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, including development wells in progress.

Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory 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.

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. For the year ended September 30, 2020, they also do not include estimated corporate taxes since the Company was not a taxpaying entity for federal income tax purposes. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.


	Years Ended September 30,
	2021		2020
	(In thousands)
Oil, natural gas and NGL sales	$	148,636	$	73,133
Lease operating expenses	21,975		20,243

Production and ad valorem taxes	8,636		4,280
Exploration costs	9,566		9,923
Depletion, accretion and amortization	25,347		20,936
Results of operations	83,112		17,751
Income tax expense (1)	(13,505)		—
Results of operations, net of income tax expense	$	69,607	$	17,751

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(1) Subsequent to the Closing Date of the Merger, the statutory combined federal and state tax rate of 21.59% is used. Prior to the Closing Date of the Merger and for the year ended September 30, 2020, the Company was a flow-through entity for federal income tax purposes. As such, no taxes are reflected here as taxable income was passed through to its members.

Our reserve reports, as of September 30, 2021 and 2020, 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 years ended September 30, 2021 and 2020 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, 2019	37,159	40,991	10,812	54,803
Extensions and discoveries	2,265	3,030	642	3,412
Revisions	(206)	11,290	(513)	1,163
Production	(2,060)	(1,628)	(260)	(2,591)
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

Proved Developed Reserves, Included Above
September 30, 2019	19,198	23,096	6,045	29,092
September 30, 2020	19,149	31,137	5,847	30,186
September 30, 2021	26,170	46,173	7,650	41,516

Proved Undeveloped Reserves, Included Above
September 30, 2019	17,961	17,895	4,767	25,711
September 30, 2020	18,009	22,546	4,834	26,601
September 30, 2021	20,093	29,846	5,579	30,647

As of September 30, 2021, reserves were comprised of 64.1% oil, 17.6% natural gas and 18.3% NGL. 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 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.

As of September 30, 2020, reserves were comprised of 65.4% oil, 15.8% natural gas and 18.8%% NGL. 2020 proved reserves were estimated based on prices of $41.91 per Bbl of oil, $(0.06) per Mcf of natural gas and $(1.96) per Bbl of NGL. Prices used in the 2020 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 2019 through September 2020. For oil and NGL volumes, the average WTI spot price of $43.63 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 $1.97 per MMBtu is adjusted for energy content, transportation fees and market differentials.

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 fiscal year in 2021, the Company did not purchase any additional reserves.

For the year ended September 30, 2020, the Company had upward revisions of previous estimates of 1,163 MBoe. These revisions consisted of a positive revision of 1,840 MBoe due to pricing and differentials, a downward revision of 1,952 MBoe due to lease operating expenses and a positive revision of 1,275 MBoe which was the result of better well performance that exceeded previous estimates. The Company had extensions and discoveries to proved developed and proved non-developed

reserves of 3,412 MBoe which consisted of 1,404 MBoe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 2,008 MBoe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the year ended September 30, 2020, 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.


	September 30,
	2021		2020
	(In thousands)
Future crude oil, natural gas and NGLs sales (1) (2)	$	2,783,910	$	1,533,286
Future production costs	(839,167)		(550,427)
Future development costs	(218,765)		(144,912)
Future income tax expense (3)	(324,487)		(3,167)
Future net cash flows	1,401,491		834,780
10% annual discount	(848,555)		(532,442)
Standardized measure of discounted future net cash flows	$	552,936	$	302,338

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(3) The Company's calculations of the standardized measure of discounted future net cash flows as of September 30, 2020 included the Company’s obligation for Texas Margin Tax but excluded the effect of estimated future income tax expenses as the Company was a limited liability company and not subject to income taxes.