Supplemental Oil and Gas Reserve Information - Unaudited

12 Months Ended

Dec. 31, 2021

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 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. All of the Company’s oil and gas reserves are attributable to properties within the United States.

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. 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.

Estimated Quantities of Proved Crude Oil and Natural Gas Reserves

The following table summarizes changes in quantities of the Company’s estimated net proved reserves for the periods presented:


	Crude Oil (MBbl)	Natural Gas (MMcf)	MBoe(1)
2019
Proved reserves
Beginning balance (Predecessor)	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 (Predecessor)	200,787	513,533	286,376
Proved developed reserves, December 31, 2019 (Predecessor)	113,418	314,000	165,751
Proved undeveloped reserves, December 31, 2019 (Predecessor)	87,369	199,533	120,625
2020
Proved reserves
Beginning balance (Predecessor)	200,787	513,533	286,376
Revisions of previous estimates	(69,782)	(98,815)	(86,251)
Extensions, discoveries and other additions	4,578	8,659	6,021
Production	(15,818)	(47,207)	(23,686)
Net proved reserves at December 31, 2020 (Successor)	119,765	376,170	182,460
Proved developed reserves, December 31, 2020 (Successor)	85,428	262,676	129,207
Proved undeveloped reserves, December 31, 2020 (Successor)	34,337	113,494	53,253
2021
Proved reserves
Beginning balance (Successor)	119,765	376,170	182,460
Revisions of previous estimates	42,411	68,768	53,871
Extensions, discoveries and other additions	7,734	14,539	10,157
Sales of reserves in place	(24,760)	(40,211)	(31,461)
Purchases of reserves in place	42,656	86,153	57,015
Production	(13,489)	(46,157)	(21,182)
Net proved reserves at December 31, 2021 (Successor)	174,317	459,262	250,860
Proved developed reserves, December 31, 2021 (Successor)	114,041	361,836	174,347
Proved undeveloped reserves, December 31, 2021 (Successor)	60,276	97,426	76,513

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

Revisions of Previous Estimates

In 2021, the Company had net positive revisions of 53.9 MMBoe, or 30% of the beginning of the year estimated net proved reserves balance. These net positive revisions were attributable to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, 37.2 MMBoe associated with higher realized prices and 6.2 MMBoe due to lower operating expenses, partially offset by negative revisions of 22.9 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 5.2 MMBoe due to the impact of removing the benefits of midstream operations from operating expenses. Proved developed net revisions of 20.3 MMBoe were primarily due to positive revisions of 36.5 MMBoe associated with higher realized prices and 6.0 MMBoe due to lower operating expenses, partially offset by negative revisions of 17.6 MMBoe attributable to reservoir analysis and well performance across our Bakken asset and 4.6 MMBoe due to the impact of removing the benefits of our midstream operations from operating expenses. Proved undeveloped (“PUD”) net revisions were primarily due to positive revisions of 38.6 MMBoe associated with alignment to the five-year development plan, offset by negative revisions of 5.1 MMBoe attributable to reservoir analysis and well performance across our Bakken asset.

In 2020, the Company had net negative revisions of 86.3 MMBoe, or 30% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 60.1 MMBoe associated with alignment

to the five-year development plan and 31.9 MMBoe due to lower realized prices, offset by positive revisions of 5.6 MMBoe for the addition of PUD reserves that were previously removed from the five-year development plan. Proved developed revisions were primarily due to negative revisions of 29.3 MMBoe due to lower realized prices, partially offset by positive revisions of 1.5 MMBoe due to lower operating expenses. The PUD revisions were primarily due to negative revisions of 54.5 MMBoe associated with alignment to the five-year development plan and 2.6 MMBoe due to lower realized price.

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 PUD 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.

Extensions, Discoveries and Other Additions

In 2021, the Company had a total of 10.2 MMBoe of additions due to extensions and discoveries. An estimated 7.6 MMBoe of PUDs were added associated with the Company’s anticipated five-year development plan, and an additional 2.6 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2021.

In 2020, the Company had a total of 6.0 MMBoe of additions due to extensions and discoveries. An estimated 3.2 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2020, with 99% of these reserves from wells producing in the Permian Basin and 1% of these reserves from wells producing in the Williston Basin. An additional 2.8 MMBoe of PUDs were added in the Williston Basin associated with the Company’s anticipated five-year development plan.

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 Permian Basin. An additional 53.6 MMBoe of PUDs were added in the Williston and Permian Basins associated with the Company’s anticipated five-year development plan, with 63% of these PUDs in the Bakken or Three Forks formations and 37% in the Permian Basin.

Sales of Reserves in Place

In 2021 and 2019, the Company divested 31.5 MMBoe of reserves associated with reservoirs in the Permian Basin and 2.5 MMBoe of reserves associated with reservoirs in the Williston Basin, respectively. The Company divested no reserves in 2020. See Note 13—Acquisitions and Divestitures for more information.

Purchases of Reserves in Place

In 2021, the Company purchased estimated net proved reserves of 57.0 MMBoe associated with reservoirs in the Williston Basin. In 2020 and 2019 there were no purchased estimated net proved reserves from acquisitions. See Note 13—Acquisitions and Divestitures for more information.

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

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 12 months were $66.55 per Bbl for crude oil and $3.64 per MMBtu for natural gas, $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas and $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas for the years ended December 31, 2021, 2020 and 2019, 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, 2021, 2020 and 2019:


	At December 31,
	2021		2020		2019

	(In thousands)
Future cash inflows	$	13,366,064	$	5,197,220	$	12,385,040
Future production costs	(6,548,794)		(2,792,921)		(5,509,127)
Future development costs	(1,322,207)		(610,658)		(1,490,521)
Future income tax expense	(717,721)		(232,849)		(188,823)
Future net cash flows	4,777,342		1,560,792		5,196,569
10% annual discount for estimated timing of cash flows	(2,080,404)		(611,915)		(2,352,200)
Standardized measure of discounted future net cash flows	$	2,696,938	$	948,877	$	2,844,369

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:


	2021		2020		2019

	(In thousands)
January 1	$	948,877	$	2,844,369	$	4,050,306
Net changes in prices and production costs	1,617,331		(1,088,936)		(1,070,192)
Net changes in future development costs	(36,645)		4,640		131,003
Sales of crude oil and natural gas, net	(796,874)		(407,417)		(943,989)
Extensions	98,125		47,693		437,700

Purchases of reserves in place	780,442		—		—
Sales of reserves in place	(204,153)		—		(36,907)
Revisions of previous quantity estimates	639,320		(694,320)		(732,253)
Previously estimated development costs incurred	102,519		87,640		246,311
Accretion of discount	94,090		293,445		467,426
Net change in income taxes	(252,347)		(76,066)		533,872
Changes in timing and other	(293,747)		(62,171)		(238,908)
December 31	$	2,696,938	$	948,877	$	2,844,369