The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.

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

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and, therefore, may cause significant variability in cash flows from year to year as prices change.

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

We engaged CG&A to prepare our reserves estimates for all of our estimated proved reserves at December 31, 2022 and 2021. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:

(1)

The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2)

The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

The following tables set forth estimates of the net reserves for the periods indicated:


	For the Year Ended December 31, 2022
	Oil	Gas	NGLs	Total
	(MBbls)	(MMcf)	(MBbls)	(MBoe)
Proved developed and undeveloped reserves:
Beginning of year	45,001	314,350	23,837	121,230
Production	(2,327)	(22,993)	(1,389)	(7,548)
Revision of previous estimates	5,194	21,435	1,578	10,345
End of year	47,868	312,792	24,026	124,027

Proved developed reserves⁽¹⁾:
Beginning of year	43,857	309,794	23,574	119,063
End of year	47,010	312,185	23,928	122,969

Proved undeveloped reserves:
Beginning of year	1,144	4,556	263	2,167
End of year	858	607	98	1,058

(1)	Our reserves related to our Beta properties are classified as proved developed non-producing at December 31, 2022.


	For the Year Ended December 31, 2021
	Oil	Gas	NGLs	Total
	(MBbls)	(MMcf)	(MBbls)	(MBoe)
Proved developed and undeveloped reserves:
Beginning of year	46,676	274,139	21,484	113,849
Extensions and discoveries	746	4,283	215	1,674
Production	(3,351)	(23,808)	(1,430)	(8,747)
Sale of minerals in place	(3)	(274)	(12)	(61)
Revision of previous estimates	933	60,010	3,580	14,515
End of year	45,001	314,350	23,837	121,230

Proved developed reserves⁽¹⁾:
Beginning of period	35,613	252,218	19,009	96,658
End of period	43,857	309,794	23,574	119,063

Proved undeveloped reserves⁽²⁾:
Beginning of period	11,063	21,921	2,475	17,191
End of period	1,144	4,556	263	2,167

(1)	Our reserves related to our Beta properties were reclassified as proved developed non-producing at December 31, 2021.

(2)	Change to the Company’s development plan has resulted in removal of PUD locations in Oklahoma, Rockies and California.

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

●

The 2.8 MMBoe increase in reserves for the year ended December 31, 2022 is primarily due to 14.2 MMBoe increase as a result of changes in commodity prices. The Company also had a 4.1 MMBoe reduction due to higher maintenance costs and a 0.2 MMBoe upward technical revision. The Company had production of 7.5 MMBoe for the year ended December 31, 2022.

●

The 7.4 MMBoe increase in reserves for the year ended December 31, 2021 is primarily due to a 30.6 MMBoe increase as a result of changes in commodity pricing offset by a 16 MMBoe reduction due to removed PUD locations in Oklahoma, Rockies and California. The Company has shifted its resources to returning Beta to production and as a result has modified future PUD development plans. The Company also had 1.7 MMBoe of extension and discoveries primarily related to wells in progress at year end in Eagle Ford and East Texas, a 1.2 MMBoe reduction due to an increase in maintenance costs and a 0.9 MMBoe upward technical revision.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:


	For the Year Ended
	December 31,
	2022		2021

	(In thousands)
Future cash inflows	$	7,373,499	$	4,569,313
Future production costs (1)		(3,824,348)		(2,691,875)
Future development costs (1)		(309,188)		(231,040)
Future income tax expense		(520,731)		—
Future net cash flows for estimated timing of cash flows		2,719,232		1,646,398
10% annual discount for estimated timing of cash flows		(1,381,276)		(726,553)
Standardized measure of discounted future net cash flows	$	1,337,956	$	919,845

(1)

For the years ended December 31, 2022 and 2021, onshore abandonment costs are included in future production cost and offshore abandonment costs are included in future development costs.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two-year period presented:


	For the Year Ended
	December 31,
	2022		2021

	(In thousands)
Beginning of year	$	919,845	$	297,811
Changes in prices and costs		856,545		572,897
Net change in taxes		(311,412)		—
Sale of oil and natural gas produced, net of production costs		(213,667)		(171,326)
Accretion of discount		91,985		29,781
Change in production rates and other		(57,484)		(31,423)
Net changes in future development costs		(20,129)		113,546
Revisions of previous quantities		59,216		46,271
Previously estimated development costs incurred		13,057		45,298
Sale of minerals in place		—		(45)
Extensions and discoveries		—		17,035
End of year	$	1,337,956	$	919,845