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Supplemental Oil and Natural Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2024
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 and the Rockies. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a consolidated basis. In addition, at December 31, 2021, we had a 37% ownership in our equity method investment, Exaro, that operates in the Jonah Field in Wyoming. During the year ended December 31, 2022, our equity method investment, Exaro, sold its operations, see NOTE 3 – Acquisitions and Divestitures for additional information.

Oil and Natural Gas Reserve Information

The following table presents our net proved reserves for the years ended December 31, 2024, 2023 and 2022 and the changes in net proved oil, natural gas and NGL reserves during such years. The net proved reserves for our equity method investment, Exaro, are presented based on our 37% ownership percentage. Exaro was acquired in 2021 and subsequently sold in 2022, thus no values are presented for 2024, 2023 and 2022.


Developed and UndevelopedOil
(MBbls)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbls)		Total
(MBoe)
Consolidated operations
Net proved reserves at December 31, 2021210,1601,469,95376,493531,645
Revisions of previous estimates (1)
(18,859)(14,815)4,167(17,158)
Extensions, discoveries, and other additions (2)
37,20860,3127,75155,011
Sales of reserves in place(6,006)(19,365)(2,680)(11,915)
Purchases of reserves in place (3)
42,444138,920—65,597
Production(21,865)(128,470)(7,110)(50,387)
Net proved reserves at December 31, 2022243,0821,506,53578,621572,793
Revisions of previous estimates (4)
(15,501)(472,337)(11,676)(105,901)
Extensions, discoveries, and other additions (5)
2,80816,2401,6357,150
Sales of reserves in place(1,655)(15,075)(1,774)(5,942)
Purchases of reserves in place (6)
46,018271,68243,301134,599
Production(24,287)(130,629)(8,475)(54,533)
Net proved reserves at December 31, 2023
250,4651,176,416101,632548,166
Revisions of previous estimates (7)
(17,316)(210,432)(11,263)(63,648)
Extensions, discoveries, and other additions (8)
16,62670,63210,60439,002
Sales of reserves in place(3,344)(5,318)(767)(4,998)
Purchases of reserves in place (9)
81,204746,98858,664264,366
Production(29,945)(183,227)(13,154)(73,637)
Net proved reserves at December 31, 2024297,6901,595,059145,716709,251
Equity affiliate
Net proved reserves at December 31, 202120420,765—3,665
Sales of reserves in place(200)(20,357)—(3,593)
Production(4)(408)—(72)
Net proved reserves at December 31, 2022————
Net proved reserves at December 31, 2023
————
Developed and UndevelopedOil
(MBbls)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbls)		Total
(MBoe)
Net proved reserves at December 31, 2024————
Total company
Net proved reserves at December 31, 2022243,0821,506,53578,621572,793
Net proved reserves at December 31, 2023250,4651,176,416101,632548,166
Net proved reserves at December 31, 2024297,6901,595,059145,716709,251
(1)Revisions of previous estimates primarily relate to increased expected future costs driven by inflation and a higher commodity price environment.
(2)Extensions, discoveries and other additions of 55.0 MMBoe primarily relate to PUD extensions most of which related to our Eagle Ford asset.
(3)Purchases of reserves in place of 65.6 MMBoe primarily related to our Uinta Acquisition.
(4)Revisions of previous estimates primarily relate to a 133 MMBoe downward revision from lower oil and natural gas prices, partially offset by 27 MMBoe in upward revisions from a variety of factors primarily driven by new contracts, operating expense revisions and upward forecast revisions in certain basins.
(5)Extensions, discoveries and other additions of 7.2 MMBoe primarily relate to PUD extensions all of which related to our Eagle Ford and Uinta assets.
(6)Purchases of reserves in place of 134.6 MMBoe primarily related to our Western Eagle Ford Acquisitions.
(7)Revisions of previous estimates relate to 79.6 MMBoe downward revisions, driven primarily by a 44.0 MMBoe downward revision from lower oil and natural gas prices, partially offset by 16.0 MMBoe in upward revisions from a variety of factors primarily driven by new contracts and operating expense revisions in certain basins.
(8)Extensions, discoveries and other additions of 39.0 MMBoe primarily relate to PUD extensions all of which related to our Eagle Ford and Uinta assets.
(9)Purchases of reserves in place of 264.4 MMBoe primarily related to our the SilverBow Merger and Central Eagle Ford 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, 2024, 2023 and 2022:

Proved Developed Reserves

Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 2024193,611 1,342,718 109,223 526,622 
December 31, 2023176,546 1,032,578 87,316 435,958 
December 31, 2022160,113 1,398,770 66,803 460,046 
Equity affiliate
December 31, 2024— — — — 
December 31, 2023— — — — 
December 31, 2022— — — — 
Proved Undeveloped Reserves

Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 2024104,079 252,341 36,493 182,629 
December 31, 202373,919 143,838 14,316 112,208 
December 31, 202282,969 107,765 11,818 112,747 
Equity affiliate
December 31, 2024— — — — 
December 31, 2023— — — — 
December 31, 2022— — — — 
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 our consolidated operations as of December 31, 2024 and 2023:

As of December 31,
20242023
(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method)$11,471,299 $8,574,478 
Unproved oil and natural gas properties374,306 283,324 
Oil and natural gas properties, at cost11,845,605 8,857,802 
Less: accumulated depreciation, depletion, amortization and impairment(3,840,344)(2,865,095)
Net capitalized costs$8,005,261 $5,992,707 
Equity affiliate
Net capitalized costs$— $— 

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

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. For a description and allocation of costs incurred for our significant acquisitions included in the table below, see NOTE 3 – Acquisitions and Divestitures. 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, 2024, 2023 and 2022:

Year Ended December 31,
202420232022
(in thousands)
Consolidated operations
Acquisition costs:
Proved$2,163,000 $836,159 $793,081 
Unproved219,326 35,474 71,387 
Field and other property and equipment25,734 — 8,200 
Exploration costs16,591 9,328 3,425 
Development745,198 578,316 624,880 
Total costs incurred$3,169,849 $1,459,277 $1,500,973 
Equity affiliate
Total costs incurred$— $— $— 

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 Topic 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, 2024, 2023 and 2022 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,
202420232022
Average benchmark price per unit:
Crude oil (Bbl)$75.48 $78.22 $93.67 
Natural gas (MMBtu)$2.13 $2.64 $6.36 

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 and excludes the midstream revenue impact on a portion of our operations that could reduce future production costs, for the years ended December 31, 2024, 2023 and 2022:

Year Ended December 31,
202420232022
(in thousands)
Consolidated operations
Future cash inflows$27,890,094 $24,267,134 $33,628,495 
Future production costs(12,981,064)(11,897,791)(14,077,136)
Future development costs (1)
(3,801,466)(2,713,247)(2,380,931)
Future income taxes (2)
(1,055,147)(410,721)(773,479)
Future net cash flows10,052,417 9,245,375 16,396,949 
Annual discount of 10% for estimated timing
(4,348,722)(3,956,193)(7,262,283)
Standardized measure of discounted future net cash flows$5,703,695 $5,289,182 $9,134,666 
Equity affiliate
Future cash inflows$— $— $— 
Future production costs— — — 
Future development costs— — — 
Future income taxes— — — 
Future net cash flows— — — 
Annual discount of 10% for estimated timing
— — — 
Standardized measure of discounted future net cash flows$— $— $— 
(1)    Future development costs include future abandonment and salvage costs.
(2)    Our future income taxes are based upon on our allocable share of any taxable income of OpCo. Estimated future taxable income or loss generated by OpCo is generally allocated and passed through to Crescent at our proportionate share of OpCo unit ownership which at December 31, 2024, 2023 and 2022 was 74%, 51% and 29%, respectively.

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, 2024, 2023 and 2022:
Year Ended December 31,
202420232022
(in thousands)
Consolidated operations
Balance at beginning of period$5,289,182 $9,134,666 $4,958,300 
Net change in prices and production costs(47,265)(2,859,297)4,156,736 
Net change in future development costs(92,580)(141,382)(132,213)
Sales and transfers of oil and natural gas produced, net of production expenses
(1,715,764)(1,354,856)(2,083,147)
Extensions, discoveries, additions and improved recovery, net of related costs318,421 119,025 1,105,549 
Purchases of reserves in place2,493,077 1,338,224 1,333,452 
Sales of reserves in place(70,549)(90,157)(118,253)
Revisions of previous quantity estimates(817,132)(2,244,012)(952,958)
Previously estimated development costs incurred369,595 301,839 488,934 
Net change in taxes(478,046)190,444 (251,714)
Accretion of discount556,612 960,208 575,440 
Changes in timing and other(101,856)(65,520)54,540 
Balance at end of period$5,703,695 $5,289,182 $9,134,666 
Equity affiliate
Balance at beginning of period$— $— $23,178 
Net change in prices and production costs— — — 
Net change in future development costs— — — 
Sales and transfers of oil and natural gas produced, net of production expenses— — (2,063)
Extensions, discoveries, additions and improved recovery, net of related costs— — — 
Purchases of reserves in place— — — 
Sales of reserves in place— — (22,845)
Revisions of previous quantity estimates— — — 
Previously estimated development costs incurred— — — 
Net change in taxes— — 1,730 
Accretion of discount— — — 
Changes in timing and other— — — 
Balance at end of period$— $— $—