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Supplemental Oil and Natural Gas Disclosures (Unaudited)
 12 Months Ended
Dec. 31, 2023
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, 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, 2023, 2022 and 2021 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. Because Exaro was acquired in 2021 as part of the Merger Transactions and subsequently sold in 2022, no values are presented for 2023 and 2022.


Developed and UndevelopedOil
(MBbls)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbls)		Total
(MBoe)
Consolidated operations
Net proved reserves at December 31, 2020167,190822,86455,324359,658
Revisions of previous estimates (1)
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 (2)
46,386451,70211,960133,630
Production(13,237)(89,455)(6,099)(34,245)
Developed and UndevelopedOil
(MBbls)		Natural Gas
(MMcf)		Natural Gas Liquids
(MBbls)		Total
(MBoe)
Net proved reserves at December 31, 2021210,1601,469,95376,493531,645
Revisions of previous estimates (3)
(18,859)(14,815)4,167(17,158)
Extensions, discoveries, and other additions (4)
37,20860,3127,75155,011
Sales of reserves in place(6,006)(19,365)(2,680)(11,915)
Purchases of reserves in place (5)
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 (6)
(15,501)(472,337)(11,676)(105,901)
Extensions, discoveries, and other additions (7)
2,80816,2401,6357,150
Sales of reserves in place(1,655)(15,075)(1,774)(5,942)
Purchases of reserves in place (8)
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
Equity affiliate
Net proved reserves at December 31, 2020————
Purchases of reserves in place20520,880—3,685
Production(1)(115)—(20)
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
————
Total company
Net proved reserves at December 31, 2021210,3641,490,71876,493535,310
Net proved reserves at December 31, 2022243,0821,506,53578,621572,793
Net proved reserves at December 31, 2023250,4651,176,416101,632548,166
(1)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.
(2)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.
(3)Revisions of previous estimates primarily relate to increased expected future costs driven by inflation and a higher commodity price environment.
(4)Extensions, discoveries and other additions of 55.0 MMBoe primarily relate to PUD extensions most of which related to our Eagle Ford asset.
(5)Purchases of reserves in place of 65.6 MMBoe primarily related to our Uinta Acquisition.
(6)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.
(7)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.
(8)Purchases of reserves in place of 134.6 MMBoe primarily related to our Western Eagle Ford Acquisitions.

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, 2023, 2022 and 2021:
Proved Developed Reserves

Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 2023176,546 1,032,578 87,316 435,958 
December 31, 2022160,113 1,398,770 66,803 460,046 
December 31, 2021158,091 1,404,570 66,402 458,588 
Equity affiliate
December 31, 2023— — — — 
December 31, 2022— — — — 
December 31, 2021204 20,765 — 3,665 
Proved Undeveloped Reserves

Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 202373,919 143,838 14,316 112,208 
December 31, 202282,969 107,765 11,818 112,747 
December 31, 202152,069 65,383 10,091 73,057 
Equity affiliate
December 31, 2023— — — — 
December 31, 2022— — — — 
December 31, 2021— — — — 

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, 2023 and 2022:

As of December 31,
20232022
(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method)$8,574,478 $7,113,819 
Unproved oil and natural gas properties283,324 314,255 
Oil and natural gas properties, at cost8,857,802 7,428,074 
Less: accumulated depreciation, depletion, amortization and impairment(2,865,095)(2,102,286)
Net capitalized costs$5,992,707 $5,325,788 
Equity affiliate
Net capitalized costs$— $— 

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

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. 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, 2023, 2022 and 2021:
Year Ended December 31,
202320222021
(in thousands)
Consolidated operations
Acquisition costs:
Proved$836,159 $793,081 $1,098,696 
Unproved35,474 71,387 41,355 
Field and other property and equipment— 8,200 — 
Exploration costs9,328 3,425 1,180 
Development578,316 624,880 194,828 
Total costs incurred$1,459,277 $1,500,973 $1,336,059 
Equity affiliate
Total costs incurred$— $— $— 

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, 2023, 2022 and 2021 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,
202320222021
Average benchmark price per unit:
Crude oil (Bbl)$78.22 $93.67 $66.56 
Natural gas (MMBtu)$2.64 $6.36 $3.60 

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, 2023, 2022 and 2021:
Year Ended December 31,
202320222021
(in thousands)
Consolidated operations
Future cash inflows$24,267,134 $33,628,495 $21,063,117 
Future production costs(11,897,791)(14,077,136)(10,194,648)
Future development costs (1)
(2,713,247)(2,380,931)(1,477,562)
Future income taxes (3)
(410,721)(773,479)(352,136)
Future net cash flows9,245,375 16,396,949 9,038,771 
Annual discount of 10% for estimated timing
(3,956,193)(7,262,283)(4,080,471)
Standardized measure of discounted future net cash flows$5,289,182 $9,134,666 $4,958,300 
Equity affiliate (2)
Future cash inflows$— $— $99,290 
Future production costs— — (55,371)
Future development costs— — (2,309)
Future income taxes— — (1,730)
Future net cash flows— — 39,880 
Annual discount of 10% for estimated timing
— — (16,702)
Standardized measure of discounted future net cash flows$— $— $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 during the year ended December 31, 2021. During the year ended December 31, 2022, our equity method investment, Exaro, sold its operations.
(3)    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, 2023, 2022 and 2021 was 51.0%, 28.9% and 24.8%, 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, 2023, 2022 and 2021:
Year Ended December 31,
202320222021
(in thousands)
Consolidated operations
Balance at beginning of period$9,134,666 $4,958,300 $1,327,860 
Net change in prices and production costs(2,859,297)4,156,736 3,330,299 
Net change in future development costs(141,382)(132,213)117,333 
Sales and transfers of oil and natural gas produced, net of production expenses
(1,354,856)(2,083,147)(872,521)
Extensions, discoveries, additions and improved recovery, net of related costs119,025 1,105,549 162,657 
Purchases of reserves in place1,338,224 1,333,452 1,236,388 
Sales of reserves in place(90,157)(118,253)(84,095)
Revisions of previous quantity estimates(2,244,012)(952,958)(295,234)
Previously estimated development costs incurred301,839 488,934 95,879 
Net change in taxes190,444 (251,714)(184,419)
Accretion of discount960,208 575,440 124,153 
Changes in timing and other(65,520)54,540 — 
Balance at end of period$5,289,182 $9,134,666 $4,958,300 
Equity affiliate
Balance at beginning of period$— $23,178 $— 
Net change in prices and production costs— — — 
Net change in future development costs— — — 
Sales and transfers of oil and natural gas produced, net of production expenses— (2,063)(1,246)
Extensions, discoveries, additions and improved recovery, net of related costs— — — 
Purchases of reserves in place— — 26,154 
Sales of reserves in place— (22,845)— 
Revisions of previous quantity estimates— — — 
Previously estimated development costs incurred— — — 
Net change in taxes— 1,730 (1,730)
Accretion of discount— — — 
Changes in timing and other— — — 
Balance at end of period$— $— $23,178