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DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended
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Dec. 31, 2021
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] |
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The Company’s oil and natural gas activities are located entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows (in thousands):
| Year Ended December 31,
| 2021 |  | 2020 |  | 2019
Acquisition(1) | $ | 4,861,619 |  |  | $ | 11,296 |  |  | $ | 12,901 |
Development(2)(3) | 315,746 |  |  | 55,934 |  |  | 209,535 |
Exploration | 7,937 |  |  | 595 |  |  | 796 |
Total | $ | 5,185,302 |  |  | $ | 67,825 |  |  | $ | 223,232 |
_________________________ (1)Acquisition costs for unproved properties for the years ended December 31, 2021, 2020, and 2019 were $648.0 million, $2.3 million, and $4.2 million, respectively. There were $4.2 billion, $9.0 million, and $8.7 million in acquisition costs for proved properties for the years ended December 31, 2021, 2020, and 2019, respectively. (2)Development costs include workover costs of $2.2 million, $1.2 million, and $1.4 million charged to lease operating expense for the years ended December 31, 2021, 2020, and 2019, respectively. (3)Includes amounts relating to asset retirement obligations of $13.8 million, $(1.0) million, and $(0.9) million, for the years ended December 31, 2021, 2020, and 2019, respectively. Suspended Well Costs The Company did not incur any exploratory well costs during the years ended December 31, 2021, 2020, and 2019. Reserves The proved reserve estimates were prepared by our third party independent reserve engineers, which were Ryder Scott at December 31, 2021 and 2020 and NSAI for the estimates at December 31, 2019. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. All of the Company’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of the Company's changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2021, 2020, and 2019 are as follows:
|  |  |  | Natural |  | Natural
|  | Oil |  | Gas |  | Gas Liquids
|  | (MBbl) |  | (MMcf) |  | (MBbl)
Balance-December 31, 2018 |  | 64,354 |  |  | 165,012 |  |  | 24,930 |
Extensions, discoveries and infills(1) |  | 8,825 |  |  | 20,604 |  |  | 3,123 |
Production |  | (5,136) |  |  | (11,967) |  |  | (1,431) |
Sales of minerals in place |  | (52) |  |  | (110) |  |  | (18) |
Removed from capital program(2) |  | (4,926) |  |  | (11,508) |  |  | (1,862) |
Purchases of minerals in place |  | 303 |  |  | 627 |  |  | 102 |
Revisions to previous estimates(3) |  | 1,045 |  |  | 49,542 |  |  | (2,683) |
Balance-December 31, 2019 |  | 64,413 |  |  | 212,200 |  |  | 22,161 |
Extensions, discoveries and infills(1) |  | 9,376 |  |  | 32,172 |  |  | 3,269 |
Production |  | (5,019) |  |  | (14,166) |  |  | (1,858) |
Removed from capital program(2) |  | (14,120) |  |  | (33,886) |  |  | (3,141) |
Purchases of minerals in place |  | 1,430 |  |  | 5,457 |  |  | 570 |
Revisions to previous estimates(3) |  | (3,287) |  |  | 33,951 |  |  | 5,110 |
Balance-December 31, 2020 |  | 52,793 |  |  | 235,728 |  |  | 26,111 |
Extensions, discoveries and infills(1) |  | 19 |  |  | 103 |  |  | — |
Production |  | (4,523) |  |  | (13,852) |  |  | (1,763) |
Removed from capital program(2) |  | (12,249) |  |  | (43,918) |  |  | (4,485) |
Purchases of minerals in place |  | 114,379 |  |  | 767,504 |  |  | 89,797 |
Revisions to previous estimates(3) |  | (6,840) |  |  | (57,066) |  |  | (3,632) |
Balance-December 31, 2021 |  | 143,579 |  |  | 888,499 |  |  | 106,028 |
Proved developed reserves: |  |  |  |  |  |
December 31, 2019 |  | 25,397 |  |  | 105,840 |  |  | 11,566 |
December 31, 2020 |  | 24,320 |  |  | 123,220 |  |  | 14,315 |
December 31, 2021 |  | 104,078 |  |  | 748,762 |  |  | 88,967 |
Proved undeveloped reserves: |  |  |  |  |  |
December 31, 2019 |  | 39,016 |  |  | 106,360 |  |  | 10,595 |
December 31, 2020 |  | 28,473 |  |  | 112,508 |  |  | 11,796 |
December 31, 2021 |  | 39,501 |  |  | 139,737 |  |  | 17,061 |
________________________ (1)During the years ended December 31, 2021, 2020, and 2019, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of nominal MMBoe, 18.0 MMBoe, and 15.4 MMBoe, respectively. (2) During the years ended December 31, 2021, 2020, and 2019, proved undeveloped reserves were reduced by 24.1 MMBoe, 22.9 MMBoe, and 8.7 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2021, the Company revised its proved reserves downward by 20.0 MMBoe primarily driven by 13.1 MMBoe in negative revisions due to changes in well operating cost methodology, 6.9 MMBoe in negative engineering revisions, and 7.1 MMBoe in negative revisions for fuel gas, interest, shrink, and other minor revisions. The commodity prices at December 31, 2021 increased to $66.56 per Bbl WTI and $3.60 per MMBtu HH from $39.57 per Bbl WTI and $1.99 per MMBtu HH at December 31, 2020, resulting in a partially offsetting positive revision of 7.1 MMBoe. As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe. As of December 31, 2019, the Company revised its proved reserves upward by 6.6 MMBoe. The commodity prices at December 31, 2019 decreased to $55.85 per Bbl WTI and $2.58 per MMBtu HH from $65.56 per Bbl WTI and $3.10 per MMBtu HH at December 31, 2018, resulting in a negative revision of 1.4 MMBoe, offset by 8.1 MMBoe in positive engineering revision. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with accounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on current costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company's oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
| Year Ended December 31,
| 2021 |  | 2020 |  | 2019
Future cash flows | $ | 14,401,814 |  |  | $ | 2,230,012 |  |  | $ | 3,827,009 |
Future production costs | (5,054,695) |  |  | (675,755) |  |  | (1,029,140) |
Future development costs | (1,107,576) |  |  | (530,970) |  |  | (850,327) |
Future income tax expense | (1,465,949) |  |  | — |  |  | — |
Future net cash flows | 6,773,594 |  |  | 1,023,287 |  |  | 1,947,542 |
10% annual discount for estimated timing of cash flows | (2,361,490) |  |  | (586,233) |  |  | (1,089,395) |
Standardized measure of discounted future net cash flows | $ | 4,412,104 |  |  | $ | 437,054 |  |  | $ | 858,147 |
Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
|  | Year Ended December 31,
|  | 2021 |  | 2020 |  | 2019
Beginning of period |  | $ | 437,054 |  |  | $ | 858,147 |  |  | $ | 954,980 |
Sale of oil and gas produced, net of production costs |  | (773,711) |  |  | (160,466) |  |  | (233,677) |
Net changes in prices and production costs |  | 874,155 |  |  | (641,137) |  |  | (372,233) |
Net changes in extensions, discoveries and improved recoveries |  | 855 |  |  | (54,269) |  |  | 45,728 |
Development costs incurred |  | 108,113 |  |  | 42,325 |  |  | 185,086 |
Changes in estimated development cost |  | 106,788 |  |  | 220,964 |  |  | 81,358 |
Purchases of minerals in place |  | 4,484,125 |  |  | 12,372 |  |  | 10,135 |
Sales of minerals in place |  | — |  |  | — |  |  | (309) |
Revisions of previous quantity estimates |  | (84,126) |  |  | 60,754 |  |  | 79,637 |
Net change in income taxes |  | (915,053) |  |  | — |  |  | — |
Accretion of discount |  | 43,705 |  |  | 85,815 |  |  | 95,498 |
Changes in production rates and other |  | 130,199 |  |  | 12,549 |  |  | 11,944 |
End of period |  | $ | 4,412,104 |  |  | $ | 437,054 |  |  | $ | 858,147 |
The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2021, 2020, and 2019 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location.
|  | Year Ended December 31,
|  | 2021 |  | 2020 |  | 2019
Oil (per Bbl) |  | $ | 61.60 |  |  | $ | 34.96 |  |  | $ | 51.22 |
Gas (per Mcf) |  | $ | 2.60 |  |  | $ | 0.95 |  |  | $ | 1.44 |
Natural gas liquids (per Bbl) |  | $ | 30.60 |  |  | $ | 6.12 |  |  | $ | 10.07 |

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