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Supplemental Oil and Natural Gas Disclosures (Unaudited) | 12 Months Ended
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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 Undeveloped | Oil (MBbls) |  | Natural Gas (MMcf) |  | Natural Gas Liquids (MBbls) |  | Total (MBoe)
Consolidated operations |  |  |  |  |  |  |
Net proved reserves at December 31, 2018 | 202,805 |  | 1,189,962 |  | 75,780 |  | 476,913
Revisions of previous estimates | 10,477 |  | 20,552 |  | (11,321) |  | 2,581
Extensions, discoveries, and other additions (1) | 12,003 |  | 24,472 |  | 1,855 |  | 17,936
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, 2019 | 211,533 |  | 1,161,239 |  | 61,126 |  | 466,199
Revisions of previous estimates (2) | (57,708) |  | (478,153) |  | (20,279) |  | (157,680)
Extensions, discoveries, and other additions | 4,088 |  | 21,479 |  | 603 |  | 8,271
Sales of reserves in place | — |  | — |  | — |  | —
Purchases of reserves in place (3) | 22,409 |  | 196,840 |  | 18,952 |  | 74,168
Production | (13,132) |  | (78,541) |  | (5,078) |  | (31,300)
Net proved reserves at December 31, 2020 | 167,190 |  | 822,864 |  | 55,324 |  | 359,658
Revisions of previous estimates (4) | 9,147 |  | 316,572 |  | 16,480 |  | 78,389
Extensions, discoveries, and other additions | 7,007 |  | 17,247 |  | 2,093 |  | 11,975
Sales of reserves in place | (6,333) |  | (48,977) |  | (3,265) |  | (17,762)
Purchases of reserves in place (5) | 46,386 |  | 451,702 |  | 11,960 |  | 133,630
Production | (13,237) |  | (89,455) |  | (6,099) |  | (34,245)
Net proved reserves at December 31, 2021 | 210,160 |  | 1,469,953 |  | 76,493 |  | 531,645
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 place | 205 |  | 20,880 |  | — |  | 3,685
Production | (1) |  | (115) |  | — |  | (20)
Net proved reserves at December 31, 2021 | 204 |  | 20,765 |  | — |  | 3,665
Total company |  |  |  |  |  |  |
Net proved reserves at December 31, 2019 | 211,533 |  | 1,161,239 |  | 61,126 |  | 466,199
Net proved reserves at December 31, 2020 | 167,190 |  | 822,864 |  | 55,324 |  | 359,658
Net proved reserves at December 31, 2021 | 210,364 |  | 1,490,718 |  | 76,493 |  | 535,310
(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, 2021 | 158,091 |  |  | 1,404,570 |  |  | 66,402 |  |  | 458,588 |
December 31, 2020 | 92,024 |  |  | 748,496 |  |  | 44,307 |  |  | 261,079 |
December 31, 2019 | 103,728 |  |  | 870,491 |  |  | 48,997 |  |  | 297,808 |
Equity affiliate |  |  |  |  |  |  |
December 31, 2021 | 204 |  |  | 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, 2021 | 52,069 |  |  | 65,383 |  |  | 10,091 |  |  | 73,057 |
December 31, 2020 | 75,166 |  |  | 74,368 |  |  | 11,017 |  |  | 98,579 |
December 31, 2019 | 107,805 |  |  | 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,
| 2021 |  | 2020
| (in thousands)
Consolidated operations |  |  |
Proved oil and natural gas properties (successful efforts method) | $ | 6,043,602 |  |  | $ | 4,910,059 |
Unproved oil and natural gas properties | 308,721 |  |  | 288,459 |
Oil and natural gas properties, at cost | 6,352,323 |  |  | 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 cost | 9,043 |  |  | — |
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,
| 2021 |  | 2020 |  | 2019
| (in thousands)
Consolidated operations |  |  |  |  |
Acquisition costs: |  |  |  |  |
Proved | $ | 1,098,696 |  |  | $ | 355,010 |  |  | $ | 795 |
Unproved | 41,355 |  |  | 680 |  |  | 7,264 |
Exploration costs | 1,180 |  |  | — |  |  | 710 |
Development | 194,828 |  |  | 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,
| 2021 |  | 2020 |  | 2019
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,
2021 |  | 2020 |  | 2019
(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 flows | 9,038,771 |  |  | 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 flows | 39,880 |  |  | — |  |  | — |
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,
| 2021 |  | 2020 |  | 2019
| (in thousands)
Consolidated operations |  |  |  |  |
Balance at beginning of period | $ | 1,327,860 |  |  | $ | 3,110,848 |  |  | $ | 4,207,347 |
Net change in prices and production costs | 3,330,299 |  |  | (1,184,939) |  |  | (821,874) |
Net change in future development costs | 117,333 |  |  | 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 costs | 162,657 |  |  | 31,688 |  |  | 182,697 |
Purchases of reserves in place | 1,236,388 |  |  | 176,480 |  |  | — |
Sales of reserves in place | (84,095) |  |  | — |  |  | — |
Revisions of previous quantity estimates | (295,234) |  |  | (887,395) |  |  | (226,561) |
Previously estimated development costs incurred | 95,879 |  |  | 32,873 |  |  | 15,676 |
Net change in taxes | (184,419) |  |  | 19,350 |  |  | (19) |
Accretion of discount | 124,153 |  |  | 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 place | 26,154 |  |  | — |  |  | — |
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 |  |  | $ | — |  |  | $ | — |

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