18. Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates at December 31, 2011, 2010 and 2009 presented in the table below are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers, in accordance with the FASB's authoritative guidance on oil and gas reserve estimation and disclosures. At December 31, 2011, all of the Company's oil and natural gas producing activities were conducted within the continental United States.

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

Estimated Quantities of Proved Oil and Natural Gas Reserves — Unaudited

The following table sets forth the Company's net proved, proved developed and proved undeveloped reserves at December 31, 2011, 2010 and 2009:

		September 30,			September 30,			September 30,
	Oil (MBbl)			Gas (MMcf)			MBoe
2009
Proved reserves
Beginning balance		2,193			671			2,304
Revisions of previous estimates		781			(84	)		767
Extensions, discoveries and other additions		8,381			3,414			8,950
Sales of reserves in place		(2	)		(16	)		(5	)
Purchases of reserves in place		1,726			1,611			1,995
Production		(658	)		(326	)		(712	)

Net proved reserves at December 31, 2009		12,421			5,270			13,299

Proved developed reserves, December 31, 2009		5,231			2,293			5,613

Proved undeveloped reserves, December 31, 2009		7,190			2,977			7,686

2010
Proved reserves
Beginning balance		12,421			5, 270			13,299
Revisions of previous estimates		2,235			1,897			2,552
Extensions, discoveries and other additions		22,445			12,172			24,473
Sales of reserves in place		(122	)		(5	)		(123	)
Purchases of reserves in place		1,363			696			1,479
Production		(1,792	)		(651	)		(1,900	)

Net proved reserves at December 31, 2010		36,550			19,379			39,780

Proved developed reserves, December 31, 2010		15,650			8,208			17,018

Proved undeveloped reserves, December 31, 2010		20,900			11,171			22,762

2011
Proved reserves
Beginning balance		36,550			19,379			39,780
Revisions of previous estimates		(262	)		(159	)		(288	)
Extensions, discoveries and other additions		36,464			40,220			43,168
Sales of reserves in place		(56	)		(518	)		(142	)
Purchases of reserves in place		100			65			111
Production		(3,732	)		(1,087	)		(3,914	)

Net proved reserves at December 31, 2011		69,064			57,900			78,715

Proved developed reserves, December 31, 2011		31,749			24,535			35,839

Proved undeveloped reserves, December 31, 2011		37,315			33,365			42,876

Purchases of Reserves in Place

The Company had no significant reserve purchases in 2011.

Of the total 1,479 MBoe of reserves purchased in 2010, 715 MBoe were from the properties acquired in Roosevelt County, Montana in November 2010 and 764 MBoe were from the properties acquired in Richland County, Montana in December 2010.

Of the total 1,995 MBoe of reserves purchased in 2009, 1,511 MBoe were from the Kerogen Acquisition Properties and 484 MBoe were from the Fidelity Acquisition Properties.

Extensions, Discoveries and Other Additions

In 2011, the Company had a total of 43,168 MBoe of additions. An estimated 12,696 MBoe of extensions and discoveries were associated with new producing wells at December 31, 2011, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 30,472 MBoe of proved undeveloped reserves were added across all three of the Company's Williston Basin project areas associated with the Company's 2011 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

In 2010, the Company had a total of 24,473 MBoe of additions. An estimated 8,122 MBoe of extensions and discoveries were associated with new wells, which were producing at December 31, 2010, with approximately 99% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 16,351 MBoe of proved undeveloped reserves were added across all three of the Company's Williston Basin project areas associated with the Company's 2010 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

In 2009, the Company had a total of 8,950 MBoe of additions. An estimated 1,508 MBoe of extensions and discoveries were associated with new wells, which were producing at December 31, 2009, with approximately 95% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 7,442 MBoe of proved undeveloped reserves were added across all three of the Company's Williston Basin project areas associated with the Company's 2009 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

Sales of Reserves in Place

In November 2011, the Company sold its remaining interests in non-core oil and gas producing properties located in the Barnett shale in Texas, which had minimal impact on the Company's proved reserves.

The Company traded interests in three non-operated properties as part of the Richland County, Montana acquisition in December 2010. These properties produce from the Red River formation and had remaining reserves of 123 MBoe.

In 2009, the Company sold a portion its interests in non-core oil and gas producing properties located in the Barnett shale in Texas, which had minimal impact on the Company's proved reserves.

Revisions of Previous Estimates

In 2011, the Company had a net negative revision of 288 MBoe, or 0.72% of the beginning of the year reserves balance. This revision is the result of several changes, such as net revenue interests, well performances, operating costs and realized prices. The unweighted arithmetic average first-day-of-the-month oil price for the 12 months prior was $96.23/Bbl for the year ended December 31, 2011 as compared to $79.40/Bbl for the year ended December 31, 2010. The unweighted arithmetic average first-day-of-the-month natural gas price for the 12 months prior was $4.12/MMBtu for the year ended December 31, 2011 as compared to $4.38/MMBtu for the year ended December 31, 2010.

In 2010, the Company had net positive revisions of 2,552 MBoe. Approximately 29% of these revisions were due to the increase in oil prices from 2009 to 2010. The unweighted arithmetic average first-day-of-the-month prices for the 12 months prior were $79.40/Bbl for the year ended December 31, 2010 as compared to $61.04/Bbl for the year ended December 31, 2009. An estimated 29% of the increase was due to higher working interests in proved wells. The remaining 42% of these revisions were due to other changes, including the estimate of recoverable hydrocarbons from proved wells.

In 2009, the Company had net positive revisions of 767 MBoe, primarily due to the increase in oil prices. The unweighted arithmetic average first-day-of-the-month prices for the 12 months prior was $61.04/Bbl for the year ended December 31, 2009 as compared to the market price for oil of $44.60/Bbl used for the December 31, 2008 reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited

The Standardized Measure represents the present value of estimated future cash flows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $96.23/Bbl for oil and $4.12/MMBtu for natural gas for the year ended December 31, 2011, $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the year ended December 31, 2010 and $61.04/Bbl for oil and $3.87/MMBtu for natural gas for the year ended December 31, 2009. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company's oil and natural gas reserves at December 31, 2011, 2010 and 2009.

		September 30,			September 30,			September 30,
	At Year Ended December 31,
	2011			2010			2009
	(In thousands)
Future cash inflows	$	6,508,604		$	2,620,530		$	664,480
Future production costs		(1,690,264	)		(696,890	)		(258,137	)
Future development costs		(783,486	)		(362,328	)		(120,212	)
Future income tax expense(1)		(1,225,395	)		(495,788	)		—

Future net cash flows		2,809,459			1,065,524			286,131
10% annual discount for estimated timing of cash flows		(1,489,988	)		(579,789	)		(152,601	)

Standardized measure of discounted future net cash flows	$	1,319,471		$	485,735		$	133,530

(1)

Does not include the effect of income taxes on discounted future net cash flows for the years ended December 31, 2009 because as of December 31, 2009, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes was provided because taxable income was passed through to the Company's equity holders.

The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.

		September 30,			September 30,			September 30,
	2011			2010			2009
	(In thousands)
January 1,	$	485,735		$	133,530		$	17,730
Net changes in prices and production costs		299,108			126,089			11,423
Net changes in future development costs		(38,244	)		(9,767	)		1,998
Sales of oil and natural gas, net		(262,485	)		(100,577	)		(25,254	)
Extensions		989,697			426,824			71,333
Discoveries		—			—			—
Purchases of reserves in place		2,679			26,919			36,809
Sales of reserves in place		(2,499	)		(1,720	)		(108	)
Revisions of previous quantity estimates		(5,058	)		55,149			7,700
Previously estimated development costs incurred		146,847			32,729			—
Accretion of discount		69,782			13,353			3,352
Net change in income taxes		(372,146	)		(212,085	)		—
Changes in timing and other		6,055			(4,709	)		8,547

December 31,	$	1,319,471		$	485,735		$	133,530