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Supplemental Oil and Gas Reserve Information - Unaudited
 12 Months Ended
Dec. 31, 2024
Oil and Gas Disclosure [Abstract]  
Supplemental Oil and Gas Reserve Information - Unaudited Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates presented below at December 31, 2024, 2023 and 2022 are based on reports prepared by Netherland, Sewell & Associates, Inc., the Company’s independent reserve engineers. All of the Company’s oil and gas reserves are attributable to properties within the United States.
Proved oil and gas reserves are the estimated quantities of crude oil, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Estimated Quantities of Proved Reserves
The following table summarizes changes in quantities of the Company’s estimated net proved reserves by product for the periods presented:
Crude Oil
(MBbl)
NGLs(1)
(MBbl)
Natural Gas
(MMcf)
MBoe(2)
2022
Proved reserves
Beginning balance174,317 — 459,262 250,860 
Revisions of previous estimates(8,032)64,557 (56,500)47,110 
Extensions, discoveries and other additions38,144 7,452 35,689 51,544 
Sales of reserves in place— — — — 
Purchases of reserves in place202,316 73,468 443,903 349,768 
Production(25,457)(7,026)(67,428)(43,722)
Net proved reserves at December 31, 2022
381,288 138,451 814,926 655,560 
Proved developed reserves, December 31, 2022
272,529 115,227 689,651 502,698 
Proved undeveloped reserves, December 31, 2022
108,759 23,224 125,275 152,862 
2023
Proved reserves
Beginning balance381,288 138,451 814,926 655,560 
Revisions of previous estimates(38,073)(5,270)(33,308)(48,895)
Extensions, discoveries and other additions53,207 15,046 62,273 78,632 
Sales of reserves in place(3,999)(53)(3,067)(4,564)
Purchases of reserves in place12,375 3,052 20,060 18,771 
Production(36,427)(13,047)(82,953)(63,300)
Net proved reserves at December 31, 2023
368,371 138,179 777,931 636,204 
Proved developed reserves, December 31, 2023
241,362 105,702 640,180 453,762 
Proved undeveloped reserves, December 31, 2023
127,008 32,476 137,751 182,442 
2024
Proved reserves
Beginning balance368,371 138,179 777,931 636,204 
Revisions of previous estimates(35,229)(3,741)(38,294)(45,351)
Extensions, discoveries and other additions43,301 10,032 62,013 63,669 
Sales of reserves in place(1,264)(204)(1,071)(1,646)
Purchases of reserves in place176,710 39,256 596,287 315,346 
Production(48,479)(16,338)(122,193)(85,182)
Net proved reserves at December 31, 2024
503,410 167,184 1,274,673 883,040 
Proved developed reserves, December 31, 2024
317,689 125,824 1,053,288 619,061 
Proved undeveloped reserves, December 31, 2024
185,721 41,360 221,385 263,979 
__________________ 
(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting reserves. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.
(2)Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.
2024
Proved reserves increased by 246.8 MMBoe during the year ended December 31, 2024 due to the following:
Purchases of reserves in place. The Company added 315.3 MMBoe of proved reserves from the purchase of reserves in place as a result of the Arrangement.
Production. Production decreased proved reserves by 85.2 MMBoe.
Revisions of previous estimates. The Company had net negative revisions of 45.4 MMBoe attributable to the following:
Decreases:
•14.5 MMBoe associated with lower crude oil, NGL and natural gas prices and weaker differentials
•23.8 MMBoe primarily associated with re-ordering of the Company’s development timing plan following the Arrangement
•11.0 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
Increases:
•3.9 MMBoe associated with the reduction in operating expenses and capital expenses primarily associated with deflation
Extensions, discoveries and other additions. The Company added 63.7 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as proved undeveloped (“PUD”) locations added as a result of offset drilling, increased proved reserves.
Sales of reserves in place. Proved reserves decreased 1.6 MMBoe primarily as a result of the divestiture of certain non-core properties located in the DJ Basin of Colorado.
2023
Proved reserves decreased by 19.4 MMBoe during the year ended December 31, 2023 due to the following:
Production. Production decreased proved reserves by 63.3 MMBoe.
Revisions of previous estimates. The Company had net negative revisions of 48.9 MMBoe attributable to the following:
Decreases:
•41.2 MMBoe associated with lower crude oil, NGL and natural gas prices and tighter differentials
•19.6 MMBoe associated with increases in operating expenses and capital expenses primarily associated with inflation
•9.9 MMBoe primarily associated with updated expectations on undeveloped well reserves and changes to development timing
Increases:
•14.4 MMBoe associated with stronger NGL yields
•7.4 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
Extensions, discoveries and other additions. The Company added 78.6 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as PUD locations added as a result of offset drilling, increased proved reserves.
Purchases of reserves in place. The Company added 18.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the Williston Basin Acquisition.
Sales of reserves in place. Proved reserves decreased 4.6 MMBoe primarily as a result of the Non-core Asset Sales.
2022
Proved reserves increased by 404.7 MMBoe during the year ended December 31, 2022 due to the following:
Purchases of reserves in place. The Company added 349.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the Merger.
Extensions, discoveries and other additions. The Company added 51.5 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as PUD locations added as a result of offset drilling, increased proved reserves.
Revisions of previous estimates. The Company had net positive revisions of 47.1 MMBoe attributable to the following:
Increases:
•30.3 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022
•26.1 MMBoe associated with higher crude oil, NGL and natural gas prices
•2.6 MMBoe associated with tighter differentials and stronger NGL yields
Decreases:
•6.7 MMBoe associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
•5.2 MMBoe primarily associated with lower working interests as a result of well payouts associated with higher commodity pricing
Production. Production decreased proved reserves by 43.7 MMBoe.
Sales of reserves in place. There were no impacts to proved reserves as a result of the sale of reserves in place.
Changes in Proved Undeveloped Reserves
The following table summarizes the changes in the Company’s estimates of PUD reserves during 2024:
Year Ended December 31, 2024
(MBoe)
Proved undeveloped reserves, beginning of period182,442 
Purchases of minerals in place121,671 
Extensions, discoveries and other additions58,287 
Revisions of previous estimates(25,393)
Conversion to proved developed reserves(73,028)
Proved undeveloped reserves, end of period263,979 
Proved undeveloped reserves increased by 81.5 MMBoe during the year ended December 31, 2024 due to the following:
Purchases of minerals in place. The Company added 121.7 MMBoe of PUD reserves from the purchase of minerals in place as a result of the Arrangement.
Extensions, discoveries and other additions. The Company added 58.3 MMBoe of PUD reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin.
Revisions of previous estimates. The Company had net negative revisions of 25.4 MMBoe primarily attributable to the following decreases:
•23.8 MMBoe primarily associated with re-ordering of the Company’s development timing plan following the Arrangement
•0.9 MMBoe associated with lower crude oil, NGL and natural gas prices and weaker differentials
•0.7 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
Conversions to proved developed reserves. The Company incurred $408.4 million in capital expenditures to convert 73.0 MMBoe of PUD reserves to proved developed reserves during 2024. The PUD conversions represented 40% of the Company’s PUD reserves balance at the beginning of 2024. The conversions to proved developed reserves included 28.9 MMBoe of PUD reserves attributable to the Arrangement that were converted to proved developed reserves subsequent to the Arrangement and therefore were not included in the PUD reserves balance at the beginning of 2024.
As of December 31, 2024, the Company expects to develop all of its PUD reserves, including all wells drilled but not yet completed within five years after the initial year booked. Substantially all PUD locations are located on properties where the leases are held by existing production or continuous drilling operations. Approximately 15% of the Company’s PUD reserves at December 31, 2024 are attributable to wells that have been drilled but not yet completed, and all of the Company’s PUD reserves are within its core acreage in the Williston Basin.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.
The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas, $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas and $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas for the years ended December 31, 2024, 2023 and 2022, respectively. These prices were adjusted by lease for quality, energy content, transportation fees and marketing differentials. Future operating costs, production taxes and capital costs were based on current costs as of each year end.
The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2024, 2023 and 2022:
 At December 31,
 202420232022
 (In thousands)
Future cash inflows$39,474,381 $31,882,940 $44,544,247 
Future production costs(18,255,819)(13,815,882)(15,879,712)
Future development costs(3,928,154)(3,055,823)(2,553,605)
Future income tax expense(3,096,730)(2,573,017)(5,283,201)
Future net cash flows14,193,678 12,438,218 20,827,729 
10% annual discount for estimated timing of cash flows(5,839,500)(5,447,578)(9,333,254)
Standardized measure of discounted future net cash flows$8,354,178 $6,990,640 $11,494,475 
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:
202420232022
 (In thousands)
January 1$6,990,640 $11,494,475 $2,696,938 
Net changes in prices and production costs(2,145,627)(6,138,846)3,148,745 
Net changes in future development costs136,608 (92,072)35,427 
Sales of crude oil and natural gas, net(2,410,774)(2,033,251)(2,161,708)
Extensions639,614 864,249 958,924 
Purchases of reserves in place3,736,382 373,913 7,441,750 
Sales of reserves in place(37,074)(75,097)— 
Revisions of previous quantity estimates(493,520)(1,142,960)1,434,357 
Previously estimated development costs incurred692,049 574,607 137,534 
Accretion of discount1,088,290 1,445,215 683,631 
Net change in income taxes(370,584)1,419,851 (2,539,182)
Changes in timing and other528,174 300,556 (341,941)
December 31$8,354,178 $6,990,640 $11,494,475