The aggregate amount of capitalized costs of natural gas and oil properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

For the years ended September 30, the Company incurred the following costs in natural gas and oil producing activities:

The following unaudited information regarding the Company’s natural gas, oil and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved natural gas and oil reserves are those quantities of natural gas and oil which, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, prepared the Company’s natural gas, oil and NGL reserves estimates as of September 30, 2021, 2020 and 2019.

The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of September 30, 2021, 2020 and 2019, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Director of Engineering, Danielle Mezo. Ms. Mezo holds a Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Mezo has more than 10 years of experience in the oil and gas industry. Before joining the Company, Ms. Mezo held various reservoir engineering, reserves, acquisitions, corporate planning, and management positions at SandRidge Energy.

The Director of Engineering, and internal staff work closely with the Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. The Company provides historical information (such as ownership interest, gas and oil production, well test data, commodity prices, operating costs, handling fees and development costs) for all properties to the Independent Consulting Petroleum Engineers. Throughout the year, the Director of Engineering and internal staff meet regularly with representatives of the Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers (SPE)

entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, development plans and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves were estimated for locations that have been permitted, are currently drilling, are drilled but not yet completed, or locations where the operator has indicated to the Company its intention to drill.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas). Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.

Net quantities of proved, developed and undeveloped natural gas, oil and NGL reserves are summarized as follows:

	Proved Reserves
	Natural Gas			Oil			NGL			Total
	(Mcf)			(Barrels)			(Barrels)			Bcfe
September 30, 2018		120,062,036			5,984,422			2,934,190			173.6

Revisions of previous estimates		(35,644,135	)		(3,266,351	)		(890,046	)		(60.6	)
Acquisitions (divestitures)		(948,496	)		(322,023	)		(18,881	)		(3.0	)
Extensions, discoveries and other additions		3,891,262			313,241			164,276			6.8
Production		(7,086,761	)		(329,199	)		(216,259	)		(10.4	)
September 30, 2019		80,273,906			2,380,090			1,973,280			106.4

Revisions of previous estimates		(34,666,426	)		(1,094,923	)		(774,214	)		(45.9	)
Acquisitions (divestitures)		911,853			57,721			70,933			1.7
Extensions, discoveries and other additions		1,816,144			260,555			118,480			4.1
Production		(5,962,704	)		(269,786	)		(168,622	)		(8.6	)
September 30, 2020		42,372,773			1,333,657			1,219,857			57.7

Revisions of previous estimates		21,930,522			287,961			389,825			26.0
Acquisitions (divestitures)		6,994,423			79,576			36,911			7.7
Extensions, discoveries and other additions		354,670			28,125			26,748			0.7
Production		(6,699,720	)		(224,479	)		(171,488	)		(9.1	)
September 30, 2021		64,952,668			1,504,840			1,501,853			83.0

The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: September 30, 2021 - $2.79/Mcf, $56.51/Bbl, $20.58/Bbl; September 30, 2020 - $1.62/Mcf, $40.18/Bbl, $9.95/Bbl; September 30, 2019 - $2.48/Mcf, $54.40/Bbl, $19.30/Bbl.

The revisions of previous estimates from 2020 to 2021 were primarily the result of:

Extensions, discoveries and other additions from 2020 to 2021 are principally attributable to:

	Proved Developed Reserves						Proved Undeveloped Reserves
	Natural Gas		Oil		NGL		Natural Gas		Oil		NGL
	(Mcf)		(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)
September 30, 2019		67,713,193		1,863,096		1,747,242		12,560,713		516,994		226,038
September 30, 2020		40,924,083		1,148,989		1,135,864		1,448,690		184,668		83,993
September 30, 2021		60,287,881		1,439,860		1,467,092		4,664,787		64,980		34,761

The following details the changes in proved undeveloped reserves for 2021 (Mcfe):

During fiscal year 2021, total net PUD reserves increased by 2.2 Bcfe. In fiscal year 2021, a total of 2.1 Bcfe (67% of the beginning balance) was transferred to proved developed. The remaining balance of approximately 4.3 Bcfe (140% of the beginning balance) of positive revisions to PUD reserves consist of acquisitions of 4.6 Bcfe in the Haynesville Shale in Texas and Louisiana and Meramec and Woodford SCOOP play in Oklahoma, and additions and extensions of 0.2 Bcfe within the active drilling program areas of (i) STACK Meramec and Woodford in western Oklahoma, (ii) the SCOOP Woodford Shale in western Oklahoma and (iii) Bakken in North Dakota. These were slightly offset by negative revisions of 0.6 Bcfe resulting from permits that expired and were not renewed by the operator, as locations are only considered PUD if they are permitted, in progress, or drilled and uncompleted (DUC).

The Company anticipates that all current PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves, which are no longer projected to be drilled within five years from the date they were added to PUD reserves, will be removed as revisions at the time that determination is made. In the event that there are undrilled PUD locations at the end of the five-year period, the Company intends to remove the reserves associated with those locations from proved reserves as revisions.

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced, based on continuation of the economic conditions applied for such year.

Estimated future income taxes are computed using current statutory income tax rates, including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Company’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process.

	2021			2020			2019
Future cash inflows	$	297,138,886		$	134,179,216		$	366,697,321
Future production costs		(115,681,617	)		(66,136,222	)		(153,935,373	)
Future development and asset retirement costs		(1,873,126	)		(1,957,225	)		(1,917,937	)
Future income tax expense		(40,697,140	)		(13,224,535	)		(47,788,416	)
Future net cash flows		138,887,003			52,861,234			163,055,595

10% annual discount		(64,096,661	)		(21,727,081	)		(77,494,066	)
Standardized measure of discounted future net cash flows	$	74,790,342		$	31,134,153		$	85,561,529

Changes in the standardized measure of discounted future net cash flows are as follows:

	2021			2020			2019
Beginning of year	$	31,134,153		$	85,561,529		$	156,325,854
Changes resulting from:
Sales of natural gas, oil and NGL, net of production costs		(25,812,485	)		(12,692,681	)		(25,072,122	)
Net change in sales prices and production costs		43,951,090			(46,499,344	)		(76,588,460	)
Net change in future development and asset retirement costs		49,542			(20,571	)		43,607,535
Extensions and discoveries		803,714			2,841,807			7,074,245
Revisions of quantity estimates		33,482,964			(28,332,653	)		(60,308,497	)
Acquisitions (divestitures) of reserves-in-place		9,041,028			1,169,819			(3,134,783	)
Accretion of discount		3,893,028			11,039,792			20,457,930
Net change in income taxes		(13,937,867	)		17,037,980			23,413,194
Change in timing and other, net		(7,814,825	)		1,028,475			(213,367	)
Net change		43,656,189			(54,427,376	)		(70,764,325	)
End of year	$	74,790,342		$	31,134,153		$	85,561,529