XML 50 R28.htm IDEA: XBRL DOCUMENT v3.22.4
Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)
 12 Months Ended
Dec. 31, 2022
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 2022, 2021 and 2020 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,
 202220212020
Acquisition cost:  
Proved$1,934,602 $465,144 $— 
Unproved77,378 43 — 
Exploration costs:
Geological and geophysical2,492 341 298 
Development costs538,114 134,035 67,550 
Total additions$2,552,586 $599,563 $67,848 
During the years ended December 31, 2022, 2021 and 2020, additions to oil and natural gas properties of $3.2 million, $2.2 million and $0.8 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired.
During the years ended December 31, 2022, 2021 and 2020, 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, 2022 and 2021, are summarized below (in thousands):
 December 31,
 20222021
Oil and gas properties, successful efforts method:  
Proved properties$4,088,553 $1,726,019 
Accumulated impairment to proved properties(100,652)(100,652)
Proved properties, net of accumulated impairments3,987,901 1,625,367 
Unproved properties349,905 289,341 
Accumulated impairment to Unproved properties(67,316)(67,316)
Unproved properties, net of accumulated impairments282,589 222,025 
Land5,482 5,382 
Total oil and gas properties, net of accumulated impairments4,275,972 1,852,774 
Accumulated depreciation, depletion and amortization(619,196)(395,625)
Net oil and gas properties$3,656,776 $1,457,149 
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, 2022, 2021 and 2020 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, 2022, 2021 and 2020 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 $93.67 per barrel, $66.56 per barrel and $39.57 per barrel, respectively. The natural gas prices as of December 31, 2022, 2021 and 2020 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $6.36 per MMBtu, $3.60 per MMBtu and $1.99 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, 2022, 2021 and 2020 averaged $39.24 per barrel, $30.16 per barrel and $11.61 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, 2022 being valued using prices of $95.82 per barrel, $5.51 per MMBtu and $39.24 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 natural gas liquid reserves for the years ended December 31, 2022, 2021 and 2020 are as follows:
Oil
(MBbl)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbl)		Total
(MBoe)
Balance - December 31, 201952,650 107,990 23,688 94,336 
Extensions420 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, 202040,090 111,215 20,249 78,875 
Extensions7,016 49,846 6,532 21,856 
Sales of minerals in place(8)(1)— (8)
Purchases of minerals in place25,114 106,539 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, 202161,075 284,881 39,031 147,587 
Extensions13,430 51,346 7,895 29,883 
Sales of minerals in place(2,044)(6,631)(1,417)(4,566)
Purchases of minerals in place85,237 429,646 56,268 213,113 
Production(11,866)(54,392)(7,599)(28,531)
Revision to previous estimates(7,432)37,316 11,663 10,450 
Balance - December 31, 2022138,400 742,166 105,841 367,936 
Proved developed reserves:
December 31, 201918,220 35,120 7,447 31,521 
December 31, 202018,878 55,764 10,125 38,298 
December 31, 202135,824 190,999 25,917 93,575 
December 31, 202288,759 574,762 80,168 264,721 
Proved undeveloped reserves:
December 31, 201934,430 72,870 16,241 62,815 
December 31, 202021,212 55,450 10,123 40,577 
December 31, 202125,251 93,882 13,114 54,012 
December 31, 202249,641 167,404 25,673 103,215 
The table below presents the quantities of proved oil, natural gas and natural gas liquids reserves attributable to noncontrolling interests as of December 31, 2022 and 2021 and 2020:
As of December 31, 2022Oil
(MBbl)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbl)		Total
(MBoe)
Proved developed21,750 140,845 19,645 64,870 
Proved undeveloped12,165 41,022 6,291 25,293 
Total proved33,915 181,867 25,936 90,163 
As of December 31, 2021Oil
(MBbl)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbl)		Total
(MBoe)
Proved developed14,011 74,702 10,137 36,598 
Proved undeveloped9,876 36,719 5,129 21,125 
Total proved23,887 111,421 15,266 57,723 
As of December 31, 2020Oil
(MBbl)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbl)		Total
(MBoe)
Proved developed10,113 29,873 5,424 20,516 
Proved undeveloped11,363 29,704 5,423 21,737 
Total proved21,476 59,577 10,847 42,253 

Notable changes in proved reserves for the year ended December 31, 2022 included the following:
•Extensions. In 2022, extensions of 29.9 MMBoe were primarily the result of successful drilling results in the Midland Basin.
•Purchases of minerals in place. In 2022, the Company completed multiple acquisitions that resulted in 213.1 MMBoe in additional reserves, as disclosed in Note 4. Acquisitions and Divestitures.
•Revision to previous estimates. In 2022, the upward revisions of prior reserves of 10.5 MMBoe consisted of 6.5 MMBoe related to changes in price and 4.0 MMBoe related to changes in performance and other economic factors.
Notable changes in proved reserves for the year ended December 31, 2021 included the following:
•Extensions. In 2021, total extensions 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 4. 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. In 2020, total extensions 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.
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, 2022, 2021 and 2020 were as follows (in MBoe): 
Proved undeveloped reserves at December 31, 2019 (1)62,815 
Conversions to developed(8,200)
Extensions— 
Revision to previous estimates(14,038)
Proved undeveloped reserves at December 31, 2020 (2)40,577 
Conversions to developed(8,274)
Extensions20,521 
Purchases of minerals in place11,577 
Revision to previous estimates(10,389)
Proved undeveloped reserves at December 31, 2021 (3)54,012 
Conversions to developed(22,637)
Extensions16,499 
Purchases of minerals in place57,432 
Revision to previous estimates(2,091)
Proved undeveloped reserves at December 31, 2022 (4)103,215 
(1)Includes 34,243 MBoe attributable to noncontrolling interests.
(2)Includes 21,737 MBoe attributable to noncontrolling interests.
(3)Includes 21,125 MBoe attributable to noncontrolling interests.
(4)Includes 25,293 MBoe attributable to noncontrolling interests.
2022 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company's year-end 2021 plan to develop its PUDs within five years, it was estimated that $190.2 million of capital would be expended in 2022 for the conversion of 45 gross / 31.8 net PUDs to add 24.5 MMBoe. In 2022, the Company spent $191.2 million to convert 42 gross / 26.6 net PUDs adding 22.6 MMBoe to developed.
Extensions. In 2022, extensions of 16.5 MMBoe were primarily the result of successful drilling results in the Delaware Basin and the Midland Basin.
Purchases of minerals in place. In 2022, the Company completed multiple acquisitions that resulted in 57.4 MMBoe of additional reserves, as disclosed in Note 4. Acquisitions and Divestitures.
Revision to previous estimates. Downward revisions of prior reserves of 2.1 MMBoe consisted of 2.4 MMBoe related to changes in performance and other economic factors, offset by a positive revision of 0.3 MMBoe related to changes in prices.
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.
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, 2022, 2021 and 2020, 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-cancellable 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, 2022, 2021 and 2020 is as follows (in thousands):
 December 31,
 202220212020
Future cash inflows$21,506,026 $6,042,508 $1,902,073 
Future production costs(6,362,901)(1,641,130)(633,248)
Future development costs(1,207,597)(470,008)(285,088)
Future income tax expense(1,910,370)(381,663)(35,557)
Future net cash flows12,025,158 3,549,707 948,180 
10% annual discount for estimated timing of cash flows(5,300,657)(1,731,335)(487,327)
Standardized measure of discounted future net cash flows (1)
$6,724,501 $1,818,372 $460,853 
(1)At December 31, 2022, 2021 and 2020, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $1.6 billion, $711.2 million and $246.9 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, 2022 (in thousands):
 December 31,
 202220212020
Beginning of year$1,818,372 $460,853 $789,577 
Sales of oil and gas produced, net of production costs(1,341,586)(343,914)(105,555)
Sales of minerals in place(76,570)14 14 
Net changes in prices and production costs3,838,439 1,346,851 (381,769)
Extensions and improved recoveries1,178,521 216,583 14,644 
Changes in income taxes, net(866,805)(185,757)17,826 
Previously estimated development costs incurred during the period246,705 41,120 66,788 
Net changes in future development costs(295,553)(104,223)258,741 
Purchases of minerals in place2,011,980 465,187 — 
Revisions of previous quantity estimates3,283 (151,748)(273,781)
Accretion of discount345,642 76,121 81,999 
Changes in timing of estimated cash flows and other(137,927)(2,715)(7,631)
End of year (1)
$6,724,501 $1,818,372 $460,853 
(1)At December 31, 2022, 2021 and 2020, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $1.6 billion, $711.2 million and $246.9 million, respectively.