections with horizontal well bore lengths of 8,000 to 9,000 feet. We anticipate completing each of these wells with approximately 20 fracture stimulation stages.

Onshore Gulf Coast

Southern Louisiana Trend

In December 2007, we entered into a joint venture with Clayton Williams Energy, Inc. to operate the drilling of six prospects over 18 months. Five of these prospects are planned for 2008 and target 3-D delineated, primarily amplitude related prospects at depths of 9,000 to 10,500 feet in Plaquemines and Saint Bernard Parishes.

In July, we announced our first joint venture well, Main Pass SL 18826 #1, encountered approximately 100 feet of apparent Miocene pay in four intervals at depths of between 7,140 and 7,680 feet. All intervals were commingled and production tested at a rate of approximately 15.4 MMcf of natural gas per day. Due to delays caused by hurricanes Gustav and Ike, we now anticipate production to sales in November.

Our second joint venture well, the Chandeleur Sound SL 19312 #1, was recently logged and encountered approximately 24 feet of apparent pay. The Chandeleur Sound SL 19312 #1 was flow tested in July at a rate of approximately 2.7 MMcf of natural gas per day. Due to the aforementioned delays, we now anticipate production to sales in January 2009.

Our third joint venture well, the Breton Sound SL 19054 #1, was logged in July and encountered approximately 60 feet of apparent pay. Approximately 15 feet of the pay has apparent porosities greater than 20%, while 45 feet of apparent pay has porosities ranging from 18 to 20%. In September, we announced the Breton Sound SL 19054 #1 was production tested at an initial rate of approximately 6 MMcf of natural gas per day. Due to pipeline permitting delays, we now anticipate production to sales in February 2009.

Our fourth joint venture well, the Romere Pass BLM 013045 #1, was plugged and abandoned as the target sands were wet.

In September, we successfully drilled and completed the Cotten Land #5, which is a joint venture well with Penn Virginia Corporation. The Cotten Land #5 is a twin to our high production rate Cotten Land #3 discovery and targeted the upper 50 feet of apparent pay which remains behind pipe in the Cotten Land #3. The Cotten Land #5 was brought on line in October at an initial production rate of approximately 17.2 MMcfe per day.

Third Quarter and First Nine Months 2008 Results

Comparison of the three month and nine month periods ended September 30, 2008 and 2007.

Production volumes


	Three months ended September 30,							Nine months ended September 30,
	2008		% Change			2007		2008		% Change			2007

Oil (MBbls)		128		32	%		97		373		25	%		298
Natural gas (MMcf)		1,722		(48	%)		3,327		5,861		(41	%)		9,997
Total (MMcfe)(1)		2,488		(36	%)		3,909		8,097		(31	%)		11,784
Average daily production ( MMcfe/d)(2)		27.6		(36	%)		43.4		30.0		(31	%)		43.6


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

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

Natural gas represented 69% of our third quarter 2008 production volumes and 72% of our first nine months 2008 volumes, compared to 85% in the third quarter of last year and 85% in the first nine months of last year.

Revenue, 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 price including derivative settlements and unrealized gains (losses).


	Three months ended September 30,									Nine months ended September 30,
	2008			% Change			2007			2008			% Change			2007

Oil revenue:
Oil revenue	$	14,381			101	%	$	7,145		$	41,178			106	%	$	19,953
Oil derivative settlement gains (losses)		(1,050	)		4900	%		(21	)		(3,237	)	NM				92

Oil revenue including oil derivative settlements	$	13,331			87	%	$	7,124		$	37,941			89	%	$	20,045
Oil derivative unrealized gains (losses)		5,055		NM				(299	)		920		NM				(793	)

Oil revenue including derivative settlements and unrealized gains (losses)	$	18,386			169	%	$	6,825		$	38,861			102	%	$	19,252
Natural gas revenue:
Natural gas revenue	$	17,350			(22	%)	$	22,336		$	59,934			(17	%)	$	72,297
Natural gas derivative settlement gains (losses)		(1,104	)	NM				1,996			(2,336	)	NM				3,313

Natural gas revenue including derivative settlements	$	16,246			(33	%)	$	24,332		$	57,598			(24	%)	$	75,610
Natural gas derivative unrealized gains (losses)		12,534		NM				(28	)		725		NM				(2,192	)

Natural gas revenue including derivative settlements and unrealized gains (losses)	$	28,780			18	%	$	24,304		$	58,323			(21	%)	$	73,418
Oil and natural gas revenue:
Oil and natural gas revenue	$	31,731			8	%	$	29,481		$	101,112			10	%	$	92,250
Oil and natural gas derivative settlement gains (losses)		(2,154	)	NM				1,975			(5,573	)	NM				3,405

Oil and natural gas revenue including derivative settlement gains (losses)		29,577			(6	%)		31,456			95,539			0	%		95,655
Oil and natural gas derivative unrealized gains (losses)		17,589		NM				(327	)		1,645		NM				(2,985	)

Oil and natural gas revenue including derivative settlements and unrealized gains (losses)		47,166			52	%		31,129			97,184			5	%		92,670
Other revenue		25			47	%		17			104			42	%		73

Total revenue	$	47,191			52	%	$	31,146		$	97,288			5	%	$	92,743


	Three months ended September 30,							Nine months ended September 30,
	2008		% Change			2007		2008		% Change			2007

Average oil prices:
Oil price (per Bbl)	$	112.60		53	%	$	73.65	$	110.54		65	%	$	66.95
Oil price including derivative settlement gains (losses) (per Bbl)		104.38		42	%		73.43		101.85		51	%		67.26
Oil price including derivative settlements and unrealized gains (losses) (per Bbl)		143.96		105	%		70.35		104.32		61	%		64.60
Average natural gas prices:
Natural gas price (per Mcf)	$	10.08		50	%	$	6.71	$	10.23		41	%	$	7.23
Natural gas price including derivative settlement gains (losses) (per Mcf)		9.44		29	%		7.31		9.83		30	%		7.56
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf)	$	16.72		129	%	$	7.31	$	9.95		36	%	$	7.34
Average equivalent prices:
Natural gas equivalent price (per Mcfe)	$	12.75		69	%	$	7.54	$	12.49		60	%	$	7.83
Natural gas equivalent price including derivative settlement gains (losses) (per Mcfe)		11.89		48	%		8.05		11.80		45	%		8.12
Natural gas equivalent price including derivative settlements and unrealized gains (losses) (per Mcfe)	$	18.96		138	%	$	7.96	$	12.00		53	%	$	7.86


	For the three			For the nine
	month periods			month periods
	ended September 30,			ended September 30,
	2008 and 2007			2008 and 2007

Change in revenue from the sale of oil
Volume variance impact	$	2,261		$	4,987
Price variance impact		4,975			16,238
Cash settlement of hedging contracts		(1,029	)		(3,329	)
Unrealized hedge gain or loss		5,354			1,713

Total change	$	11,561		$	19,609

Change in revenue from the sale of natural gas
Volume variance impact	$	(10,784	)	$	(29,923	)
Price variance impact		5,798			17,560
Cash settlement of hedging contracts		(3,100	)		(5,649	)
Unrealized hedge gain or loss		12,562			2,917

Total change	$	4,476		$	(15,095	)

Change in revenue from the sale of oil and natural gas
Volume variance impact	$	(8,523	)	$	(24,936	)
Price variance impact		10,773			33,798
Cash settlement of hedging contracts		(4,129	)		(8,978	)
Unrealized hedge gain or loss		17,916			4,630

Total change	$	16,037		$	4,514

Third quarter 2008 oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), increased $16.0 million, or 52%, when compared to the third quarter 2007. The change in revenues was attributable to the following:

•		a 48% decrease in natural gas production, partially offset by an 32% increase in oil production resulted in an overall $8.5 million decrease in oil and natural gas revenues;

•		a 50% increase in the sales price of natural gas and a 53% increase in the sales price of oil resulted in a $10.8 million increase in oil and natural gas revenues;

•		a $2.1 million derivative settlement loss in the third quarter 2008 versus a $2.0 million derivative settlement gain in third quarter 2007 decreased revenues by $4.1 million; and

•		a $17.6 million unrealized derivative gain in third quarter 2008 versus a $0.3 million unrealized derivative loss in third quarter 2007 increased revenues by $17.9 million.

First nine months 2008 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses), increased $4.5 million, or 5%, compared to the first nine months 2007. The change in revenues was attributable to the following:

•		a 41% decrease in natural gas production partially offset by a 25% increase in oil production resulted in a $24.9 million decrease in oil and natural gas revenues;

•		a 41% increase in the sales price of natural gas and a 65% increase in the sales price of oil resulted in a $33.8 million increase in oil and natural gas revenues;

•		a $5.6 million derivative settlement loss in the first nine months 2008 versus a $3.4 million derivative settlement gain in third quarter 2007 decreased revenues by $9.0 million; and

•		a $1.6 million unrealized derivative gain in first nine months 2008 versus a $3.0 million unrealized derivative loss in the first nine months 2007 increased revenues by $4.6 million.

Hedging. We utilize collars and three way costless collars to (i) reduce the effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans.

The following table details derivative contracts that settled during the third quarter and nine months ended 2008 and 2007 and includes the type of derivative contract, the volume hedged, 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,
	2008			% Change			2007			2008			% Change			2007

*Oil collars*
Volumes (Bbls)		49,000			(16	%)		58,500			141,500			(32	%)		207,500
Average floor price ($ per Bbl)	$	74.92			34	%	$	56.00		$	68.42			22	%	$	56.01
Average ceiling price ($ per Bbl)	$	100.07			22	%	$	82.00		$	92.37			14	%	$	80.86
Gain (loss) upon settlement ($ in thousands)	$	(1,050	)		4900	%	$	(21	)	$	(3,237	)	NM			$	92

*Total oil*
Gain (loss) upon settlement ($ in thousands)	$	(1,050	)		4900	%	$	(21	)	$	(3,237	)	NM			$	92

*Natural gas collars*
Volumes (MMbtu)		1,130,000			(46	%)		2,090,000			4,020,000			(32	%)		5,885,000
Average floor price ($ per MMbtu)	$	7.42			5	%	$	7.10		$	7.494			3	%	$	7.25
Average ceiling price ($ per MMbtu)	$	9.95			(9	%)	$	10.89		$	10.751			(14	%)	$	12.44
Gain (loss) upon settlement ($ in thousands)	$	(1,104	)	NM			$	1,996		$	(2,336	)	NM			$	3,313

*Total gas*
Gain (loss) upon settlement ($ in thousands)	$	(1,104	)	NM			$	1,996		$	(2,336	)	NM			$	3,313

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

Operating costs and expenses

Production costs. We believe that per unit 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 Mcfe)							(In thousands)
	Three months ended September 30,							Three months ended September 30,
	2008		% Change			2007		2008		% Change			2007

Production costs:
Operating & maintenance	$	1.07		123	%	$	0.48	$	2,684		45	%	$	1,847
Expensed workovers		0.04		(43	%)		0.07		92		(68	%)		292
Ad valorem taxes		0.13		18	%		0.11		316		(26	%)		425

Lease operating expenses	$	1.24		88	%	$	0.66	$	3,092		21	%	$	2,564

Production taxes		0.56		133	%		0.24		1,383		45	%		951

Production costs	$	1.80		100	%	$	0.90	$	4,475		27	%	$	3,515

Third quarter 2008 per unit of production costs increased when compared to the third quarter 2007 because of the following:

•		Per unit operating and maintenance (O&M) expense increased by $0.59 per Mcfe, or 123%, from the corresponding period last year because of the impact from our lower production volumes, as well as increased salt water disposal expense, compressor and equipment rental expense and fuel costs;

•		Production tax expense increased $0.32 per Mcfe, or 133%, from the third quarter 2007. The increase was attributable to a $0.3 million decrease in production tax abatements in the third quarter 2008 versus the third quarter 2007 and the migration of our production mix towards a higher production tax environment in North Dakota.


	Unit-of-Production							Amount
	(Per Mcfe)							(In thousands)
	Nine months ended September 30,							Nine months ended September 30,
	2008		% Change			2007		2008		% Change			2007

Production costs:
Operating & maintenance	$	0.82		46	%	$	0.56	$	6,542		(1	%)	$	6,585
Expensed workovers		0.16		220	%		0.05		1,316		114	%		616
Ad valorem taxes		0.09		(18	%)		0.11		768		(39	%)		1,257

Lease operating expenses	$	1.07		49	%	$	0.72	$	8,626		2	%	$	8,458

Production taxes		0.51		292	%		0.13		4,107		161	%		1,573

Production costs	$	1.58		86	%	$	0.85	$	12,733		27	%	$	10,031

First nine months 2008 per unit of production costs increased when compared to the first nine months of last year because of the following:

•		Per unit O&M expense increased by $0.26 per Mcfe, or 46%, because of lower production volumes in the first nine months 2008 versus the first nine months 2007;

•		Workover expense increased $0.11 per Mcfe, or 220% because of an increase in the number and cost of our workovers; and

•		Production taxes increased $0.38 per Mcfe, or 292%, due to a $2.6 million decrease in production tax abatements in the first nine months of 2008 versus the first nine months of 2007, as well as the aforementioned production mix migration towards a higher production tax environment in North Dakota.

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,
	2008			% Change			2007			2008			% Change			2007
	(In thousands, except per unit measurements)

General and administrative costs	$	4,650			0	%	$	4,636		$	14,403			9	%	$	13,163
Capitalized general and administrative costs		(2,148	)		1	%		(2,122	)		(6,712	)		8	%		(6,190	)

General and administrative expenses	$	2,502			0	%	$	2,514		$	7,691			10	%	$	6,973


General and administrative expense ($ per Mcfe)	$	1.01			58	%	$	0.64		$	0.95			61	%	$	0.59

Our general and administrative (G&A) costs for the third quarter 2008 were in line with the third quarter of last year. Lower production volumes resulted in a 58% increase in per Mcfe expenses.

G&A costs for the first nine months 2008 were 9% higher than the first nine months of last year. G&A costs increased because of higher payroll expenses associated with new hires and retention costs and higher audit and tax fees. Decreased production was the primary factor resulting in our G&A expenses increasing on a per unit basis by 61% to $0.95 per Mcfe.

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,
	2008		% Change			2007		2008		% Change			2007
	(In thousands, except per unit measurements)

Depletion of oil and natural gas properties	$	11,718		(21	%)	$	14,776	$	36,566		(19	%)	$	45,347
Depletion of oil and natural gas properties ($ per Mcfe)	$	4.71		25	%	$	3.78	$	4.52		17	%	$	3.85

Our depletion expense for the third quarter 2008 was $3.1 million lower than that in the third quarter 2007. Reduced production volumes decreased depletion expense by $5.4 million, while a higher depletion rate increased depletion expense by $2.3 million. Our depletion expense for the first nine months 2008 was $8.8 million lower than that in the comparable period in 2007. Reduced production volumes decreased depletion expense by $14.2 million, while a higher depletion rate increased depletion expense by $5.4 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; and 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 writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings and reduces stockholders’ equity in the period of occurrence.

The risk that we will experience a ceiling test write-down increases when oil and gas prices are depressed or if we have substantial downward revisions in its estimated proved reserves. Based on oil and gas prices in effect on September 30, 2008 ($7.12 per MMBtu for Henry Hub gas and $100.64 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 and we therefore did not record an impairment to our oil and gas properties.

During the first nine months of 2007, we recorded a $6.5 million ($4.1 million after tax) impairment to our oil and gas properties. The unamortized costs of our oil and gas properties based on the oil and gas prices in effect at the end of June 2007 ($6.80 per MMBtu for Henry Hub gas and $70.47 per barrel for West Texas Intermediate oil, adjusted for differentials) exceeded the ceiling limit causing the impairment change in the second quarter 2007.

Net interest expense. Interest on borrowings under our 9 5/8% senior notes due 2014 (the “Senior Notes”), our senior credit agreement and dividends on our Series A mandatorily redeemable preferred stock represents the largest portion of our interest costs. Other costs include commitment fees that we pay on the unused portion of the borrowing base and amortization of debt issuance costs. We capitalize a portion of our interest costs associated with major capital projects.


	Three months ended September 30,									Nine months ended September 30,
	2008			% Change			2007			2008			% Change			2007
	(In thousands)

Interest on Senior Notes	$	3,851			10	%	$	3,490		$	11,551			12	%	$	10,273
Interest on senior credit facility		612			(25	%)		811			1,112			(48	%)		2,159
Commitment fees		64			12	%		57			198			26	%		157
Dividend on mandatorily redeemable preferred stock		153			0	%		153			455			0	%		453
Amortization of deferred loan and debt issuance costs		261			7	%		243			759			11	%		686
Other general interest expense		0			(100	%)		1			0			(100	%)		2
Capitalized interest expense		(1,179	)		51	%		(779	)		(3,412	)		28	%		(2,659	)

Net interest expense	$	3,762			(5	%)	$	3,976		$	10,663			(4	%)	$	11,071


Weighted average debt outstanding	$	231,399			18	%	$	196,663		$	206,676			7	%	$	193,275
Average interest rate on outstanding indebtedness (a)		8.0	%		(12	%)		9.1	%		8.6	%		(4	%)		9.0	%


(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 2008 net interest expense was $0.2 million lower than the corresponding period last year primarily due to a 51% increase in our capitalized interest expense, which reduced net interest expense by $0.4 million. First nine months 2008 interest expense was $0.4 million lower than the comparable period in 2007 because of a 28% increase in our capitalized interest expense.

We made $0.6 million in cash payments for interest during the third quarter 2008. For the first nine months of 2008, we made $8.9 million in aggregate cash payments for interest.

Other income (expense).

Other income (expense) included:


	Three months ended September 30,							Nine months ended September 30,
	2008		% Change			2007		2008		% Change			2007
	(In thousands)
Other income (expense):
Non-cash gain (loss)		—	NM				—		—		(100	%)		40
Cash income (expense)		16		(85	%)		105		419		(57	%)		967

Total other income	$	16		(85	%)	$	105	$	419		(58	%)	$	1,007

Nine months ended 2007 cash income includes $0.4 million related to the receipt of a bankruptcy claim that had previously been written down and $0.l million related to the sale of a production barge.

Income taxes. We recorded deferred federal income tax expense of $10.3 million in the nine months ended September 30, 2008, compared to deferred federal income tax expense of $4.9 million in the nine months ended September 30, 2007. We also recorded deferred state income tax expense of $0.9 million in the nine months ended September 30, 2008, compared to deferred state income tax expense of $0.3 million in the nine months ended September 30, 2007. The increases in the deferred federal and state income tax expenses were primarily due to higher income before income taxes for the nine months ended September 30, 2008. For the first nine months of 2008, our effective tax rate was 37.9%, which was higher than the statutory rate of 35% primarily due to state income taxes and non-deductibility of preferred stock dividends and certain portions of our non-cash stock compensation expense for federal income 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.

As a result of the acceleration of our drilling in the Williston Basin from one operated rig to two operated rigs in September 2008 and increased levels of acreage acquisitions in the area, exploration and development capital expenditures in the Williston Basin are expected to increase to $109 million in 2008 relative to the originally budgeted $48 million. Our overall capital expenditure budget is expected to increase to $189 million from the originally budgeted $134 million. The table below summarizes our 2008 oil and gas capital expenditure budget, the amount spent through September 30, 2008 and the amount of our 2008 oil and gas capital expenditure budget that remains to be spent.


			Amount
	2008		Spent Through		Amount
	Budget		September 30, 2008		Remaining (a)
	(In millions)
Drilling	$	140,633	$	99,433	$	41,200
Net land and seismic		34,191		28,230		5,961
Capitalized costs (b)		13,636		10,128		3,508
Asset retirement obligation		491		267		224

Total oil and gas capital expenditures (c)	$	188,951	$	138,058	$	50,893


(a)		Calculated based on the revised 2008 capital expenditure budget announced in July 2008 less amount spent through September 30, 2008.

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

(c)		Excludes other property capital expenditures.

Determination of Capital Expenditure Budget

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

This value creation measure and the final determination with respect to our 2008 budgeted expenditures will depend on a number of factors, including:

	•		changes in commodity prices;

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

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

	•		variances in a prospect’s risked reserve size;

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

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

	•		economic and industry conditions at the time of drilling;

	•		the availability of more economically attractive prospects; and

	•		the ability to access external sources of capital.

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

Liquidity and Capital Resources

Sources of Capital

For the remainder of 2008, we anticipate funding our capital expenditure program and contractual commitments with cash flows from operations, borrowings under our senior credit agreement, reimbursements of prior land and seismic costs by third parties who participate in our projects, and the sale of interests in projects and properties or alternative financing sources. Continued turmoil in the both the credit and equity markets as well as uncertainty regarding the timing of a recovery will make it more difficult for us to secure external sources of capital, which would enable us to outspend our cash flow during the remainder of 2008 and into 2009. If available, costs for such funding sources may increase.

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 agreement.

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, 2008.

Senior Credit Agreement

Our senior credit agreement provides for revolving credit borrowings up to $200 million and matures June 2010. In May 2008, in conjunction with our regularly scheduled semi-annual redetermination, the borrowing base was reset to $135 million. In November, our banking group agreed to and provided commitments for an increase in our borrowing base from $135 million to $145 million. We are currently in the documentation stage of closing on the increase.

As of September 30, 2008, we had $72.9 million outstanding under our senior credit facility and we issued $6.9 million in letters of credit related to pipe purchases, which expire December 31, 2008. Without taking into account the letters of credit, we had $62.1 million of unused committed borrowing capacity available under our senior credit agreement at the end of September. We strive to manage the amounts we borrow under our senior credit agreement in order to maintain excess borrowing capacity.

Since the borrowing base for our senior credit agreement is redetermined at least semi-annually, the amount of borrowing capacity available to us under our senior credit agreement can fluctuate. While we do not expect the amount that we have borrowed under our senior credit agreement to exceed the borrowing base, in the event that the borrowing base is adjusted below the amount that we have borrowed, our access to further borrowings will be reduced, and we may not have the resources necessary to carry out our planned spending for exploration and development activities. The next semi-annual borrowing base redetermination is anticipated to occur in May 2009.

Borrowings under our senior credit agreement bear interest, at our election, at a base rate or a Eurodollar rate, plus an applicable margin. The applicable margin table below was increased by 0.25% for each of the percent utilization categories below as a part of our increase in the borrowing base from $135 million to $145 million. These margins are reset quarterly based on the percent of the borrowing base utilized. The margins are shown below:


Percent of	Eurodollar
Borrowing Base	Rate			Base Rate
Utilized	Advances			Advances(1)
<50%		1.500	%		0.000	%
50% and < 75%		1.750	%		0.250	%
75% and < 90%		2.000	%		0.500	%
90%		2.250	%		0.750	%


(1)		Base rate is defined as for any day a fluctuating rate per annum equal to the highest of: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of one month 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 commitment fee that we pay was increased by 0.05% for less than 50% utilization and by 0.125% for the remaining utilization categories as a part of our increase in the borrowing base from $135 million to $145 million. The margins and commitment fees that we pay are as follows:


Percent of
Borrowing Base	Quarterly
Utilized	Commitment Fee
<50%		0.300	%
50% and < 75%		0.375	%
75% and < 90%		0.500	%
90%		0.500	%

Our senior credit agreement also contains customary restrictions and covenants. Should we be unable to comply with these or other covenants, our senior lenders may be unwilling to waive compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our senior credit agreement, we are required to maintain a current ratio of at least 1 to 1 and an interest coverage ratio for the four most recent quarters of at least 3 to 1. Our current ratio at September 30, 2008 and interest coverage ratio for the twelve-month period ended September 30, 2008 were 1.6 to 1 and 7.1 to 1, respectively. As of September 30, 2008, we were in compliance with all covenant requirements in connection with our senior credit agreement.

Access to the committed and undrawn portion of our borrowing base could be limited based on the covenants that are part of the indenture governing the Senior Notes. Future amounts borrowed under our senior credit agreement will depend primarily on net cash provided by operating activities, proceeds from other financing activities, reimbursements of prior land and seismic costs by third party participants in our projects and proceeds generated from asset dispositions.

Mandatorily Redeemable Preferred Stock

As of September 30, 2008, we had $10.1 million in mandatorily redeemable Series A preferred stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse Securities (USA), LLC. We are required to satisfy all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is redeemable at our option at 100% or 101% of the stated value per share (depending upon certain conditions) at anytime prior to maturity.

Access to Capital Markets

We currently have two effective universal shelf registration statements covering the sale, from time to time, of our common stock, preferred stock, depositary shares, warrants and debt securities, or a combination of any of these securities. One of our universal shelf registration statements has not been utilized to date and has $300 million available. Our other shelf registration statement has $73.4 million remaining available and expires on December 1, 2008.

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

Off Balance Sheet Arrangements

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

Analysis of Changes in Cash and Cash Equivalents

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


	Nine months ended September 30,
	2008			% Change			2007
	(In thousands)

Net income	$	18,304			119	%	$	8,366
Non-cash items		48,871			(22	%)		62,994
Changes in working capital and other items		6,463			224	%		1,992

Cash flows provided by operating activities	$	73,638			0	%	$	73,352
Cash flows used by investing activities		(143,251	)		91	%		(75,163	)
Cash flows provided by financing activities		64,413			704	%		8,007

Net increase in cash and cash equivalents	$	(5,200	)	NM			$	6,196

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 2008, cash flow provided by operating activities was in line with the comparable period last year. Our net income for the first nine months 2008 was higher than the comparable period last year primarily because of higher realized prices and higher unrealized hedging gains. These items were partially offset by a decrease in our production volumes. Our non-cash items decreased due to the $6.5 million impairment charge taken in 2007 and an $8.8 million decrease in depletion expense in 2008. These decreases were slightly offset by a $6.0 million increase in deferred income taxes. Changes in working capital were higher in 2008 as we experienced a $21.4 million increase in accounts payable from the third quarter 2007 to the third quarter 2008, while accounts receivable and other current assets only increased $14.2 million and $3.3 million respectively over the same time period.

Analysis of changes in cash flows used in investing activities


	Nine months ended September 30,
	2008			% Change			2007
	(In thousands)
Capital expenditures for oil and natural gas activities:
Drilling	$	99,433			40	%	$	71,068
Net land and seismic		28,230			183	%		9,969
Capitalized cost		10,128			14	%		8,849
Capitalized asset retirement obligation		267			(18	%)		325

Total	$	138,058			53	%	$	90,211


Reconciling Items:
Asset Sale Proceeds including ARO liability reduction	$	—			(100	%)	$	(36,050	)
Change in accrued drilling costs		59			(100	%)		19,742
Change in drilling advances paid		3,061			98	%		1,545
Change in restricted cash		2,562		NM				—
Other		(489	)		72	%		(285	)

Total Reconciling Items		5,193		NM				(15,048	)

Net cash used in investing activities	$	143,251			91	%	$	75,163

Net cash used by investing activities in the first nine months 2008 increased by 91% over the comparable period in 2007 due to the following:

•		Drilling capital expenditures increased by $28.4 million primarily because of increased drilling activity in the Williston Basin versus the corresponding period last year;

•		Land and seismic expenditures increased by $18.3 million due to an increased level of land and seismic acquisitions in the Williston Basin;

•		Asset sale proceeds decreased by $36 million in the first nine months of 2008 due to the impact of our Granite Wash asset sale, which was completed in September 2007;

•		Drilling advances increased by $1.5 million associated with a higher level of non-operated activity in the Williston Basin;

•		Restricted cash increased by $2.6 million associated with the escrowing of funds for a fixed cost drilling contract; and

•		Offsetting the aforementioned increases was a $19.6 million decrease in our accrued drilling costs.

Analysis of changes in cash flows from financing activities

Net cash provided by financing activities in the first nine months 2008 was 704% higher than the first nine months 2007. During the first nine months of 2008, we borrowed approximately $56.4 million more than the comparable period last year primarily because of our increased levels of drilling activity and land acquisitions.

Common Stock Transactions

The following is a list of common stock transactions that occurred in the nine months ended September 30, 2008 and 2007.


	Shares Issued		Net Proceeds
	(In thousands, except share data)
*2008 common stock transactions:*
Exercise of employee stock options		385,715	$	2,072

*2007 common stock transactions:*
Exercise of employee stock options		57,000	$	231

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 achieves 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

On December 12, 2007, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force on Issue No. 07-01 “Accounting for Collaborative Arrangements”. This Issue will be effective for our fiscal year beginning January 1, 2009. This pronouncement is not expected to have a material impact on our financial statements.

The Financial Accounting Standards Board revised Statement of Financial Accounting Standards No. 141 (Revised 2007) “Business Combinations” (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement 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. An entity may not apply it before that date. We are currently evaluating the impact on the financial statements.

In February 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities— Including an amendment of FASB Statement No. 115.” The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. Companies are required to report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. It does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. We have not elected the fair value option for any eligible items.

In December 2007, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 160 “Noncontrolling Interest in Consolidated Financial Statements — an Amendment of ARB 51” (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. We are currently evaluating the impact 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 2008 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, 2007 including, but not limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. We assume no obligation to update any of these statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Management Opinion Concerning Derivative Instruments

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

Derivative Instruments and Hedging Activities

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

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

During 2007 and 2008, we were party to natural gas costless collars, natural gas three-way costless collars and oil costless collars.

We use costless collars to establish floor (purchased put option) and ceiling (written call option) prices 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, 2008, the associated volumes and the corresponding weighted average NYMEX floor and cap price.


	Natural		Purchased		Written
	Gas		Put		Call
Settlement Period	(MMbtu)		(Nymex)		(Nymex)
*Natural Gas Costless Collars*
10/01/08 – 10/31/08		50,000		7.25		10.40
10/01/08 – 12/31/08		240,000		9.75		11.50
10/01/08 – 03/31/09		300,000		7.75		9.82
10/01/08 – 03/31/09		180,000		8.00		10.20
10/01/08 – 03/31/09		300,000		8.00		11.20
01/01/09 – 01/31/09		80,000		10.25		12.25
02/01/09 – 03/31/09		140,000		10.25		12.25
04/01/09 – 09/30/09		300,000		7.00		9.73
04/01/09 – 09/30/09		120,000		7.25		9.80
04/01/09 – 09/30/09		420,000		8.00		10.70

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMbtu)

(Nymex)

Natural Gas Three Way Costless Collars

10/01/08 – 03/31/09

300,000

8.00

10.35

5.50


	Crude		Purchased		Written
	Oil		Put		Call
Settlement Period	(Bbls)		(Nymex)		(Nymex)
*Oil Costless Collars*
10/01/08 – 12/31/08		6,000		85.00		117.00
10/01/08 – 10/31/08		6,000		90.00		120.00
10/01/08 – 12/31/08		6,000		57.50		76.00
10/01/08 – 10/31/08		3,000		65.70		90.00
10/01/08 – 12/31/08		6,000		57.50		75.50
11/01/08 – 06/30/09		24,000		62.00		81.75
11/01/08 – 12/31/08		8,000		87.75		120.00
01/01/09 – 03/31/09		21,000		86.50		120.00

The following tables reflects commodity derivative contracts entered into subsequent to September 30, 2008, the associated volumes and the corresponding weighted average NYMEX floor and cap price.

Natural

Purchased

Written

Gas

Put

Call

Put

Settlement Period

(MMbtu)

(Nymex)

Natural Gas Three Way Costless Collars

10/01/09 – 03/31/10

420,000

8.00

10.00

5.50

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2008, 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 2008 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 Information, we are party to various legal actions arising in the ordinary course of business and do not expect these matters to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

None.

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

Issuer Purchases of Equity Securities

In 2008, 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
July 2008		5,516	$	15.50
September 2008		9,779	$	11.09

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS


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

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

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

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

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Consolidated Balance Sheets — September 30, 2008 and December 31, 2007		1

Consolidated Statements of Operations — Three and nine months ended September 30, 2008 and 2007		2

Consolidated Statement of Stockholders’ Equity — Nine months ended September 30, 2008		3

Consolidated Statements of Cash Flows — Nine months ended September 30, 2008 and 2007		4

Notes to the Consolidated Financial Statements		5

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		32

ITEM 4. CONTROLS AND PROCEDURES		34

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		35

ITEM 1.A. RISK FACTORS		35

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		35

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		35

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS		35

ITEM 5. OTHER INFORMATION		35

ITEM 6. EXHIBITS		35

SIGNATURES		36

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


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

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


Exhibit No.		Description

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

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

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

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