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 new 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.


	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Acquisition of properties
Proved	$	450	$	67	$	74
Unproved	1,468		193		1,562
Exploration costs	157		—		7,993
Development costs	119,673		20,348		59,948
Total costs incurred	$	121,748	$	20,608	$	69,577

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, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Oil, natural gas and NGL sales	$	319,343	$	56,650	$	148,636
Lease operating expenses	32,458		7,419		21,975

Production and ad valorem taxes	19,273		3,005		8,636
Exploration costs	2,032		611		9,566
Depletion, accretion and amortization	31,500		6,742		25,347
Impairment of oil and natural gas properties	7,325		—		—
Results of operations	226,755		38,873		83,112
Income tax expense (1)	48,957		(8,393)		(13,505)
Results of operations, net of income tax expense	$	275,712	$	30,480	$	69,607

_____________________________________________________

Our reserve reports, as of the year ended December 31, 2022, three months ended December 31, 2021, and year ended September 30, 2021, were prepared by Netherland, Sewell & Associates, Inc. and are presented below. 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)

September 30, 2020	37,158	53,683	10,681	56,787
Extensions and discoveries	9,308	12,089	2,436	13,759
Revisions	2,138	12,850	492	4,772
Production	(2,341)	(2,603)	(380)	(3,155)
September 30, 2021	46,263	76,019	13,229	72,163
Extensions and discoveries	1,328	1,961	371	2,026
Revisions	99	350	(24)	133
Production	(669)	(844)	(105)	(915)
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

Proved Developed Reserves, Included Above
September 30, 2021	26,170	46,173	7,650	41,516
December 31, 2021	27,096	47,974	7,949	43,041
December 31, 2022	29,632	59,314	9,604	49,122

Proved Undeveloped Reserves, Included Above
September 30, 2021	20,093	29,846	5,579	30,647
December 31, 2021	19,925	29,512	5,522	30,366
December 31, 2022	19,250	26,704	4,850	28,551

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 West Texas Intermediate ("WTI") spot 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 spot price of $6.36 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of December 31, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. December 31, 2021 proved reserves were estimated based on prices of $64.60 per Bbl of oil, $1.65 per Mcf of natural gas and $13.75 per Bbl of NGL. Prices used in the December 31, 2021 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 2021 through December 2021. For oil and NGL volumes, the average WTI spot price of $66.55 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 spot price of $3.60 per MMBtu is adjusted for energy content, transportation fees and market differentials.

As of September 30, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. September 30, 2021 proved reserves were estimated based on prices of $55.73 per Bbl of oil, $0.99 per Mcf of natural gas and $9.83 per Bbl of NGL. Prices used in the September 30, 2021 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 October 2020 through September 2021. For oil and NGL volumes, the average WTI spot price of $57.64 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 spot price of $2.94 per MMBtu is adjusted for energy content, transportation fees and market differentials.

For the year ended December 31, 2022, the Company had downward revisions of previous estimates of 6,331 MBoe. These revisions are primarily the result of changes in well level projections in certain undeveloped areas and increases in service costs. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 14,796 MBoe which consisted of 7,759 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,037 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the fiscal year in 2022, the Company did not purchase any additional reserves.

For the three months ended December 31, 2021, the Company had net upward revisions of previous estimates of 133 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 2,026 MBoe as a result of drilling successful wells that were previously classified as unproved locations. During the three months ended December 31, 2021, the Company did not purchase any additional reserves.

For the year ended September 30, 2021, the Company had upward revisions of previous estimates of 4,772 MBoe. These revisions are primarily the result of increases in pricing. The Company had extensions and discoveries to proved developed and proved non-developed reserves of 13,759 MBoe which consisted of 6,564 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 7,195 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended September 30, 2021, the Company did not purchase any additional 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 crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for 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 Securities and Exchange Commission. 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, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Future crude oil, natural gas and NGLs sales (1)(2)(3)	$	5,135,650	$	3,350,506	$	2,783,910
Future production costs	(1,559,266)		(912,468)		(839,167)
Future development costs	(341,481)		(216,138)		(218,765)
Future income tax expense	(658,340)		(436,829)		(324,487)
Future net cash flows	2,576,563		1,785,071		1,401,491
10% annual discount	(1,468,187)		(1,081,602)		(848,555)
Standardized measure of discounted future net cash flows	$	1,108,376	$	703,469	$	552,936

_____________________________________________________

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


	Year Ended December 31, 2022		Three Months Ended December 31, 2021		Year Ended September 30, 2021
	(In thousands)
Balance, beginning of period	$	703,469	$	552,936	$	302,338
Sales of crude oil, natural gas and NGLs, net	(267,612)		(46,226)		(118,030)
Net change in prices and production costs	406,803		194,596		237,475
Net changes in future development costs	(40,226)		1,267		(18,856)
Extensions and discoveries	321,009		35,111		144,392

Revisions of previous quantity estimates	(83,188)		(536)		50,283
Previously estimated development costs incurred	8,775		4,182		12,844
Net change in income taxes	(117,098)		(47,881)		(124,625)
Accretion of discount	87,914		17,018		30,551
Other	88,530		(6,998)		36,564
Balance, end of period	$	1,108,376	$	703,469	$	552,936