18. Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates at December 31, 2012, 2011 and 2010 presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. At December 31, 2012, 2011 and 2010, 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 estimated net proved, proved developed and proved undeveloped reserves at December 31, 2012, 2011 and 2010:


	Oil (MBbl)			Gas (MMcf)			MBoe
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

2012
Proved reserves
Beginning balance		69,064			57,900			78,715
Revisions of previous estimates		(567	)		(8,495	)		(1,983	)
Extensions, discoveries and other additions		66,245			45,759			73,871
Sales of reserves in place		—			—			—
Purchases of reserves in place		881			512			966
Production		(7,533	)		(4,146	)		(8,224	)

Net proved reserves at December 31, 2012		128,090			91,530			143,345

Proved developed reserves, December 31, 2012		62,602			44,695			70,051

Proved undeveloped reserves, December 31, 2012		65,488			46,835			73,294

Purchases of Reserves in Place

In 2012, the Company purchased 966 MBoe of estimated net proved reserves from properties acquired in Burke and Mountrail counties. The Company had no significant reserve purchases in 2011. Of the total 1,479 MBoe of estimated net proved 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.

Extensions, Discoveries and Other Additions

In 2012, the Company had a total of 73,871 MBoe of additions due to extensions and discoveries. An estimated 16,548 MBoe of these extensions and discoveries were associated with new producing wells at December 31, 2012, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 57,322 MBoe of proved undeveloped reserves were added across all three of the Company’s Williston Basin project areas associated with the Company’s 2012 operated and non-operated drilling program, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

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.

Sales of Reserves in Place

In 2012, the Company did not have any sales of reserves. 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 estimated net proved reserves. In December 2010, the Company traded interests in three non-operated properties as part of the Richland County, Montana acquisition. These properties produce from the Red River formation and had remaining estimated net proved reserves of 123 MBoe.

Revisions of Previous Estimates

In 2012, the Company had a net negative revision of 1,983 MBoe, or 2.5% of the beginning of the year estimated net proved reserves balance. The primary causes for this revision were negative well performances offset by working interest increases in the proved locations. Actual well results in portions of the Company’s acreage came in below the proved forecasts prepared in 2011. The proved forecasts for the 2012 reserve report have been adjusted to reflect these well performances. The working interest increases arose from acreage trades, non-participation by other interest owners and additional mineral leasing in the reserve locations. Operating costs and realized prices had an immaterial impact to the reserves balance.

In 2011, the Company had a net negative revision of 288 MBoe, or 0.72% of the beginning of the year estimated net proved reserves balance. This net negative revision was the result of several immaterial changes, including well performances, net revenue interest changes, operating costs and realized prices.

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 twelve 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.

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 net cash flows from estimated net 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.

The Company’s estimated net 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 twelve months were $94.68/Bbl for oil and $2.75/MMBtu for natural gas for the year ended December 31, 2012, $96.23/Bbl for oil and $4.12/MMBtu for natural gas for the year ended December 31, 2011 and $79.40/Bbl for oil and $4.38/MMBtu for natural gas for the year ended December 31, 2010. 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 estimated net oil and natural gas reserves at December 31, 2012, 2011 and 2010.


	At December 31,
	2012			2011			2010
	(In thousands)
Future cash inflows	$	11,321,992		$	6,508,604		$	2,620,530
Future production costs		(2,809,960	)		(1,690,264	)		(696,890	)
Future development costs		(1,434,648	)		(783,486	)		(362,328	)
Future income tax expense		(2,123,973	)		(1,225,395	)		(495,788	)

Future net cash flows		4,953,411			2,809,459			1,065,524
10% annual discount for estimated timing of cash flows		(2,693,514	)		(1,489,988	)		(579,789	)

Standardized measure of discounted future net cash flows	$	2,259,897		$	1,319,471		$	485,735

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


	2012			2011			2010
	(In thousands)
January 1,	$	1,319,471		$	485,735		$	133,530
Net changes in prices and production costs		(7,814	)		299,108			126,089
Net changes in future development costs		28,124			(38,244	)		(9,767	)
Sales of oil and natural gas, net		(542,515	)		(262,485	)		(100,577	)
Extensions		1,358,479			989,697			426,824
Discoveries		—			—			—
Purchases of reserves in place		15,890			2,679			26,919
Sales of reserves in place		—			(2,499	)		(1,720	)
Revisions of previous quantity estimates		(47,957	)		(5,058	)		55,149
Previously estimated development costs incurred		480,925			146,847			32,729
Accretion of discount		190,370			69,782			13,353
Net change in income taxes		(400,196	)		(372,146	)		(212,085	)
Changes in timing and other		(134,880	)		6,055			(4,709	)

December 31,	$	2,259,897		$	1,319,471		$	485,735