Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)

12 Months Ended

Dec. 31, 2021

Extractive Industries [Abstract]

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)

Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)

Costs Incurred Related to Oil and Gas Activities

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.

The Company’s oil and natural gas activities for 2021, 2020 and 2019 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows (in thousands):

	Years Ended December 31,
	2021		2020		2019
Acquisition cost (1):
Proved	$	465,144	$	—	$	(141)
Unproved	43		—		(125)
Exploration costs:
Abandonment costs	—		—		653
Geological and geophysical	341		298		—
Development costs	134,035		67,550		210,520
Total additions	$	599,563	$	67,848	$	210,907

(1)Acquisition costs incurred during 2019 consisted primarily of purchase price adjustments related to 2018 acquisitions.      

During the years ended December 31, 2021, 2020 and 2019, additions to oil and natural gas properties of $2.2 million, $0.8 million and $0.1 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired.  

During the years ended December 31, 2021, 2020 and 2019, the Company had no capitalized exploratory well costs, nor capitalized costs related to share-based compensation, general corporate overhead or similar activities.

Capitalized Costs

Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2021 and 2020, are summarized below (in thousands):

	December 31,
	2021		2020
Oil and gas properties, successful efforts method:
Proved properties	$	1,726,019	$	1,118,148
Accumulated impairment to proved properties	(100,652)		(100,652)
Proved properties, net of accumulated impairments	1,625,367		1,017,496
Unproved properties	289,341		301,083
Accumulated impairment to Unproved properties	(67,316)		(67,316)
Unproved properties, net of accumulated impairments	222,025		233,767
Land	5,382		5,382
Total oil and gas properties, net of accumulated impairments	1,852,774		1,256,645
Accumulated depreciation, depletion and amortization	(395,625)		(291,213)
Net oil and gas properties	$	1,457,149	$	965,432

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 represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating

conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates shown herein for the years ended December 31, 2021, 2020 and 2019 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2021, 2020 and 2019 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $66.56 per barrel, $39.57 per barrel and $55.69 per barrel, respectively. The natural gas prices as of December 31, 2021, 2020 and 2019 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $3.60 per MMBtu, $1.99 per MMBtu and $2.58 per MMBtu, respectively. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2021, 2020 and 2019 averaged $30.16 per barrel, $11.61 per barrel and $16.17 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas and natural gas liquids reserves as of December 31, 2021 being valued using prices of $65.64 per barrel, $3.01 per MMBtu and $30.16 per barrel, respectively. All prices are held constant in accordance with SEC guidelines.    

A summary of the Company’s changes in quantities of proved oil, natural gas and NGL reserves for the years ended December 31, 2021, 2020 and 2019 are as follows:      

	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBoe)
Balance - December 31, 2018	59,034	113,217	20,943	98,847
Extensions and discoveries	3,598	4,476	721	5,065
Sales of minerals in place	(31)	(4)	(1)	(32)
Production	(3,086)	(4,760)	(1,022)	(4,902)
Revision to previous estimates	(6,865)	(4,939)	3,047	(4,642)
Balance - December 31, 2019	52,650	107,990	23,688	94,336
Extensions and discoveries	420	1,258	230	860
Production	(3,180)	(7,282)	(1,237)	(5,630)
Revision to previous estimates	(9,800)	9,249	(2,432)	(10,691)
Balance - December 31, 2020	40,090	111,215	20,249	78,875
Extensions and discoveries	7,016	49,846	6,532	21,856
Sales of minerals in place	(8)	(1)	—	(8)
Purchases of minerals in place	25,114	106,539	17,103	59,973
Production	(4,381)	(14,505)	(2,257)	(9,055)
Revision to previous estimates	(6,756)	31,787	(2,596)	(4,054)
Balance - December 31, 2021	61,075	284,881	39,031	147,587
Proved developed reserves:
December 31, 2018	14,325	26,110	4,969	23,646
December 31, 2019	18,220	35,120	7,447	31,521
December 31, 2020	18,878	55,764	10,125	38,298
December 31, 2021	35,824	190,999	25,917	93,575
Proved undeveloped reserves:
December 31, 2018	44,709	87,107	15,974	75,201
December 31, 2019	34,430	72,870	16,241	62,815
December 31, 2020	21,212	55,450	10,123	40,577
December 31, 2021	25,251	93,882	13,114	54,012

The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2021 and 2020:

As of December 31, 2021	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBoe)
Proved developed	14,011	74,702	10,137	36,598
Proved undeveloped	9,876	36,719	5,129	21,125
Total proved	23,887	111,421	15,266	57,723
As of December 31, 2020	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBoe)
Proved developed	10,113	29,873	5,424	20,516
Proved undeveloped	11,363	29,704	5,423	21,737
Total proved	21,476	59,577	10,847	42,253
As of December 31, 2019	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBoe)
Proved developed	9,933	19,146	4,060	17,183
Proved undeveloped	18,769	39,724	8,853	34,243
Total proved	28,702	58,870	12,913	51,426

Notable changes in proved reserves for the year ended December 31, 2021 included the following:

•Extensions and discoveries. In 2021, extensions and discoveries of 21.9 MMBoe were primarily the result of successful drilling results in the Midland Basin.

•Purchases of mineral in place. In 2021, the Company completed multiple acquisitions that resulted in 60.0 MMBoe in additional reserves, as disclosed above in Note 3. Acquisitions and Divestitures.

•Revision to previous estimates. In 2021, the downward revisions of prior reserves of 4.1 MMBoe consisted of changes in anticipated well densities and changes in performance and other economic factors totaling 9.2 MMBoe and 5.5 MMBoe, respectively, offset by a positive revision of 10.6 MMBoe related to changes in prices.

Notable changes in proved reserves for the year ended December 31, 2020 included the following:

•Extensions and discoveries. In 2020, total extensions and discoveries of 860.0 MBoe were primarily the result of successful drilling results in the Midland Basin.

•Revision to previous estimates. In 2020, the downward revisions of prior reserves of 10.7 MMBoe were composed of negative revisions due to the reclassification of 11.9 MMBoe of reserves from proved undeveloped to non-proved due to the SEC's five-year development rule and negative revisions of 2.7 MMBoe due to changes in price offset by revisions of 3.9 MMBoe related to changes in performance and other economic factors.

Notable changes in proved reserves for the year ended December 31, 2019 included the following:

•Extensions and discoveries. In 2019, total extensions and discoveries of 5.1 MMBoe were primarily the result of successful drilling results in the Midland Basin.

•Sales of minerals in place. Sales of minerals in place totaled 32.0 MBoe during 2019, resulting from the disposition of certain non-operated properties in the Midland Basin. See Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.  

•Revision to previous estimates. In 2019, the downward revisions of prior reserves of 4.6 MMBoe were primarily due to reduced commodity prices.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field. PUD locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data.  

Changes in PUD reserves for the years ended December 31, 2021, 2020 and 2019 were as follows (in MBoe): 

Proved undeveloped reserves at December 31, 2018(1)	75,201
Conversions to developed	(10,254)
Extensions and discoveries	1,230
Revision to previous estimates	(3,362)
Proved undeveloped reserves at December 31, 2019 (2)	62,815
Conversions to developed	(8,200)
Revision to previous estimates	(14,038)
Proved undeveloped reserves at December 31, 2020 (3)	40,577
Conversions to developed	(8,274)
Extensions and discoveries	20,521
Purchases of minerals in place	11,577
Revision to previous estimates	(10,389)
Proved undeveloped reserves at December 31, 2021 (4)	54,012

(1)Includes 41,560 MBoe attributable to noncontrolling interests.

(2)Includes 34,243 MBoe attributable to noncontrolling interests.

(3)Includes 21,737 MBoe attributable to noncontrolling interests.

(4)Includes 21,125 MBoe attributable to noncontrolling interests.

2021 Changes in Proved Undeveloped Reserves

Conversions to developed. In the Company's year-end 2020 plan to develop its PUDs within five years, it was estimated that $41.1 million of capital would be expended in 2021 for the conversion of 13 gross / 10.5 net PUDs to add 6.7 MMBoe. In 2021, due to improved commodity prices, the Company spent $55.1 million to convert 16 gross / 13.1 net PUDs adding 8.3 MMBoe to developed.

Revision to previous estimates. Downward revisions of prior reserves of 10.4 MMBoe consisted of changes in anticipated well densities and changes in performance and other economic factors of 9.2 MMBoe and 2.9 MMBoe, respectively, offset by a positive revision of 1.7 MMBoe related to changes in prices.

2020 Changes in Proved Undeveloped Reserves

Conversions to developed. In the Company's year-end 2019 plan to develop its PUDs within five years, the Company estimated that $111.1 million of capital would be expended in 2020 for the conversion of 28 gross / 17.6 net PUDs to add 11.3 MMBoe. In 2020, due to unforeseeable conditions previously described, the Company spent $67.8 million to convert 18 gross / 10.3 net PUDs adding 8.2 MMBoe to developed.

Revision to previous estimates. The Company maintains a five-year development plan, reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within the Company's inventory of undrilled well locations. In response to lower commodity prices, the Company reduced the pace of activity in its five-year development plan. This resulted in the reclassification of 11.9 MMBoe of reserves from proved undeveloped to non-proved during the year ended December 31, 2020 due to the five-year development rule. Based on the Company's then-current acreage position, strip prices, anticipated well economics, and its development plans at the time these reserves were classified as proved, the Company's management believes the previous classification of these locations as proved undeveloped was appropriate. The remaining revisions of 2.1 MMBoe were primarily due to reduced commodity prices.

2019 Changes in Proved Undeveloped Reserves

Conversions to developed. In the Company's year-end 2018 plan to develop its PUDs within five years, the Company estimated that $103.8 million of capital would be expended in 2019 for the conversion of 30 gross / 12.3 net PUDs to add 9.9 MMBoe, which was consistent with the $111.5 million actually spent to convert 32 gross / 13.4 net PUDs adding 10.3 MMBoe to developed reserves.

Extensions and discoveries. Additionally, 1.2 MMBoe were added as extensions and discoveries due to successful drilling results on the Company's acreage positions because of the wells the Company drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to the Company's acreage.

Revision to previous estimates. Revisions of 3.4 MMBoe were primarily due to reduced commodity prices.

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

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing FASB ASC Topic 932, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third-party petroleum engineering firm. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

•Future costs and commodity prices will probably differ from those required to be used in these calculations;

•Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

•A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

•Future net revenues may be subject to different rates of income taxation.

At December 31, 2021, 2020 and 2019, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves above. Future production costs include per-well overhead expenses allowed under joint operating agreements, abandonment costs (net of salvage value), and a non-cancelable fixed cost agreement to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

The Standardized Measure at December 31, 2021, 2020 and 2019 is as follows (in thousands):

	December 31,
	2021		2020		2019
Future cash inflows	$	6,042,508	$	1,902,073	$	3,250,868
Future production costs	(1,641,130)		(633,248)		(1,027,464)
Future development costs	(470,008)		(285,088)		(628,692)
Future income tax expense	(381,663)		(35,557)		(58,824)
Future net cash flows	3,549,707		948,180		1,535,888
10% annual discount for estimated timing of cash flows	(1,731,335)		(487,327)		(746,311)
Standardized measure of discounted future net cash flows (1)	$	1,818,372	$	460,853	$	789,577

(1)At December 31, 2021, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $711.2 million, $246.9 million and $430.4 million, respectively.

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

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2021 (in thousands):

	December 31,
	2021		2020		2019
Beginning of year	$	460,853	$	789,577	$	959,452
Sales of oil and gas produced, net of production costs	(343,914)		(105,555)		(150,708)
Sales of minerals in place	14		14		(458)
Net changes in prices and production costs	1,346,851		(381,769)		(565,240)
Extensions, discoveries, and improved recoveries	216,583		14,644		127,182
Changes in income taxes, net	(185,757)		17,826		12,697
Previously estimated development costs incurred during the period	41,120		66,788		210,520
Net changes in future development costs	(104,223)		258,741		118,348
Purchases of minerals in place	465,187		—		—
Revisions of previous quantity estimates	(151,748)		(273,781)		(35,588)
Accretion of discount	76,121		81,999		107,432
Changes in timing of estimated cash flows and other	(2,715)		(7,631)		5,940
End of year (1)	$	1,818,372	$	460,853	$	789,577

(1)At December 31, 2021, 2020 and 2019, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $711.2 million, $246.9 million and $430.4 million, respectively.