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Supplemental Oil and Gas Information (Unaudited)
 12 Months Ended
Dec. 31, 2024
Extractive Industries [Abstract]  
Supplemental Oil and Gas Information (Unaudited) Supplemental Oil and Gas Information (Unaudited)
Capitalized Costs
Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities.
Capitalized costs for unproved properties include costs for acquiring or extending oil and natural gas leaseholds where no proved reserves have been identified. Work in progress include costs of exploratory and development wells that are in the process of drilling or in active completion, and costs of exploratory and development wells suspended or waiting on completion. For a summary of these costs, please refer to Note 5 – Oil and Natural Gas Properties.
Costs Incurred for Property Acquisition, Exploration and Development
Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include ARO established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities.
The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the periods presented below:
Year Ended December 31,
20242023
(In thousands)
Acquisition of properties
Proved$4,592 $228,147 
Unproved16,641 102,742 
Exploration costs— — 
Development costs106,773 152,309 
Total costs incurred$128,006 $483,198 
Results of Operations
The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. They do not include any allocation of the Company's interest costs or general corporate overhead. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.
Year Ended December 31,
20242023
(In thousands)
Oil, natural gas and NGL sales$409,801 $372,647 
Lease operating expenses71,463 58,817 
Production and ad valorem taxes29,42825,559
Exploration costs2,5954,165
Depletion, accretion and amortization74,02564,471
Impairment of oil and natural gas properties11,317 9,760 
Other impairments30,158 — 
Results of operations$190,815 $209,875 
Income tax expense (1)
(43,105)(44,493)
Results of operations, net of income tax expense$147,710 $165,382 
_____________________
(1)    The statutory combined federal and state tax rate of 22.59% and 21.20% is used for the years ended December 31, 2024, and 2023, respectively.
Oil, Natural Gas and NGL Quantities
Our reserve report for the year ended December 31, 2024, and 2023, was prepared by Ryder Scott Company, L.P. All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL 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. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. 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 natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
The following table sets forth information for the periods below with respect to changes in the Company’s proved (i.e., proved developed and undeveloped) reserves:
OilNatural GasNGLsTotal
(MBbl)(MMcf)(MBbl)(MBoe)
December 31, 202248,882 86,018 14,454 77,673 
Acquisitions
12,810 39,261 6,711 26,064 
Extensions and discoveries14,822 22,945 4,224 22,870 
Revisions(5,403)(18,411)(3,634)(12,106)
Production(4,803)(5,865)(1,006)(6,786)
December 31, 202366,308 123,948 20,749 107,715 
Acquisitions
1,989 6,624 1,176 4,269 
Extensions and discoveries8,894 17,218 3,837 15,600 
Revisions(5,137)21,933 5,751 4,270 
Production(5,519)(7,484)(1,486)(8,252)
December 31, 202466,535 162,239 30,027 123,602 
Proved Developed Reserves, Included Above
December 31, 202229,632 59,314 9,604 49,122 
December 31, 202336,731 71,671 11,502 60,178 
December 31, 202440,111 103,337 19,312 76,646 
Proved Undeveloped Reserves, Included Above
December 31, 202219,250 26,704 4,850 28,551 
December 31, 202329,577 52,277 9,247 47,537 
December 31, 202426,424 58,902 10,715 46,956 
As of December 31, 2024, proved reserves were comprised of 53.8% oil, 21.9% natural gas and 24.3% NGL. 2024 proved reserves were estimated based on average realized prices of $74.27 per Bbl of oil, $(0.43) per Mcf of natural gas and $(3.56) per Bbl of NGL. Prices used in the 2024 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period ("SEC price") January 2024 through December 2024. For oil and NGL volumes, the average WTI SEC price of $76.32 per Bbl was adjusted for quality, transportation fees, and market differentials which were included as a deduction to oil revenue. For gas volumes, the average Henry Hub SEC price of $2.13 per MMBtu is adjusted for energy content, transportation fees and market differentials which were included as a deduction to natural gas revenue.
As of December 31, 2023, proved reserves were comprised of 61.5% oil, 19.2% natural gas and 19.3% NGL. 2023 proved reserves were estimated based on average realized prices of $76.02 per Bbl of oil, $0.46 per Mcf of natural gas and $7.11 per Bbl of NGL. Prices used in the 2023 reserve report are based on the twelve month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January 2023 through December 2023. For oil and NGL volumes, the average WTI SEC price of $78.22 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub SEC price of $2.64 per MMBtu is adjusted for energy content, transportation fees and market differentials.
For the year ended December 31, 2024, the Company added 15.9 MMBoe of proved reserves, with such additions due to extensions and discoveries, positive revisions and acquisitions, partially offset by production. The Company had acquisitions of 4.3 MMBoe primarily as a result of acquired reserves in an acreage swap and the 2024 New Mexico Asset Acquisition and extensions and discoveries of proved reserves of 15.6 MMBoe, which consisted of 7.7 MMBoe added to PDPs as a result of drilling successful wells that were previously classified as unproved locations and 7.9 MMoe added to PUDs as a result of drilling activity during the year, which allowed for the booking of adjacent PUDs for locations that were previously booked as unproved reserves or not at all. The Company had upward revisions of previous estimates of 4.3 MMBoe, including 15.3 MMBoe of positive revisions which were partially offset by 11.0 MMBoe of negative revisions. Our positive revisions were primarily due to increased forecasted natural gas sales volumes of 9.2 MMBoe based on improved gas processing capacity in
addition to a decrease in operating expenses and midstream fees that caused positive revisions of 6.1 MMBoe. These positive revisions were partially offset by negative revisions which included development plan changes driven by shifting focus to more profitable areas of our assets, which resulted in the removal of PUD locations representing 4.2 MMBoe of PUD reserves from our 5-year forecast, 2.6 MMBoe due to type curve updates, 2.0 MMBoe due to interest changes, 1.5 MMBoe due to lower commodity prices and 0.7 MMBoe due to reserve category changes. Consistent with Securities and Exchange Commission ("SEC") guidelines, PUDs are limited to those locations that are reasonably certain to be developed within five years.
For the year ended December 31, 2023, the Company had added 30.0 MMBoe of proved reserves, with such additions due to acquisitions and extensions and discoveries, partially offset by negative revisions and production. The Company had acquisitions of 26.1 MMBoe primarily as a result of the 2023 New Mexico Acquisition and extensions and discoveries to proved reserves of 22.9 MMBoe, which consisted of 8.3 MMBoe added to PDP as a result of drilling successful wells that were previously classified as unproved locations, and 14.6 MMBoe added to PUDs as a result of drilling successful wells offsetting locations that were previously unproven locations. The Company had downward revisions of previous estimates of 12.1 MMBoe, including 19.3 MMBoe of negative revisions which were partially offset by 7.2 MMBoe of positive revisions. Our negative revisions included development plan changes, driven by the 2023 New Mexico acquisition, which resulted in the removal of PUD locations representing 6.7 MMBoe of PUD reserves from our 5-year forecast, 6.3 MMBoe from lower forecasted natural gas sales volumes due to estimated limitations on processing capacity, 2.9 MMBoe due to lower commodity prices, 2.4 MMBoe due to increased operating expenses, 0.7 MMBoe due to the removal of uneconomic locations and 0.3 MMBoe from other minor revisions. Positive revisions included 7.2 MMBoe due to changes in well forecasts based on improved well performance from producing wells.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves
The Company follows the guidelines prescribed in ASC Topic 932 Extractive Activities – Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (i) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (ii) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves; (iii) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (iv) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (v) future net cash flows are discounted to present value by applying a discount rate of 10%.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. 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 natural gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:
Year Ended December 31,
20242023
(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)
$4,764,599 $5,244,927 
Future production costs(1,638,032)(1,896,397)
Future development costs(325,414)(362,218)
Future income tax expense (524,581)(538,926)
Future net cash flows2,276,572 2,447,386 
10% annual discount(1,034,771)(1,186,921)
Standardized measure of discounted future net cash flows$1,241,801 $1,260,465 
_____________________
(1)    December 31, 2024, proved reserves were derived based on average realized prices of $74.27 per barrel of oil, $(0.43) per Mcf of natural gas and $(3.56) per barrel of NGL.
(2)    December 31, 2023, proved reserves were derived based on average realized prices of $76.02 per barrel of oil, $0.46 per Mcf of natural gas and $7.11 per barrel of NGL.

Principal sources of change in the Standardized Measure are shown below:
Year Ended December 31,
20242023
(In thousands)
Balance, beginning of period$1,260,465 $1,108,376 
Sales of crude oil, natural gas and NGLs, net(308,907)(288,270)
Net change in prices and production costs(238,938)(618,441)
Net changes in future development costs9,976 21,423 
Extensions and discoveries253,381 385,482 
Acquisition of reserves47,020 613,295 
Revisions of previous quantity estimates71,800 (188,364)
Previously estimated development costs incurred38,858 31,124 
Net change in income taxes(2,035)(5,976)
Accretion of discount158,406 140,115 
Other(48,225)61,701 
Balance, end of period$1,241,801 $1,260,465