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.

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 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,
	2023		2022
	(In thousands)
Oil, natural gas and NGL sales	$	372,647	$	319,343
Lease operating expenses	58,817		32,458

Production and ad valorem taxes	25,559		19,273
Exploration costs	4,165		2,032
Depletion, accretion and amortization	64,471		31,500
Impairment of oil and natural gas properties	9,760		7,325
Results of operations	209,875		226,755
Income tax expense (1)	(44,493)		(48,957)
Results of operations, net of income tax expense	$	165,382	$	177,798

_____________________

Our reserve report for the year ended December 31, 2023 was prepared by Ryder Scott Company, L.P. For the year ended December 31, 2022, our reserve report was prepared by Netherland, Sewell & Associates, Inc. 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:


	Oil	Natural Gas	NGLs	Total
	(MBbl)	(MMcf)	(MBbl)	(MBoe)

December 31, 2021	47,021	77,486	13,471	73,407
Extensions and discoveries	9,949	13,178	2,651	14,796
Revisions	(4,871)	(1,417)	(1,224)	(6,331)
Production	(3,217)	(3,229)	(444)	(4,199)
December 31, 2022	48,882	86,018	14,454	77,673
Acquisitions	12,810	39,261	6,711	26,064
Extensions and discoveries	14,822	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, 2023	66,308	123,948	20,749	107,715

Proved Developed Reserves, Included Above
December 31, 2021	27,096	47,974	7,949	43,041
December 31, 2022	29,632	59,314	9,604	49,122
December 31, 2023	36,731	71,671	11,502	60,178

Proved Undeveloped Reserves, Included Above
December 31, 2021	19,925	29,512	5,522	30,366
December 31, 2022	19,250	26,704	4,850	28,551
December 31, 2023	29,577	52,277	9,247	47,537

As of December 31, 2023, 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 ("SEC price") January 2023 through December 2023. For oil and NGL volumes, the average West Texas Intermediate ("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.

As of December 31, 2022, reserves were comprised of 62.9% oil, 18.5% natural gas and 18.6% NGL. 2022 proved reserves were estimated based on prices of $91.96 per Bbl of oil, $3.16 per Mcf of natural gas and $25.55 per Bbl of NGL. Prices used in the 2022 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 2022 through December 2022. For oil and NGL volumes, the average WTI SEC price of $94.14 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 $6.36 per MMBtu is adjusted for energy content, transportation fees and market differentials.

For the year ended December 31, 2023, the Company 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 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, which are primarily attributable to the removal of PUDs due to changes in the Company's development schedule. Consistent with SEC guidelines, PUDs are limited to those locations that are reasonably certain to be developed within five years.

For the year ended December 31, 2022, the Company had downward revisions of previous estimates of 6.3 MMBoe. These revisions are primarily the result of changes in certain well level projections and higher projected operating costs. The Company had extensions and discoveries to proved reserves of 14.8 MMBoe, which consisted of 7.8 MMBoe added to PDP as a result of drilling successful wells that were previously classified as unproved locations, and 7.0 MMBoe added to PUDs as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended December 31, 2022, the Company did not acquire any 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.


	Year Ended December 31,
	2023		2022
	(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)	$	5,244,927	$	5,135,650
Future production costs	(1,896,397)		(1,559,266)
Future development costs	(362,218)		(341,481)
Future income tax expense	(538,926)		(658,340)
Future net cash flows	2,447,386		2,576,563
10% annual discount	(1,186,921)		(1,468,187)
Standardized measure of discounted future net cash flows	$	1,260,465	$	1,108,376

_____________________

Principal sources of change in the Standardized Measure are shown below:


	Year Ended December 31,
	2023		2022
	(In thousands)
Balance, beginning of period	$	1,108,376	$	703,469
Sales of crude oil, natural gas and NGLs, net	(288,270)		(267,612)
Net change in prices and production costs	(618,441)		406,803
Net changes in future development costs	21,423		(40,226)
Extensions and discoveries	385,482		321,009
Acquisition of reserves	613,295		—
Revisions of previous quantity estimates	(188,364)		(83,188)
Previously estimated development costs incurred	31,124		8,775
Net change in income taxes	(5,976)		(117,098)
Accretion of discount	140,115		87,914
Other	61,701		88,530
Balance, end of period	$	1,260,465	$	1,108,376