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Supplemental Oil and Natural Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2021
Extractive Industries [Abstract]  
Supplemental Oil and Natural Gas Disclosures (Unaudited) Supplemental Oil and Natural Gas Disclosures (Unaudited)
Geographic Area of Operation

All of the oil and natural gas properties in which we have working interests and mineral and royalty interests are located within the continental U.S., with the majority concentrated in Texas, Rockies and Oklahoma. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a combined and consolidated basis. In addition, we have a 37% ownership in our equity method investment, Exaro, that operates in the Jonah Field in Wyoming.

Oil and Natural Gas Reserve Information

The following table presents our net proved reserves for the years ended December 31, 2021, 2020 and 2019 and the changes in net proved oil, natural gas and NGL reserves during such years. In addition, the net proved reserves for our equity method investment, Exaro, are presented based on our 37% ownership percentage. Because Exaro was acquired in 2021 as part of the Merger Transactions, prior periods are not presented.


Developed and UndevelopedOil
(MBbls)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbls)		Total
(MBoe)
Consolidated operations
Net proved reserves at December 31, 2018202,8051,189,96275,780476,913
Revisions of previous estimates10,47720,552(11,321)2,581
Extensions, discoveries, and other additions (1)
12,00324,4721,85517,936
Sales of reserves in place————
Purchases of reserves in place————
Production(13,752)(73,747)(5,188)(31,231)
Net proved reserves at December 31, 2019211,5331,161,23961,126466,199
Revisions of previous estimates (2)
(57,708)(478,153)(20,279)(157,680)
Extensions, discoveries, and other additions4,08821,4796038,271
Sales of reserves in place————
Purchases of reserves in place (3)
22,409196,84018,95274,168
Production(13,132)(78,541)(5,078)(31,300)
Net proved reserves at December 31, 2020167,190822,86455,324359,658
Revisions of previous estimates (4)
9,147316,57216,48078,389
Extensions, discoveries, and other additions7,00717,2472,09311,975
Sales of reserves in place(6,333)(48,977)(3,265)(17,762)
Purchases of reserves in place (5)
46,386451,70211,960133,630
Production(13,237)(89,455)(6,099)(34,245)
Net proved reserves at December 31, 2021210,1601,469,95376,493531,645
Equity affiliate
Net proved reserves at December 31, 2020————
Revisions of previous estimates————
Extensions, discoveries, and other additions————
Sales of reserves in place————
Purchases of reserves in place20520,880—3,685
Production(1)(115)—(20)
Net proved reserves at December 31, 202120420,765—3,665
Total company
Net proved reserves at December 31, 2019211,5331,161,23961,126466,199
Net proved reserves at December 31, 2020167,190822,86455,324359,658
Net proved reserves at December 31, 2021210,3641,490,71876,493535,310
(1)During the year ended December 31, 2019, we added 17.9 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Eagle Ford and Permian. Approximately 77% of the reserve additions for the year ended December 31, 2019 were crude oil and NGLs.
(2)Revisions of previous estimates include 92.0 MMBoe downward revisions of our PUD reserves. The revisions are primarily due to declining commodity prices which decreased the quantity of reserves recoverable from our proved locations, and also resulted in the removal of certain PUD locations that were uneconomic at year end prices.
(3)Purchases in place of 74.2 MMBoe were primarily related to the Permian and DJ Basins.
(4)Revisions of previous estimates include 92.7 MMBoe upward revision due to pricing and cost changes, offset by 21.1 MMBoe downward revisions of our PUD reserves due to the removal of certain locations that are no longer part of our five-year consolidated development plan following the Merger Transactions.
(5)Purchases in place included 125.6 MMBoe from our Merger Transactions, 5.6 MMBoe from our Central Basin Platform Acquisition and 2.5 MMBoe from our DJ Basin Acquisition.

The following table sets forth our net proved oil, natural gas and NGL reserves for both our consolidated operations and our investment in Exaro as of the years ended December 31, 2021 and 2020, 2019 and 2018:

Proved Developed Reserves

Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 2021158,091 1,404,570 66,402 458,588 
December 31, 202092,024 748,496 44,307 261,079 
December 31, 2019103,728 870,491 48,997 297,808 
Equity affiliate
December 31, 2021204 20,765 — 3,665 
December 31, 2020— — — — 
December 31, 2019— — — — 
Proved Undeveloped Reserves

Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 202152,069 65,383 10,091 73,057 
December 31, 202075,166 74,368 11,017 98,579 
December 31, 2019107,805 290,748 12,129 168,391 
Equity affiliate
December 31, 2021— — — — 
December 31, 2020— — — — 
December 31, 2019— — — — 

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes the capitalized costs relating to our oil and natural gas producing activities for both our consolidated operations and our investment in Exaro as of December 31, 2021 and 2020:
As of December 31,
20212020
(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method)$6,043,602 $4,910,059 
Unproved oil and natural gas properties308,721 288,459 
Oil and natural gas properties, at cost6,352,323 5,198,518 
Less accumulated depreciation, depletion and amortization(1,881,933)(1,666,620)
Net capitalized costs$4,470,390 $3,531,898 
Equity affiliate
Proved oil and natural gas properties (successful efforts method)$9,043$— 
Unproved oil and natural gas properties— — 
Oil and natural gas properties, at cost9,043 — 
Less accumulated depreciation, depletion and amortization(67)— 
Net capitalized costs$8,976 $— 

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

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

The following table summarizes costs incurred related to our oil and natural gas activities for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:

Year Ended December 31,
202120202019
(in thousands)
Consolidated operations
Acquisition costs:
Proved$1,098,696 $355,010 $795 
Unproved41,355 680 7,264 
Exploration costs1,180 — 710 
Development194,828 83,013 318,157 
Total costs incurred$1,336,059 $438,703 $326,926 
Equity affiliate
Acquisition costs:
Proved$— $— $— 
Unproved— — — 
Exploration costs— — — 
Development— — — 
Total costs incurred$— $— $— 

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

The following information has been developed utilizing procedures prescribed by ASC 932 – Extractive Industries – Oil and Gas and based on crude oil, NGL and natural gas reserves and production volumes estimated by our engineering staff. The estimates were based on a 12-month average for first-day-of-the month commodity prices. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of our current value.
The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

Future net cash flows were calculated at December 31, 2021, 2020 and 2019 by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, with consideration of known contractual price changes. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

Year Ended December 31,
202120202019
Average benchmark price per unit:
Crude oil (Bbl)$66.56 $39.56 $55.69 
Natural gas (MMBtu)$3.60 $1.99 $2.62 

The following table sets forth the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro from projected production of oil and natural gas reserves, for the years ended December 31, 2021, 2020 and 2019:

Year Ended December 31,
202120202019
(in thousands)
Consolidated operations
Future cash inflows$21,063,117 $8,232,932 $15,745,942 
Future production costs(10,194,648)(4,280,563)(6,766,410)
Future development costs (1)
(1,477,562)(1,353,957)(2,323,420)
Future income taxes(352,136)(30,155)(63,136)
Future net cash flows9,038,771 2,568,257 6,592,976 
Annual discount of 10% for estimated timing
(4,080,471)(1,240,397)(3,482,128)
Standardized measure of discounted future net cash flows$4,958,300 $1,327,860 $3,110,848 
Equity affiliate (2)
Future cash inflows$99,290 $— $— 
Future production costs(55,371)— — 
Future development costs(2,309)— — 
Future income taxes(1,730)— — 
Future net cash flows39,880 — — 
Annual discount of 10% for estimated timing
(16,702)— — 
Standardized measure of discounted future net cash flows$23,178 $— $— 
(1)    Future development costs include future abandonment and salvage costs.
(2)    The average benchmark prices used for the equity affiliate were $66.55 per barrel for crude oil and $3.64 per MMBtu for natural gas.

Changes in standardized measure of discounted future net cash flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro for the years ended December 31, 2021, 2020 and 2019:
Year Ended December 31,
202120202019
(in thousands)
Consolidated operations
Balance at beginning of period$1,327,860 $3,110,848 $4,207,347 
Net change in prices and production costs3,330,299 (1,184,939)(821,874)
Net change in future development costs117,333 160,465 (59,359)
Sales and transfers of oil and natural gas produced, net of production expenses
(872,521)(290,053)(568,665)
Extensions, discoveries, additions and improved recovery, net of related costs162,657 31,688 182,697 
Purchases of reserves in place1,236,388 176,480 — 
Sales of reserves in place(84,095)— — 
Revisions of previous quantity estimates(295,234)(887,395)(226,561)
Previously estimated development costs incurred95,879 32,873 15,676 
Net change in taxes(184,419)19,350 (19)
Accretion of discount124,153 283,954 424,278 
Changes in timing and other— (125,411)(42,672)
Balance at end of period$4,958,300 $1,327,860 $3,110,848 
Equity affiliate
Balance at beginning of period$— $— $— 
Net change in prices and production costs— — — 
Net change in future development costs— — — 
Sales and transfers of oil and natural gas produced, net of production expenses(1,246)— — 
Extensions, discoveries, additions and improved recovery, net of related costs— — — 
Purchases of reserves in place26,154 — — 
Sales of reserves in place— — — 
Revisions of previous quantity estimates— — — 
Previously estimated development costs incurred— — — 
Net change in taxes(1,730)— — 
Accretion of discount— — — 
Changes in timing and other— — — 
Balance at end of period$23,178 $— $—