Exhibit 99.1

		NEWS RELEASE FOR IMMEDIATE RELEASE

BRIGHAM EXPLORATION REPORTS RECORD QUARTERLY PRODUCTION VOLUMES, THIRD QUARTER 2010 RESULTS AND UPDATES FOURTH QUARTER 2010 FORECASTS

Austin, TX — November 1, 2010 — Brigham Exploration Company (NASDAQ:BEXP) today announced record quarterly production volumes and reported record revenues and operating income, excluding the impact of unrealized hedging losses.

THIRD QUARTER 2010 RESULTS

Our average daily production volumes for the third quarter 2010 were a quarterly record 8,509 barrels of crude oil equivalent (Boe) per day, up 64% from the third quarter 2009 and up 10% from the second quarter 2010. Our previous record quarterly production volumes of 7,756 Boe per day were achieved in the second quarter 2010.

Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our high value crude oil production volumes for the third quarter 2010 averaged 6,356 barrels of crude oil per day, which represents a 144% increase from that in the third quarter 2009 and a 14% sequential increase from that in the second quarter 2010. Our high value crude oil production volumes represented 75% of our total production volumes in the third quarter 2010, as compared to 50% in the third quarter 2009 and 72% in the second quarter 2010.

Our production volumes in the Williston Basin for the third quarter 2010 were 6,466 Boe per day, which represents a 202% increase from that in the third quarter 2009 and a 17% sequential increase from that in the second quarter 2010.

Our third quarter production volumes included approximately 7,395 barrels of crude oil produced during the third quarter 2010 and added to inventory. Adjusting our production volumes for amounts included in inventory resulted in third quarter 2010 daily sales volumes of 8,427 Boe per day.

Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the third quarter 2010, were up 134% to $44.4 million as compared to that in the third quarter 2009. Higher crude oil sales volumes and crude oil prices increased revenues by $19.7 million and $4.1 million, respectively. Higher natural gas prices increased revenues by $1.9 million, while lower natural gas sales volumes decreased revenues by $0.8 million. Finally, higher cash hedge settlements increased revenues by $0.5 million.

During the third quarter 2010, our average realized price for crude oil was $67.07 per barrel, which included no gain or loss from the cash settlement of our crude oil derivative contracts. This compares to an average realized price in the third quarter 2009 of $57.45 per barrel, which included a $2.29 per barrel cash loss due to the settlement of our crude oil derivative contracts. Our average realized price for natural gas in the third quarter 2010 was $5.63 per Mcf, which included a $0.65 per Mcf cash gain due to the settlement of our natural gas derivative contracts. This compares to an average realized price in the third quarter 2009 of $3.95 per Mcf, which included a $0.57 per Mcf cash gain due to the settlement of our natural gas derivative contracts.

Our third quarter 2010 production costs, which include costs for operating and maintaining (O&M expense) our producing wells, expensed workovers, ad valorem taxes and production taxes, were up $0.52 per Boe when compared to the third quarter 2009. The increase was driven by a $2.30 per Boe increase in production taxes, which was driven by higher commodity prices and higher levels of production in North Dakota, which are subject to an 11.5% tax rate. The increases in production taxes were partially offset by a $1.01 per Boe decrease in O&M expense due primarily to our higher production volumes and a $0.43 per Boe decrease in expensed workovers due to fewer workovers associated with our conventional Gulf Coast and Anadarko Basin natural gas wells.

Our general and administrative (G&A) expenses for the third quarter 2010 decreased by $0.16 per Boe as compared to the prior year’s quarter due to our higher production volumes. The gains associated with our higher production volumes were partially offset by an increase in employee compensation costs, which were partially associated with increased levels of employee bonuses and bonus accruals as we re-instated our performance bonus plan in 2010 after suspending the plan in 2009.

Our depletion expense for the third quarter 2010 was $15.3 million ($20.20 per Boe) compared to $7.8 million ($16.74 per Boe) in the third quarter 2009. Our higher sales volumes increased depletion expense by $4.9 million and our higher depletion rate increased depletion expense by $2.6 million.

Our net interest expense for the third quarter 2010 decreased $2.5 million from the third quarter 2009. This decrease was primarily due to the repayment of our Senior Credit Facility as a result of our October 2009 equity offering and an increase in our capitalized interest associated with our higher level of drilling activity in the Williston Basin.

We recorded no federal income tax expense in either the third quarter 2010 or the third quarter 2009, as we continue to have a net deferred tax asset, which is offset by a valuation allowance. In the third quarter 2009, we recorded $0.3 million in deferred state income tax expense.

Our reported net income (loss) for the third quarter 2010 was ($0.7) million (($0.01) per diluted share) versus net income of $0.5 million ($0.01 per diluted share) for the same period last year. Our after-tax earnings in the third quarter 2010 excluding the loss on the early redemption of our Senior Notes due 2014 and unrealized mark-to-market hedging losses were $18.1 million ($0.15 per diluted share) as compared to our after-tax earnings (loss) in the third quarter 2009 excluding our unrealized mark-to-market hedging gains and the non-cash write-down of the carrying value of our inventory were ($0.3) million (($0.00) per diluted share). After-tax earnings excluding the above items is a non-GAAP measure and a reconciliation of GAAP net income to after-tax earnings excluding the above items is included in our accompanying financial tables found later in this release.

In the third quarter 2010, we spent $171.3 million in exploration and development capital expenditures. Exploration and development and total oil and gas capital expenditures for the third quarter 2010 and 2009 were:

		Three months ended September 30,
		2010				2009
		(in thousands)
Drilling		$	84,392			$	11,118
Field level infrastructure			13,309				—
Land and seismic			10,553				2,475
Acreage acquisitions			63,080				—
Exploration and development capital expenditures		$	171,334			$	13,593
Capitalized costs			5,515				2,880
Capitalized FAS 143 ARO			290				27
Total oil and gas capital expenditures		$	177,139			$	16,500

FIRST NINE MONTHS 2010 RESULTS

Our average daily production volumes for the first nine months of 2010 were 7,228 Boe per day, up 44% from that in the first nine months of 2009. Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our high value crude oil production volumes for the first nine months of 2010 averaged 5,164 barrels per day, which represents a 144% increase from that in the first nine months of 2009. Our high value crude oil production volumes represented 71% of our total production volumes in the first nine months of 2010 as compared to 42% in the first nine months of 2009.

Our production volumes in the Williston Basin for the first nine months of 2010 were 5,074 Boe per day, which represents a 223% increase from that in the first nine months of 2009.

Our first nine months of 2010 production volumes included approximately 17,496 barrels of crude oil produced and added to inventory during the period. Adjusting our production volumes for amounts included in inventory results in average first nine months of 2010 daily sales volumes of 7,163 Boe per day.

Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the first nine months of 2010, were up 110% to $115.4 million as compared to that in the first nine months of 2009. Higher crude oil sales volumes and crude oil commodity prices increased revenues by $39.5 million and $27.6 million, respectively. Higher natural gas prices increased revenues by $5.4 million while lower natural gas sales volumes decreased revenues by $5.1 million. Lower hedge settlements reduced revenues by $6.9 million.

During the first nine months of 2010, our average realized price for crude oil was $68.97 per barrel, which included a $0.15 per barrel cash loss due to the cash settlement of our crude oil derivative contracts. This compares to an average realized price in the first nine months of 2009 of $49.62 per barrel, which included a $0.56 per barrel cash gain due to the settlement of our crude oil derivative contracts. Our average realized price for natural gas in the first nine months of 2010 was $6.11 per Mcf, which included a $0.73 per Mcf cash gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the first nine months of 2009 of $5.62 per Mcf, which included a $1.86 per Mcf cash gain due to the settlement of our natural gas derivative contracts.

Our production costs for the first nine months of 2010 were up $1.86 per Boe when compared to those in the corresponding period last year. The increase was largely driven by a $3.15 per Boe increase in production taxes, which was driven by higher commodity prices and higher levels of production in North Dakota, which are subject to an 11.5% tax rate. Expensed workovers increased $0.47 per Boe, with the majority of the increase due to several workovers of our conventional Gulf Coast and Anadarko Basin natural gas wells. The increases in production taxes and expensed workovers were partially offset by a $1.52 per Boe decrease in O&M expense due primarily to our higher production volumes.

Our G&A expenses for the first nine months of 2010 decreased by $0.09 per Boe as compared to the prior year’s quarter due to our higher production volumes. The gains associated with our higher production volumes were partially offset by an increase in employee compensation costs as a result of re-instating our employee performance bonus plan for 2010.

Our depletion expense for the first nine months of 2010 was $38.8 million ($20.05 per Boe) versus $23.9 million ($17.63 per Boe) in the first nine months of 2009. Our higher sales volumes increased depletion expense by $10.2 million and our higher depletion rate increased depletion expense by $4.7 million.

Our net interest expense for the first nine months of 2010 decreased $5.0 million from the corresponding period last year. This decrease was primarily due to the repayment of our Senior Credit Facility as a result of our October 2009 equity offering and an increase in capitalized interest expense associated with our higher level of drilling activity in the Williston Basin.

We recorded no federal income tax expense in the first nine months of 2010 as we continue to have a net deferred tax asset, which is offset by a valuation allowance. In the first nine months of 2009, we recorded $0.3 million in deferred state income tax expense.

Our reported net income for the first nine months of 2010 was $29.1 million ($0.26 per diluted share) versus net income (loss) of ($125.5) million (($2.00) per diluted share) for the same period last year. Our after-tax earnings in the first nine months of 2010 excluding the loss on early redemption of Senior Notes due 2014 and unrealized mark-to-market hedging losses were $41.3 million ($0.37 per diluted share) as compared to our after-tax earnings (loss) in the first nine months of 2009 excluding the effect of our first quarter 2009 ceiling test write-down, unrealized mark-to-market hedging losses, and non-cash write-down of the carrying value of our inventory were ($2.5) million (($0.04) per diluted share). After-tax earnings excluding the above items is a non-GAAP measure and a reconciliation of GAAP net income to after-tax earnings excluding the above items is included in our accompanying financial tables found later in this release.

Through September 30, 2010, we spent $317.4 million in exploration and development capital expenditures. Exploration and development and total oil and gas capital expenditures for the first nine months of 2010 and 2009 were:

		Nine months ended September 30,
		2010				2009
		(in thousands)
Drilling		$	197,970			$	37,610
Field level infrastructure			16,259				—
Land and seismic			40,092				(3,212	)
Acreage acquisitions			63,080				—
Exploration and development capital expenditures		$	317,401			$	34,398
Capitalized costs			14,489				8,543
Capitalized FAS 143 ARO			547				302
Total oil and gas capital expenditures		$	332,437			$	43,243

FOURTH QUARTER 2010 FORECASTS

The following forecasts and estimates for the fourth quarter 2010 are forward-looking statements subject to the risks and uncertainties identified in the “Forward-Looking Statements Disclosure” at the end of this release.

We are forecasting that our fourth quarter 2010 total production volumes to average between 10,200 Boe per day and 10,800 Boe per day and that our crude oil volumes will comprise approximately 77% of our total fourth quarter production volumes.

For the fourth quarter 2010, lease operating expenses are projected to be $5.50 per Boe based on the mid-point of our production guidance, production taxes are projected to be approximately 10.0 to 10.5% of pre-hedge crude oil and natural gas revenues, and general and administrative expenses are projected to be $3.6 million ($3.81 per Boe).

UPDATED 2010 EXPLORATION AND DEVELOPMENT BUDGET

Our updated 2010 exploration and development capital budget totals $466.1 million, which represents a 15% increase from the budget that we had announced in August 2010. The updated 2010 budget will fund approximately 44.8 net Williston Basin wells, two net Vicksburg wells in South Texas and 2.8 net wells primarily in the West Texas Wolfberry oil resource play. The $62.1 million increase in our 2010 budget is comprised of $40.3 million of additional drilling cap-ex related to approximately 7 additional net Williston Basin wells and $18.6 million of additional land and acreage acquisition cap-ex.

Our updated 2010 exploration and development capital budget is as follows:

		(in millions)
Drilling		$	315.8
Field level infrastructure			36.0
Land and seismic			51.2
Acreage acquisitions			63.1
Exploration and development capital expenditures		$	466.1

MANAGEMENT COMMENTS

Gene Shepherd, Brigham’s Chief Financial Officer, commented, “During the third quarter, the continued strong performance of our horizontal Bakken and Three Forks drilling program led to record production volumes and, excluding unrealized hedge settlements, record revenues and operating income. Furthermore, with the proceeds of our September senior notes offering, we ended the third quarter with $315 million of cash, cash equivalents and investments on the balance sheet and an undrawn credit facility. When combined with our growing cash flow and expanded hedging program, this level of liquidity ensures the company’s ability to fully fund our drilling program for 2011 and beyond.”

Gene Shepherd continued, “The expectation that we will average 10,500 Boe per day in the fourth quarter should ensure another record quarter for Brigham in terms of production and financial performance. Further, the growth in production that we have achieved as we have moved through 2010 provides some insight into the 2010 proved reserve growth that we expect to be able to announce in February 2011.”

CONFERENCE CALL INFORMATION

Our management will host a conference call to discuss operational and financial results for the third quarter 2010 with investors, analysts and other interested parties on Tuesday, November 2, at 11:00 a.m. Eastern Time. To participate in the call, participants within the U.S. please dial 888-713-4218 and participants outside the U.S. please dial 617-213-4870. The participant passcode for the call is 21582582. Participants may pre-register for the call at https://cossprereg.btci.com/prereg/key.process?key=PVNELWLGV. Pre-registrants will be issued a pin number to use when dialing into the live call which will provide quick access to the conference. A telephone recording of the conference call will be available approximately two hours after the call is completed through 12:00 p.m. Eastern Time on Tuesday, November 9, 2010. To access the recording, domestic callers dial 888-286-8010 and international callers dial 617-801-6888. The passcode for the conference call playback is 42559492. In addition, a live and archived web cast of the conference call will be available over the Internet at either www.bexp3d.com or www.streetevents.com.

A copy of this press release and other financial and statistical information about the periods covered by this press release and by the conference call that will take place on Tuesday, November 2, 2010, will be available on our website. To access the press release, go to www.bexp3d.com, click on Investor Relations and then click on News Releases. The file with a copy of the press release is named Brigham Exploration Reports Third Quarter 2010 Results and is dated Monday, November 1, 2010. To access the other financial and statistical information that will be covered by the conference call that will take place on Tuesday, November 2, 2010, go to www.bexp3d.com, click on Investor Relations and then click on Event Calendar. The file with the other financial and statistical information is named Financial and Statistical Information for the Third Quarter 2010 Conference Call and is dated Monday, November 1, 2010.

ABOUT BRIGHAM EXPLORATION

Brigham Exploration Company is an independent exploration, development and production company that utilizes advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. For more information about Brigham Exploration, please visit our website at www.bexp3d.com or contact Investor Relations at 512-427-3444.

FORWARD-LOOKING STATEMENTS DISCLOSURE

Except for the historical information contained herein, the matters discussed in this press release are forward-looking statements within the meaning of the federal securities laws. Important factors that could cause our actual results to differ materially from those contained in the forward-looking statements include our growth strategies, our ability to successfully and economically explore for and develop oil and natural gas resources, anticipated trends in our business, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and natural gas industry, our ability to make and integrate acquisitions, the impact of governmental regulation and other risks more fully described in the company’s filings with the Securities and Exchange Commission. Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. All forward-looking statements contained in this release, including any forecasts and estimates, are based on management’s outlook only as of the date of this release, and we undertake no obligation to update or revise these forward-looking statements, whether as a result of subsequent developments or otherwise.

Contact:		Rob Roosa, Finance Manager (512) 427-3300

BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) (unaudited)

		Three months ended								Nine months ended
		September 30,								September 30,
		2010				2009				2010				2009
Revenues:
Crude oil sales		$	37,868			$	14,010			$	95,161			$	28,065
Natural gas sales			5,795				4,737				17,996				17,700
Hedging settlements			757				260				2,200				9,067
			44,420				19,007				115,357				54,832
Unrealized hedging gains/ losses			(7,814	)			854				(1,261	)			(6,037	)
			36,606				19,861				114,096				48,795
Other revenue			4				6				17				72
Total revenue			36,610				19,867				114,113				48,867
Costs and expenses:
Lease operating			3,964				3,279				12,684				10,651
Production taxes			4,250				1,551				10,658				3,196
General and administrative			3,255				2,082				9,052				6,468
Depletion of crude oil and natural gas properties			15,312				7,835				38,770				23,901
Impairment of crude oil and gas properties			—				—				—				114,781
Depreciation and amortization			362				234				856				550
Loss on inventory valuation			—				29				—				2,196
Accretion of discount on asset retirement obligations			103				107				312				313
			27,246				15,117				72,332				162,056
Operating income (loss)			9,364				4,750				41,781				(113,189	)
Other income (expense):
Interest expense, net			(2,058	)			(4,521	)			(7,893	)			(12,899	)
Interest income			1,716				157				3,056				361
Loss on early redemption of Senior Notes			(10,948	)			—				(10,948	)			—
Other income (expense)			1,250				400				3,116				482
			(10,040	)			(3,964	)			(12,669	)			(12,056	)
Income before income taxes			(676	)			786				29,112				(125,245	)
Income tax expense:
Current			—				—				—				—
Deferred			—				(295	)			—				(295	)
			—				(295	)			—				(295	)
Net income (loss)		$	(676	)		$	491			$	29,112			$	(125,540	)
Net income per share available to common stockholders:
Basic		$	(0.01	)		$	0.01			$	0.27			$	(2.00	)
Diluted		$	(0.01	)		$	0.01			$	0.26			$	(2.00	)
Weighted average shares outstanding:
Basic			115,921				82,085				109,657				62,633
Diluted			115,921				82,756				111,562				62,633

BRIGHAM EXPLORATION COMPANY
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
(unaudited)

		Three months ended September 30,								Nine months ended September 30,
		2010				2009				2010				2009
Average net daily production volumes:
Crude oil (Bbls)			6,356				2,606				5,164				2,119
Natural gas (MMcf)			12.9				15.6				12.4				17.4
Equivalent crude oil (Boe) (6:1)			8,509				5,200				7,228				5,022
Total net production volumes:
Crude oil (MBbls)			572				235				1,394				572
Natural gas (MMcf)			1,163				1,401				3,344				4,703
Equivalent crude oil (MBoe) (6:1)			766				468				1,952				1,356
% Crude oil			75	%			50	%			71	%			42	%
Increase in inventory:
Crude oil (Bbls)			7,395				—				17,496				—
Natural gas (MMcf)			—				—				—				—
Equivalent crude oil (Boe) (6:1)			7,395				—				17,496				—
Average net daily sales volumes (Average net production volumes less average net daily increase in inventory):
Crude oil (Bbls)			6,274				2,606				5,099				2,119
Natural gas (MMcf)			12.9				15.6				12.4				17.4
Equivalent crude oil (Boe) (6:1)			8,427				5,200				7,163				5,022
Total net sales volumes (Total net production volumes less increase in inventory):
Crude oil (MBbls)			565				235				1,377				572
Natural gas (MMcf)			1,163				1,401				3,344				4,703
Equivalent crude oil (MBoe) (6:1)			758				468				1,934				1,356
% Crude oil			75	%			50	%			71	%			42	%
Sales price:
Crude oil ($/Bbl)		$	67.07			$	59.74			$	69.12			$	49.06
Natural gas ($/Mcf)			4.98				3.38				5.38				3.76
Equivalent crude oil ($/Boe) (6:1)			57.57				40.06				58.51				33.75
Sales price including derivative settlement gains (losses):
Crude oil ($/Bbl)		$	67.07			$	57.45			$	68.97			$	49.62
Natural gas ($/Mcf)			5.63				3.95				6.11				5.62
Equivalent crude oil ($/Boe) (6:1)			58.57				40.61				59.64				40.44
Sales price including derivative settlement gains (losses) and unrealized gains (losses):
Crude oil ($/Bbl)		$	51.58			$	62.90			$	66.64			$	44.27
Natural gas ($/Mcf)			6.44				3.65				6.68				4.99
Equivalent crude oil ($/Boe) (6:1)			48.27				42.44				58.99				35.98

SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)

		September 30, 2010				December 31, 2009
		(unaudited)
Assets:
Current assets		$	392,758			$	158,439
Oil and natural gas properties, net (full cost method)			601,430				330,733
Other property and equipment, net			16,311				3,025
Other non-current assets			12,032				6,059
Total assets		$	1,022,531			$	498,256
Liabilities and stockholders’ equity:
Current liabilities		$	138,618			$	67,773
Senior notes			300,000				158,968
Other non-current liabilities			9,225				7,232
Total liabilities		$	447,843			$	233,973
Stockholders’ equity			574,688				264,283
Total liabilities and stockholders’ equity		$	1,022,531			$	498,256

BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) (unaudited)

		Three months ended September 30,								Nine months ended September 30,
		2010				2009				2010				2009
Cash flows from operating activities:
Net income		$	(676	)		$	491			$	29,112			$	(125,540	)
Depletion, depreciation and amortization			15,674				8,069				39,626				24,451
Impairment of oil and gas properties			—				—				—				114,781
Accretion of discount on ARO			103				107				312				313
Amortization of deferred loan fees and debt issuance costs			461				501				1,475				1,127
Loss on early redemption of Senior Notes			10,948				—				10,948				—
Non-cash stock compensation			895				563				1,933				1,360
Market value adjustments for derivatives instruments			7,814				(854	)			1,262				6,037
Deferred income tax expense			—				295				—				295
Other noncash items			1				—				—				35
Changes in operating assets and liabilities			(8,919	)			6,092				8,553				8,352
Cash flows provided by operating activities		$	26,301			$	15,264			$	93,221			$	31,211
Cash flows used by investing activities			(114,449	)			(25,094	)			(408,241	)			(70,592	)
Cash flows (used) provided by financing activities			131,330				(2,378	)			400,243				55,216
Net increase (decrease) in cash and cash equivalents		$	43,182			$	(12,208	)		$	85,223			$	15,835

SUMMARY PER BOE DATA
(unaudited)

		Three months ended September 30,								Nine months ended September 30,
		2010				2009				2010				2009
Revenues:
Crude oil and natural gas sales		$	57.57			$	40.06			$	58.51			$	33.75
Hedge settlements			1.00				0.56				1.13				6.69
Unrealized hedge gains (losses)			(10.30	)			1.82				(0.65	)			(4.45	)
Other revenue			0.01				0.01				0.01				0.05
		$	48.28			$	42.45			$	59.00			$	36.04
Costs and expenses:
Lease operating			5.23				7.01				6.56				7.85
Production taxes			5.61				3.31				5.51				2.36
General and administrative			4.29				4.45				4.68				4.77
Depletion of crude oil and natural gas properties			20.20				16.74				20.05				17.63
Impairment of crude oil and natural gas properties			—				—				—				84.65
Depreciation and amortization			0.48				0.50				0.44				0.41
Loss on inventory valuation			—				0.06				—				1.62
Accretion of discount on ARO			0.14				0.23				0.16				0.23
		$	35.95			$	32.30			$	37.40			$	119.52
Operating income (loss)		$	12.33			$	10.15			$	21.60			$	(83.48	)
Interest expense, net of interest income (a)			(0.45	)			(9.32	)			(2.50	)			(9.25	)
Other income (expense)			(12.79	)			0.85				(4.05	)			0.36
Adjusted income		$	(0.91	)		$	1.68			$	15.05			$	(92.37	)

BRIGHAM EXPLORATION COMPANY
RECONCILIATION OF GAAP NET INCOME TO EARNINGS EXCLUDING THE EFFECT OF CERTAIN ITEMS
(in thousands)

		Three months ended September 30,								Nine months ended September 30,
		2010				2009				2010				2009
Net income (loss) as reported		$	(676	)		$	491			$	29,112			$	(125,540	)
Unrealized derivative (gains) losses			7,814				(854	)			1,261				6,037
Impairment of crude oil and natural gas properties			—				—				—				114,781
Loss on inventory valuation			—				29				—				2,196
Loss on early redemption of Senior Notes			10,948				—				10,948				—
Tax impact			—				—				—				—
Earnings without the effect of certain items		$	18,086			$	(334	)		$	41,321			$	(2,526	)

Earnings without the effect of certain items represent net income excluding our unrealized gains and losses on derivative contracts, our non-cash impairment charge of our oil and gas properties, our non-cash loss on inventory valuation and our loss on the early redemption of our Senior Notes due 2014. Management believes that exclusion of all of these items will help enhance comparability of operating results between periods.

SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF NOVEMBER 1, 2010
(unaudited)

						2010				2011																2012
						Q4				Q1				Q2				Q3				Q4				Q1				Q2				Q3				Q4
Crude Oil Costless Collars:
Daily volumes		Bbls/d					4,114				5,256				5,610				5,435				5,707				6,580				6,580				4,190				674
Floor		$/Bbl				$	63.64			$	66.27			$	65.74			$	65.75			$	65.66			$	65.50			$	65.50			$	65.00			$	65.00
Cap		$/Bbl				$	95.49			$	98.41			$	98.95			$	99.70			$	99.82			$	101.92			$	101.92			$	106.83			$	112.65
Crude Oil Floors:
Daily volumes		Bbls/d					—				500				500				1,250				1,250				1,250				1,250				—				—
Floor		$/Bbl				$	—			$	65.00			$	65.00			$	65.00			$	65.00			$	65.00			$	65.00			$	—			$	—
Natural Gas Costless Collars:
Daily volumes		MMBtu/d					5,870				6,000				3,626				3,587				3,587				—				—				—				—
Floor		$/MMBtu				$	5.94			$	6.17			$	5.48			$	5.48			$	5.48			$	—			$	—			$	—			$	—
Cap		$/MMBtu				$	7.59			$	7.79			$	7.16			$	7.16			$	7.16			$	—			$	—			$	—			$	—

Hedged volumes and prices reflected in this table represent average contract amounts for the quarterly periods presented; natural gas hedge prices and crude oil hedge contract prices are based on NYMEX pricing.