Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2020

Supplemental Oil and Gas Disclosures [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES

(UNAUDITED)

The supplemental data presented herein reflects information for all our oil and natural gas producing activities. Our oil and gas operations are substantially located in the United States.

Capitalized Costs

The capitalized costs at year end were as follows:


	Successor		Predecessor
	2020		2019
	(In thousands)
Proved properties	$	238,581	$	6,341,582
Unproved properties (wells in progress)	1,591		252,874
	240,172		6,594,456
Accumulated depreciation, depletion, amortization, and impairment	(40,806)		(5,846,177)
Net capitalized costs	$	199,366	$	748,279

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

The following table sets forth costs incurred related to our oil and natural gas activities for the periods indicated:


	Successor		Predecessor
	Period September 1, 2020 through December 31, 2020		Period January 1, 2020 through August 31, 2020		For the Year Ended December 31, 2019

	(In thousands)
Unproved properties acquired	$	26	$	2,373	$	34,668
Proved properties acquired	—		382		3,653
Exploration	—		—		16,480
Development	3,992		6,440		211,443
Asset retirement obligation	(1,702)		(29,189)		76
Total costs incurred	$	2,316	$	(19,994)	$	266,320

Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.

The results of operations for producing activities are as follows:


	Successor		Predecessor
	Period September 1, 2020 through December 31, 2020		Period January 1, 2020 through August 31, 2020		For the Year Ended December 31, 2019

	(In thousands)
Revenues	$	55,272	$	96,033	$	314,925
Production costs	(20,510)		(46,633)		(116,051)
Depreciation, depletion, amortization, and impairment	(40,840)		(461,901)		(727,529)
	(6,078)		(412,501)		(528,655)
Income tax (expense) benefit	128		6,698		101,952
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	(5,950)	$	(405,803)	$	(426,703)

Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:


	Oil Bbls	NGLs Bbls	Natural Gas Mcf	Total MBoe
	(In thousands)












2019
Proved developed and undeveloped reserves:
Beginning of year	22,558	47,796	535,963	159,681
Revision of previous estimates (1)	(8,263)	(20,961)	(234,852)	(68,366)
Extensions and discoveries (1)	703	845	8,798	3,015
Infill reserves in existing proved fields	271	434	4,806	1,506
Purchases of minerals in place	183	101	1,316	503
Production	(3,208)	(4,773)	(53,064)	(16,825)
Sales	(48)	(412)	(42,780)	(7,590)
Net proved reserves at December 31, 2019	12,196	23,030	220,187	71,924
Proved developed reserves, December 31, 2019	12,196	23,030	220,187	71,924
Proved undeveloped reserves, December 31, 2019	—	—	—	—
2020
Proved developed and undeveloped reserves:
Beginning of year	12,196	23,030	220,187	71,924
Revision of previous estimates	(1,909)	(4,477)	(38,901)	(12,870)
Extensions and discoveries	8	13	110	39
Infill reserves in existing proved fields	97	66	452	238
Purchases of minerals in place	62	20	172	112
Production	(2,186)	(3,444)	(37,567)	(11,891)
Sales	(1)	—	(62)	(11)
Net proved reserves at December 31, 2020	8,267	15,208	144,391	47,541
Proved developed reserves, December 31, 2020	8,267	15,208	144,391	47,541
Proved undeveloped reserves, December 31, 2020	—	—	—	—

_________________________

1.Revisions of previous estimates and extensions and discoveries decreased primarily due to the removal of proved undeveloped reserves due to uncertainty regarding our ability to finance the development of our proved undeveloped reserves over a five-year period and from lower commodity prices.

Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed, the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.

The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:


	Successor		Predecessor
	2020		2019
	(In thousands)
Future cash flows	$	698,685	$	1,386,777
Future production costs	(416,095)		(698,357)
Future development costs	—		—
Future income tax expenses	(39)		(321)
Future net cash flows	282,551		688,099
10% annual discount for estimated timing of cash flows	(89,530)		(226,390)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	193,021	$	461,709

The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:


	2020		2019

Sales and transfers of oil and natural gas produced, net of production costs	$	(84,163)	$	(200,233)
Net changes in prices and production costs	(165,978)		(508,066)
Revisions in quantity estimates and changes in production timing	(50,979)		(338,994)
Extensions, discoveries, and improved recovery, less related costs	2,827		53,123
Changes in estimated future development costs	—		311,190
Previously estimated cost incurred during the period	—		64,362
Purchases of minerals in place	852		6,416
Sales of minerals in place	(46)		(25,813)
Accretion of discount	46,203		110,571
Net change in income taxes	282		121,708
Changes in timing and other	(17,686)		(116,233)
Net change	(268,688)		(521,969)
Beginning of year	461,709		983,678
End of year	$	193,021	$	461,709

Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.

The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.

The December 31, 2020, future cash flows were computed by applying the unescalated 12-month average prices of $39.57 per barrel for oil, $18.70 per barrel for NGLs, and $1.98 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.

Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves.

Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.