Supplemental Crude Oil and Natural Gas Information (Unaudited)

The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. ("Ryder Scott") prepared reserve estimates for properties comprising approximately 99%, 99%, and 99% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2015, 2014, and 2013, respectively. Properties comprising 99% of proved crude oil reserves and 97% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2015. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been recorded for the Company's Canadian operations at December 31, 2015.

Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered.

Reserves at December 31, 2015, 2014 and 2013 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.

Natural gas imbalance receivables and payables for each of the three years ended December 31, 2015, 2014 and 2013 were not material and have not been included in the reserve estimates.

Proved crude oil and natural gas reserves

Changes in proved reserves were as follows for the periods presented:



	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved reserves as of December 31, 2012	561,163		1,341,084		784,677
Revisions of previous estimates	(55,783	)	(241,623	)	(96,054	)
Extensions, discoveries and other additions	267,009		1,065,870		444,654
Production	(34,989	)	(87,730	)	(49,610	)
Sales of minerals in place	—		—		—
Purchases of minerals in place	388		419		458
Proved reserves as of December 31, 2013	737,788		2,078,020		1,084,125
Revisions of previous estimates	(67,151	)	(244,783	)	(107,949	)
Extensions, discoveries and other additions	239,526		1,206,569		440,621
Production	(44,530	)	(114,295	)	(63,579	)
Sales of minerals in place	(123	)	(18,623	)	(3,227	)
Purchases of minerals in place	850		1,498		1,100
Proved reserves as of December 31, 2014	866,360		2,908,386		1,351,091
Revisions of previous estimates	(246,840	)	(302,143	)	(297,198	)
Extensions, discoveries and other additions	134,764		710,453		253,173
Production	(53,517	)	(164,454	)	(80,926	)
Sales of minerals in place	(253	)	(456	)	(329	)
Purchases of minerals in place	—		—		—
Proved reserves as of December 31, 2015	700,514		3,151,786		1,225,811

Revisions of previous estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Downward revisions to proved reserves in 2013 primarily represented the removal of PUD reserves resulting from a decision in 2013 to focus the Company's drilling program on certain areas of the Bakken and SCOOP plays with more attractive rates of return and multi-well pad drilling capabilities, while building on success in the Company's development of the Lower Three Forks reservoirs in the Bakken.

Downward revisions to proved reserves in 2014 resulted from the Company refining its drilling program and reducing its planned rig count in response to the significant decrease in crude oil prices in the latter part of 2014, which contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked.

Downward revisions to proved reserves in 2015 resulted primarily from the significant decrease in commodity prices in 2015. The 12-month average price for crude oil decreased 47% from $94.99 per Bbl for 2014 to $50.28 per Bbl for 2015, while the 12-month average price for natural gas decreased 41% from $4.35 per MMBtu for 2014 to $2.58 per MMBtu for 2015. These decreases shortened the economic lives of certain producing properties and caused certain exploration and development projects to become uneconomic which had an adverse impact on the Company's proved reserve estimates, resulting in downward revisions of 185 MMBo and 391 Bcf (totaling 251 MMBoe) in 2015.

In response to the continued decrease in commodity prices throughout 2015, the Company has further refined its drilling program and reduced its planned rig count to concentrate its efforts in core areas of North Dakota and Oklahoma that provide the best opportunities to improve recoveries and rates of return. The refinement of the Company's drilling program contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. One element leading to the removal is an increased emphasis on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized. Further, in the SCOOP play the Company removed certain PUD locations originally planned to be developed with standard lateral drilling lengths in favor of PUDs to be developed with extended length laterals in similar locations that provide opportunities for improved well productivity and economics. The combination of these and other factors resulted in the removal of 65 MMBo and 197 Bcf (totaling 98 MMBoe) of PUD reserves in 2015.

Additionally, changes in anticipated production performance on certain properties resulted in 63 MMBo of downward revisions to crude oil proved reserves and 125 Bcf of upward revisions to natural gas proved reserves (netting to 42 MMBoe of downward revisions) in 2015.

The downward revisions described above were partially offset by upward revisions in 2015 due to lower operating costs being realized in conjunction with depressed commodity prices and improvements in operating efficiencies as well as other factors.

Extensions, discoveries and other additions. These are additions to proved reserves resulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.

Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity in our Bakken and SCOOP plays. Proved reserve additions in the Bakken totaled 75 MMBo and 124 Bcf (totaling 96 MMBoe) and reserve additions in SCOOP totaled 36 MMBo and 340 Bcf (totaling 93 MMBoe) for the year ended December 31, 2015. Additionally, 2015 extensions and discoveries were significantly impacted by successful drilling results in the Northwest Cana/STACK area, resulting in proved reserve additions of 20 MMBo and 222 Bcf (totaling 57 MMBoe) in 2015.

Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 14. Property Dispositions for a discussion of notable dispositions.

Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. There were no notable acquisitions in the three years reflected in the table above.

The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2015, 2014 and 2013:



	December 31,
	2015	2014	2013
Proved Developed Reserves
Crude oil (MBbl)	326,798	342,137	278,630
Natural Gas (MMcf)	1,190,343	962,051	768,969
Total (MBoe)	525,188	502,479	406,792
Proved Undeveloped Reserves
Crude oil (MBbl)	373,716	524,223	459,158
Natural Gas (MMcf)	1,961,443	1,946,335	1,309,051
Total (MBoe)	700,623	848,612	677,333
Total Proved Reserves
Crude oil (MBbl)	700,514	866,360	737,788
Natural Gas (MMcf)	3,151,786	2,908,386	2,078,020
Total (MBoe)	1,225,811	1,351,091	1,084,125

Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that require relatively major capital expenditures to recover. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.

Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves

The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2015, 2014 and 2013.



	December 31,
In thousands	2015			2014			2013
Future cash inflows	$	36,551,672		$	90,867,459		$	78,646,274
Future production costs	(10,869,493		)	(25,799,221		)	(21,333,460		)
Future development and abandonment costs	(6,935,958		)	(12,842,174		)	(10,250,789		)
Future income taxes	(3,717,612		)	(13,800,737		)	(12,447,127		)
Future net cash flows	15,028,609			38,425,327			34,614,898
10% annual discount for estimated timing of cash flows	(8,552,325		)	(19,992,293		)	(18,319,131		)
Standardized measure of discounted future net cash flows	$	6,476,284		$	18,433,034		$	16,295,767

The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $41.63, $84.54, and $91.50 per barrel at December 31, 2015, 2014 and 2013, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $2.35, $6.06, and $5.36 per Mcf at December 31, 2015, 2014 and 2013, respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows.

The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years.



	December 31,
In thousands	2015			2014			2013
Standardized measure of discounted future net cash flows at January 1	$	18,433,034		$	16,295,767		$	11,180,357
Extensions, discoveries and improved recoveries, less related costs	1,091,283			5,516,528			6,613,665
Revisions of previous quantity estimates	(2,156,028		)	(1,755,366		)	(1,765,300		)
Changes in estimated future development and abandonment costs	5,008,731			476,665			1,942,585
Purchases (sales) of minerals in place, net	(7,768		)	(3,196		)	12,012
Net change in prices and production costs	(16,111,142		)	(1,925,349		)	263,541
Accretion of discount	1,843,303			1,629,576			1,118,036
Sales of crude oil and natural gas produced, net of production costs	(2,002,997		)	(3,500,790		)	(2,992,447		)
Development costs incurred during the period	1,394,584			2,466,748			1,210,223
Change in timing of estimated future production and other	(3,844,259		)	(309,902		)	464,111
Change in income taxes	2,827,543			(457,647		)	(1,751,016		)
Net change	(11,956,750		)	2,137,267			5,115,410
Standardized measure of discounted future net cash flows at December 31	$	6,476,284		$	18,433,034		$	16,295,767