Supplemental Oil and Gas Information (Unaudited)

12 Months Ended

Dec. 31, 2019

Extractive Industries [Abstract]

Supplemental Oil and Gas Information (Unaudited)

Note 21. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.

	December 31,			December 31,
	2019			2018
	(In thousands)
Evaluated oil and natural gas properties	$	797,005		$	598,331
Support equipment and facilities		140,023			108,760
Accumulated depletion, depreciation, and amortization		(136,747	)		(82,389	)
Total	$	800,281		$	624,702

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

			Successor				Predecessor
					Period from
	For the		For the		May 5, 2017		Period from
	Year Ended		Year Ended		through		January 1,
	December 31,		December 31,		December 31,		2017 through
	2019		2018		2017		May 4, 2017
	(In thousands)						(In thousands)
Property acquisition costs, proved	$	150,871	$	—	$	—	$	—
Property acquisition costs, unproved		7,674		—		—		—
Exploration		—		—		—		—
Development		71,460		42,878		51,925		9,573
Total	$	230,005	$	42,878	$	51,925	$	9,573

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and 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 that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

We engaged Cawley, Gillespie and Associates (“CG&A”) to prepare our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2019. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:

	2019		2018		2017
Oil ($/Bbl):
WTI (1)	$	55.69	$	65.56	$	51.34
NGL ($/Bbl):
WTI (1)	$	55.69	$	65.56	$	51.34
Natural Gas ($/MMbtu):
Henry Hub (2)	$	2.58	$	3.10	$	2.98

(1) The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2) The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

The following tables set forth estimates of the net reserves for the periods indicated:

	For the Year Ended December 31, 2019
	Oil			Gas			NGLs			Total
	(MBbls)			(MMcf)			(MBbls)			(MBoe)
Proved developed and undeveloped reserves:
Beginning of year		69,624			293,959			21,572			140,189
Extensions and discoveries		301			576			44			441
Purchase of minerals in place		17,429			202,409			18,533			69,697
Production		(3,498	)		(26,489	)		(1,343	)		(9,256	)
Revision of previous estimates		(13,084	)		(92,586	)		(9,554	)		(38,069	)
End of year		70,772			377,869			29,252			163,002
Proved developed reserves:
Beginning of year		54,147			232,110			17,324			110,156
End of year		53,476			320,731			23,646			130,577
Proved undeveloped reserves:
Beginning of year		15,477			61,849			4,248			30,033
End of year		17,296			57,138			5,606			32,425

	For the Year Ended December 31, 2018 (Successor)
	Oil			Gas			NGLs			Total
	(MBbls)			(MMcf)			(MBbls)			(MBoe)
Proved developed and undeveloped reserves:
Beginning of period		72,004			406,558			25,189			164,953
Extensions and discoveries		1,207			2,910			231			1,923
Production		(3,335	)		(29,176	)		(1,496	)		(9,694	)
Sale of minerals in place		(159	)		(56,328	)		(1,469	)		(11,016	)
Revision of previous estimates		(93	)		(30,005	)		(883	)		(5,977	)
End of period		69,624			293,959			21,572			140,189
Proved developed reserves:
Beginning of period		50,014			299,481			17,982			117,910
End of period		54,147			232,110			17,324			110,156
Proved undeveloped reserves:
Beginning of period		21,990			107,077			7,207			47,043
End of period		15,477			61,849			4,248			30,033

	For the period from May 5, 2017 through December 31, 2017 (Successor)
	Oil			Gas			NGLs			Total
	(MBbls)			(MMcf)			(MBbls)			(MBoe)
Proved developed and undeveloped reserves:
Beginning of period		80,960			419,472			30,572			181,444
Extensions and discoveries		121			4,900			261			1,199
Production		(2,380	)		(21,885	)		(1,114	)		(7,142	)
Revision of previous estimates		(6,697	)		4,071			(4,530	)		(10,548	)
End of period		72,004			406,558			25,189			164,953
Proved developed reserves:
Beginning of period		57,803			297,101			21,963			129,283
End of period		50,014			299,481			17,982			117,910
Proved undeveloped reserves:
Beginning of period		23,157			122,371			8,609			52,161
End of period		21,990			107,077			7,207			47,043

	For the period from January 1, 2017 through May 4, 2017 (Predecessor)
	Oil			Gas			NGLs			Total
	(MBbls)			(MMcf)			(MBbls)			(MBoe)
Proved developed and undeveloped reserves:
Beginning of year		65,741			371,016			25,184			152,761
Extensions and discoveries		53			45			8			69
Production		(1,204	)		(12,411	)		(616	)		(3,890	)
Revision of previous estimates		16,370			60,822			5,996			32,504
End of year		80,960			419,472			30,572			181,444
Proved developed reserves:
Beginning of year		45,536			280,035			18,923			111,132
End of year		57,803			297,101			21,963			129,283
Proved undeveloped reserves:
Beginning of year		20,205			90,981			6,261			41,630
End of year		23,157			122,371			8,609			52,161

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

• The 22.8 MMBoe increase in reserves for the year ended December 31, 2019 is primarily due to the Merger in which we acquired 69.7 MMBoe partially offset by downward pricing revision of a 25.9 MMBoe and a downward revision of 12.1 MMBoe due to updated well performance data and future anticipated maintenance cost increases.

• The 24.7 MMBoe reduction in reserves for the year ended December 31, 2018 is primarily due to a 4.6 MMBoe upward pricing revision and a 10.6 MMBoe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We divested 11.0 MMBoe during the year ended December 31, 2018. We added 1.9 MMBoe during the year ended December 31, 2018 due to extensions and discoveries.

• The 16.5 MMBoe reduction in reserves for the period from May 5, 2017 through December 31, 2017 is primarily due to a 2.2 MMBoe upward pricing revision and a 12.8 MMBoe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We added 1.2 MMBoe during the period from May 5, 2017 through December 31, 2017 due to extensions and discoveries.

• The 28.7 MMBoe increase in reserves for the January 1, 2017 through May 4, 2017 is primarily due to a 34.1 MMBoe upward pricing revision and a 1.5 MMBoe downward revision due to updated well performance data. Proved undeveloped reserves increased primarily due to upward pricing during the period from January 1, 2017 through May 4, 2017.

See Note 6 for additional information on acquisitions and divestitures.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:

				Successor						Predecessor
							Period from
	For the			For the			May 5, 2017			Period from
	Year Ended			Year Ended			through			January 1,
	December 31,			December 31,			December 31,			2017 through
	2019			2018			2017			May 4, 2017
	(In thousands)									(In thousands)
Future cash inflows	$	5,146,288		$	6,000,268		$	5,149,623		$	5,246,487
Future production costs		(2,917,262	)		(3,280,778	)		(2,982,035	)		(3,275,952	)
Future development costs		(567,423	)		(474,413	)		(530,133	)		(492,610	)
Future income tax expense		—			—			—			—
Future net cash flows for estimated timing of cash flows		1,661,603			2,245,077			1,637,455			1,477,925
10% annual discount for estimated timing of cash flows		(745,042	)		(1,132,048	)		(869,784	)		(786,836	)
Standardized measure of discounted future net cash flows	$	916,561		$	1,113,029		$	767,671		$	691,089

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2019:

	Successor									Predecessor
							Period from
	For the			For the			May 5, 2017			Period from
	Year Ended			Year Ended			through			January 1,
	December 31,			December 31,			December 31,			2017 through
	2019			2018			2017			May 4, 2017
	(In thousands)									(In thousands)
Beginning of year	$	1,113,029		$	767,671		$	691,089		$	395,841
Sale of oil and natural gas produced, net of production costs		(113,545	)		(181,841	)		(100,946	)		(57,420	)
Purchase of minerals in place		408,370			—			—			—
Sale of minerals in place		—			(29,036	)		—			—
Extensions and discoveries		5,334			27,157			7,187			1,320
Changes in prices and costs		(623,592	)		507,888			161,106			306,375
Previously estimated development costs incurred		84,341			73,761			61,851			9,227
Net changes in future development costs		110,892			24,396			(31,438	)		(55,333	)
Revisions of previous quantities		(183,300	)		(86,812	)		(27,060	)		99,591
Accretion of discount		92,998			51,769			46,072			13,195
Change in production rates and other		22,034			(41,924	)		(40,190	)		(21,707	)
End of year	$	916,561		$	1,113,029		$	767,671		$	691,089