Supplemental Oil and Gas Reserve Information - Unaudited

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Oil and Gas Reserve Information - Unaudited

Supplemental Oil and Gas Reserve Information — Unaudited

The reserve estimates at December 31, 2019, 2018 and 2017 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 crude oil and natural gas reserve estimation and disclosures. At December 31, 2019, 2018 and 2017, all of the Company’s crude 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 gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Proved oil and gas reserves are the estimated quantities of crude 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 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 Crude 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, 2019, 2018 and 2017:


	Crude Oil (MBbl)	Natural Gas (MMcf)	MBoe⁽¹⁾
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
2019
Proved reserves
Beginning balance	228,416	552,726	320,537
Revisions of previous estimates	(51,965)	(68,301)	(63,349)
Extensions, discoveries and other additions	49,297	87,382	63,861
Sales of reserves in place	(2,136)	(2,368)	(2,531)

Production	(22,825)	(55,906)	(32,142)
Net proved reserves at December 31, 2019	200,787	513,533	286,376
Proved developed reserves, December 31, 2019	113,418	314,000	165,751
Proved undeveloped reserves, December 31, 2019	87,369	199,533	120,625

__________________

(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 2019, the Company had net negative revisions of 63.3 MMBoe, or 20% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 51.2 MMBoe due to well performance, 11.2 MMBoe due to lower realized prices and 7.6 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 6.7 MMBoe due to lower operating expenses. Proved developed revisions were primarily due to negative revisions of 30.2 MMBoe for performance largely related to higher than anticipated decline rates in recently developed spacing units and 9.6 MMBoe due to lower realized prices, partially offset by positive revisions of 5.1 MMBoe due to lower operating expenses. The proved undeveloped revisions were primarily due to negative revisions of 21.1 MMBoe for performance largely related to reductions in the anticipated hydrocarbon recoveries of proved areas during full field development due to changes in anticipated well densities and well performance and 7.0 MMBoe associated with alignment to the anticipated five-year development plan, offset by positive revisions of 1.7 MMBoe due to lower operating expenses.

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.

Extensions, Discoveries and Other Additions

In 2019, the Company had a total of 63.9 MMBoe of additions due to extensions and discoveries. An estimated 10.3 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2019, with 60% of these reserves from wells producing in the Bakken or Three Forks formations and 40% of reserves from wells producing in the Delaware Basin, respectively. An additional 53.6 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins associated with the Company’s anticipated five-year development plan, with 63% of these proved undeveloped reserves in the Bakken or Three Forks formations in the Williston Basin and 37% of proved undeveloped reserves in the Delaware Basin.

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 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 2017 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 2019 and 2018, the Company divested 2.5 MMBoe and 15.9 MMBoe, respectively, 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.

Purchases of Reserves in Place

In 2019, there were no purchased estimated net proved reserves from acquisitions. 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.

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 crude 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 $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas, $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas and $51.34 per Bbl for crude oil and $2.99 per MMBtu for natural gas for the years ended December 31, 2019, 2018 and 2017, 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, 2019, 2018 and 2017:


	At December 31,
	2019		2018		2017

	(In thousands)
Future cash inflows	$	12,385,040	$	16,652,405	$	11,636,126
Future production costs	(5,509,127)		(6,609,097)		(4,458,418)
Future development costs	(1,490,521)		(1,701,672)		(992,271)
Future income tax expense	(188,823)		(968,466)		(580,481)
Future net cash flows	5,196,569		7,373,170		5,604,956
10% annual discount for estimated timing of cash flows	(2,352,200)		(3,322,864)		(2,304,261)
Standardized measure of discounted future net cash flows	$	2,844,369	$	4,050,306	$	3,300,695

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:


	2019		2018		2017

	(In thousands)
January 1	$	4,050,306	$	3,300,695	$	2,483,065
Net changes in prices and production costs	(1,070,192)		1,003,008		881,742
Net changes in future development costs	131,003		(89,304)		(60,929)
Sales of crude oil and natural gas, net	(943,989)		(1,155,223)		(769,367)
Extensions	437,700		461,196		661,467

Purchases of reserves in place	—		385,763		6,518
Sales of reserves in place	(36,907)		(197,867)		(9,024)
Revisions of previous quantity estimates	(732,253)		(115,015)		(78,942)
Previously estimated development costs incurred	246,311		303,364		157,386
Accretion of discount	467,426		368,374		262,776
Net change in income taxes	533,872		(240,908)		(238,354)
Changes in timing and other	(238,908)		26,223		4,357
December 31	$	2,844,369	$	4,050,306	$	3,300,695