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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2023
Extractive Industries [Abstract]  
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities
The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
 December 31,
 20232022
Oil and natural gas properties
Proved$1,538,724 $1,507,690 
Unproved11,197 11,516 
Total oil and natural gas properties1,549,921 1,519,206 
Less accumulated depreciation, depletion and impairment(1,393,801)(1,380,574)
Net oil and natural gas properties capitalized costs$156,120 $138,632 
Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development
Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
Year Ended December 31,
202320222021
Acquisitions of properties
Proved$11,232 $1,431 $3,545 
Unproved— — — 
Exploration (1)(46)809 905 
Development22,478 48,399 10,045 
Total cost incurred$33,664 $50,639 $14,495 
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(1)    Includes land, geological, geophysical and leasehold costs.
Results of Operations for Oil, Natural Gas and NGL Producing Activities
The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings.
Year Ended December 31,
202320222021
Revenues$148,641 $254,258 $168,882 
Expenses
Production costs53,099 57,221 46,309 
Depreciation and depletion15,657 11,542 9,372 
Total expenses68,756 68,763 55,681 
Income (loss) before income taxes79,885 185,495 113,201 
Income tax expense (benefit) (1)19,374 45,055 26,734 
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)$60,511 $140,440 $86,467 
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(1)    Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to (loss) income before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.
Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves
The summary below presents changes in the Company’s estimated reserves. NPB is included in 2021 and 2020.
OilNGLNatural GasTotal
 (MBbls)(MBbls)(MMcf) (1)MBoe
Proved developed and undeveloped reserves
As of December 31, 20208,485 11,245 102,893 36,879 
Revisions of previous estimates (2)3,627 14,924 148,736 43,340 
Acquisitions of new reserves135 438 5,235 1,446 
Sales of reserves in place(3,440)(28)(716)(3,587)
Production(957)(2,266)(21,417)(6,793)
As of December 31, 20217,850 24,313 234,731 71,285 
Revisions of previous estimates (2)971 2,825 25,841 8,102 
Acquisitions of new reserves39 65 528 192 
Extensions and discoveries510 227 2,823 1,208 
Production(949)(1,997)(21,101)(6,463)
As of December 31, 20228,421 25,433 242,822 74,324 
Revisions of previous estimates (2)(1,027)(8,200)(36,464)(15,304)
Acquisitions of new reserves453 379 5,474 1,745 
Extensions and discoveries283 357 3,431 1,211 
Sales of reserves in place(26)(49)(427)(147)
Production(1,047)(1,705)(20,403)(6,152)
As of December 31, 20237,057 16,215 194,433 55,677 
Proved developed reserves
As of December 31, 20208,485 11,245 102,893 36,879 
As of December 31, 20217,850 24,313 234,731 71,285 
As of December 31, 20228,421 25,433 242,822 74,324 
As of December 31, 20237,057 16,215 194,433 55,677 
Proved undeveloped reserves
As of December 31, 2020— — — — 
As of December 31, 2021— — — — 
As of December 31, 2022— — — — 
As of December 31, 2023— — — — 
Totals may not sum or recalculate due to rounding
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(1)    Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2)    Revisions include changes due to commodity prices, production costs, previous quantity estimates, and other commercial factors. Primary factor for revisions in years ended 2023, 2022 and 2021 were changes in SEC prices, among other factors. See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail.
Calculation of Weighted Average Per Unit Prices
The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
 At December 31,
 202320222021
Oil (per Bbl)$76.65 $93.73 $64.95 
Natural gas (per Mcf)$1.62 $4.76 $2.56 
NGL (per Bbl)$21.53 $33.42 $19.26 
Standardized Measure of Discounted Future Cash Flows
The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
December 31,
202320222021
Future cash inflows from production$1,204,568 $2,795,762 $1,579,734 
Future production costs (1)(627,715)(1,131,145)(735,904)
Future development costs (2)(39,288)(36,730)(66,732)
Future income tax expenses (3)— (17,780)— 
Undiscounted future net cash flows537,565 1,610,107 777,098 
10% annual discount(241,272)(803,242)(344,184)
Standardized measure of discounted future net cash flows $296,293 $806,865 $432,914 
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(1)    Consists of severance taxes, ad valorem taxes, and lease operating expenses.
(2)    Includes abandonment costs.
(3)    The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.
Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
Year Ended December 31,
202320222021
Beginning present value $806,865 $432,914 $104,986 
Changes during the year
Revenues less production(95,909)(197,419)(122,964)
Net changes in prices, production and other costs(372,897)465,116 380,026 
Development costs incurred645 846 83 
Net changes in future development costs (1,307)3,028 446 
Extensions and discoveries18,422 36,984 — 
Revisions of previous quantity estimates (1)(171,758)98,579 112,926 
Accretion of discount81,066 34,138 6,016 
Net change in income taxes3,798 (3,798)— 
Purchases of reserves in-place14,450 3,039 15,541 
Sales of reserves in-place(1,394)— (29,792)
Timing differences and other (2)14,312 (66,562)(34,354)
Net change for the year(510,572)373,951 327,928 
Ending present value (3) $296,293 $806,865 $432,914 
____________________
(1)     A significant portion of the revisions of previous quantity estimates is related to the decrease in pricing which affects well life and other economic factors. Performance revisions were positive. See Proved Reserves discussion.
(2)     The change in timing differences and other are related to revisions in the Company's estimated time of production and development.
(3)    Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.