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Supplementary Information On Natural Gas, Oil And NGL Reserves

12 Months Ended

Dec. 31, 2023

Supplementary Information On Natural Gas, Oil And NGL Reserves

SUPPLEMENTARY INFORMATION ON NATURAL GAS, OIL AND NGL RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of natural gas and oil properties and related accumulated depreciation, depletion and amortization as of December 31, 2023 and September 30, 2022 is as follows:


	December 31,			September 30,
	2023			2022
Producing properties	$	209,082,847		$	248,978,928
Non-producing minerals		56,670,341			50,032,539
Non-producing leasehold		2,150,104			1,746,797
		267,903,292			300,758,264
Accumulated depreciation, depletion and amortization		(113,506,928	)		(168,349,542	)
Net capitalized costs	$	154,396,364		$	132,408,722

Costs Incurred

For the year ended December 31, 2023, three months ended December 31, 2022, and year ended September 30, 2022, the Company incurred the following costs in natural gas and oil producing activities:


	Year Ended		Three Months Ended		Year Ended
	December 31, 2023		December 31, 2022		September 30, 2022
Property acquisition costs	$	30,435,595	$	14,637,290	$	46,224,928
Development costs		113,967		36,801		156,752
	$	30,549,562	$	14,674,091	$	46,381,680

Estimated Quantities of Proved Natural Gas, Oil and NGL Reserves

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 Cawley, Gillespie and Associates, Inc. (CG&A) of Fort Worth, Texas, prepared the Company’s natural gas, oil and NGL reserves estimates as of December 31, 2023, December 31, 2022, and September 30, 2022.

The Company’s net proved natural gas, oil and NGL reserves, which are located in the contiguous United States, as of December 31, 2023, December 31, 2022, and September 30, 2022, 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 the Company’s Vice President of Engineering. The Vice President 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 Vice President 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, 2021		64,952,668			1,504,840			1,501,853			83.0

Revisions of previous estimates		2,405,959			(13,498	)		409,597			4.8
Acquisitions		15,302,364			29,987			18,260			15.6
Divestitures		(16,624,066	)		(72,244	)		(83,931	)		(17.6	)
Extensions, discoveries and other additions		3,627,989			132,227			82,024			4.9
Production		(7,427,708	)		(198,535	)		(165,120	)		(9.6	)
September 30, 2022		62,237,206			1,382,777			1,762,683			81.1

Revisions of previous estimates		(3,126,679	)		(31,388	)		(31,989	)		(3.5	)
Acquisitions		1,424,204			8,179			7,370			1.5
Divestitures		(131,497	)		-			(7,861	)		(0.2	)
Extensions, discoveries and other additions		2,471,579			64,844			16,983			3.0
Production		(1,669,320	)		(52,406	)		(38,611	)		(2.2	)
December 31, 2022		61,205,493			1,372,006			1,708,575			79.7

Revisions of previous estimates		(4,997,247	)		29,514			(86,414	)		(5.3	)
Acquisitions		7,322,724			35,228			20,361			7.7
Divestitures		(7,296,462	)		(340,265	)		(145,231	)		(10.2	)
Extensions, discoveries and other additions		7,211,533			158,395			102,849			8.8
Production		(7,457,084	)		(182,916	)		(137,484	)		(9.4	)
December 31, 2023		55,988,957			1,071,962			1,462,656			71.2

The prices used to calculate reserves and future cash flows from reserves for natural gas, oil and NGL, respectively, were as follows: December 31, 2023 - $2.67/Mcf, $76.85/Bbl, $21.98/Bbl; December 31, 2022 - $6.52/Mcf, $92.74/Bbl, $39.18/Bbl; September 30, 2022 - $6.41/Mcf, $90.33/Bbl, $38.09/Bbl.

The changes in reserves at December 31, 2022, as compared to September 30, 2022, are attributable to:

Revisions of previous estimates from September 30, 2022 to December 31, 2022 that were primarily the result of

•

Negative pricing revisions of 1.4 Bcfe due to a four well pad that did not reach the permitted lateral length when drilled in the Haynesville Shale, therefore reducing royalty interest in each well, and permit expirations, as our PUD reserves consist only of wells that are permitted, drilling, or waiting on completion.

•

Negative performance revisions of 2.1 Bcfe principally due to the shut in of a significant working interest well in the SCOOP play in the Ardmore basin of Oklahoma, and (i) wells located in an area with gas takeaway constraints located in the Haynesville Shale play of Louisiana and (ii) wells drilled in the last two years in the Haynesville play of Texas.

Acquisitions and divestitures were the result of

•

The sale of 0.2 Bcfe proved developed, consisting predominately of working interest properties in the Arkoma Stack play in Oklahoma.

•

The acquisition of 1.5 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 0.5 Bcfe were proved developed and 1.0 Bcfe were proved undeveloped.

Extensions, discoveries and other additions from September 30, 2022 to December 31, 2022 that are principally attributable to

•

Reserve extensions, discoveries and other additions of 3.0 Bcfe (comprised of 0.3 Bcfe proved developed and 2.7 Bcfe proved undeveloped reserves) principally resulting from:

The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana.

The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, oil and NGL utilizing horizontal drilling in the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma.

And production of 2.2 Bcfe from the Company’s natural gas and oil properties.

The changes in reserves at December 31, 2023, as compared to December 31, 2022, are attributable to:

Revisions of previous estimates from December 31, 2022 to December 31, 2023 that were primarily the result of

•

Negative pricing revisions of 4.8 Bcfe due to natural gas and oil wells reaching their economic limits earlier than was projected in 2022 due to lower commodity prices.

•

Negative performance revisions of 0.5 Bcfe principally due to steeper decline and lower than expected volumes in wells located in an area with gas takeaway constraints located in the Haynesville Shale.

Acquisitions and divestitures were the result of

•

The sale of 10.2 Bcfe proved developed, consisting predominately of working interest properties in the Eagle Ford Shale play in Texas and the Arkoma Stack play and Western Anadarko Basin in Oklahoma.

•

The acquisition of 7.7 Bcfe, predominately of royalty interest properties in the active drilling programs of the Haynesville Shale play in east Texas and western Louisiana and the Mississippi and Woodford Shale intervals in the SCOOP play in the Ardmore basin of Oklahoma, of which 3.4 Bcfe were proved developed and 4.3 Bcfe were proved undeveloped.

Extensions, discoveries and other additions from December 31, 2022 to December 31, 2023 that are principally attributable to

•

Reserve extensions, discoveries and other additions of 8.8 Bcfe (comprised of 1.0 Bcfe proved developed and 7.8 Bcfe proved undeveloped reserves) principally resulting from:

The Company’s royalty interest ownership in the ongoing development of unconventional natural gas, utilizing horizontal drilling, in the Haynesville Shale play of East Texas and Western Louisiana.

And production of 9.4 Bcfe from the Company’s natural gas and oil properties.


	Proved Developed Reserves						Proved Undeveloped Reserves
	Natural Gas		Oil		NGL		Natural Gas		Oil		NGL
	(Mcf)		(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)
September 30, 2022		50,304,185		1,275,853		1,698,046		11,933,021		106,924		64,637
December 31, 2022		48,596,944		1,253,838		1,660,439		12,608,549		118,168		48,136
December 31, 2023		44,479,988		937,465		1,362,944		11,508,969		134,497		99,712

The following details the changes in proved undeveloped reserves for 2023 (Mcfe):


Beginning proved undeveloped reserves	13,606,373
Proved undeveloped reserves transferred to proved developed	(12,328,750	)
Revisions	(471,393	)
Extensions and discoveries	7,819,628
Sales	-
Purchases	4,288,365
Ending proved undeveloped reserves	12,914,223

During fiscal year 2023, total net PUD reserves decreased by 0.7 Bcfe. In fiscal year 2023, a total of 12.3 Bcfe (91% of the beginning balance) was transferred to proved developed. The remaining balance of approximately 11.6 Bcfe (86% of the beginning balance) of positive revisions to PUD reserves consist of acquisitions of 4.3 Bcfe in the Haynesville Shale in Texas and Louisiana and Meramec and Woodford SCOOP play in Oklahoma, additions and extensions of 7.8 Bcfe within the active drilling program areas of (i) the Haynesville Shale in Texas and Louisiana, (ii) the SCOOP Meramec and Woodford in Oklahoma, (iii) the STACK Meramec and Woodford in Oklahoma and (iv) the Bakken in North Dakota, and negative revisions of 0.5 Bcfe primarily due to permit expirations, as our PUD reserves consist only of wells that are permitted, drilling, or waiting on completion.

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 will remove the reserves associated with those locations from proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

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.


	Year Ended			Three Months Ended			Year Ended
	December 31, 2023			December 31, 2022			September 30, 2022
Future cash inflows	$	264,083,714		$	592,958,683		$	591,082,414
Future production costs		(67,959,181	)		(128,291,757	)		(131,377,260	)
Future development and asset retirement costs		(1,224,333	)		(2,531,896	)		(2,543,510	)
Future income tax expense		(18,437,730	)		(82,500,751	)		(107,209,614	)
Future net cash flows		176,462,470			379,634,279			349,952,030

10% annual discount		(76,071,084	)		(182,144,644	)		(167,382,649	)
Standardized measure of discounted future net cash flows	$	100,391,386		$	197,489,635		$	182,569,381

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


	Year Ended			Three Months Ended			Year Ended
	December 31, 2023			December 31, 2022			September 30, 2022
Beginning of year	$	197,489,635		$	182,569,381		$	74,790,342
Changes resulting from:
Sales of natural gas, oil and NGL, net of production costs		(29,380,772	)		(11,799,485	)		(56,691,954	)
Net change in sales prices and production costs		(112,688,455	)		5,708,897			172,990,983
Net change in future development and asset retirement costs		171,076			3,771			(360,323	)
Extensions and discoveries		13,586,306			9,002,111			14,493,340
Revisions of quantity estimates		(16,554,366	)		(10,623,730	)		14,569,169
Acquisitions (divestitures) of reserves-in-place		(19,144,486	)		4,085,305			(5,808,769	)
Accretion of discount		24,132,484			5,948,166			9,652,434
Net change in income taxes		34,208,654			11,522,045			(33,623,250	)
Change in timing and other, net		8,571,310			1,073,174			(7,442,591	)
Net change		(97,098,249	)		14,920,254			107,779,039
End of year	$	100,391,386		$	197,489,635		$	182,569,381