Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates at December 31, 2018, 2017 and 2016 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, 2018, 2017 and 2016, 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 that 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, 2018, 2017 and 2016:



	Oil (MBbl)		Gas (MMcf)		MBoe⁽¹⁾
2016
Proved reserves
Beginning balance	184,928		199,828		218,233
Revisions of previous estimates	11,713		116,539		31,136
Extensions, discoveries and other additions	10,790		24,520		14,876
Sales of reserves in place	(5,828	)	(10,839	)	(7,635	)
Purchases of reserves in place	50,164		100,629		66,936
Production	(15,174	)	(19,573	)	(18,436	)
Net proved reserves at December 31, 2016	236,593		411,104		305,110
Proved developed reserves, December 31, 2016	152,337		229,568		190,598
Proved undeveloped reserves, December 31, 2016	84,256		181,536		114,512
2017
Proved reserves
Beginning balance	236,593		411,104		305,110
Revisions of previous estimates	(28,323	)	54,726		(19,200	)
Extensions, discoveries and other additions	36,238		89,489		51,153
Sales of reserves in place	(1,196	)	(1,147	)	(1,387	)
Purchases of reserves in place	466		1,230		671
Production	(18,818	)	(31,946	)	(24,143	)
Net proved reserves at December 31, 2017	224,960		523,456		312,204
Proved developed reserves, December 31, 2017	150,628		301,101		200,812
Proved undeveloped reserves, December 31, 2017	74,332		222,355		111,392
2018
Proved reserves
Beginning balance	224,960		523,456		312,204
Revisions of previous estimates	(17,352	)	3,019		(16,850	)
Extensions, discoveries and other additions	30,640		46,309		38,358
Sales of reserves in place	(12,470	)	(20,735	)	(15,926	)
Purchases of reserves in place	25,688		43,107		32,873
Production	(23,050	)	(42,430	)	(30,122	)
Net proved reserves at December 31, 2018	228,416		552,726		320,537
Proved developed reserves, December 31, 2018	144,533		339,444		201,107
Proved undeveloped reserves, December 31, 2018	83,883		213,282		119,430

__________________


(1)	Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.

Revisions of Previous Estimates

In 2018, the Company had net negative revisions of 16.9 MMBoe, or 5% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 42.3 MMBoe due to well performance and 9.4 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 14.7 MMBoe for the addition of proved undeveloped reserves (“PUDs”) that were previously removed from the five-year development plan, 14.4 MMBoe due to higher realized prices and 5.4 MMBoe for ownership adjustments. The proved developed net negative revisions of 20.2 MMBoe were primarily due to negative revisions of 33.0 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, partially offset by positive revisions of 12.2 MMBoe due to higher realized prices. The proved undeveloped revisions were primarily due to positive revisions of 14.7 MMBoe for the addition of PUDs that were previously removed from the five-year development plan, 5.6 MMBoe for ownership adjustments and 2.2 MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with alignment to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units.

In 2017, the Company had net negative revisions of 19.2 MMBoe, or 6% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 39.1 MMBoe associated with well performance and 2.1 MMBoe for alignment to the anticipated five-year development plan, offset by positive revisions of 16.1 MMBoe due to higher realized prices and 2.5 MMBoe for ownership adjustments. The proved developed negative revisions of 14.2 MMBoe were primarily due to negative revisions of 29.7 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, offset by positive revisions of 14.1 MMBoe from increased realized prices. The proved undeveloped negative revisions of 5.0 MMBoe were primarily due to negative revisions of 9.4 MMBoe for performance revisions largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units and negative 1.8 MMBoe revisions associated with alignment to the five-year development plan, offset by positive revisions of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe from increased realized prices.

In 2016, the Company had net positive revisions of 31.1 MMBoe, or 14% of the beginning of the year estimated net proved reserves balance. These net positive revisions were attributable to positive revisions of 30.4 MMBoe due to well performance and larger completion designs, 8.2 MMBoe due to a higher gas to oil ratio and 8.2 MMBoe due to ownership adjustments, offset by 9.5 MMBoe due to the removal of proved undeveloped reserves that were no longer aligned with the Company’s anticipated five-year drilling plan and 8.2 MMBoe due to lower commodity prices.

Extensions, Discoveries and Other Additions

In 2018, the Company had a total of 38.4 MMBoe of additions due to extensions and discoveries. An estimated 9.0 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2018, with 77% of these reserves from wells producing in the Bakken or Three Forks formations and 23% of reserves from wells producing in the Delaware Basin, respectively. An additional 29.4 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins associated with the Company’s anticipated five-year development plan, with 76% of these proved undeveloped reserves in the Bakken or Three Forks formations in the Williston Basin and 24% of proved undeveloped reserves in the Delaware Basin.

In 2017, the Company had a total of 51.2 MMBoe of additions due to extensions and discoveries. An estimated 17.9 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2017, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 33.3 MMBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s anticipated five-year development plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

In 2016, the Company had a total of 14.9 MMBoe of additions due to extensions and discoveries. An estimated 6.2 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2016, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 6.5 MMBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s 2016 operated and non-operated drilling program and anticipated five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.

Sales of Reserves in Place

In 2018, the Company divested 15.9 MMBoe of reserves associated with reservoirs in the Bakken or Three Forks formations (see Note 11 – Divestitures). In 2017, the Company divested 1.4 MMBoe of reserves associated with reservoirs other than the Bakken or Three Forks formations. In 2016, the Company divested 7.6 MMBoe of reserves associated with its traded acreage and sold wells.

Purchases of Reserves in Place

In 2018, the Company purchased estimated net proved reserves of 32.9 MMBoe from acquisitions in the Delaware Basin (see Note 10 – Acquisitions). In 2017, the Company purchased estimated net proved reserves of 0.7 MMBoe from acquisitions of additional working interests in its existing properties in the Williston Basin. In 2016, the Company purchased 66.9 MMBoe of estimated net proved reserves from acquisitions.

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 DD&A 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 $65.66 per Bbl for oil and $3.16 per MMBtu for natural gas, $51.34 per Bbl for oil and $2.99 per MMBtu for natural gas and $42.60 per Bbl for oil and $2.47 per MMBtu for natural gas for the years ended December 31, 2018, 2017 and 2016, respectively. 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. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2018, 2017 and 2016:



	At December 31,
	2018			2017			2016
	(In thousands)
Future cash inflows	$	16,652,405		$	11,636,126		$	9,426,963
Future production costs	(6,609,097		)	(4,458,418		)	(3,996,657		)
Future development costs	(1,701,672		)	(992,271		)	(784,727		)
Future income tax expense	(968,466		)	(580,481		)	(279,345		)
Future net cash flows	7,373,170			5,604,956			4,366,234
10% annual discount for estimated timing of cash flows	(3,322,864		)	(2,304,261		)	(1,883,169		)
Standardized measure of discounted future net cash flows	$	4,050,306		$	3,300,695		$	2,483,065

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



	2018			2017			2016
	(In thousands)
January 1	$	3,300,695		$	2,483,065		$	1,914,330
Net changes in prices and production costs	1,003,008			881,742			(367,527		)
Net changes in future development costs	(89,304		)	(60,929		)	69,992
Sales of oil and natural gas, net	(1,155,223		)	(769,367		)	(403,739		)
Extensions	461,196			661,467			165,926
Purchases of reserves in place	385,763			6,518			533,505
Sales of reserves in place	(197,867		)	(9,024		)	(57,770		)
Revisions of previous quantity estimates	(115,015		)	(78,942		)	333,398
Previously estimated development costs incurred	303,364			157,386			91,518
Accretion of discount	368,374			262,776			202,272
Net change in income taxes	(240,908		)	(238,354		)	(36,303		)
Changes in timing and other	26,223			4,357			37,463
December 31	$	4,050,306		$	3,300,695		$	2,483,065